Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________________
FORM 10-K
_______________________________________
ý
¨
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number: 1-34776
_______________________________________
Oasis Petroleum Inc.
(Exact name of registrant as specified in its charter)
_______________________________________
Delaware
(State or other jurisdiction of
incorporation or organization)
1001 Fannin Street, Suite 1500
Houston, Texas
(Address of principal executive offices)
80-0554627
(I.R.S. Employer
Identification No.)
77002
(Zip Code)
(281) 404-9500
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Common Stock, par value $0.01 per share
(Title of Class)
New York Stock Exchange
(Name of Exchange)
Securities Registered Pursuant to Section 12(g) of the Act:
None
_______________________________________
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ý No ¨
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes ¨ No ý
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit such files). Yes ý No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will
not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. ý
/
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller
reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
ý
Non-accelerated filer
¨
Accelerated filer
¨
Smaller reporting company ¨
Emerging growth company
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ý
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at
which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of
the registrant’s most recently completed second fiscal quarter: $4,124,266,176
Number of shares of registrant’s common stock outstanding as of February 22, 2019: 321,790,575
_______________________________________
Documents Incorporated By Reference:
Portions of the registrant’s definitive proxy statement for its 2019 Annual Meeting of Stockholders, which will be filed with the
Securities and Exchange Commission within 120 days of December 31, 2018, are incorporated by reference into Part III of this
report for the year ended December 31, 2018.
/
OASIS PETROLEUM INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2018
TABLE OF CONTENTS
Table of Contents
Part I –
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II –
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III –
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
Part IV –
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act
of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange
Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our
control. All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our
strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and
objectives of management are forward-looking statements. When used in this Annual Report on Form 10-K, the words “could,”
“believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar
expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such
identifying words.
Forward-looking statements may include statements about:
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our business strategic tactics;
estimated future net reserves and present value thereof;
timing and amount of future production of oil and natural gas;
drilling and completion of wells;
estimated inventory of wells remaining to be drilled and completed;
costs of exploiting and developing our properties and conducting other operations;
availability of drilling, completion and production equipment and materials;
availability of qualified personnel;
owning and operating a midstream company, including ownership interests in a master limited partnership;
owning and operating a well services company;
infrastructure for produced and flowback water gathering and disposal;
gathering, transportation and marketing of oil and natural gas, both in the Williston and Delaware Basins and other
regions in the United States;
property acquisitions, including our recent acquisition of oil and gas properties in the Delaware Basin;
integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of
indebtedness;
the amount, nature and timing of capital expenditures;
availability and terms of capital;
our financial strategy, budget, projections, execution of business plan and operating results;
cash flows and liquidity;
oil and natural gas realized prices;
general economic conditions;
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operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;
changes in environmental, safety and other laws and regulations;
effectiveness of risk management activities;
competition in the oil and natural gas industry;
counterparty credit risk;
environmental liabilities;
governmental regulation and the taxation of the oil and natural gas industry;
developments in oil-producing and natural gas-producing countries;
technology;
the effects of accounting pronouncements issued periodically during the periods covered by forward-looking
statements;
uncertainty regarding future operating results;
plans, objectives, expectations and intentions contained in this report that are not historical;
our ability to remediate the identified material weakness in our internal control over financial reporting; and
certain factors discussed elsewhere in this Form 10-K.
All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We disclaim any obligation to
update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-
looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-
looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans,
intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially
from our expectations under “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations” and elsewhere in this Annual Report on Form 10-K. These cautionary statements qualify all forward-
looking statements attributable to us or persons acting on our behalf.
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Item 1. Business
Overview
PART I
Oasis Petroleum Inc. (together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) was originally formed in
2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. We are an independent exploration and
production (“E&P”) company focused on the acquisition and development of onshore, unconventional oil and natural gas
resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP
Permian”) conduct our exploration and production activities and own our proved and unproved oil and natural gas properties
located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Delaware Basin, respectively.
We operate a midstream services business through OMS Holdings LLC (“OMS”), through which we own a majority of the
outstanding units of Oasis Midstream Partners LP (NYSE: OMP) (“OMP” or “Oasis Midstream”), which completed its initial
public offering on September 25, 2017. We also operate a well services business through Oasis Well Services LLC (“OWS”).
As of December 31, 2018, we have accumulated 413,552 net leasehold acres in the Williston Basin, of which approximately 97%
is held by production. We are currently exploiting significant resource potential from the Bakken and Three Forks formations,
which are present across a substantial portion of our acreage. We believe the location, size and concentration of our acreage create
an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory. In
addition, on February 14, 2018, we closed on an acquisition of approximately 22,000 net acres in the Delaware Basin,
representing our initial entry into the Delaware Basin (the “Permian Basin Acquisition”). The Permian Basin Acquisition more
than doubled our core net inventory and allows us to further capitalize on our operational strengths. As of December 31, 2018, we
have accumulated 23,366 net leasehold acres in the Delaware Basin, of which approximately 67% is held by production. Our
management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling
programs, which we refer to as “resource conversion” opportunities, and has substantial Williston Basin and Delaware Basin
experience.
In 2018, we completed and placed on production 121 gross operated wells and had average daily production of 82,525 barrels of
oil equivalent per day (“Boepd”) in the Williston and Delaware Basins. As of December 31, 2018, we had 1,053 gross (784.6 net)
operated producing horizontal wells in the Bakken and Three Forks formations in the Williston Basin and 31 gross (29.5 net)
operated producing horizontal wells in the Delaware Basin. As of December 31, 2018, DeGolyer and MacNaughton, our
independent reserve engineers, estimated our net proved reserves to be 280.1 million barrels of oil equivalent (“MMBoe”) in the
Williston Basin, of which 67% were classified as proved developed and 70% were oil, and net proved reserves to be 40.5 MMBoe
in the Delaware Basin, of which 30% were classified as proved developed and 80% were oil.
Our business
Our goal is to enhance value by investing capital to build reserves, production and cash flows at attractive rates of return through
the following strategic tactics:
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Efficiently develop our Williston Basin and Delaware Basin leasehold positions. We are developing our acreage positions
to maximize the value of our resource potential, while maintaining flexibility to preserve future value when oil prices are
low. During 2018, we completed and brought on production 114 gross (79.0 net) operated wells in the Williston Basin and
7 gross (6.3 net) operated wells in the Delaware Basin. As of December 31, 2018, we had 64 gross operated wells waiting
on completion in the Williston Basin and 4 gross operated wells awaiting completion in the Delaware Basin. Our 2019
capital plan contemplates completing and placing on production approximately 70 gross operated wells in the Williston
Basin and approximately 9 to 11 gross operated wells in the Delaware Basin. We have the ability to increase or decrease
the number of wells drilled and the number of wells completed during 2019 based on market conditions and program
results.
Enhance returns by focusing on operational and cost efficiencies. Our management team is focused on continuous
improvement of our operations and has significant experience in successfully operating cost-efficient development
programs. We believe the magnitude and concentration of our acreage within the Williston Basin, particularly in the core of
the play, has provided and will continue to provide us with the opportunity to capture economies of scale, including the
ability to drill multiple wells from a single drilling pad into multiple formations, utilize centralized production and oil, gas
and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization. The Permian Basin
Acquisition enables us to transfer our technical, operational and managerial knowledge from full-field development of the
Williston Basin to the Delaware Basin. In addition, we expect OMS and OWS to continue to provide operational synergies
going forward compared to third party providers.
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•
Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and
completion techniques to maximize overall well economics. Completion techniques have significantly evolved over the
past decade, resulting in increased initial production rates and recoverable hydrocarbons per well. High intensity
completion techniques continue to deliver production performance greater than prior completion techniques. We
continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our
operating practices. This ongoing evolution may enhance our initial production rates, increase ultimate recovery factors,
lower well capital costs and improve rates of return on invested capital.
• Maintain financial flexibility. Based on current market conditions, we have a strong liquidity position. We have no short-
term debt maturities, and as of December 31, 2018, we had $972.2 million of liquidity available, including $22.2 million of
cash and cash equivalents and $950.0 million in the aggregate of unused borrowing base capacity available under our
Revolving Credit Facilities (as defined in “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Liquidity and Capital Resources”). Our liquidity position, along with internally generated cash
flows from operations, will provide continued financial flexibility as we actively manage the pace of development on our
acreage positions in the Williston Basin and the Delaware Basin. We currently believe we have access to the public and
private capital markets, and we intend to maintain a balanced capital structure by prudently raising proceeds from future
offerings as additional capital needs arise. We also continue to evaluate options to monetize certain assets in our portfolio,
which could result in increased liquidity and lower leverage.
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Pursue strategic acquisitions with significant resource potential. As opportunities arise, we intend to identify and acquire
additional acreage and producing assets to supplement our existing operations. On February 14, 2018, we completed the
Permian Basin Acquisition, and going forward, we may acquire additional acreage in the Williston Basin and Delaware
Basin or may selectively target additional basins that would allow us to employ our resource conversion strategy on large
undeveloped acreage positions similar to what we have accumulated in the Williston Basin.
Our competitive strengths
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
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Substantial leasehold position in two of North America’s leading unconventional oil-resource plays. We believe our
Williston Basin acreage is one of the largest concentrated leasehold positions that is prospective in the Bakken and Three
Forks formations. As of December 31, 2018, we had 413,552 net leasehold acres in the Williston Basin, of which 400,711
net acres were held by production, and 70% of our 280.1 MMBoe estimated net proved reserves in this area were
comprised of oil. In addition, we made our initial entry into one of the most prolific oil plays in North America, the
Delaware Basin. As of December 31, 2018, we had 23,366 net leasehold acres in the Delaware Basin, of which 15,767 net
acres were held by production, and 80% of our 40.5 MMBoe estimated net proved reserves in this area were comprised of
oil. In 2019, we will continue our drilling and completion activities in the Williston Basin as well as in the Delaware Basin.
Large, multi-year project inventory. We believe we have a large inventory of potential drilling locations that we have not
yet drilled, a majority of which are operated by us, and the Permian Basin Acquisition more than doubled our top-tier
inventory. We plan to complete approximately 70 gross operated wells with a working interest of approximately 65% in the
Williston Basin and approximately 9 to 11 gross operated wells with a working interest of approximately 90% in the
Delaware Basin in 2019.
• Management team with proven operating and acquisition skills. Our senior management team has extensive expertise in
the oil and gas industry with an average of more than 25 years of industry experience, including experience in multiple
North American resource plays as well as experience in international basins. We believe our management and technical
team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in
identification, acquisition and execution of resource conversion opportunities. In addition, our technical team possesses
substantial expertise in horizontal drilling techniques and managing and acquiring large development programs.
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Incentivized management team. In 2018, an average of 70% of our executive officers’ overall compensation was in long-
term equity-based incentive awards, and such officers owned approximately 4.0 million shares of our outstanding common
stock as of December 31, 2018. We believe our executive officers’ ownership interest in us provides them with significant
incentives to grow the value of our business for the benefit of all stakeholders.
Operating control over the majority of our portfolio. In order to maintain better control over our asset portfolio, we have
established a leasehold position comprised primarily of properties that we expect to operate. As of December 31, 2018,
96% of our estimated net proved reserves were attributable to properties that we expect to operate. Approximately 94% of
our 2018 drilling and completion capital expenditures and approximately 97% of our 2019 plan are related to operated
wells. Controlling operations will allow us to dictate the pace of development and better manage the costs, type
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and timing of exploration and development activities. We believe that maintaining operational control over the majority of
our acreage will allow us to better pursue our strategies of enhancing returns through operational and cost efficiencies and
maximizing hydrocarbon recovery through continuous improvement of drilling and completion techniques. We are also
better able to control infrastructure investment to drive down operating costs, optimize oil price realizations and increase
the monetization of gas production.
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Vertical integration. Our investments in and operational control of OMS and OWS provide us with additional operational
efficiencies and cost savings compared to our peers. This vertical integration helps us control capital dollars being spent in
advance of production to ensure volumes flow, improve uptime performance of our producing wells, protect against rising
service costs, increase transparency in the planning process and increase communications with vendors by purchasing
directly from them.
Our operations - exploration and production activities
Proved reserves
Our estimated net proved reserves and related PV-10 at December 31, 2018, 2017 and 2016 are based on reports prepared by
DeGolyer and MacNaughton, our independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated
100% of the reserves and discounted values at December 31, 2018, 2017 and 2016 in accordance with the rules and regulations of
the Securities and Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities.
Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure do not include probable or
possible reserves and were determined using the preceding twelve months’ unweighted arithmetic average of the first-day-of-the-
month index prices for oil and natural gas, which were held constant throughout the life of the properties. The unweighted
arithmetic average first-day-of-the-month prices for the prior twelve months were $65.66 per Bbl for oil and $3.16 per MMBtu
for natural gas, $51.34 per Bbl for oil and $2.99 per MMBtu for natural gas and $42.60 per Bbl for oil and $2.47 per MMBtu for
natural gas for the years ended December 31, 2018, 2017 and 2016, respectively. These prices were adjusted by lease for quality,
transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at
the wellhead. The information in the following table does not give any effect to or reflect our commodity derivatives. Future
operating costs, production taxes and capital costs were based on current costs as of each year-end. For a definition of proved
reserves under the SEC rules, please see the “Glossary of oil and natural gas terms” included at the end of this report. For more
information regarding our independent reserve engineers, please see “Independent petroleum engineers” below. Future net
revenues represent projected revenues from the sale of our estimated net proved reserves (excluding derivative contracts) net of
production and development costs (including operating expenses and production taxes). PV-10 and Standardized Measure
represent the present value of the future net revenues discounted at 10%, before and after income taxes, respectively.
There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often
arrive at different estimates for the same properties. There can be no assurance that our estimated net proved reserves will be
produced within the periods indicated or that prices and costs will remain constant. A substantial or extended decline in oil prices
could result in a significant decrease in our estimated net proved reserves and related future net revenues, Standardized Measure
and PV-10 in the future.
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The following table summarizes our estimated net proved reserves and related future net revenues, Standardized Measure and PV-
10:
Estimated proved reserves:
Oil (MMBbls)
Natural gas (Bcf)
Total estimated proved reserves (MMBoe)
Percent oil
Estimated proved developed reserves:
Oil (MMBbls)
Natural gas (Bcf)
Total estimated proved developed reserves (MMBoe)
Percent proved developed
Estimated proved undeveloped reserves:
Oil (MMBbls)
Natural gas (Bcf)
Total estimated proved undeveloped reserves (MMBoe)
Future net revenues (in millions)
Standardized Measure (in millions)(1)
PV-10 (in millions)(2)
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(1)
At December 31,
2018
2017
2016
228.4
552.7
320.5
225.0
523.5
312.2
236.6
411.1
305.1
71%
72%
78%
144.5
339.4
201.1
150.6
301.1
200.8
152.3
229.6
190.6
63%
64%
62%
83.9
213.3
119.4
8,341.6
4,050.3
4,674.3
$
$
$
74.3
222.4
111.4
6,185.4
3,300.7
3,683.7
$
$
$
84.3
181.5
114.5
4,645.6
2,483.1
2,627.8
$
$
$
Standardized Measure represents the present value of estimated future net cash flows from proved oil and natural gas
reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses,
discounted at 10% per annum to reflect timing of future cash flows.
(2)
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable
financial measure under accounting principles generally accepted in the United States of America (“GAAP”), because it
does not include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor Standardized Measure
represents an estimate of the fair market value of our oil and natural gas reserves. The oil and gas industry uses PV-10 as a
measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax
characteristics of such entities. See “Reconciliation of PV-10 to Standardized Measure” below.
The following table provides additional information regarding our estimated net proved developed and undeveloped oil and
natural gas reserves by basin as of December 31, 2018:
Williston Basin
Delaware Basin
Total
Proved Developed
Proved Undeveloped
Oil
(MMBbls)
Natural Gas
(Bcf)
Total
(MMBoe)
Oil
(MMBbls)
Natural Gas
(Bcf)
Total
(MMBoe)
134.6
9.9
144.5
325.5
14.0
339.5
188.8
12.3
201.1
61.5
22.4
83.9
178.4
34.9
213.3
91.2
28.2
119.4
Estimated net proved reserves at December 31, 2018 were 320.5 MMBoe, a 3% increase from estimated net proved reserves of
312.2 MMBoe at December 31, 2017, primarily due to increases of 38.4 MMBoe for additions and 32.9 MMBoe for acquisitions
in the Delaware Basin, partially offset by a decrease of 30.1 MMBoe for production, net negative revisions of 16.9 MMBoe and
15.9 MMBoe for divestitures of non-strategic assets in the Williston Basin. The net negative revisions were attributable to
negative revisions of 42.3 MMBoe due to well performance and 9.4 MMBoe associated with alignment to the five-year
development plan, offset by positive revisions of 14.7 MMBoe for the addition of proved undeveloped reserves (“PUDs”) that
were previously removed from our five-year development plan, 14.4 MMBoe due to higher realized prices and 5.4 MMBoe for
ownership adjustments. Our proved developed reserves increased 0.3 MMBoe, or 0.1%, to 201.1 MMBoe for the year ended
December 31, 2018 from 200.8 MMBoe for the year ended December 31, 2017, primarily due to our 2018 development program,
which included 137 gross (85.5 net) wells that were completed and brought on production during 2018
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and resulted in conversions of PUDs of 48.9 MMBoe and additions of 9.0 MMBoe. In addition, increases in proved developed
reserves were due to purchases of 8.7 MMBoe, offset by decreases of 30.1 MMBoe for production, net negative revisions of 20.2
MMBoe and 15.9 MMBoe for divestitures. Proved developed revisions were primarily due to negative revisions of 33.0 MMBoe
for performance largely related to higher than anticipated decline rates in recently developed spacing units, partially offset by
positive revisions of 12.2 MMBoe due to higher realized prices. Our proved undeveloped reserves increased 8.0 MMBoe, or 7%,
to 119.4 MMBoe for the year ended December 31, 2018 from 111.4 MMBoe for the year ended December 31, 2017 due to
additions of 29.4 MMBoe, acquisitions of 24.2 MMBoe and net positive revisions of 3.4 MMBoe, offset by the conversion of
wells to proved developed of 48.9 MMBoe. The proved undeveloped revisions were primarily due to positive revisions of 14.7
MMBoe for the addition of PUDs that were previously removed from our five-year development plan, 5.6 MMBoe for ownership
adjustments and 2.2 MMBoe due to higher realized prices, offset by negative revisions of 9.4 MMBoe associated with alignment
to the anticipated five-year development plan and 9.3 MMBoe for performance largely related to the associated impact of higher
than anticipated decline rates in recently developed spacing units.
Estimated net proved reserves at December 31, 2017 were 312.2 MMBoe, a 2% increase from estimated net proved reserves of
305.1 MMBoe at December 31, 2016 primarily due to an increase of 51.2 MMBoe for additions, partially offset by a decrease
of 24.1 MMBoe for production and net negative revisions of 19.2 MMBoe. These net negative revisions were attributable to
negative revisions of 39.1 MMBoe due to well performance and 2.1 MMBoe for alignment to the anticipated five-year
development plan, offset by positive revisions of 16.1 MMBoe due to higher realized prices and 2.5 MMBoe for ownership
adjustments. Our proved developed reserves increased 10.2 MMBoe, or 5%, to 200.8 MMBoe for the year ended December 31,
2017 from 190.6 MMBoe for the year ended December 31, 2016, primarily due to our 2017 development program, which
included 153 gross (63.0 net) wells that were completed and brought on production during 2017 and resulted in additions of 17.9
MMBoe and conversions of 32.0 MMBoe. These increases were partially offset by a decrease of 24.1 MMBoe for production and
negative revisions of 14.2 MMBoe. Proved developed revisions were primarily due to negative revisions of 29.7 MMBoe for
performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, offset by
positive revisions of 14.1 MMBoe from increased realized prices. Our proved undeveloped reserves decreased to 111.4 MMBoe
for the year ended December 31, 2017 from 114.5 MMBoe for the year ended December 31, 2016 due to the conversion of wells
to proved developed of 32.0 MMBoe and negative revisions of 5.0 MMBoe, partially offset by 33.3 MMBoe of additions. The
proved undeveloped revisions were primarily due to negative revisions of 9.4 MMBoe for performance revisions largely related
to the associated impact of higher than anticipated decline rates in recently developed spacing units and negative revisions of 1.8
MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 2.6 MMBoe for ownership
adjustments and 2.0 MMBoe from increased realized prices. In 2017, we divested 1.4 MMBoe of reserves associated with
reservoirs other than the Bakken or Three Forks formations.
Reconciliation of Standardized Measure to PV-10
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable
GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax
basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting
future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it
presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future
corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas
properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to
other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas
properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10
measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and
natural gas reserves.
The following table provides a reconciliation of the Standardized Measure of discounted future net cash flows to PV-10:
Standardized Measure of discounted future net cash flows
Add: present value of future income taxes discounted at 10%
PV-10
At December 31,
2018
2017
2016
(In millions)
4,050.3 $
3,300.7 $
624.0
383.0
4,674.3 $
3,683.7 $
$
$
2,483.1
144.7
2,627.8
The PV-10 of our estimated net proved reserves at December 31, 2018 was $4,674.3 million, a 27% increase from PV-10 of
$3,683.7 million at December 31, 2017. This increase was primarily due to higher commodity price assumptions and an increase
in reserves year over year.
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Proved undeveloped reserves
At December 31, 2018, we had approximately 119.4 MMBoe of proved undeveloped reserves as compared to 111.4 MMBoe at
December 31, 2017.
The following table summarizes the changes in our proved undeveloped reserves during 2018:
Proved undeveloped reserves, beginning of period
Extensions, discoveries and other additions
Purchases of minerals in place
Sales of minerals in place
Revisions of previous estimates
Conversion to proved developed reserves
Proved undeveloped reserves, end of period
Year Ended
December 31, 2018
(MBoe)
111,392
29,384
24,194
—
3,387
(48,927)
119,430
During 2018, we spent a total of $659.3 million related to the development of proved undeveloped reserves, $79.2 million of
which was spent on proved undeveloped reserves that represent wells in progress at year-end. The remaining $580.1 million
resulted in the conversion of 48.9 MMBoe of proved undeveloped reserves, or 44% of our proved undeveloped reserves balance
at the beginning of 2018, to proved developed reserves. We added 29.4 MMBoe of proved undeveloped reserves as a result of our
five-year development plan. The 2018 proved undeveloped revisions of 3.4 MMBoe were primarily due to positive revisions of
14.7 MMBoe for the addition of PUDs that were previously removed from our five-year development plan, 5.6 MMBoe for
ownership adjustments and 2.2 MMBoe due to higher realized prices, offset by negative revisions of 9.4 MMBoe associated with
alignment to the anticipated five-year development plan and 9.3 MMBoe for performance largely related to the associated impact
of higher than anticipated decline rates in recently developed spacing units.
We expect to develop all of our proved undeveloped reserves, including all wells drilled but not yet completed, as of December
31, 2018 within five years after the initial year booked. The future development of such proved undeveloped reserves is
dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to
liquidity sources, such as capital markets, our Revolving Credit Facilities and our derivative contracts. All proved undeveloped
locations are located on properties where the leases are held by existing production or continuous drilling operations.
Approximately 15% of our proved undeveloped reserves at December 31, 2018 are attributable to wells that have been drilled but
not yet completed, and 74% and 26% of our undrilled reserves are within our core acreage in the Williston Basin and Delaware
Basin, respectively.
Independent petroleum engineers
Our estimated net proved reserves and related future net revenues and PV-10 at December 31, 2018, 2017 and 2016 are based on
reports prepared by DeGolyer and MacNaughton, our independent reserve engineers, by the use of appropriate geologic,
petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the
petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007) and definitions and current
guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston,
Moscow, Astana, Buenos Aries, Baku and Algiers. The firm’s more than 200 professionals include engineers, geologists,
geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and
other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and
international energy industry. DeGolyer and MacNaughton has provided such services for over 80 years. The Senior Vice
President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a
Registered Professional Engineer in the State of Texas with over 30 years of experience in oil and gas reservoir studies and
reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from The University of Texas at
Austin in 1984, and he is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it
own operating interests in any oil, gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of
professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas
Registered Engineering Firm.
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Technology used to establish proved reserves
In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities,
proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under
existing economic conditions, operating methods and government regulations. The term “reasonable certainty” means
deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there
should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be
established using techniques that have been proved effective by actual production from projects in the same reservoir or an
analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including
computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with
consistency and repeatability in the formation being evaluated or in an analogous formation.
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and
techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of
the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information (Revision as of February 19, 2007). The method or combination of methods used in the analysis of each reservoir
was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production
history.
Based on the current stage of field development, production performance, the development plans provided by us to DeGolyer and
MacNaughton and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the
evaluation of all reserves categories. Performance-based methodology primarily includes (i) production diagnostics, (ii) decline-
curve analysis and (iii) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data
quality control, identification of flow regimes and characteristic well performance behavior. Analysis was performed for all well
groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including
one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model‑based analysis
may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well
performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis
was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production
history and appropriate reserves definitions.
Internal controls over reserves estimation process
We employ DeGolyer and MacNaughton as the independent reserves evaluator for 100% of our reserves base. We maintain an
internal staff of petroleum engineers and geoscience professionals who work closely with the independent reserve engineers to
ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Brett Newton, Senior Vice
President of Asset Management and Chief Engineer, is the technical person primarily responsible for overseeing our reserves
evaluation process. He has over 25 years of industry experience with positions of increasing responsibility in engineering and
management. He holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Mr. Newton
reports directly to our President and Chief Operating Officer.
Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss
evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control
procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves
evaluation software as well as management review, such as, but not limited to the following:
•
•
•
•
•
•
Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure
to the operating costs input in our reserves database;
Review of working interests and net revenue interests in our reserves database against our well ownership system;
Review of historical realized prices and differentials from index prices as compared to the differentials used in our
reserves database;
Review of updated capital costs prepared by our operations team;
Review of internal reserve estimates by well and by area by our internal reservoir engineers;
Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President of
/
Asset Management and Chief Engineer;
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•
•
Review of a preliminary copy of the reserve report by our President and Chief Operating Officer with our internal
technical staff; and
Review of our reserves estimation process by our Audit Committee on an annual basis.
Production, revenues, price and cost history
We produce and market oil and natural gas, which are commodities. The price that we receive for the oil and natural gas we
produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, access to
markets, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural
gas can result in substantial price volatility. Oil supply in the United States has grown dramatically over the past several years,
putting downward pressure on oil prices. Historically, commodity prices have been volatile, and we expect that volatility to
continue in the future. A substantial or extended decline in oil and natural gas prices or poor drilling results could have a material
adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be
economically produced and our ability to access capital markets. Please see “Item 1A. Risk Factors—Risks related to the oil and
natural gas industry and our business—A substantial or extended decline in commodity prices, in oil and, to a lesser extent,
natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital
expenditure obligations and financial commitments.”
The following table sets forth information regarding our oil and natural gas production, realized prices and production costs for
the periods indicated. For additional information on price calculations, please see information set forth in “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations.”
Net production volumes:
Oil (MBbls)
Natural gas (MMcf)
Oil equivalents (MBoe)
Average daily production (Boe per day)
Average sales prices:
Oil, without derivative settlements (per Bbl)
Oil, with derivative settlements (per Bbl)(1)
Natural gas, without derivative settlements (per Mcf)(2)
Natural gas, with derivative settlements (per Mcf)(1)(2)
Costs and expenses (per Boe of production):
Lease operating expenses
Marketing, transportation and gathering expenses(3)
Production taxes
Exploration and production general and administrative expenses
Cash E&P G&A(4)
__________________
(1)
Year Ended December 31,
2018
2017
2016
23,050
42,430
30,122
82,525
18,818
31,946
24,143
66,144
61.84 $
48.51 $
52.65
3.88
3.84
47.99
3.81
3.86
6.44 $
7.34 $
3.56
4.44
3.40
2.48
2.31
3.65
3.21
2.16
15,174
19,573
18,436
50,372
38.64
46.68
1.99
1.99
7.35
1.63
3.07
4.28
3.02
$
$
Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for or
were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and
losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to
acquire or modify the derivative instruments that were settled.
(2)
(3)
(4)
Natural gas prices include the value for natural gas and natural gas liquids.
Prior to the first quarter of 2017, marketing, transportation and gathering expenses included purchased oil and gas
expenses, which represent the crude oil purchased primarily for blending at our crude oil terminal. Prior periods have been
adjusted retrospectively to reflect these expenses in purchased oil and gas expenses on our Consolidated Statements of
Operations. For the year ended December 31, 2016, marketing, transportation and gathering expenses have been adjusted
to exclude $10.3 million of purchased oil and gas expenses.
Cash E&P G&A, a non-GAAP measure, represents general and administrative expenses less non-cash equity-based
compensation expenses included in our exploration and production segment. See “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for a reconciliation of our
exploration and production segment general and administrative expenses to Cash E&P G&A.
/
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Net production volumes for the year ended December 31, 2018 were 30,122 MBoe as compared to net production of
24,143 MBoe for the year ended December 31, 2017. Our net production volumes increased from 2017 to 2018, primarily due to
our acquisition of producing properties in connection with the Permian Basin Acquisition and a successful operated and non-
operated drilling and completion program, offset by the natural decline in production in wells that were producing as of December
31, 2017. Average oil sales prices, without derivative settlements, increased by $13.33 per barrel, or 27%, to an average of $61.84
per barrel for the year ended December 31, 2018 as compared to the year ended December 31, 2017. Giving effect to our
derivative transactions in both periods, our oil sales prices increased $4.66 per barrel to $52.65 per barrel for the year ended
December 31, 2018 from $47.99 per barrel for the year ended December 31, 2017.
Net production volumes for the year ended December 31, 2017 were 24,143 MBoe as compared to net production of 18,436
MBoe for the year ended December 31, 2016. Our net production volumes increased from 2016 to 2017 primarily due to our
acquisition of producing properties in December 2016 and a successful operated and non-operated drilling and completion
program, offset by the natural decline in production in wells that were producing as of December 31, 2016. Average oil sales
prices, without derivative settlements, increased by $9.87 per barrel, or 26%, to an average of $48.51 per barrel for the year ended
December 31, 2017 as compared to the year ended December 31, 2016. Giving effect to our derivative transactions in both
periods, our oil sales prices increased $1.31 per barrel to $47.99 per barrel for the year ended December 31, 2017 from $46.68 per
barrel for the year ended December 31, 2016.
Productive wells
The following table presents the total and operated gross and net productive wells by basin as of December 31, 2018:
Williston Basin - horizontal wells
Williston Basin - other
Delaware Basin - horizontal wells
Delaware Basin - other
Total wells
Total wells
Operated wells
Gross
Net
Gross
Net
1,400
1
103
38
1,542
825.7
1.0
30.1
22.3
879.1
1,053
1
31
19
1,104
784.6
1.0
29.5
17.1
832.2
All of our productive wells are oil wells. Gross wells are the number of wells, operated and non-operated, in which we own a
working interest and net wells are the total of our working interests owned in gross wells.
Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage by basin in which we own a
working interest as of December 31, 2018. Acreage related to royalty, overriding royalty and other similar interests is excluded
from this summary.
Williston Basin
Delaware Basin
Total
Developed acres
Undeveloped acres
Total
Gross
467,100
18,090
485,190
Net
356,766
12,110
368,876
Gross
89,883
20,621
110,504
Net
56,786
11,257
68,043
Gross
556,983
38,711
595,694
Net
413,552
23,367
436,919
Our total acreage that is held by production decreased to 416,478 net acres at December 31, 2018 from 480,023 net acres at
December 31, 2017.
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Undeveloped acreage
The following table sets forth the number of gross and net undeveloped acres by basin as of December 31, 2018 that will expire
over the next three years unless production is established on the acreage prior to the expiration dates:
Year ending December 31,
2019
2020
2021
Gross
Net
Gross
Net
Gross
Net
2,320
966
3,286
1,894
826
2,720
10,420
3,454
13,874
7,763
1,228
8,991
2,430
827
3,257
2,299
156
2,455
Williston Basin
Delaware Basin
Total
Drilling and completion activity
The following table summarizes our completion activity for the years ended December 31, 2018, 2017 and 2016. Gross wells
reflect the sum of all productive and dry wells, operated and non-operated, in which we own a working interest. Net wells reflect
the sum of our working interests in gross wells. The gross and net wells represent wells completed during the periods presented,
regardless of when drilling was initiated.
Development wells:
Oil
Gas
Dry
Total development wells
Exploratory wells:
Oil
Gas
Dry
Total exploratory wells
Total wells
Year ended December 31,
2018
2017
2016
Gross
Net
Gross
Net
Gross
Net
135
—
—
135
2
—
—
2
84.2
—
—
84.2
1.3
—
—
1.3
153
—
—
153
—
—
—
—
63.0
—
—
63.0
—
—
—
—
137
85.5
153
63.0
64
—
—
64
—
—
—
—
64
38.1
—
—
38.1
—
—
—
—
38.1
Over the past several years, we have focused on full field development and have concentrated on improving capital efficiency and
completing more wells using high-intensity completion techniques. We also continued to participate in a number of wells on a
non-operated basis.
We did not drill any dry hole wells in 2018, 2017 or 2016.
As of December 31, 2018, we had six operated rigs running, 6 gross (4.2 net) operated wells drilling and an inventory of 68 gross
operated wells waiting on completion. We expect to continue to concentrate drilling activities within our top-tier acreage in 2019,
including our acreage in the Bakken and Three Forks formations in the Williston Basin as well as our acquired acreage in the
Bone Spring and Wolfcamp formations in the Delaware Basin.
Capital expenditures
In 2018, we spent $1,925.8 million on capital expenditures, excluding midstream capital expenditures, which represented a
220.4% increase as compared to the $601.1 million spent on capital expenditures, excluding midstream, during 2017. Excluding
acquisitions of $951.9 million in 2018, which includes the Permian Basin Acquisition, and $54.0 million in 2017, our non-
midstream capital expenditures increased to $974.0 million from the $547.1 million spent during 2017, which represented a
78.0% increase year over year. This increase was attributable to increased drilling and completion activity as a result of higher
commodity prices in 2018. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
—Liquidity and Capital Resources—Cash flows used in investing activities.”
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We have decreased our planned 2019 capital expenditures as compared to 2018, excluding acquisitions and midstream, as a result
of current commodity prices. Our total 2019 capital expenditure plan, excluding midstream capital expenditures, is approximately
$540 million to $560 million, which includes approximately $405 million to $420 million focused in the Williston Basin and
approximately $135 million to $140 million focused in the Delaware Basin (with approximately 85% of the E&P capital allocated
to drilling and completions). In addition, our 2019 planned capital expenditures includes other capital expenditures for OWS and
administrative capital and excludes capitalized interest of approximately $15 million. We plan to complete and place on
production approximately 70 gross operated wells in the Williston Basin and approximately 9 to 11 gross operated wells in the
Delaware Basin in 2019.
While we have planned approximately $540 million to $560 million in 2019 for these purposes, the ultimate amount of capital we
will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses.
Additionally, if we acquire additional acreage, our capital expenditures may be higher than planned. See “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Description of properties
As of December 31, 2018, we had 101 gross (56.7 net) wells in the process of being drilled or completed in the Williston and
Delaware Basins, which includes 6 gross operated wells drilling, 68 gross operated wells waiting on completion and 27 gross
non-operated wells drilling or completing. We participated in 137 gross (85.5 net) wells that were completed and brought on
production during 2018.
Williston Basin
As of December 31, 2018, our operations were focused in the North Dakota and Montana areas of the Williston Basin. Our
development activities are currently concentrated in the Bakken and Three Forks formations. Our management team originally
targeted the Williston Basin because of its oil-prone nature, multiple producing horizons, substantial resource potential and
management’s previous professional history in the basin. The Williston Basin also generally has established infrastructure and
access to materials and services. Our development activity is focused in the deepest part of the Williston Basin, which we call our
top-tier acreage.
As of December 31, 2018, our total leasehold position in the Williston Basin consisted of 413,552 net acres, and our estimated net
proved reserves in the Williston Basin were 280.1 MMBoe, of which 188.8 MMBoe were proved developed reserves and
91.2 MMBoe were proved undeveloped reserves. As of December 31, 2018, we had a total of 826.7 net producing wells and
785.6 net operated producing wells in the Williston Basin. We had average daily production of 78,203 net Boe per day for the
year ended December 31, 2018 in the Williston Basin. During 2018, our Bakken and Three Forks wells produced a daily average
of 78,168 net Boe per day with 784.6 net operated producing wells on December 31, 2018. Accordingly, our 784.6 net operated
producing Bakken and Three Forks wells were responsible for nearly 100% of our average daily production during 2018. As of
December 31, 2018, our working interest for all producing Bakken and Three Forks wells averaged 59% and averaged 75% in the
wells we operate.
Delaware Basin
On February 14, 2018, we closed the Permian Basin Acquisition, which represented our initial entry into the Delaware Basin. The
assets underlying the Permian Basin Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the
Delaware sub-basin, across Ward, Winkler, Loving and Reeves Counties, Texas.
As of December 31, 2018, our total leasehold position in the Delaware Basin consisted of 23,366 net acres, and our estimated net
proved reserves in the Delaware Basin were 40.5 MMBoe, of which 12.3 MMBoe were proved developed reserves and
28.2 MMBoe were proved undeveloped reserves. As of December 31, 2018, we had a total of 52.4 net producing wells and 46.6
net operated producing wells in the Delaware Basin. We had average daily production of 4,322 net Boe per day for the year ended
December 31, 2018 in the Delaware Basin. During 2018, our horizontal wells in the Delaware Basin produced a daily average of
4,164 net Boe per day with 29.5 net operated producing wells on December 31, 2018. Accordingly, our 29.5 net operated
producing horizontal wells in the Delaware Basin were responsible for nearly 96% of our average daily production during 2018.
As of December 31, 2018, our working interest for all producing horizontal wells in the Delaware Basin averaged 29% and in the
wells we operate averaged 95%.
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Continuous Development Agreement. In connection with the closing of the Permian Basin Acquisition, Forge Energy, LLC
(“Forge Energy”) entered into and assigned to OP Permian a continuous development agreement with the Commissioner of the
General Land Office, on behalf of the State of Texas (collectively, the “State”), as approved by the Board for Lease of University
Lands (the “Board,” and together with the State, “University Lands”). This agreement concerns certain leases covering a
substantial portion of the acreage that the Company indirectly acquired from Forge Energy in the Permian Basin Acquisition and
under which University Lands is the lessor. Pursuant to this agreement, the tracts covered by these leases are pooled into a single
development area for which the Company indirectly holds an eight year initial term ending on December 31, 2025, with an
additional five year term for certain retained acreage at certain depths in the Delaware, Bone Springs and Wolfcamp formations. If
OP Permian fails to meet certain drilling and development obligations, this agreement may be subject to early termination, in
which case, the additional five year term would begin on such date and we may be obligated to pay non-performance fees of up to
approximately $100 million.
Marketing, transportation and major customers
The Williston Basin crude oil rail and pipeline transportation and refining infrastructure has grown substantially over the past
decade, largely in response to drilling activity in the Bakken and Three Forks formations. In December 2018, oil production in
North Dakota was approximately 1,401,000 barrels per day. According to the North Dakota Pipeline Authority website’s data last
updated January 15, 2019, there was approximately 1,421,000 barrels per day of combined crude oil pipeline transportation and
refining capacity and approximately 1,520,000 barrels per day of specifically dedicated rail loading capacity in the Williston
Basin as of December 31, 2018. In 2018, we continued to sell a significant amount of our crude oil production through gathering
systems connected to multiple pipeline and rail facilities. These gathering systems, which typically originate at the wellhead,
reduce the need to transport barrels by truck from the wellhead. As of December 31, 2018, we were flowing approximately 88%
of our gross operated oil production through these gathering systems in the Williston Basin. In the Delaware Basin, approximately
51% of our gross operated oil production was connected to oil gathering systems as of December 31, 2018.
Crude oil produced and sold in the Williston Basin has historically sold at a discount to the NYMEX West Texas Intermediate
crude oil index price (“WTI”) due to transportation costs and takeaway capacity. In the past, there have been periods when this
discount has substantially increased due to the production of oil in the area increasing to a point that it temporarily surpasses the
available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline
facilities have reduced the prior constraint on oil transportation out of the Williston Basin and improved netback pricing received
at the lease. In 2015, our price differentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S.
markets and transportation on rail gradually declined. Since 2016, our price differentials have averaged less than $5.00 per barrel
discount to WTI. In the second half of 2017 and throughout most of 2018, our crude oil price differentials improved to less than
$2.00 per barrel discount to WTI primarily due to the additional takeaway capacity of the Dakota Access Pipeline of over 500,000
barrels per day. In the fourth quarter of 2018, above average refinery maintenance combined with production in the basin reaching
record levels temporarily caused basis differentials to widen to more than $6.50 per barrel discount to WTI, but have since come
back in line with the first three quarters of 2018. Our market optionality on the crude oil gathering systems allows us to shift
volumes between pipeline and rail markets in order to optimize price realizations. In the Delaware Basin, price differentials in
2018 averaged more than $4.00 per barrel below WTI due to pipeline constraints. Expansions of pipelines occurring in 2019
should greatly reduce these differentials and provide ample takeaway for our Delaware production beginning in mid-2019. For a
discussion of the potential risks to our business that could result from transportation and refining infrastructure constraints in the
Williston Basin, please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—
Insufficient transportation, end-market refining utilization or natural gas processing capacity in the Williston Basin and Delaware
Basin could cause significant fluctuations in our realized oil and natural gas prices.”
We principally sell our oil and natural gas production to refiners, marketers and other purchasers that have access to nearby
pipeline and rail facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which
cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk Factors—Risks related to the
oil and natural gas industry and our business—Market conditions or operational impediments may hinder our access to oil and
natural gas markets or delay our production” and “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and
our business—Insufficient transportation, end-market refining utilization or natural gas processing capacity in the Williston Basin
and Delaware Basin could cause significant fluctuations in our realized oil and natural gas prices.”
In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities
in-house, which enables us to market and sell our oil and natural gas to a broad array of potential purchasers. As of December 31,
2018, we sold a substantial majority of our oil and condensate through bulk sales at delivery points on crude oil gathering systems
to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-
based price, which incorporates regional differentials that include, but are not limited to, transportation costs. In addition, from
time to time we may enter into third party purchase and sales transactions that allow us to optimize our
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advantageous gathering and transportation positions and increase the value of our oil price realizations. We also entered into
various short-term sales contracts for a portion of our portfolio at fixed differentials. Due to the availability of other markets and
pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect
on our results of operations or cash flows.
For the year ended December 31, 2018, no purchaser accounted for more than 10% of the Company’s total sales. For the year
ended December 31, 2017, sales to Shell Trading (US) Company accounted for approximately 16% of our total sales. For the year
ended December 31, 2016, sales to PBF Holding Company LLC accounted for approximately 10% of our total sales. No other
purchasers accounted for more than 10% of our total oil and natural gas sales for the years ended December 31, 2017 and 2016.
We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are a
number of alternative crude oil and natural gas purchasers in the Williston and Delaware Basins.
Since most of our oil and natural gas production is sold under market-based or spot market contracts, the revenues generated by
our operations are highly dependent upon the prices of and demand for oil and natural gas. The price we receive for our oil and
natural gas production depends upon numerous factors beyond our control, including but not limited to seasonality, weather,
competition, availability of transportation and gathering capabilities, worldwide and regional economic conditions, global and
domestic oil supply, foreign imports, political conditions in other oil-producing and natural gas-producing regions, the actions of
the Organization of Petroleum Exporting Countries (“OPEC”) and domestic government regulation, legislation and policies.
Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—A substantial or extended
decline in commodity prices, in oil and, to a lesser extent, natural gas prices may adversely affect our business, financial condition
or results of operations and our ability to meet our capital expenditure obligations and financial commitments.” Furthermore, a
decrease in the price of oil and natural gas could have an adverse effect on the carrying value of our estimated proved reserves
and on our revenues, profitability and cash flows. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas
industry and our business—If oil and natural gas prices decline substantially or for an extended period of time from their current
levels, we may be required to take write-downs of the carrying values of our oil and natural gas properties.”
Market, economic, transportation and regulatory factors may in the future materially affect our ability to market our oil or natural
gas production. Please see “Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our business—Market
conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.”
Our operations - midstream services
We continue to develop our midstream services business, which includes produced and flowback water gathering and disposal,
natural gas gathering, compression and processing, fresh water supply and distribution and crude oil gathering and transportation.
Our midstream services assets are strategically located in the Williston Basin and Delaware Basin and support our upstream
operations. These assets also provide services to third party customers.
Our midstream services operations include those of OMP, a publicly-traded consolidated subsidiary and limited partnership that
owns, develops, operates and acquires a diversified portfolio of midstream assets in North America. OMP is a growth-oriented,
fee-based master limited partnership we formed in 2014 and organized in a development company structure. On September 25,
2017, OMP completed its initial public offering (“IPO”) of common units. At December 31, 2018, our ownership interest in
OMP consisted of a 67.6% limited partner interest and 90% controlling interest in its general partner interest, which owns all of
OMP’s incentive distribution rights and its non-economic general partner interest. OMP conducts its operations through its three
development companies (collectively, the “DevCos”): Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat
DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”).
OMP divides its operations into two primary areas with developed midstream infrastructure, both of which are supported by
significant acreage dedications from us. In Wild Basin, we have dedicated to OMP approximately 65,000 acres, of which
approximately 29,000 acres are within our current gross operated acreage position, and in which OMP has the right to provide oil,
natural gas and water services to support our existing and future volumes. Outside of Wild Basin, we have dedicated to OMP
approximately 581,000 acres for produced and flowback water services, of which approximately 299,000 acres are within our
current gross operated acreage. In addition, we have dedicated to OMP approximately 364,000 acres for freshwater services, of
which approximately 203,000 acres are within our current gross operated acreage. In addition, OMP has received certain
commitments from third parties in which OMP has the right to provide its full suite of midstream services to support existing and
future third party volumes.
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Contractual arrangements
In connection with the OMP IPO, we entered into several 15-year, fee-based contractual arrangements with OMP for midstream
services, including (i) gas gathering, compression, processing and gas lift services; (ii) crude gathering, stabilization, blending,
storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply
and distribution services. In addition, we provide substantial labor and overhead support for OMP. Upon completion of the OMP
IPO, we entered into a 15-year services and secondment agreement with OMP pursuant to which we provide all personnel,
equipment, electricity, chemicals and services (including third-party services) required for OMP to operate such assets, and OMP
reimburses us for its share of the actual costs of operating such assets. In addition, pursuant to the services and secondment
agreement, we perform centralized corporate, general and administrative services for OMP, such as legal, corporate
recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and
claims processing, risk management, health, safety and environmental, information technology, human resources, investor
relations, cash management and banking, payroll, internal audit, taxes and engineering. We have also seconded to OMP certain of
its employees to operate, construct, manage and maintain its assets, and OMP reimburses us for direct general and administrative
expenses we incurred for the provision of the above services. The expenses of executive officers and non-executive employees
are allocated to OMP based on the amount of time spent managing its business and operations.
OMP public offering and dropdown
On November 14, 2018, OMP completed a public offering of 2,300,000 common units (including 300,000 common units issued
pursuant to the underwriters’ option to purchase additional common units) representing limited partnership interests, at a price to
the public of $20.00 per common unit. OMP received net proceeds from the public offering of approximately $44.5 million, after
deducting underwriting discounts, commissions and offering costs, which were used to fund a portion of its acquisition of
additional ownership interest in Bobcat DevCo and Beartooth DevCo.
In connection with the OMP public offering, on November 19, 2018, OMP acquired an additional 15% ownership interest in
Bobcat DevCo increasing its ownership to 25% and an additional 30% ownership interest in Beartooth DevCo increasing its
ownership to 70% in exchange for consideration of $251.4 million (“OMP Dropdown”).
The $251.4 million consideration consisted of $172.4 million in cash and 3,950,000 common units representing limited partner
interests in OMP. OMP funded the cash portion of the consideration with a combination of borrowings under the revolving credit
facility among OMP, as parent, OMP Operating LLC, a subsidiary of OMP, as borrower, Wells Fargo Bank, N.A., as
administrative agent and the lenders party thereto (the “OMP Credit Facility”) and proceeds from its public offering of common
units. As a result of the OMP Dropdown, we now own 75% of the non-controlling interests of Bobcat DevCo and 30% of the
non-controlling interests of Beartooth DevCo.
Capital expenditures
In 2018, midstream capital expenditures primarily related to the second natural gas processing plant constructed in our Wild Basin
area in North Dakota and the development of additional midstream infrastructure in the Wild Basin area in North Dakota. We
have decreased our planned 2019 midstream capital expenditures, excluding acquisitions, to approximately $150.0 million to
$170.0 million as compared to 2018 midstream capital expenditures, excluding acquisitions.
Competition
The oil and natural gas industry is worldwide and highly competitive in all phases. We encounter competition from other oil and
natural gas companies in all areas of operation, including the acquisition of leasing options on oil and natural gas properties to the
exploration and development of those properties. Our competitors include major integrated oil and natural gas companies,
numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are
large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such
companies may be able to pay more for lease options on oil and natural gas properties and exploratory locations and to define,
evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit. Our
ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive environment. Please see “Item 1A. Risk Factors—
Risks related to the oil and natural gas industry and our business—Competition in the oil and natural gas industry is intense,
making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.”
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Title to properties
As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do
not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title
examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations
reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will
not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained
title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing
properties in accordance with general industry standards. Prior to completing an acquisition of producing oil and natural gas
leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain
a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and
other interests, liens to secure borrowings under our Revolving Credit Facilities, liens for current taxes and other burdens, which
we believe do not materially interfere with the use or affect our carrying value of the properties. Please see “Item 1A. Risk
Factors—Risks related to the oil and natural gas industry and our business—We may incur losses as a result of title defects in the
properties in which we invest.”
Seasonality
Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities
and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily
halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for
meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and
summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.
Regulation of the oil and natural gas industry
Our oil and natural gas producing, midstream and well services operations are substantially affected by federal, tribal, regional,
state and local laws and regulations. In particular, oil and natural gas production, oil gathering and transportation, natural gas
processing and related operations are, or have been, subject to price controls, taxes and numerous laws and regulations. All of the
jurisdictions in which we own or operate properties for oil and natural gas production or otherwise provide midstream services
have statutory provisions regulating the exploration for and production of oil and natural gas or the gathering, transportation and
processing of those commodities, including provisions related to permits for the drilling of wells or processing of natural gas,
bonding requirements to drill or operate producing or injection wells, the location of wells, the method of drilling and casing
wells, the surface use and restoration of properties upon which wells are drilled or processing plants are constructed, sourcing and
disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to
various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the
number of wells that may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines,
and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of
natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and
individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry
increases the cost of doing business and affects profitability. Historically, our compliance costs with applicable laws and
regulations have not had a material adverse effect on our financial position, cash flows and results of operations; however, new
laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased
governmental enforcement may occur and, thus, there can be no assurance that such costs will not be material in the future.
Additionally, environmental incidents such as spills or other releases may occur or past non-compliance with environmental laws
or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional
proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal
Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may be
finalized and become effective.
Regulation of transportation and sales of oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless,
Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common
carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the
Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all
shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC
implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that
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allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index,
without making a cost of service filing. Many existing pipelines utilize the FERC oil index to change transportation rates annually
every July 1, and our Bighorn DevCo Johnson’s Corner line will utilize the FERC oil index beginning on July 1, 2022. Every five
years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. Most recently, on
December 17, 2015, FERC established a new price index for the five-year period commencing July 1, 2016 and ending June 30,
2021, in which common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price
Index plus 1.23%.
On March 15, 2018, in a set of related issuances, FERC addressed treatment of federal income tax allowances in regulated entity
rates. FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that, among
other things and with respect to oil and refined products pipelines subject to FERC jurisdiction, the pipeline is required to reflect
the impacts to its cost of service from the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) on
Page 700 of FERC Form No. 6. This information will be used by FERC in its next five-year review of the oil pipeline index to
generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act
in the determination of indexed rates prospectively, effective July 1, 2021. FERC’s establishment of a just and reasonable rate,
including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will
affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other
pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on
FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and
tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to
cost-of-service based rates in the future, including indexed rates.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil
pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to
state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the
regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our
competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open
access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and
under the same rates. When oil pipelines operate at full capacity, access is generally governed by prorationing provisions set forth
in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be
available to us to the same extent as to our similarly situated competitors.
We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. Several
derailments of freight trains since 2013 have led transportation safety regulators in the United States and Canada to examine
whether the hazardous nature of crude oil from the Bakken shale is being assessed properly prior to its shipment. In particular,
there are concerns that the testing and ensuing designations of crude oil on the shipping documentation do not in all cases
accurately capture the flammability of the Bakken shale crude oil. In early 2014, the federal Pipeline and Hazardous Materials
Safety Administration (“PHMSA”) released a Safety Alert alerting regulators, emergency responders, transporters and shippers
that crude oil from the Bakken shale may have flammability characteristics that are different from other forms of crude oil and
that it was vital that all shipments of crude oil be tested and properly characterized on all shipping documentation. The Safety
Alert also notified the regulated community that PHMSA and the Federal Railroad Administration (“FRA”) had launched an
enforcement initiative that involved unannounced inspections on crude oil shipments to test the contents of the shipments in order
to ensure that they are properly characterized. In 2014, the U.S. Department of Transportation released a report finding that, based
on the results of this enforcement initiative from August 2013 to May 2014, Bakken shale crude oil tended to be more volatile and
flammable than other crude oils, and thus posed an increased risk for a significant accident.
These events have also spurred efforts to improve the safety of tank cars that are used in transporting crude oil by rail. Since 2011,
all new railroad tank cars that have been built to transport crude oil or other petroleum type fluids, including ethanol, have been
built to more stringent safety standards. In 2015, PHMSA adopted a final rule that included, among other things, additional
requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program
for crude oil, and a requirement that older DOT-111 tank cars be phased out beginning in October 2017 if they are not already
retrofitted to comply with new tank car design standards. The 2015 final rule also included a new braking standard for certain
trains, designated new operational protocols for trains transporting large volumes of flammable liquids, such as routing analyses,
speed restrictions and information for local government agencies and provided new sampling and testing requirements to improve
classification of energy products placed into transport; however, in September 2018, PHMSA published a final rule that removed
requirements for the new braking standard established under its 2015 final rule. In 2016, PHMSA released a final rule mandating
a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol,
between 2018 and 2029. Additionally, in 2016, PHMSA proposed a new rule, which has not yet been finalized, that would expand
the applicability of comprehensive oil spill response plans so that any railroad that transports a single train carrying 20 or more
loaded tanks of liquid petroleum oil in a continuous block or a single train
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carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train must have a current, comprehensive, written
plan. Also, in response to a petition from the New York Attorney General, PHMSA issued an advance notice of proposed
rulemaking (“ANPR”) in early 2017 stating that it was considering revising the Hazardous Materials Regulations to establish
vapor pressure limits for unrefined petroleum-based products and potentially all Class 3 flammable liquid hazardous materials
that would apply during the transportation of the products or materials by any mode. Similarly, in 2016, the FRA modified its
accident and incident reports to gather additional data concerning rail cars carrying crude oil in any train involved in an FRA-
reportable accident. In addition to these or other actions taken or proposed by federal agencies, a number of states proposed or
enacted laws in recent years that encourage safer rail operations or urge the federal government to strengthen requirements for
these operations.
Safety improvements or updates to existing tank cars that are imposed under PHMSA’s 2015 final rule requirements could drive
up the cost of transport and lead to shortages in availability of tank cars. We do not currently own or operate rail transportation
facilities or rail cars; however, we cannot assure that costs incurred by the railroad industry to comply with these enhanced
standards resulting from PHMSA’s final rule will not increase our costs of doing business or limit our ability to transport and sell
our crude oil at favorable prices, the consequences of which could be material to our business, financial condition or results of
operations. However, we believe that any such consequences would not affect our operations in any way that is of material
difference from those of our competitors who are similarly situated.
Efforts are likewise underway in Canada to assess and address risks from the transport of crude oil by rail. For example, in 2014,
Transport Canada issued a protective order prohibiting oil shippers from using 5,000 of the DOT-111 tank cars and imposing a
three year phase out period for approximately 65,000 tank cars that do not meet certain safety requirements. Transport Canada
also imposed a 50 mile per hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada
to have an emergency response plan. At the same time that PHMSA released its 2015 rule, Canada’s Minister of Transport
announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. Likewise, Transport
Canada’s rail car retrofitting and phase out timeline largely aligns with the timeline introduced under the 2015 and 2016 PHMSA
rules. Transport Canada has also introduced new requirements that railways carry minimum levels of insurance depending on the
quantity of crude oil or dangerous goods that they transport as well as a final report recommending additional practices for the
transportation of dangerous goods. Both Transport Canada and PHMSA issued final rules in January 2018 and November 2018,
respectively, that further harmonize their respective tank car standards, including with respect to tank car approvals and design
requirements.
Historically, our hazardous materials transportation compliance costs have not had a material adverse effect on our results of
operations; however, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal
requirements or increased governmental enforcement regarding hazardous material transportation may occur in the future, which
could directly and indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of
tank cars. We cannot assure that costs incurred to comply with standards and regulations emerging from these existing and any
future rulemakings will not be material to our business, financial condition or results of operations. Moreover, we may incur
significant constraints on transportation capacity during the period while tank cars are being retrofitted or newly constructed to
comply with the new regulations. In addition, any derailment of crude oil from the Bakken shale or Delaware Basin involving
crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.
Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will
cover the entirety of any damages that may arise from such an event. Nonetheless, we believe that any such consequences would
not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Regulation of transportation and sales of natural gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the
Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In
the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural
gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural
gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which
removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of
natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to
make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC
has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline
industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural
gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.
Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access
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policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single
service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an
open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers,
they are intended to foster increased competition within all phases of the natural gas industry.
In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance
competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings
for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to
scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. The natural gas industry
historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory
approach recently established by FERC under Order No. 637 will continue. However, we do not believe that any action taken will
affect us in a way that materially differs from the way it affects other natural gas producers.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to
state regulation. However, with regard to our physical sales of energy commodities, we are required to observe anti-market
manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”) and
the Federal Trade Commission (“FTC”). Please see below the discussion of “Other federal laws and regulations affecting our
industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be
subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant
to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous
calendar year. Order No. 704 requires certain natural gas market participants to report information regarding their reporting of
transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their
wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted.
Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.”
Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in
state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering
function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by
case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some
circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by
state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain
transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural
gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services
varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers
within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in
any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of
material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate
transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our
natural gas.
Regulation of production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders
and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports
concerning operations. We own and operate properties in North Dakota and Montana, which have regulations governing
conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of
maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and
abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our
wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such
regulations or to have reductions in well spacing. Moreover, both states impose a production or severance tax with respect to the
production and sale of oil, natural gas and natural gas liquids within their jurisdictions.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural
gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
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Other federal laws and regulations affecting our industry
Energy Policy Act of 2005
On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (“EPAct 2005”). EPAct 2005 is a
comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to
the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an
anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC,
and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides FERC with the power to assess civil
penalties of up to $1,269,500 per day, adjusted annually for inflation, for violations of the NGA and increases FERC’s civil
penalty authority under the NGPA from $5,000 per violation per day to $1,269,500 per violation per day, adjusted annually for
inflation. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate
commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct
2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the
purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the
jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material
fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice
or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities
that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage
companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the
extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which
now includes the annual reporting requirements under Order No. 704, as described below. The anti-manipulation rules and
enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all
applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
FERC market transparency rules
On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by
subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million
MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas
gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year,
aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize,
contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which
individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market
participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with
FERC’s policy statement on price reporting.
Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting
market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the
purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or
course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or
deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made
by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A
violation of this rule may result in civil penalties of up to $1,191,842 per day per violation, adjusted annually for inflation, in
addition to any applicable penalty under the Federal Trade Commission Act.
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Texas Railroad Commission oil and natural gas rules
The Texas Railroad Commission (“RRC”), through its Oil and Gas Division, regulates the exploration, production, and
transportation of oil and natural gas in Texas. Among other duties, the RRC develops and adopts regulations to prevent waste of
the state’s oil and natural resources, protects the correlative rights of different interest owners, prevents pollution, and provides
safety with respect to operations including, for example, hydrogen sulfide emissions. The RRC grants drilling permits based on
established spacing and density rules. Additionally, each month, the RRC assigns production allowables on oil and natural gas
wells based on factors such as tested well capability, reservoir mechanics, market demand for production, and past production, as
well as receives operators’ production reports on oil leases and gas wells, and audits the oil disposition path to ensure production
did not exceed allowables. The RRC also regulates oil field injection and disposal wells under a federally-approved program that
includes permitting, annual reporting and periodic testing activities. Through this program, fluids are injected into either
productive reservoirs under enhanced recovery projects to increase production or into non-productive reservoirs for disposal. In
other pollution prevention activities, the RRC assures waste management is carried out by permitting pits and landfarming,
discharges, waste haulers, waste minimization, and hazardous waste management tasks. To prevent pollution of the state’s surface
and ground water resources, the RRC has an abandoned well plugging and abandoned site remediation program that uses funds
provided by industry through fees and taxes. Wells and sites are remediated with funds from this program when responsible
operators cannot be found.
North Dakota Industrial Commission oil and natural gas rules
The North Dakota Industrial Commission (“NDIC”) regulates the drilling and production of oil and natural gas in North Dakota.
Beginning in 2012, the NDIC adopted more stringent rules, imposing increased bonding amounts for the drilling of wells,
severely restricting the discharge and storage of production wastes such as produced water, drilling mud, waste oil and other
wastes in earthen pits, implementing more stringent hydraulic fracturing requirements and requiring the provision of public
disclosure on FracFocus.org regarding chemicals used in the hydraulic fracturing process. In 2016, the NDIC approved a suite of
additional rules for the conservation of crude oil and natural gas, including new requirements relating to site construction,
underground gathering pipelines, spill containment bonding requirements for underground gathering pipelines, and construction
of berms around facilities, which new requirements are now in effect. These requirements have increased the well costs incurred
by us and similarly situated oil and natural gas E&P operators, and we expect to continue to incur these increased costs as well as
any added costs arising from new NDIC legal requirements laws and regulations applicable to the drilling and production of oil
and natural gas that may be issued in the future.
Furthermore, in 2014, the NDIC adopted an order intended to reduce natural gas flaring, which order was subsequently modified
in late 2015 and the underlying flaring program’s policy goals were revised in November 2018. Please see below the discussion of
“Environmental protection and natural gas flaring initiatives” for more information on this order. In addition, in 2014, the NDIC
adopted conditioning standards that are now in effect and improve the safety of Bakken crude oil for transport. Among other
things, the 2014 rule sets operating standards for conditioning equipment to properly separate production fluids, addresses limits
to the vapor pressure of produced crude oil, and includes parameters for temperatures and pressures associated with the
production equipment.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the
courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not
believe that we would be affected by any such action materially differently than similarly situated competitors.
Pipeline safety regulation
Certain of our pipelines are subject to regulation by PHMSA under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) with
respect to oil and condensates and the Natural Gas Pipeline Safety Act (“NGPSA”) with respect to natural gas. The HLPSA and
NGPSA govern the design, installation, testing, construction, operation, replacement and management of oil and natural gas
pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation
pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified
anomalies and other measures to ensure pipeline safety in high consequence areas (“HCAs”), such as high population areas, areas
unusually sensitive to environmental damage and commercially navigable waterways. In addition, states have adopted regulations
similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines, which regulations may impose
more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a
material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the
future or that such future compliance costs will not have a material adverse effect on our business and operating results. New
pipeline safety laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or
increased governmental enforcement may impose more stringent requirements applicable to integrity management programs and
other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational
delays.
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Legislation in recent years has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing
and adopting regulations that impose increased pipeline safety requirements on pipeline operators. The HLPSA and NGPSA were
amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). The 2011
Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed
pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for
existing pipelines. In June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016
Pipeline Safety Act”) was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring
PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards
for natural gas storage facilities. The 2016 Pipeline Safety Act also empowers PHMSA to address unsafe conditions or practices
constituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of
hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim
regulations in 2016 to implement the agency’s expanded authority to address such conditions or practices that pose an imminent
hazard to life, property or the environment.
The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or
safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA
issued a final rule that significantly extends and expands the reach of certain PHMSA hazardous liquid pipeline integrity
management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s
proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines,
including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal
Register has been delayed following the January 2017 change in presidential administrations. In a second example, in March
2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas
lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for
natural gas pipelines in newly defined “moderate consequence areas” that contain as few as five dwellings within a potential
impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be
tested to determine their maximum allowable operating pressures (“MAOP”); and requiring certain onshore and offshore
gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line
markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase
PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating
threats to pipelines. PHMSA has split this proposed rule into three separate rulemaking proceedings and is expected to finalize
those proceedings in 2019. New legislation or any new regulations adopted by PHMSA may impose more stringent requirements
applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur
increased capital and operating costs and operational delays. In the absence of the PHMSA pursuing any legal requirements, state
agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.
Environmental and occupational health and safety regulation
Our exploration, development and production operations, oil gathering and transportation activities, natural gas processing
services and related operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing
occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection.
These laws and regulations may, among other things, require the acquisition of permits to conduct drilling or provide midstream
services; govern the amounts and types of substances that may be released into the environment; limit or prohibit construction or
drilling activities in environmentally-sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered species;
require investigatory and remedial actions to mitigate pollution conditions; impose obligations to reclaim and abandon well sites,
pits, processing plants and pipelines; and impose specific criteria addressing worker protection. Failure to comply with these laws
and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of
investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions,
delays or cancellations in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of
our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the
rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing
business in the industry and consequently affects profitability.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment,
and thus, any new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or
increased governmental enforcement that result in more stringent and costly well construction, drilling, water management or
completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse
effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our
customers. Moreover, accidental spills or other releases may occur in the course of our operations, and we cannot assure you that
we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for
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damage to property, natural resources or persons. While, historically, our compliance costs with environmental laws and
regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no
assurance that such costs will not be material in the future as a result of such existing laws and regulations or any new laws and
regulations, or that such future compliance will not have a material adverse effect on our business and operating results.
The following is a summary of the more significant existing environmental and occupational health and safety laws, as amended
from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on
our capital expenditures, results of operations or financial position.
Hazardous substances and wastes
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law,
and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of
persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These classes of
persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged
for the disposal of the hazardous substances released at the site. Under CERCLA, these “responsible persons” may be subject to
joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S.
Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for
neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the
release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations
that may be regulated as hazardous substances.
We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes.
RCRA imposes strict requirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and
nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA, sometimes
in conjunction with their own, more stringent requirements. In the course of our operations, we generate ordinary industrial
wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other
wastes associated with exploration, development and production of oil and natural gas from regulation as hazardous wastes.
These wastes, instead, are regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws.
However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as
nonhazardous wastes could be classified as hazardous wastes in the future. For example, pursuant to a consent decree issued by a
federal court, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D
regulations that result in such oil and natural gas wastes being regulated as hazardous wastes, or sign a determination that revision
of those RCRA regulations is unnecessary. If the EPA proposes a rulemaking for revised oil and natural gas regulations, the
Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.
Repeal or modification of the current RCRA exclusion or similar exemptions under state law could increase the amount of
hazardous waste we are required to manage and dispose of and could cause us or our customers to incur increased operating costs,
which could have a significant impact on us as well as reduce demand for our midstream and well services.
We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore
and produce oil and natural gas or for conducting midstream services. Although we have utilized operating and disposal practices
that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released
on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons
and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by third parties
whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control.
These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws.
Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform
remedial plugging or pit, processing plant or pipeline closure operations to prevent future contamination.
Air emissions
The federal Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of various air pollutants from
many sources through air emissions standards, construction and operating permitting programs, and the imposition of other
monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or
modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply
with stringent air permit requirements or utilize specific equipment or technologies to control emissions of
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certain pollutants. Obtaining permits has the potential to restrict, delay or cancel the development of oil and natural gas projects.
Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other
air emissions-related issues. For example, in 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air
Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion under both the primary and secondary standards. In
2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,”
“unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local
and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of these revised
standards could result in stricter permitting requirements, delay, limit or prohibit our ability to obtain such permits, and result in
increased expenditures for pollution control equipment, the costs of which could be significant. Compliance with this final rule or
any other new legal requirements could, among other things, require installation of new emission controls on some of our
equipment, result in longer permitting timelines, significantly increase our capital expenditures and operating costs, and reduce
demand for the oil and natural gas that we produce, which one or more developments could adversely impact our production,
midstream and well services businesses.
Environmental protection and natural gas flaring initiatives
We attempt to conduct our operations in a manner that protects the health, safety and welfare of the public, our employees and the
environment. We are focused on the reduction of air emissions produced from our operations, particularly with respect to flaring
of natural gas from our operated well sites. The rapid growth of crude oil production in North Dakota in recent years, coupled
with a historical lack of natural gas gathering infrastructure in the state, has led to efforts to reduce flaring of natural gas produced
in association with crude oil production. We recognize the environmental and financial risks associated with natural gas flaring,
and we seek to manage these risks on an ongoing basis, consistent with applicable requirements.
We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is the inability of
operators to promptly connect their wells to natural gas processing and gathering infrastructure due to external factors out of the
control of the operator, such as, for example, the granting of right-of-way access by land owners, investment from third parties in
the development of gas gathering systems and processing facilities, and the development and adoption of regulations. However,
we have allocated significant resources to connect our Bakken and Three Forks wells to natural gas infrastructure to reduce our
flared volumes. We have exceeded a goal that we voluntarily set in 2014 to maintain well connections for an average of 90% of
our operated Bakken and Three Forks wells, by having approximately 98% of our operated Bakken and Three Forks wells
connected to gathering systems since 2015. We believe that achieving this goal helps us to minimize our flared volumes of natural
gas.
In 2014, the NDIC adopted Order No. 24665 (the “2014 Order”), pursuant to which the agency adopted legally enforceable “gas
capture percentage goals” targeting the capture of natural gas produced in the state between October 1, 2014 and October 1, 2020.
Modification of the July 2014 Order by the NDIC in late 2015, resulted in revised gas capture percentage goals of 88% and 91%
required to be achieved by November 1, 2018 and November 1, 2020, respectively. Most recently, in November 2018, the NDIC
considered revising its 2018 and 2020 gas capture percentage goals but elected to retain those standards; however, the NDIC
revised the flaring program’s policy goals such that the oil and gas exploration and production industry has more flexibility in
removing certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals. The
NDIC continues to adhere to other aspects of the modified 2014 Order, including development of Gas Capture Plans that provide
measures for reducing the amount of natural gas flared by those operators so as to be consistent with the agency’s gas capture
percentage goals. Also, wells must continue to meet or exceed the NDIC’s gas capture percentage goals on a statewide, county,
per-field, or per-well basis. If an operator is unable to attain the applicable gas capture percentage goal at maximum efficiency
rate, wells will be restricted in production to 200 barrels of oil per day if at least 60% of the monthly volume of associated natural
gas produced from the well is captured, or otherwise oil production from such wells shall not exceed 100 barrels of oil per day.
However, the NDIC will consider flexibility to these production restrictions, by means of temporary exemptions, for other types
of extenuating circumstances after notice and hearing if the effect of such flexibility is a significant net increase in gas capture
within one year of the date such relief is granted. Monetary penalty provisions also apply under this policy in the event an
operator not meeting the gas capture percentage goals fails to timely file for a hearing with the NDIC upon being unable to meet
such percentage goals or if the operator fails to timely implement production restrictions once below the applicable percentage
goals. As of December 31, 2018, we were capturing approximately 88% of our natural gas production in North Dakota. While we
were satisfying the applicable gas capture percentage goals as of December 31, 2018 and expect to satisfy the November 1, 2020
gas capture percentage goals of 91%, there is no assurance that we will remain in compliance in the future or that such future
satisfaction of such goals will not have a material adverse effect on our business and results of operations.
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Climate change
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals
have been made and are likely to continue to be made at the international, national, regional and state levels of government to
monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration by states or groupings of
states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG
emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has
determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the
environment and has adopted regulations under existing provisions of the CAA that establish Prevention of Significant
Deterioration (“PSD”) construction under Title V operating permit reviews for GHG emissions from certain large stationary
sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain
PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. The EPA has
also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an
annual basis, including, among others, onshore and offshore oil and natural gas production facilities and onshore processing,
transmission, storage and distribution facilities, which include certain of our operations. The EPA has amended and expanded the
GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and
blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In 2016,
the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified
or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions.
These Subpart OOOOa standards expand the previously issued NSPS Subpart OOOO requirements issued in 2012 by using
certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well
as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In June
2017, the EPA published a proposed rule to stay certain portions of the 2016 standards for two years but the rule was not
finalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule, and in
September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to other
requirements, such as fugitive emission monitoring frequency. Furthermore, in November 2016, the Bureau of Land Management
(“BLM”) published a final rule to reduce methane emissions by regulating venting, flaring, and leaking from oil and natural gas
operations on public lands. However, in September 2018, the BLM published a final rule that rescinds most of the new
requirements of the November 2016 final rule and codifies the BLM’s prior approach to venting and flaring, but the rule
rescinding the November 2016 final rule has been challenged in federal court and remains pending. Internationally, in April 2016,
the United States joined other countries in entering into a United Nations-sponsored non-binding agreement in Paris, France
(“Paris Agreement”) for nations to limit their GHG emissions through individually-determined reduction goals every five years
beginning in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United
States to withdraw from the Paris Agreement, which provides for a four-year exit process beginning when the agreement took
effect in November 2016.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that
require reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur
increased costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with
new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have
an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory
programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the
demand for the oil and natural gas we or our customers produce and lower the value of our reserves as well as reduce demand for
our midstream and well services. Notwithstanding potential risks related to climate change, the International Energy Agency
estimates that oil and gas will continue to represent a major share of global energy use through 2040 and other studies by the
private sector project continued growth in demand for the next two decades. However, recent activism directed at shifting funding
away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the
energy sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream
activities.
Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that
have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such
effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse
effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our
production activities because of climate related damages to our facilities, our costs of operations potentially arising from such
climatic effects, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for
insurance coverage in the aftermath of such effects. At this time, we have not developed a comprehensive plan to address the
legal, economic, social or physical impacts of climate change on our operations.
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Water discharges
The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated
waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Federal and
state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or
other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure
requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of
navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and
analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from
certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters,
including wetlands, unless authorized by permit. In 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) issued a final
rule outlining their position on the federal jurisdictional reach over waters of the United States. The rule has been challenged in
federal district court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the
rule has been enjoined in twenty-eight states, including North Dakota, Montana and Texas, where we conduct operations, pending
resolution of the legal challenges. In July 2017, the EPA and the Corps published a proposed rule to rescind the 2015 rule and, in
February 2018, the agencies published a final rule adding a February 6, 2020 applicable date to the 2015 rule. The February 2018
rule extending the 2015 final rule’s date of applicability is currently subject to litigation. Also, in December 2018, the EPA and
the Corps published a proposed rule defining the Clean Water Act’s jurisdiction, for which agencies will seek public comment. As
a result of these developments, future implementation of the rule is uncertain at this time. To the extent this rule expands the
scope of the Clean Water Act’s jurisdiction, drilling programs could incur increased costs and delays with respect to obtaining
permits for dredge and fill activities in wetland areas.
The Oil Pollution Act of 1990 (“OPA”) amends the Clean Water Act and sets minimum standards for prevention, containment and
cleanup of oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect
waters of the United States. Under the OPA, responsible parties including owners and operators of onshore facilities may be held
strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result
from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for
responding to a worst-case discharge of oil into waters of the United States.
Operations associated with our production and development activities generate drilling muds, produced waters and other waste
streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface
formations. These injection wells are regulated pursuant to the federal Safe Drinking Water Act (“SDWA”) Underground
Injection Control (“UIC”) program and analogous state laws. The UIC program requires permits from the EPA or analogous state
agency for disposal wells that we operate, establishes minimum standards for injection well operations and restricts the types and
quantities of fluids that may be injected. Any leakage from the subsurface portions of the injection wells may cause degradation
of fresh water, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental
agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners or other
parties claiming damages for alternative water supplies, property damages and personal injuries. Moreover, any changes in the
laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of
produced waters and ultimately increase the cost of our operations, which costs could be significant. Furthermore, in response to
recent seismic events near underground injection wells used for the disposal of produced water from oil and natural gas activities,
federal and some state agencies are investigating whether such wells have caused increased seismic activity. In 2016, the United
States Geological Survey identified Texas as being among the states with areas of increased rates of induced seismicity that could
be attributed to fluid injection or oil and gas extraction. In response to concerns regarding induced seismicity, regulators in some
states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or
otherwise to assess any relationship between seismicity and the use of such wells. For example, in Texas, the Texas Railroad
Commission has adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other
fluids resulting from the production of oil and gas in order to address these seismic activity concerns within the state. Among
other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit
applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or
terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Another
consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring
properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional
regulation and restrictions on the use of injection wells by us or our customers. If new regulatory initiatives are implemented that
restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in operational
activities, our or our customers’ costs to operate may significantly increase and our or our customers’ ability to continue
production or conduct midstream services or dispose of produced water may be delayed or limited, which could have a material
adverse effect on our results of operations and financial position.
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Hydraulic fracturing activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from
unconventional formations, including shales. The process involves the injection of water, sand or other proppants and chemical
additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We
routinely use hydraulic fracturing techniques in many of our drilling and completion programs.
The hydraulic fracturing process is typically regulated by state oil and natural gas commissions or similar agencies, but several
federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted
regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and
issued guidance covering such activities, as well as published an ANPR regarding Toxic Substances Control Act reporting of the
chemical substances and mixtures used in hydraulic fracturing. The EPA also issued final CAA regulations in 2012 and 2016
governing performance standards, including standards for the capture of air emissions released during oil and natural gas
hydraulic fracturing or from compressors, controls, dehydrators, storage tanks, natural gas processing plants, and certain other
equipment. In addition, in 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater
from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, the BLM
published a final rule in 2015 establishing new or more stringent standards relating to hydraulic fracturing on federal and
American Indian lands, but the BLM rescinded the 2015 rule in December 2017; however, litigation challenging the BLM’s
decision was filed in federal District Court in January 2018 and remains pending.
From time to time Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA
and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states, including North
Dakota and Texas where we primarily operate, have adopted, and other states are considering adopting, legal requirements that
could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities.
States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York.
Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling
activities in general or hydraulic fracturing activities in particular. Nevertheless, if new or more stringent federal, state or local
legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially
significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration,
development, or production activities and perhaps even be precluded from drilling wells.
Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking
water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking
water resources under some circumstances.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation
concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation
could also lead to added delays, restrictions or cancellations in the pursuit of our operations or increased operating costs in our or
our customers’ production of oil and natural gas. The adoption of any federal, state or local laws or the implementation of
regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells,
which could have a material adverse effect on our business or results of operations with respect to E&P activities and midstream
services. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Endangered Species Act considerations
The federal Endangered Species Act (“ESA”) and comparable state laws may restrict exploration, development and production
activities that may affect endangered and threatened species or their habitats. The ESA provides broad protection for species of
fish, wildlife and plants that are listed as threatened or endangered in the United States and prohibits the taking of endangered
species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to
ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed or
endangered species or modify their critical habitats. Some of our facilities may be located in areas that are designated as habitat
for endangered or threatened species. If endangered or threatened species are located in areas of the underlying properties where
we or our customers wish to conduct seismic surveys, development activities or abandonment operations, such work could be
prohibited or delayed by seasonal or permanent restrictions or require the implementation of expensive mitigation. Moreover, as a
result of one or more settlements entered into by the U.S. Fish and Wildlife Service, the agency is required to make
determinations on the listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The
designation of previously unprotected species as threatened or endangered in areas where underlying property operations are
conducted or planned could cause us or our customers to incur increased costs arising from species protection measures or could
result in delays or limitations on our or our customers’ E&P activities, including the performance of drilling programs that could
have an adverse impact on our ability to develop and produce reserves or an indirect adverse impact on the demand for our
midstream services.
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Operations on federal lands
Performance of oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the federal
BLM are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM and
the federal Bureau of Indian Affairs, to evaluate major agency actions, such as the issuance of permits that have the potential to
significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that
assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed
environmental impact statement that may be made available for public review and comment. Depending on any mitigation
strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs,
which could be substantial, and be subject to delays, limitations or prohibitions in the scope of oil and natural gas projects or
performance of midstream services. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of
which may delay or halt our or our customers’ E&P activities.
Employee health and safety
We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act
and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational
Safety and Health Administration (“OSHA”) hazard communication standard, the EPA community right-to-know regulations
under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state regulations require that
information be maintained concerning hazardous materials used or produced in our operations and that this information be
provided to employees, state and local government authorities and citizens.
Employees
As of December 31, 2018, we employed 727 people. Our future success will depend partially on our ability to attract, retain and
motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or
work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of
independent contractors to perform various field and other services.
Offices
As of December 31, 2018, we lease 130,300 square feet of office space in Houston, Texas at 1001 Fannin Street, where our
principal offices are located, and sub-lease 8,820 square feet and 7,800 square feet of office space in Houston, Texas, and
Midland, Texas, respectively. The lease for our Houston office expires in March 2029 and our sub-leases for our Houston and
Midland offices expire in December 2019 and August 2020, respectively. We also own field offices in the North Dakota
communities of Williston, Powers Lake, Alexander and Watford City.
Available information
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our filings
with the SEC are available to the public from commercial document retrieval services and at the SEC’s website at
http://www.sec.gov.
Our common stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “OAS.” Our reports, proxy
statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad
Street, New York, New York 10005.
We also make available on our website at http://www.oasispetroleum.com all of the documents that we file with the SEC, free of
charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our
website is not incorporated by reference into this Annual Report on Form 10-K.
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Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on
Form 10-K, actually occurs, our business, financial condition, results of operations or cash flows could suffer. The risks
described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider
immaterial also may adversely affect us.
Risks related to the oil and natural gas industry and our business
A substantial or extended decline in commodity prices, in oil and, to a lesser extent, natural gas prices may adversely affect
our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and
financial commitments.
The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital
and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in
response to relatively minor changes in supply and demand. For example, average daily prices for WTI crude oil ranged from a
high of $76.41 per barrel to a low of $42.53 per barrel during 2018. Average daily prices for NYMEX Henry Hub natural gas
ranged from a high of $6.24 per MMBtu to a low of $2.49 per MMBtu during 2018. Historically, the markets for oil and natural
gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production,
and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
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worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
the actions of OPEC;
the price and quantity of imports of foreign oil and natural gas;
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current
conflicts in the Middle East and conditions in South America, China, India and Russia;
the level of global oil and natural gas E&P activities;
the level of global oil and natural gas inventories;
localized supply and demand fundamentals and regional, domestic and international transportation availability;
weather conditions and natural disasters;
domestic and foreign governmental regulations and policies, including environmental requirements;
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the
energy sector or restrict the exploration, development and production of oil and natural gas and related
infrastructure;
price and availability of competitors’ supplies of oil and natural gas;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under short-term (less than twelve-month) contracts at market-based
prices. Low oil and natural gas prices will reduce our cash flows, borrowing ability, the present value of our reserves and our
ability to develop future reserves. See “Our exploration, development and exploitation projects require substantial capital
expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our
leases or a decline in our estimated net oil and natural gas reserves” below. Low oil and natural gas prices may also reduce the
amount of oil and natural gas that we can produce economically and may affect our proved reserves. See also “The present value
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of future net revenues from our estimated net proved reserves will not necessarily be the same as the current market value of our
estimated oil and natural gas reserves” below.
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Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest
rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to
increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for
drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial
markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our
operations. We require continued access to capital. A significant reduction in the availability of credit could materially and
adversely affect our ability to achieve our planned operating results.
We may not be able to generate enough cash flows to meet our debt obligations.
We expect our earnings and cash flows to vary significantly from year to year due to the nature of our industry. As a result, the
amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash
flows may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our
business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a
result, our ability to generate cash flows from operations and to pay our debt obligations. Many of these factors, such as oil and
natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors,
are beyond our control. If we do not generate enough cash flows from operations to satisfy our debt obligations, we may have to
undertake alternative financing plans, such as:
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selling assets;
reducing or delaying capital investments;
seeking to raise additional capital; or
refinancing or restructuring our debt.
If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the
agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and
payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our
lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making
payments on our Notes (as defined in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources”). If amounts outstanding under our Revolving Credit Facilities or our Notes were
to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our
other debt holders. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
—Liquidity and Capital Resources.”
Our Revolving Credit Facilities and the indentures governing our Senior Notes all contain operating and financial restrictions
that may restrict our business and financing activities.
Our Revolving Credit Facilities and the indentures governing our Senior Notes (as defined in “Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources”) contain a number of
restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to,
among other things:
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sell assets, including equity interests in our subsidiaries;
pay distributions on, redeem or repurchase our common stock or redeem or repurchase our debt;
make investments;
incur or guarantee additional indebtedness or issue preferred stock;
create or incur certain liens;
make certain acquisitions and investments;
redeem or prepay other debt;
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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
engage in transactions with affiliates;
create unrestricted subsidiaries;
enter into sale and leaseback transactions; and
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engage in certain business activities.
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage
in favorable business activities or finance future operations or capital needs.
Our ability to comply with some of the covenants and restrictions contained in our Revolving Credit Facilities and the indentures
governing our Senior Notes may be affected by events beyond our control. If market or other economic conditions deteriorate or
if oil and natural gas prices decline substantially or for an extended period of time from their current levels, our ability to comply
with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Revolving Credit Facilities,
the indentures governing our Senior Notes or any future indebtedness could result in an event of default under our Revolving
Credit Facilities, the indentures governing our Senior Notes or our future indebtedness, which, if not cured or waived, could have
a material adverse effect on our business, financial condition and results of operations.
If an event of default under either of our Revolving Credit Facilities occurs and remains uncured, the lenders under the applicable
Revolving Credit Facility:
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would not be required to lend any additional amounts to us;
could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and
payable;
may have the ability to require us to apply all of our available cash to repay these borrowings; or
may prevent us from making debt service payments under our other agreements.
A payment default or an acceleration under our Revolving Credit Facilities could result in an event of default and an acceleration
under the indentures for our Notes. If the indebtedness under the Notes were to be accelerated, there can be no assurance that we
would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under the Oasis
Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our assets, including
mortgage liens on oil and natural gas properties having at least 90% of the reserve value as determined by reserve reports, and if
we are unable to repay our indebtedness under the Oasis Credit Facility, the lenders could seek to foreclose on our assets. Please
see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources.”
Our level of indebtedness may increase and reduce our financial flexibility.
As of December 31, 2018, we had $468.0 million of outstanding borrowings and had $14.0 million of outstanding letters of credit
under the Oasis Credit Facility, $318.0 million of outstanding borrowings under the OMP Credit Facility, $950.0 million
available for future secured borrowings under the Revolving Credit Facilities and $2,039.4 million outstanding in Notes. Please
see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources—Senior secured revolving line of credit,” “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Liquidity and Capital Resources—Senior unsecured notes” and “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior unsecured convertible
notes.” In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.
Our level of indebtedness could affect our operations in several ways, including the following:
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a significant portion of our cash flows could be used to service our indebtedness;
a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow
additional funds, dispose of assets, pay dividends and make certain investments;
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our
industry;
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged
and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
a high level of debt may make it more likely that a reduction in our borrowing base following a periodic
redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
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a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital
expenditures, acquisitions, general corporate or other purposes.
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A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt
obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and
natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these
factors are beyond our control. If oil and natural gas prices decline substantially or for an extended period of time from their
current levels, we may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and
borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash
through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets
and our performance at the time we need capital.
In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank
borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make
such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange
new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and
financial results.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we
currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including
collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and
record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are
recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our
derivative instruments.
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contract obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual price
received.
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil
and natural gas and may expose us to cash margin requirements.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our
business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development
and production activities. Our oil and natural gas E&P activities are subject to numerous risks beyond our control, including the
risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop
or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and
geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying
interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated net proved reserves are based
on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and
operating wells is often uncertain before drilling commences. These levels of uncertainty may be increased with respect to our
recently acquired positions in the Delaware Basin due to our inexperience operating in the area. See “The Permian Basin
Acquisition represents our initial expansion outside of the Williston Basin, and we may not be successful in operating in other
geographic regions” below. Overruns in planned expenditures are common risks that can make a particular project uneconomical.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
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shortages of or delays in obtaining equipment and qualified personnel;
facility or equipment malfunctions and/or failure;
unexpected operational events, including accidents;
pressure or irregularities in geological formations;
adverse weather conditions, such as blizzards, ice storms and floods;
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reductions in oil and natural gas prices;
delays imposed by or resulting from compliance with regulatory requirements;
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proximity to and capacity of transportation facilities;
title problems; and
limitations in the market for oil and natural gas.
Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant
inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our
reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many
assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant
inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves
shown in this Annual Report on Form 10-K. See “Item 1. Business—Our operations - exploration and production activities” for
information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net
revenues as of December 31, 2018, 2017 and 2016.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also
analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can
vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by
our independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities
of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the
estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust
estimates of net proved reserves to reflect production history, results of exploration and development, prevailing oil and natural
gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped
acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production
than would be the case with properties having a longer production history.
The present value of future net revenues from our estimated net proved reserves will not necessarily be the same as the current
market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market
value of our estimated net oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31,
2018, 2017 and 2016, we based the estimated discounted future net revenues from our estimated net proved reserves on the
twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving
effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such
as:
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actual prices we receive for oil and natural gas;
actual cost of development and production expenditures;
the amount and timing of actual production; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and
natural gas properties will affect the timing and amount of actual future net revenues from estimated net proved reserves, and thus
their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be
the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and
natural gas industry in general.
Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report
on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our estimated
net proved reserves.
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If oil and natural gas prices decline substantially or for an extended period of time from their current levels, we may be
required to take write-downs of the carrying values of our oil and natural gas properties.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in
the recoverability of their carrying value may have occurred. In addition, we assess our unproved properties periodically for
impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.
Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation
of development plans, production data, economics and other factors, we may be required to write down the carrying value of our
oil and natural gas properties, which may result in a decrease in the amount available under our Revolving Credit Facilities. A
write-down constitutes a non-cash charge to earnings. A substantial or extended decline in oil and natural gas prices may cause us
to incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our
Revolving Credit Facilities and our results of operations for the periods in which such charges are taken. Due to the volatility of
expected future oil prices, we reviewed our proved oil and natural gas properties for impairment as of December 31, 2018, 2017
and 2016. During the year ended December 31, 2018, we recorded an impairment loss of $383.4 million to adjust the carrying
value of certain non-strategic proved and unproved oil and natural gas properties held for sale to their estimated fair value,
determined based on the expected sales price less costs to sell. For the year ended December 31, 2017, no impairment was
recorded on our proved oil and natural gas properties. During the year ended December 31, 2016, we recorded impairment losses
of $1.1 million to adjust the carrying values of our proved oil and natural gas properties held for sale to their estimated fair values.
During the years ended December 31, 2018, 2017 and 2016, we recorded non-cash impairment charges of $0.9 million, $6.9
million and $1.1 million, respectively, on our unproved properties due to expiring leases and periodic assessments of our
unproved properties.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the
unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and
development plans within our budget and on a timely basis.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel.
During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater and their availability to us may
be limited. Additionally, these services may not be available on commercially reasonable terms.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services or the unavailability of sufficient
transportation for our production could delay or adversely affect our development and exploration operations or cause us to incur
significant expenditures that are not provided for in our capital plan, which could have a material adverse effect on our business,
financial condition or results of operations. Additionally, compliance with new or emerging legal requirements that affect
midstream operations in North Dakota may reduce the availability of transportation for our production. For example, the NDIC
adopted regulations in late 2013 that impose more rigorous pipeline development standards on midstream operators, some of
whom we rely on to construct and operate pipeline infrastructure to transport the oil and natural gas we produce.
Part of our strategic tactics involve drilling in existing or emerging shale plays using some of the latest available horizontal
drilling and completion techniques. The results of our planned drilling in these plays are subject to drilling and completion
technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur
material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in
order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling
include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling
horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other
equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not
limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore
during completion operations, successfully cleaning out the well bore after completion of the final fracture stimulation stage and
successfully protecting nearby producing wells from the impact of fracture stimulation.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and
production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are
unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited
takeaway capacity or otherwise, and/or oil and natural gas prices decline, the return on our investment in these areas may not be
as attractive as we anticipate. We could incur material write-downs of unevaluated properties, and the value of our undeveloped
acreage could decline in the future.
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Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain
needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net
oil and natural gas reserves.
Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital
expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves.
Excluding acquisitions of $951.9 million in 2018 and $54.0 million in 2017, we spent $1,251.6 million and $782.2 million related
to capital expenditures for the years ended December 31, 2018 and 2017, respectively. Our total capital expenditure plan for 2019
is approximately $690 million to $730 million, which includes approximately $540 million to $560 million for E&P and other
capital expenditures, including approximately $405 million to $420 million focused in the Williston Basin and approximately
$135 million to $140 million focused in the Delaware Basin (with approximately 85% of the E&P capital allocated to drilling and
completions). Other capital expenditures includes OWS and administrative capital, and excludes capitalized interest of
approximately $15 million. Since our initial public offering, our capital expenditures have been financed with proceeds from
public equity offerings, proceeds from our issuance of senior notes, borrowings under our Revolving Credit Facilities, net cash
provided by operating activities, the sale of non-strategic oil and gas properties and cash settlements of derivative contracts.
DeGolyer and MacNaughton projects that we will incur capital costs of $1,592.0 million over the next five years to develop the
proved undeveloped reserves in the Williston Basin and Delaware Basin covered by its December 31, 2018 reserve report. The
actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other
things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory,
technological and competitive developments.
A significant increase in product prices could result in an increase in our capital expenditures. We intend to finance our future
capital expenditures primarily through cash flows provided by operating activities, borrowings under our Revolving Credit
Facilities and cash settlements of derivative contracts; however, our financing needs may require us to alter or increase our
capitalization substantially through the issuance of additional debt or equity securities or the sale of non-strategic assets. The
issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the
payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital
expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our
common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our
borrowing base under the Oasis Credit Facility will be automatically reduced by an amount equal to 25% of the aggregate
principal amount of such debt securities.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:
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our estimated net proved reserves;
the level of oil and natural gas we are able to produce from existing wells and new projected wells;
the prices at which our oil and natural gas are sold;
the costs of developing and producing our oil and natural gas production;
our ability to acquire, locate and produce new reserves;
the ability and willingness of our banks to lend; and
our ability to access the equity and debt capital markets.
If the borrowing base under our Revolving Credit Facilities or our revenues decrease as a result of low oil or natural gas prices,
operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to
sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on
terms favorable to us, or at all. If cash generated by operations or cash available under our Revolving Credit Facilities is not
sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations
relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in
our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
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We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of
exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
We may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our
locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the
drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for
those locations. The success and timing of exploration and development activities operated by our partners will depend on a
number of factors that will be largely outside of our control, including:
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the timing and amount of capital expenditures;
the operator’s expertise and financial resources;
approval of other participants in drilling wells;
selection of technology; and
the rate of production of reserves, if any.
This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on
our results of operations and financial condition.
All of our producing properties and operations are located in the Williston Basin and Delaware Basin regions, making us
vulnerable to risks associated with operating among a limited number of geographic areas.
As of December 31, 2018, 87% and 95% of our proved reserves and production, respectively, were located in the Williston Basin
in northwestern North Dakota and northeastern Montana and the remaining 13% and 5% of our proved reserves and production,
respectively, were located in the Delaware Basin in west Texas. As a result, we may be disproportionately exposed to the impact
of economics in the Williston Basin and Delaware Basin or delays or interruptions of production from those wells caused by
transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services,
significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or
interruption of transportation of oil or natural gas produced from the wells in those areas. In addition, the effect of fluctuations on
supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the
Williston Basin and Delaware Basin, which may cause these conditions to occur with greater frequency or magnify the effect of
these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of
the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on
other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse
effect on our financial condition and results of operations.
The Permian Basin Acquisition represents our initial expansion outside of the Williston Basin, and we may not be successful
in operating in other geographic regions.
Our operations have historically focused on a single geographic region, namely the North Dakota and Montana regions of the
Williston Basin. Thus, the Permian Basin Acquisition represents our initial entry into the Delaware Basin, and our first expansion
of our operations outside of the Williston Basin. Certain aspects related to operating in the Delaware Basin may not be as familiar
to us as our existing project areas. As a result, we may encounter obstacles that may cause us not to achieve the expected results
of the Permian Basin Acquisition. These obstacles may include a less familiar geological landscape, different completion
techniques, midstream and downstream operators with whom we have no established relationship, greater competition for
acreage, unfamiliar operating conditions and a distinct regulatory environment. Any adverse conditions, regulations or
developments related to our expansion into the Delaware Basin may have a negative impact on our business, financial condition
and results of operations.
Our business depends on oil and natural gas gathering and transportation facilities, some of which are owned by third parties.
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering
and pipeline systems owned by third parties and by OMP. The unavailability of, or lack of, available capacity on these systems
and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties.
See also “Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our
production” and “Insufficient transportation, end-market refining utilization or natural gas processing capacity in the Williston
Basin and Delaware Basin could cause significant fluctuations in our realized oil and natural gas prices” below. The
transportation of our production can be interrupted by other customers that have firm arrangements. In addition, these third parties
may also impose specifications for the products that they are willing to accept. If the total mix of a product fails to meet the
applicable product quality specifications, the third parties may refuse to accept all or a part of the products or may invoice
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us for the costs to handle or damages from receiving the out-of-specification products. In those circumstances, we may be
required to delay the delivery of or find alternative markets for that product, or shut-in the producing wells that are causing the
products to be out of specification, potentially reducing our revenues.
The disruption of third-party facilities due to maintenance, weather or other interruptions of service could also negatively impact
our ability to market and deliver our products. We have no control over when or if such facilities are restored. A total shut-in of
our production could materially affect us due to a resulting lack of cash flows, and if a substantial portion of the production is
hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.
Potential crude oil train derailments or crashes could also impact our ability to market and deliver our products and cause
significant fluctuations in our realized oil and natural gas prices due to tighter safety regulations imposed on crude-by-rail
transportation and interruptions in service.
Insufficient transportation, end-market refining utilization or natural gas processing capacity in the Williston Basin and
Delaware Basin could cause significant fluctuations in our realized oil and natural gas prices.
The crude oil business environment has historically been characterized by periods when oil production has surpassed local
transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for
WTI crude oil. In the past, there have been periods when this discount has substantially increased due to the production of oil in
the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining
capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on oil transportation out of
the Williston Basin and Delaware Basin and improved netback pricing received at the lease. On barrels that we transport and sell
outside of the basins, our realized price for crude oil is generally the quoted price at the point of sale less transportation costs. In
2017 and the majority of 2018, our Williston Basin price differentials relative to WTI strengthened as new pipelines opened to
eastern Canada and U.S. markets and transportation on rail gradually declined. In the fourth quarter of 2018, Williston Basin
differentials weakened as overall basin production grew faster than forecasted. Since 2016, our Williston Basin price differentials
have averaged less than $5.00 per barrel discount to WTI on a quarterly basis. During 2017 and throughout most of 2018, our
Williston Basin crude oil price differentials improved to less than $2.00 per barrel discount to WTI primarily due to the additional
takeaway capacity of the Dakota Access Pipeline of over 500,000 barrels per day. In 2018, our Delaware Basin price differentials
relative to WTI weakened due to transportation capacity restraints, averaging more than $4.00 per barrel below WTI.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil
and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends
on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering
systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable
terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or
unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of
these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the
products to market.
The development of our proved undeveloped reserves in the Williston Basin, Delaware Basin and other areas of operation may
take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped
reserves may not be ultimately developed or produced.
Approximately 37% of our estimated net proved reserves were classified as proved undeveloped as of December 31, 2018.
Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The
future development of our proved undeveloped reserves is dependent on future commodity prices, costs and economic
assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, our Revolving
Credit Facilities and derivative contracts. Delays in the development of our reserves or increases in costs to drill and develop such
reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such
reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us
to have to reclassify our proved reserves as unproved reserves.
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Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our
business, financial condition and results of operations.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved
reserves, our estimated net proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs
generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our
future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success
in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable
reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production
at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our
business, financial condition and results of operations would be adversely affected.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we
may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and
adversely affect our business, financial condition or results of operations. Our oil and natural gas E&P activities are subject to all
of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline and tank ruptures,
encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and
completion fluids, toxic gas or other pollutants into the environment;
abnormally pressured formations;
shortages of, or delays in, obtaining water for hydraulic fracturing activities;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing failure;
personal injuries and death; and
natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
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injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and
completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks
generally are not fully insurable. Also, we may elect not to obtain insurance if we believe that the cost of available insurance is
excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could have a material
adverse effect on our business, financial condition and results of operations.
We have incurred losses in 2018 and prior years and may do so again in the future.
For the year ended December 31, 2018, we incurred a net loss of $35.3 million. For the year ended December 31, 2017, we
incurred a pre-tax loss of $75.9 million, but had a positive net income after taxes primarily due to the income tax benefit related to
the tax rate change under the Tax Act. For the year ended December 31, 2016, we incurred a net loss of $243.0 million. Our
development of and participation in an increasingly larger number of drilling locations has required and will continue to require
substantial capital expenditures, including planned capital expenditures for 2019 of approximately $690 million to $730 million.
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The uncertainty and risks described in this Annual Report on Form 10-K may impede our ability to economically find, develop,
exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash
flows provided by operating activities in the future.
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Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will
require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular
location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable.
The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to
drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to
be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive
hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a
reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our
current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you
that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be
applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin and
Delaware Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and
operating any well is often uncertain, and new wells may not be productive.
Our potential drilling location inventories are scheduled to be drilled over several years, making them susceptible to
uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the
substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.
Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our
existing acreage. These potential drilling locations, including those without proved undeveloped reserves, represent a significant
part of our execution strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the
availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. These levels
of uncertainty may be increased with respect to our recently acquired positions in the Delaware Basin due to our inexperience
operating in the area. See “The Permian Basin Acquisition represents our initial expansion outside of the Williston Basin, and we
may not be successful in operating in other geographic regions” above. Because of these uncertainties, we do not know if the
numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas
from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions,
proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of
booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our
drilling program.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production
is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the
leases are renewed. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will
result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
As of December 31, 2018, approximately 97% and 67% of our total net acreage in the Williston Basin and Delaware Basin,
respectively, was held by production. The leases for our net acreage not held by production will expire at the end of their primary
term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their
primary terms under continuous drilling provisions or the leases are renewed. In the Williston Basin, our acreage must be drilled
before lease expiration, generally within three to five years, in order to hold the acreage by production. Unless production is
established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for
such acreage will expire. In the Delaware Basin, our acreage must be drilled before lease or term assignment expiration and, in
some leases, must be further perpetuated via additional drilling activity to satisfy continuous drilling and development provisions.
Additionally, certain leases and term assignments in the Delaware Basin require development at various depths in order to
perpetuate our ownership as to those depths. As of December 31, 2018, we had leases representing 2,720 net acres expiring in
2019, 8,992 net acres expiring in 2020 and 2,456 net acres expiring in 2021 in the Williston Basin and Delaware Basin. The cost
to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms
or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. Our
ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the
availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease
expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution
systems, regulatory approvals and other factors. As such, our actual drilling activities may materially differ from our current
expectations, which could adversely affect our business. During the years ended December 31, 2018, 2017 and 2016, we recorded
non-cash impairment charges of $0.9 million, $6.9 million and $1.1 million on our unproved properties due to expiring leases and
periodic assessments of our unproved properties.
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Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to
significant costs and liabilities.
Our oil and natural gas E&P operations, oil gathering and transportation activities, natural gas processing services, well servicing
operations and related operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing
occupational health and safety aspects, the discharge of materials into the environment or otherwise relating to environmental
protection. These laws and regulations may impose numerous obligations that are applicable to our operations and services
including the acquisition of a permit before conducting drilling, providing midstream services or other regulated activities; the
restriction on types, quantities and concentration of materials that may be released into the environment; the limitation or
prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of
specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting
from our operations. Numerous governmental authorities, such as the EPA and OSHA, and analogous state agencies have the
power to enforce compliance with these laws and regulations and the permits issued under them, which may cause us to incur
significant capital or operating expenditures or costly actions to achieve and maintain compliance. Failure to comply with these
laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties; the
imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of
restrictions, delays or cancellations in the permitting or development or expansion of projects; and the issuance of injunctions
limiting or preventing some or all of our operations in affected areas.
Our operations risk incurring significant environmental costs and liabilities as a result of our handling of petroleum hydrocarbons
and wastes, because of air emissions and waste water discharges related to our operations and due to historical industry operations
and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict
liability for the removal or remediation of previously released materials or property contamination regardless of whether we were
responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those
actions were taken. Private parties, including the owners of properties upon which our wells are drilled or processing facilities or
pipelines are located and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also
have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental
laws and regulations or for personal injury or property or natural resource damage. In addition, accidental spills or other releases
could expose us to significant costs and liabilities that could have a material adverse effect on our financial condition or results of
operations.
Changes in environmental laws and regulations occur frequently, and any changes that result in delayed, restricted or more
stringent or costly well drilling, plant or pipeline construction, completion or water management activities or waste handling,
storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain
compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial
condition. For example, pursuant to a consent decree issued by a federal district court, the EPA is required to propose no later than
March 15, 2019, a rulemaking for revision of certain Subtitle D regulations that could result in such oil and natural gas wastes
being regulated as hazardous wastes, or sign a determination that revision of those RCRA regulations is unnecessary. Also, in
2015, the EPA issued a final rule lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and
secondary ozone standards. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either
“attainment/unclassifiable,” “unclassifiable” or “non-attainment” and, in November 2018, issued final requirements that apply to
state, local and tribal air agencies for implementing the 2015 NAAQS. State implementation of these revised NAAQS standards
could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased
expenditures for pollution control equipment, the costs of which could be significant. Compliance with any of these rules or any
other new or amended legal requirements could, among other things, require installation of new emission controls on some of our
equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which
could adversely impact our business.
We may not be able to recover some or any of these costs from insurance.
Failure to comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil
and natural gas and may result in substantial penalties.
Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the
regulation of oil and natural gas production and transportation. These laws and regulations include regulation of oil and natural
gas E&P and related operations, including a variety of activities related to the drilling of wells, and the interstate transportation of
oil and natural gas by federal agencies such as FERC, as well as state agencies. We may incur substantial costs in order to
maintain compliance with these laws and regulations. As well as recent incidents involving the release of oil and natural gas and
fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state
levels to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and
natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of
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these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a
material adverse effect on our business, financial condition and results of operations. We must also comply with laws and
regulations prohibiting fraud and market manipulations in energy markets. To the extent we are a shipper on interstate pipelines,
we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate
capacity.
Should we fail to comply with all applicable statutes, rules, regulations and orders of FERC, the CFTC or the FTC, we could
be subject to substantial penalties and fines.
In addition, federal laws prohibit market manipulation in connection with the purchase or sale of oil and/or natural gas. Failure to
comply with federal, state and local laws could adversely affect our ability to produce, gather and transport our oil and natural gas
and may result in substantial penalties. Please see “Item 1. Business—Other federal laws and regulations affecting our industry.”
Our business involves the selling and shipping by rail of crude oil, including from the Bakken shale and the Delaware Basin,
which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential
regulatory changes that may adversely impact our business, financial condition or results of operations.
A portion of our crude oil production is transported to market centers by rail. Past derailments in North America of trains
transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal
governments, to focus attention on transportation by rail of flammable materials. Transportation safety regulators in the United
States and Canada are concerned that crude oil from the Bakken shale may be more flammable than crude oil from other
producing regions and are investigating that issue and are also considering changes to existing regulations to address those
possible risks. In 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank
car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, and a requirement
that older DOT-111 tank cars be phased out by as early as January 1, 2018 if they are not already retrofitted to comply with new
tank car design standards. The rule also includes a new braking standard for certain trains, designates new operational protocols
for trains transporting large volumes of flammable liquids, such as routing analyses, speed restrictions and information for local
government agencies, and provides new sampling and testing requirements to improve classification of energy products placed
into transport; however, in September 2018, PHMSA published a final rule that removed requirements for the new braking
standard established under its 2015 final rule.
In 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3
flammable liquids, including crude oil and ethanol, between 2018 and 2029. Additionally, in 2016, PHMSA proposed a new rule,
which has not been finalized, that would expand the applicability of comprehensive oil spill response plans so that any railroad
that transports a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train
carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train must have a current, comprehensive, written
plan. Also, in response to a petition from the New York Attorney General, PHMSA issued an ANPR in early 2017 stating that it
was considering revising the Hazardous Materials Regulations to establish vapor pressure limits for unrefined petroleum-based
products and potentially all Class 3 flammable liquid hazardous materials that would apply during the transportation of the
products or materials by any mode. PHMSA has not yet issued a final version of the rule. Similarly, in February 2016, the FRA
modified its accident and incident reports to gather additional data concerning rail cars carrying crude oil in any train involved in
a FRA-reportable accident. In addition to these or other actions taken or proposed by federal agencies, a number of states
proposed or enacted laws in recent years that encourage safer rail operations or urge the federal government to strengthen
requirements for these operations.
Efforts are likewise underway in Canada to assess and address risks from the transport of crude oil by rail. For example, in 2014,
Transport Canada issued a protective order prohibiting oil shippers from using 5,000 of the DOT-111 tank cars and imposing a
three year phase out period for approximately 65,000 tank cars that do not meet certain safety requirements. Transport Canada
also imposed a 50 mile per hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada
to have an emergency response plan. At the same time that PHMSA released its 2015 rule, Canada’s Minister of Transport
announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. Likewise, Transport
Canada’s rail car retrofitting and phase out timeline largely aligns with the timeline introduced under the 2015 and 2016 PHMSA
rules. Transport Canada has also introduced new requirements that railways carry minimum levels of insurance depending on the
quantity of crude oil or dangerous goods that they transport as well as a final report recommending additional practices for the
transportation of dangerous goods. Both Transport Canada and PHMSA issued final rules in January 2018 and November 2018,
respectively, that further harmonize their respective tank car standards, including with respect to tank car approvals and design
requirements.
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New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased
governmental enforcement regarding hazardous material transportation may occur in the future, which could directly and
indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of tank cars. We cannot
assure that costs incurred to comply with standards and regulations emerging from these existing and any future rulemakings will
not be material to our business, financial condition or results of operations. Moreover, we may incur significant constraints on
transportation capacity during the period while tank cars are being retrofitted or newly constructed to comply with the new
regulations. In addition, any derailment of crude oil from the Bakken shale or Delaware Basin involving crude oil that we have
sold or are shipping may result in claims being brought against us that may involve significant liabilities. Although we believe
that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any
damages that may arise from such events.
Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs
and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our
production and cause us to incur significant costs in preparing for or responding to those effects.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals
have been made and are likely to continue to be made at the international, national, regional and state levels of government to
monitor and limit emissions of GHGs. These efforts have included consideration by states or groupings of states of cap-and-trade
programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain
sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has
determined that emissions of GHGs present an endangerment to public health and the environment and has adopted regulations
under existing provisions of the CAA that establish PSD construction and Title V operating permit reviews for GHG emissions
from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions.
Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control
technology” standards. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified
sources in the United States on an annual basis, including, among others, certain onshore and offshore oil and natural gas
production facilities, and onshore processing, transmission, storage and distribution facilities, which includes certain of our
operations. The EPA has amended and expanded the GHG reporting requirements to all segments of the oil and natural gas
industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In 2016,
the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and
natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards
expand the previously issued Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control
practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection
and repair requirements for natural gas compressor and booster stations. In June 2017, the EPA published a proposed rule to stay
certain portions of the 2016 standards for two years but the rule was not finalized. Rather, in February 2018, the EPA finalized
amendments to certain requirements of the 2016 final rule, and in September 2018 the EPA proposed additional amendments,
including rescission of certain requirements and revisions to other requirements, such as fugitive emission monitoring frequency.
In another example, the BLM published a final rule in November 2016 that imposes requirements to reduce methane emissions
from venting, flaring and leaking from oil and natural gas operations on public, federal and Indian lands. However, in September
2018, the BLM published a final rule that rescinds most of the new requirements of the November 2016 final rule and codifies the
BLM’s prior approach to venting and flaring, but the rule rescinding the November 2016 final rule has been challenged in federal
court and remains pending. Internationally, in April 2016, the United States joined other countries in entering into the Paris
Agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years beginning
in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to
withdraw from the Paris Agreement, which provides for a four-year exit process beginning when the agreement took effect in
November 2016.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives
imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur
increased costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with
new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have
an adverse effect on our or our customers’ business, financial condition and results of operations. Moreover, such new legislation
or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could
reduce the demand for the oil and natural gas we or our customer produce and lower the value of our reserves as well as reduce
demand for our midstream and well services. Notwithstanding potential risks related to climate change, the International Energy
Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040 and other studies by
the private sector project continued growth in demand for the next two decades. However, recent
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activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on
certain sources of funding for the energy sector. Ultimately, this could make it more difficult to secure funding for exploration and
production, midstream activities or well services.
Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that
have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such
effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse
effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our
production activities because of climate related damages to our facilities, our costs of operations potentially arising from such
climatic effects, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for
insurance coverage in the aftermath of such effects. At this time, we have not developed a comprehensive plan to address the
legal, economic, social or physical impacts of climate change on our operations.
Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or
delays that could adversely affect the drilling program’s production of oil and natural gas.
Operations associated with our production and development activities generate drilling muds, produced waters and other waste
streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface
formations. These injection wells are regulated pursuant to the UIC program established under the SDWA. In response to recent
seismic events near underground injection wells used for the disposal of produced water from oil and natural gas activities,
federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have
restricted, suspended or shut down the use of such injection wells. In March 2016, the United States Geological Survey identified
Texas as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil
and gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are
considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any
relationship between seismicity and the use of such wells. For example, in Texas, the Texas Railroad Commission has adopted
rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the
production of oil and gas in order to address these seismic activity concerns within the state. Among other things, these rules
require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more
frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a
disposal well is likely to be, or determined to be, causing seismic activity. Another consequence of seismic events may be
lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and
federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of
injection wells by us or our customers. If new regulatory initiatives are implemented that restrict or prohibit the use of
underground injection wells in areas where we rely upon the use of such wells in operational activities, our or our customers’
costs to operate may significantly increase and our ability to continue production or conduct midstream services or dispose of
produced water may be delayed or limited, which could have a material adverse effect on our business, financial condition and
results of operations.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews
of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and
natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense
subsurface rock formations. The process involves the injection of water, sand or other proppant and chemical additives under
pressure into the targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use
hydraulic fracturing techniques in many of our drilling and completion programs.
The process is typically regulated by state oil and natural gas commissions or similar agencies, but several federal agencies have
asserted regulatory authority or conducted investigations over certain aspects of the process. For example, the EPA has asserted
regulatory authority under the SDWA over hydraulic fracturing activities involving the use of diesel and issued guidance covering
such activities, as well as published an ANPR regarding Toxic Substances Control Act reporting of the chemical substances and
mixtures used in hydraulic fracturing; issued final CAA regulations that include NSPS for completions of hydraulically fractured
natural gas wells and new emissions standards for methane from certain new, modified and reconstructed equipment and
processes in the oil and natural gas source category; and published an effluent limit guideline final rule prohibiting the discharge
of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also,
in 2015, the BLM published a final rule establishing new or more stringent standards relating to hydraulic fracturing on federal
and American Indian lands, but the BLM rescinded the 2015 rule in December 2017. However, litigation challenging the BLM’s
decision was filed in federal district court in January 2018 and remains pending. Also, in late 2016, the EPA released its final
report on the potential impacts of hydraulic fracturing on drinking water resources,
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concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some
circumstances.
In addition, from time to time Congress has considered legislation to provide for federal regulation of hydraulic fracturing under
the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states,
including North Dakota and Texas where we primarily operate, have adopted, and other states are considering adopting, legal
requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic
fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by
the State of New York. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place
and manner of drilling activities in general or hydraulic fracturing activities in particular. Increased regulation and attention given
to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production
activities using hydraulic fracturing techniques. Also, new or more stringent legislation or regulation adopted in areas where we
operate could also lead to delays in, or restriction or cancellation of, our or our customers’ operations, result in increased
operating costs in our or our customers’ production of oil and natural gas, and perhaps cause a decrease in the completion of new
oil and natural gas wells, which could have a material adverse effect on our business or results of operations with respect to E&P
activities and midstream and well services. We may not be insured for, or our insurance may be inadequate to protect us against,
these risks.
Operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to
obtain water for E&P activities and the disposal of flowback and produced water may impact operations and have a
corresponding adverse effect on our business, financial conditions and results of operations.
Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing
processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended
drought, private, third party competition for water in localized areas or the implementation of local or state governmental
programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate
local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of
water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our inability to locate
or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our E&P operations or
midstream and well services and have a corresponding adverse effect on our business, financial condition and results of
operations.
Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on
our or our customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting
from E&P activities. Applicable laws, including the Clean Water Act, impose restrictions and strict controls regarding the
discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge
pollutants to such waters. For example, in 2015, the EPA and the Corps issued a final rule outlining their position on the federal
jurisdictional reach over waters of the United States, but the rule has been challenged in federal district court on the grounds that
it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been enjoined in twenty-eight
states, including North Dakota, Montana and Texas, where we conduct operations, pending resolution of the legal challenges. In
July 2017, the EPA and the Corps published a proposed rule to rescind the 2015 rule and, in February 2018, the agencies
published a final rule adding a February 6, 2020 applicable date to the 2015 rule. The February 2018 rule extending the 2015 final
rule’s date of applicability is currently subject to litigation. Also, in December 2018, the EPA and the Corps published a proposed
rule defining the Clean Water Act’s jurisdiction for which the agencies will seek public comment. As a result of these
developments, future implementation of the rule is uncertain at this time. Additionally, regulations implemented under the Clean
Water Act and similar state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other
substances related to the oil and natural gas industry into coastal waters. The Clean Water Act and analogous state laws provide
for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of
reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit
requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of
wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our or our
customers’ flowback and produced water on economic terms may increase our or our customers’ operating costs and cause
delays, interruptions or termination of our or our customers’ operations, the extent of which cannot be predicted.
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Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent
safety controls, substantial changes to existing integrity management programs, or more stringent enforcement of applicable
legal requirements could subject us to increased capital and operating costs and operational delays.
Certain of our pipelines are subject to regulation by PHMSA under the HLPSA with respect to oil and condensate and the
NGPSA with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation,
replacement and management of oil and natural gas pipeline facilities. These laws have resulted in the adoption of rules by
PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs,
including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in HCAs,
such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In
addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous
liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our
pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no
assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse
effect on our business and operating results. New pipeline safety laws or regulations, amendment of existing laws and regulations,
reinterpretation of legal requirements or increases in governmental enforcement adopted by PHMSA may impose more stringent
requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause
us to incur increased capital and operating costs and operational delays.
Legislation in recent years has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing
and adopting regulations that impose increased pipeline safety requirements on pipeline operators. The HLPSA and NGPSA were
amended by the 2011 Pipeline Safety Act, which among other things, increased the penalties for safety violations, established
additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the
adoption of new regulatory requirements by PHMSA for existing pipelines. In 2016, the 2016 Pipeline Safety Act was passed,
extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its
outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities.
The 2016 Act also empowers PHMSA to address unsafe conditions or practices constituting imminent hazards by imposing
emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline
facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in 2016 to implement the
agency’s expanded authority to address such conditions or practices that pose an imminent hazard to life, property or the
environment.
The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or
safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA
issued a final rule that significantly extends and expands the reach of certain PHMSA hazardous liquid pipeline integrity
management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s
proximity to a HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all
hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register
remains uncertain following the January 2017 change in Presidential Administrations. In a second example, in March 2016,
PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines
and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural
gas pipelines in newly defined “moderate consequence areas” that contain as few as five dwellings within a potential impact area;
requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to
determine their MAOP; and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage
prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional
requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas
pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has split this proposed rule into
three separate rulemaking proceedings and is expected to finalize those proceedings in 2019. New legislation or any new
regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other
pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational
delays. In the absence of the PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state
standards, including standards for rural gathering lines.
We do not own all of the land on which our pipelines and associated facilities are located, which could result in disruptions to
our operations.
We do not own all of the land on which our pipelines and associated facilities have been constructed, and we are, therefore,
subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-
of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by
third parties and governmental agencies for a specific period of time. Additionally, following a decision issued in May 2017 by
the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted
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land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the
allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-
way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will
always be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs. Any loss of
rights with respect to our real property, through our inability to renew right-of-way contracts or otherwise, could have a material
adverse effect on our business, results of operations, financial position and ability to make cash distributions to the unitholders of
OMP.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and
natural gas and secure trained personnel.
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to
evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring
properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for
capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial,
technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil
and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of
properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to
withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and
generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from
changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be
able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract
and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the
future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves,
marketing hydrocarbons, attracting and retaining qualified personnel and raising additional capital, which could have a material
adverse effect on our business.
The loss of senior management or technical personnel could adversely affect our operations.
To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our
senior management or technical personnel, including Thomas B. Nusz, our Chairman and Chief Executive Officer, and Taylor L.
Reid, our President and Chief Operating Officer, could have a material adverse effect on our operations. We do not maintain, nor
do we plan to obtain, any insurance against the loss of any of these individuals.
Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in the Williston Basin and Delaware Basin are adversely affected by seasonal weather conditions.
In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter
months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. Results of
operations in the Delaware Basin may also be negatively affected by inclement weather during the winter months. These
constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our
operating and capital costs.
The inability of one or more of our customers or affiliates to meet their obligations to us may adversely affect our financial
results.
Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production ($234.2
million in receivables at December 31, 2018), which we market to energy marketing companies, refineries and affiliates, and joint
interest receivables ($93.9 million at December 31, 2018).
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers.
This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in
economic and other conditions. For the year ended December 31, 2018, no purchaser accounted for more than 10% of the
Company’s total sales. For the year ended December 31, 2017, sales to Shell Trading (US) Company accounted for approximately
16% of our total sales. For the year ended December 31, 2016, sales to PBF Holding Company LLC accounted for approximately
10% of our total sales. No other purchasers accounted for more than 10% of our total oil and natural gas sales for the years ended
December 31, 2017 and 2016. We do not require all of our customers to post collateral. The inability or failure of our significant
customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
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Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in
our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control
participation in our wells. For the year ended December 31, 2018, we recorded bad debt expense of $1.5 million as a result of our
assessment that it is probable certain receivables may not be collected.
In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by
counterparties. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net
basis, as all counterparty contracts provide for net settlement. At December 31, 2018, we had derivatives in place with nine
counterparties and a total net derivative asset of $106.8 million.
We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well
performance and potential liabilities, as well as uncertainties in forecasting oil and gas prices and future development,
production and marketing costs, and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear
to fit within our overall business strategic tactics. The successful acquisition of producing properties requires an assessment of
several factors, including:
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recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
development and operating costs;
potential for future drilling and production;
validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase
agreement; and
potential environmental and other liabilities, together with associated litigation of such matters.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the
subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or
potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and
potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not
necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or
unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual
indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire
properties on an “as is” basis. Indemnification from the sellers will generally be effective only during a limited time period after
the closing and subject to certain dollar limitations and minimums. We may not be able to collect on such indemnification
because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for
unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations
or cash flows.
Significant acquisitions and other strategic transactions may involve other risks, including:
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diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and
strategic transactions;
the challenge and cost of integrating acquired operations, information management and other technology systems
and business cultures with those of our operations while carrying on our ongoing business;
difficulty associated with coordinating geographically separate organizations;
an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded
operations and unknown liabilities; and
the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members
of our senior management may be required to devote considerable amounts of time to this integration process, which will
decrease the time they will have to manage our business. If our senior management is not able to effectively manage the
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integration process, or if any significant business activities are interrupted as a result of the integration process, our business could
suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it may not be possible to realize the full
benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits
anticipated from an acquisition or realize these benefits within the expected time frame.
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If we fail to realize the anticipated benefits of a significant acquisition, such as the Delaware Basin Acquisition, our results of
operations may be lower than we expect.
The success of a significant acquisition will depend, in part, on our ability to realize anticipated opportunities from combining the
acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full
benefits we may expect in estimated net proved reserves, production volume, cost savings from operating synergies or other
benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an
acquisition may be offset by operating losses relating to changes in commodity prices, in oil and natural gas industry conditions,
by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key
personnel, an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an
acquisition, our results of operations and stock price may be adversely affected.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the
mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in
examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.
Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the
operator of the well to obtain a preliminary title review to ensure there are no obvious defects in the title to the well. Frequently,
as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such
curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase
production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure.
Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects
in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative
instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our
business.
On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer
Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter
derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and
other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank
Act, the CFTC has proposed new regulations to set position limits for certain futures, options and swap contracts in designated
physical commodities, including, among others, oil and natural gas. The Dodd-Frank Act and CFTC rules have also designated
certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange
trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent that we
engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with the
clearing and exchange trading requirements or to take steps to qualify for an exemption to such requirements. In addition, certain
banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps.
Although we expect to qualify for the non-financial end-user exception from margin requirements for swaps to other market
participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging. If any of our
swaps do not qualify for the non-financial end-user exception, we could be required to post initial or variation margin, which
would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect
cash flows. Other regulations to be promulgated under the Dodd-Frank Act also remain to be finalized. As a result, it is not
possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such
effects. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the
terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to
monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we
reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more
volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital
expenditures. Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-
Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse
effect on our financial position, results of operations and cash flows. In addition, the European Union and other non-U.S.
jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in
foreign jurisdictions, we may become subject to such regulations.
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Final regulations relating to and interpretations of provisions of the Tax Act may vary from our current interpretation of such
legislation and could adversely affect our financial position, results of operations and cash flows.
The U.S. federal income tax legislation enacted on December 22, 2017, commonly referred to as the Tax Act, is highly complex
and subject to interpretation. The presentation of our financial position and results of operations is based upon our current
interpretation of the provisions contained in the Tax Act. In the future, the Treasury Department and the Internal Revenue Service
are expected to issue final regulations and additional interpretive guidance with respect to the provisions of the Tax Act. Any
significant variance of our current interpretation of such provisions from any future final regulations or interpretive guidance
could adversely affect our financial position, results of operations and cash flows.
We may not be able to utilize a portion of our net operating losses (“NOLs”) to offset future taxable income for U.S. federal or
state tax purposes, which could adversely affect our net income and cash flows.
As of December 31, 2018, we had significant federal and state income tax NOLs, which will begin to expire in 2033 and 2020 for
U.S. federal and state income tax purposes, respectively. Utilization of these NOLs depends on many factors, including our future
taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section
382”), generally imposes an annual limitation on the amount of an NOL that may be used to offset taxable income when a
corporation has undergone an “ownership change.” Determining the limitations under Section 382 is technical and highly
complex. We continue to study whether we have undergone or may in the future undergo an ownership change under Section 382.
If an ownership has occurred or occurs in the future, we may be prevented from fully utilizing our NOLs, which could adversely
affect our financial position, results of operations and cash flows.
An unfavorable resolution of the Mirada Litigation could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
On March 23, 2017, Mirada (as defined in “Item 3. Legal Proceedings”) filed a lawsuit against Oasis Petroleum Inc., OPNA and
Oasis Midstream Services LLC in the 334th Judicial District Court of Harris County, Texas. Mirada asserts that it is a working
interest owner in certain acreage owned and operated by us and that we have breached certain agreements our predecessors in
interest previously entered into with Mirada, or its predecessors interest, with respect to such acreage. We filed an answer denying
all of Mirada’s claims, and intend and continue to vigorously defend against Mirada’s claims. Discovery is ongoing, and each of
the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the
course of the claim. On June 30, 2017, Mirada amended its original petition to add a claim that we have breached certain
agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is
entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without
deductions for midstream services provided by OPNA or its affiliates. On February 2, 2018 and February 16, 2018, Mirada filed a
second and third amended petition, respectively. In these filings, Mirada alleged new legal theories for being entitled to enforce
the underlying contracts and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting
that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. On March 2, 2018,
Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets
purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added
Oasis Midstream Partners LP as a defendant, asserting that it was created in bad faith in an effort to avoid contractual obligations
owed to Mirada. Mirada may further amend its petition from time to time to assert additional claims as well as defendants. Trial
was previously scheduled for May 2019, but, in connection with a request by the parties to continue the trial until a later date, the
trial is now scheduled for February 20, 2020. For further information regarding this lawsuit, please read “Item 3. Legal
Proceedings.” We cannot predict the outcome of the Mirada Litigation or the amount of time and expense that will be required to
resolve the lawsuit. If such litigation were to be determined adversely to our interests, or if we were forced to settle such matter
for a significant amount, such resolution or settlement could have a material adverse effect on our business, results of operations
and financial condition. Such an adverse determination could materially impact our ability to operate our properties in Wild Basin
or develop our identified drilling locations in Wild Basin on our current development schedule. A determination that Mirada has a
right to participate in our midstream operations could materially reduce the interests of us in our current assets and future
midstream opportunities and related revenues in Wild Basin. In addition, we have agreed to indemnify OMP for any losses
resulting from this litigation under the omnibus agreement we entered into with OMP at the time of its initial public offering.
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Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of
operations.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of our potential
customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets,
such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Also, destructive
forms of protests and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and
natural gas development and production or midstream processing or transportation activities could potentially result in damage or
injury to persons, property or the environment or lead to extended interruptions of our operations. Our insurance may not protect
us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a
material adverse effect on our business, financial condition and results of operations.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including
certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for
compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as
SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long
distances, such as oil and gas pipelines. We depend on digital technology, including information systems and related infrastructure
as well as cloud applications and services, to process and record financial and operating data and to communicate with our
employees and business partners. Our business partners, including vendors, service providers and financial institutions, are also
dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of
theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also
has increased. A cyber attack could include gaining unauthorized access to digital systems or data for purposes of
misappropriating assets or sensitive information, corrupting data or causing operational disruption. SCADA-based systems are
potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks and data, and those of our business partners, may become the target of cyber attacks or
information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of
proprietary and other information or other disruption of our business operations. In addition, certain cyber incidents, such as
unauthorized surveillance or a cyber breach, may remain undetected for an extended period.
A cyber incident involving our information systems or data and related infrastructure, or that of our business partners, including
any vendor or service provider, could disrupt our business plans and negatively impact our operations in the following ways,
among others:
•
•
•
•
•
supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying
the start of cash flows from the project;
delays in delivering or failure to deliver product at the tailgate of our facilities, resulting in a loss of revenues;
operational disruption resulting in loss of revenues;
events of non-compliance that could lead to regulatory fines or penalties; and
business interruptions that could result in expensive remediation efforts, distraction of management, damage to our
reputation or a negative impact on the price of our units.
Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to
monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor
intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring.
As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or
enhance our protective measures or to investigate and remediate any information security vulnerabilities.
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Ineffective internal controls could impact our business and financial results.
Our internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including
the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide
only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the
adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience
difficulties in their implementation, our business and financial results could be harmed and we could fail to meet our financial
reporting obligations. In connection with the preparation of our consolidated financial statements for the year ended December
31, 2018, we identified errors in our previously issued 2017 annual consolidated financial statements and in each of the interim
periods within 2018 and 2017. These prior period errors related to the manner in which we accounted for certain crude oil
purchase and sale arrangements. See Note 2 to our consolidated financial statements for more information on this revision, and
for a discussion of our internal control over financial reporting and a description of the identified material weakness and the
remediation efforts being implemented for that material weakness, see “Management's report on internal control over financial
reporting” included in Item 9A of this report.
A material weakness in our internal control over financial reporting could adversely impact our ability to provide timely and
accurate financial information. In response to the material weakness identified, management has developed a remediation plan,
including enhanced communication and improved management review of crude oil purchase and sale arrangements in order to
remediate this material weakness, and has begun working on that remediation plan. However, if our remedial measures are
insufficient to address the material weakness or if additional material weaknesses or significant deficiencies in our internal control
over financial reporting are discovered or occur in the future, we may not be able to timely or accurately report our financial
condition, results of operations or cash flows or maintain effective disclosure controls and procedures.
Risks Relating to our Common Stock
We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, our
shareholders’ only opportunity to achieve a return on their investment is if the price of our stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently
restricted from making any cash dividends pursuant to the terms of our Revolving Credit Facilities and the indentures governing
our Senior Notes. Consequently, our shareholders’ only opportunity to achieve a return on their investment in us will be if the
market price of our common stock appreciates, which may not occur, and the shareholder sells their shares at a profit. There is no
guarantee that the price of our common stock will ever exceed the price that the shareholder paid.
Our amended and restated certificate of incorporation, as amended, and amended and restated bylaws, as well as Delaware
law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market
price of our common stock.
Our amended and restated certificate of incorporation, as amended, authorizes our Board of Directors to issue preferred stock
without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party
to acquire us. In addition, some provisions of our amended and restated certificate of incorporation, as amended, and amended
and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be
beneficial to our stockholders, including:
•
•
•
a classified Board of Directors, so that only approximately one-third of our directors are elected each year;
limitations on the removal of directors; and
limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for
stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of
stockholders.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that
a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this
person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of
Directors.
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Conversion of the Senior Convertible Notes may dilute the ownership interest of existing stockholders, or may otherwise
depress the market price of our common stock.
The conversion of some or all of the Senior Convertible Notes (as defined in “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Liquidity and Capital Resources”) may dilute the ownership interests of existing
stockholders of our common stock. Any sales in the public market of the shares of our common stock issuable upon such
conversion could adversely affect prevailing market prices of our common stock. In addition, the existence of the Senior
Convertible Notes may encourage short selling by market participants because the conversion of the Senior Convertible Notes
could be used to satisfy short positions, and anticipated conversion of the Senior Convertible Notes into shares of our common
stock could depress the market price of our common stock.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The information required by Item 2. is contained in Item 1. Business.
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Item 3. Legal Proceedings
Mirada litigation
On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC
(collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and Oasis Midstream Services LLC, seeking monetary damages in
excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America
LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a
working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that
the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream
operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain
agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain
Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) overstating the estimated costs of proposed
well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at
Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and
Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding
proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well
at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the
Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right
to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and
gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the
Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the
midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by
charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be
paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for
midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings,
Mirada alleged new legal theories for being entitled to enforce the underlying contracts and added Bighorn DevCo LLC, Bobcat
DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid
contractual obligations owed to Mirada.
On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests
in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition
that added Oasis Midstream Partners LP as a defendant, asserting that it was created in bad faith in an effort to avoid contractual
obligations owed to Mirada.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the
applicable agreements and that some of Mirada’s claims are grounded in agreements that do not apply to the Company. The
Company filed answers denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims.
OMP has not yet filed an answer because it has not yet been served with process. Discovery is ongoing, and each of the parties
has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the
claim. Trial was previously scheduled for May 2019, but, in connection with a request by the parties to continue the trial until a
later date, the trial is now scheduled for February 20, 2020. The Company cannot predict or guarantee the ultimate outcome or
resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were
forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the
Company’s business, financial condition, results of operations or cash flows. Such an adverse determination could materially
impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on
its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations
could materially reduce the interests of the Company in their current assets and future midstream opportunities and related
revenues in Wild Basin. In addition, the Company has agreed to indemnify OMP for any losses resulting from this litigation under
the omnibus agreement it entered into with OMP at the time of OMP’s initial public offering.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Holders. As of February 22, 2019, the number of record holders of our common stock was 797. Based on inquiry, management
believes that the number of beneficial owners of our common stock is approximately 37,716 as of February 20, 2019.
On February 28, 2019, the last sale price of our common stock, as reported on the NYSE, was $5.59 per share.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2018.
Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities
during the three months ended December 31, 2018:
Period
October 1 – October 31, 2018
November 1 – November 30, 2018
December 1 – December 31, 2018
Total
Total Number
of Shares
Exchanged(1)
Average Price
Paid
per Share
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
2,129 $
593
527
3,249 $
14.23
10.34
7.14
0.08
—
—
—
—
Maximum Number (or
Approximate Dollar Value) of
Shares that May Be Purchased
Under the Plans or Programs
—
—
—
—
__________________
(1)
Represent shares that employees surrendered back to us that equaled in value the amount needed to pay payroll tax
withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly
announced program to repurchase shares of our common stock, nor do we have a publicly announced program to
repurchase shares of our common stock.
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Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not
be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any
future filing under the Securities Act or the Exchange Act, except to the extent that we specifically request that such information
be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.
The performance graph shown below compares the cumulative total return to our common stockholders as compared to the
cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas
Exploration & Production Index (“S&P 500 O&G E&P”) for the period of December 2013 through December 2018. The
comparison was prepared based upon the following assumptions:
1.
$100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on December 31, 2013 at the closing
price on such date; and
2. Dividends were reinvested.
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Item 6. Selected Financial Data
Set forth below is our summary historical consolidated financial data for the years ended December 31, 2014 through 2018. This
information may not be indicative of our future results of operations, financial position and cash flows and should be read in
conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” presented elsewhere in this Annual Report on Form 10-K. We believe that the
assumptions underlying the preparation of our historical consolidated financial statements are reasonable.
Statement of operations data:
Revenues:
Oil and gas revenues(2)
Purchased oil and gas sales(2)
Midstream revenues
Well services revenues
Total revenues
Expenses:
Year ended December 31,
2018
2017
2016(1)
2015
2014
(In thousands, except per share data)
$
1,590,024 $
1,034,634 $
625,233 $
721,672 $
1,304,004
551,808
119,040
61,075
133,542
72,752
52,791
10,272
35,406
33,754
—
23,769
44,294
—
11,614
74,610
2,321,947
1,293,719
704,665
789,735
1,390,228
Lease operating expenses
193,912
177,134
135,444
144,481
169,600
Midstream operating expenses
Well services operating expenses(3)
Marketing, transportation and
gathering expenses(4)
Purchased oil and gas expenses(2)
Production taxes
Depreciation, depletion and
amortization
Exploration expenses
Rig termination(5)
Impairment
General and administrative expenses(3)
31,912
41,200
17,589
37,228
9,003
20,675
6,198
24,782
107,193
55,740
30,108
31,610
554,307
133,696
134,615
88,133
10,258
56,565
—
69,584
127,648
476,331
485,322
412,334
636,296
27,432
—
384,228
121,346
530,802
11,600
—
6,887
91,797
1,785
—
4,684
89,342
2,369
3,895
46,109
89,549
Total operating expenses
2,231,522
1,151,525
834,195
903,899
Gain (loss) on sale of properties
28,587
1,774
(1,303)
—
119,012
143,968
(130,833)
(114,164)
4,647
45,605
29,133
—
3,064
—
47,238
92,306
931,575
186,999
645,652
28,457
(71,657)
(105,317)
210,376
327,011
(159,085)
(146,837)
(140,305)
(149,648)
(158,390)
Gain (loss) on extinguishment of debt
(13,848)
Other income (expense)
121
—
(1,332)
4,741
160
Total other income (expense)
(144,355)
(219,826)
(240,721)
(25,343)
5,843
(75,858)
203,304
(371,554)
128,538
—
(2,935)
57,793
(56,371)
16,123
—
195
168,816
814,468
(307,591)
Operating income (loss)
Other income (expense)
Net gain (loss) on derivative
instruments
Interest expense, net of capitalized
interest
Income (loss) before income taxes
Income tax benefit (expense)
Net income (loss) including non-
controlling interests
Less: Net income attributable to non-
controlling interests(6)
Net income (loss) attributable to Oasis
Earnings (loss) per share:
Basic
Diluted
$
$
(19,500)
127,446
(243,016)
(40,248)
506,877
15,796
3,650
—
—
—
(35,296) $
123,796 $
(243,016) $
(40,248) $
506,877
(0.11) $
(0.11)
0.53 $
0.52
(1.32) $
(1.32)
(0.31) $
(0.31)
/
5.09
5.05
__________________
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(1)
Our statement of operations data for the years ended December 31, 2018 and 2016 do not include the full twelve months
effects of our acquisitions for 2018 and 2016, respectively. We acquired such interests on February 14, 2018 for our 2018
acquisition and December 1, 2016 for our 2016 acquisition. See Note 10 to our consolidated financial statements for more
information on the 2018 acquisition.
(2) We have revised the Consolidated Statements of Operations to correct the presentation of certain purchase and sale
arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and
gas revenues, by increasing purchased oil and gas sales and purchased oil and gas expenses by $45.6 million and $45.3
million, respectively, and decreasing oil and gas revenues by $0.3 million for the year ended December 31, 2017. See
Note 2 to our consolidated financial statements for more information on this revision.
(3)
(4)
(5)
(6)
For the years ended December 31, 2016 and 2015, well services operating expenses have been adjusted to include $2.9
million and $3.7 million, respectively, for certain well services direct field labor compensation expenses which were
previously recognized in general and administrative expenses on our Consolidated Statements of Operations.
Prior to the first quarter of 2017, marketing, transportation and gathering expenses included purchased oil and gas
expenses, which represent the crude oil purchased primarily for blending at our crude oil terminal. Prior periods have been
adjusted retrospectively to reflect these expenses in purchased oil and gas expenses on our Consolidated Statements of
Operations. For the year ended December 31, 2016, marketing, transportation and gathering expenses have been adjusted
to exclude $10.3 million of purchased oil and gas expenses.
During the year ended December 31, 2015, we elected to early terminate certain drilling rig contracts and recorded rig
termination expenses of $3.9 million.
As OMP completed its initial public offering on September 25, 2017, net income attributable to non-controlling interests
represents the OMP interest owned by the public for the period from September 25, 2017 through December 31, 2017. As
of November 19, 2018, net income attributable to non-controlling interests represents the OMP interest owned by the
public following the OMP Dropdown. See Note 3 to our consolidated financial statements for more information on the
OMP Dropdown.
At December 31,
2018
2017
2016
2015
2014
(In thousands)
$
22,190 $
16,720 $
11,226 $
9,730 $
45,811
7,027,109
6,173,486
5,919,567
5,218,242
7,626,142
6,622,929
6,178,632
5,649,375
2,735,276
2,097,606
2,297,214
2,302,584
3,918,880
3,513,579
2,923,157
2,319,342
5,186,786
5,909,076
2,670,664
1,872,301
Balance sheet data:
Cash and cash equivalents
Net property, plant and equipment
Total assets(1)(2)
Long-term debt(1)
Total stockholders’ equity
__________________
(1)
Prior to 2015, we presented deferred financing costs related to our Senior Notes in other assets on our Consolidated
Balance Sheets. Upon the adoption of new accounting guidance in 2015, such costs are presented as a deduction from the
carrying value of long-term debt. As of December 31, 2018, 2017, 2016 and 2015, deferred financing costs related to our
Senior Notes totaling $20.9 million, $23.0 million, $28.3 million and $35.4 million, respectively, were included in long-
term debt on our Consolidated Balance Sheets. Prior periods have been adjusted retrospectively to reflect the period-
specific effects of applying the new guidance. Reclassified amounts total $29.3 million for the year ended December 31,
2014.
(2) We have revised the Consolidated Balance Sheets to correct the presentation of certain purchase and sale arrangements
that should have been presented on a gross basis, which were previously recognized on a net basis in accounts receivable,
by increasing both accounts receivable and accrued liabilities by $7.8 million as of December 31, 2017, which resulted in
increases in both total assets and total liabilities. See Note 2 to our consolidated financial statements for more information
on this revision.
Year ended December 31,
2018
2017
2016
2015
2014
(In thousands)
Other financial data:
Net cash provided by operating activities
$
996,421 $
507,876 $
228,018 $
359,815 $
872,516
/
Net cash used in investing activities
(1,613,536)
(714,760)
(1,070,828)
(479,148)
(1,077,452)
Net cash provided by financing activities
622,585
212,378
844,306
83,252
158,846
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our
consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following
discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We
caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual
results, and the differences can be material. Some of the key factors which could cause actual results to vary from our
expectations include changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital
expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results,
operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets
generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties
regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as
those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of
these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary note regarding
forward-looking statements.”
Overview
We are an independent E&P company focused on the acquisition and development of onshore, unconventional oil and natural gas
resources in the United States. Since our inception, we have acquired properties that provide current production and significant
upside potential through further development. Our drilling activity has primarily been directed toward projects that we believe can
provide us with repeatable successes in the Bakken and Three Forks formations. On February 14, 2018, we acquired
approximately 22,000 net acres in the Delaware Basin from Forge Energy, LLC, representing our initial entry into the Delaware
Basin (the “Permian Basin Acquisition”). The Permian Basin Acquisition more than doubled our core net inventory and allows us
to further capitalize on our operational strengths. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian
LLC (“OP Permian”) conduct our domestic oil and natural gas E&P activities and own our proved and unproved oil and natural
gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas regions of the Delaware
Basin, respectively. In 2019, we will continue our drilling and completion activities in the Williston and Delaware Basins.
We also operate a midstream services business through OMS Holdings LLC (“OMS”) and a well services business through Oasis
Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to our primary
development and production activities. The midstream services business is conducted by Oasis Midstream Partners LP (“OMP”
or “Oasis Midstream”), which completed an initial public offering in September 2017. We own the general partner and a majority
of the outstanding units of OMP. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working
interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most
attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed
our rate of return criteria. We built our Williston Basin assets through acquisitions and development activities, which were
financed with a combination of capital from private investors, borrowings under a $1,600.0 million senior secured revolving
credit facility among OPNA, as Borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the
“Oasis Credit Facility”) and a $400.0 million senior secured revolving credit facility among OMP, as parent, OMP Operating
LLC, a subsidiary of OMP, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “OMP
Credit Facility,” and, together with the Oasis Credit Facility, our “Revolving Credit Facilities”), cash flows provided by operating
activities, proceeds from our senior unsecured notes, proceeds from our public equity offerings, the sale of certain non-strategic
oil and gas properties and cash settlements of derivative contracts. For acquisitions of properties with additional development,
exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control
the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what
we believe to be attractive rates of return either because they provided an entry into a new area of interest or complemented our
existing operations. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and
geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis. We intend to
continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
Due to the geographic concentration of our oil and natural gas properties in the Williston Basin and Delaware Basin, we believe
the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:
•
•
•
•
commodity prices for oil and natural gas;
transportation capacity;
availability and cost of services; and
availability of qualified personnel.
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Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political
and regulatory developments as well as competition from other sources of energy. Prices for oil and natural gas can fluctuate
widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as
market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas
activities, commodity prices have experienced significant fluctuations and may fluctuate widely in the future. As a result of
current oil prices, we have decreased our planned 2019 capital expenditures as compared to 2018, excluding acquisitions, and we
are continuing to concentrate our drilling activities in certain areas that are the most economic in the Williston Basin and the
Delaware Basin. A substantial or extended decline in prices for oil or natural gas could materially and adversely affect our
financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and
our access to capital.
In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities
in-house, which enables us to market and sell our oil and natural gas to a broad array of potential purchasers. We enter into crude
oil and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial
instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due
to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas
customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant
amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering
systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. Currently, 86% of our
gross operated oil production and substantially all of our gross operated natural gas production are connected to gathering
systems. Please see “Item 1. Business—Marketing, transportation and major customers.”
Our quarterly average net realized oil prices and average price differentials are shown in the tables below.
Average Realized Oil Prices ($/Bbl)(1)
Average Price Differential ($/Bbl)(2)
Average Price Differential Percentage(2)
Average Realized Oil Prices ($/Bbl)(1)
Average Price Differential ($/Bbl)(2)
Average Price Differential Percentage(2)
Average Realized Oil Prices ($/Bbl)(1)
Average Price Differential ($/Bbl)(2)
Average Price Differential Percentage(2)
__________________
(1)
Q1
61.75
1.12
$
$
Q2
65.82
2.07
2018
$
$
Q3
68.33
1.16
$
$
Q4
52.01
6.79
$
$
2%
3%
2%
12%
Q1
47.03
4.88
$
$
Q2
44.58
3.71
2017
$
$
Q3
46.34
1.84
$
$
Q4
54.95
0.51
$
$
9%
8%
4%
1%
Q1
28.74
4.85
$
$
Q2
40.81
4.86
2016
$
$
Q3
40.54
4.40
$
$
Q4
44.57
4.91
$
$
14%
11%
10%
10%
Year ended
December 31, 2018
61.84
2.88
4%
Year ended
December 31, 2017
48.51
2.62
5%
Year ended
December 31, 2016
38.64
4.76
11%
$
$
$
$
$
$
Realized oil prices do not include the effect of derivative contract settlements.
(2)
Price differential reflects the difference between realized oil prices and WTI crude oil index prices.
Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to
optimize price realizations. Crude oil produced and sold in the Williston Basin has historically sold at a discount to WTI due to
transportation costs and takeaway capacity. In the past, there have been periods when this discount has substantially increased due
to oil production in the area increasing to a point that it temporarily surpassed the available pipeline transportation, rail
transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on
oil transportation out of the Williston Basin and improved our price differentials received at the lease. In 2015, our price
differentials relative to WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail
gradually declined. In the second half of 2017 and throughout most of 2018, our crude oil price differentials improved to less than
$2.00 per barrel discount to WTI primarily due to the additional takeaway capacity of the Dakota Access Pipeline of over 500,000
barrels per day. In the fourth quarter of 2018, above average refinery maintenance combined with production in the Williston
Basin reaching record levels temporarily caused basis differentials to widen to more than $6.50 per barrel discount to WTI, but
have since come back in line with the first three quarters of 2018. Our market optionality on the crude oil gathering systems
allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. In the Delaware Basin, price
differentials in 2018 averaged more than $4.00 per barrel below WTI due to pipeline constraints. Expansions of pipelines
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occurring in 2019 should greatly reduce these differentials and provide ample takeaway for our Delaware production beginning in
mid-2019.
We believe our large concentrated acreage position provides us with a multi-year inventory of drilling projects and requires
forward planning visibility for obtaining services and necessary permits to drill wells. As a result of current oil prices, we are
planning to decrease our well completions from 114 gross (79.0 net) operated wells in the Williston Basin in 2018 to
approximately 70 gross operated wells in 2019. In the Delaware Basin, we are planning a slight increase in well completions from
7 gross (6.3 net) operated wells in 2018 to approximately 9 to 11 gross operated wells in 2019. Additionally, we have the ability
to control the pace of completions to allow for additional financial flexibility. In 2018, we wrote off $0.9 million of leases that we
did not expect to develop before their 2019 contract expirations, as we continue to focus our 2019 drilling activities in our core
acreage in the Williston Basin and the Delaware Basin.
Our 2018, 2017 and 2016 activities included development and exploration drilling in the Williston Basin. Our current activities
are focused on evaluating and developing our asset bases in the Williston Basin and the Delaware Basin and optimizing our
operations. Based on the reserve reports prepared by our independent reserve engineers, we had 320.5 MMBoe of estimated net
proved reserves with a PV-10 of $4,674.3 million and a Standardized Measure of $4,050.3 million at December 31, 2018, 312.2
MMBoe of estimated net proved reserves with a PV-10 of $3,683.7 million and a Standardized Measure of $3,300.7 million at
December 31, 2017 and 305.1 MMBoe of estimated net proved reserves with a PV-10 of $2,627.8 million and a Standardized
Measure of $2,483.1 million at December 31, 2016. Our estimated net proved reserves and related future net revenues, PV-10 and
Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions,
and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for
the prior twelve months for the years ended December 31, 2018, 2017 and 2016 were $65.66 per Bbl for oil and $3.16 per
MMBtu for natural gas, $51.34 per Bbl for oil and $2.99 per MMBtu for natural gas and $42.60 per Bbl for oil and $2.47 per
MMBtu for natural gas, respectively. These prices were adjusted by lease for quality, transportation fees, geographical
differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating
costs, production taxes and capital costs were based on current costs as of each year-end. Changes in commodity prices and future
operating costs may significantly affect the economic viability of drilling projects as well as the economic valuation and
economic recovery of oil and gas reserves. A substantial or extended decline in oil prices could result in a significant decrease in
our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure in the future.
Forward commodity prices and estimates of future production also play a significant role in determining impairment. As a result
of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and
natural gas properties for impairment. In 2018 and 2016, we recorded impairment charges of $134.8 million and $1.1 million,
respectively, to write down our proved properties held for sale to their estimated fair value, less costs to sell. No proved
impairment charges were recorded during the year ended December 31, 2017. The excess of our expected undiscounted future
cash flows over the carrying value of our proved oil and natural gas properties in the Williston Basin has decreased slightly to
$2,672.8 million as of December 31, 2018 as compared to an excess of $2,697.2 million at December 31, 2017. The excess of our
expected undiscounted future cash flows over the carrying value of our proved oil and gas reserves in the Delaware Basin was
$491.0 million as of December 31, 2018. The underlying commodity prices embedded in our expected undiscounted cash flows
were determined using NYMEX forward strip prices for five years, escalating 3% per year thereafter. Our expected undiscounted
estimated cash flows also included a 3% inflation factor applied to the future operating and development costs after five years.
In connection with the preparation of the our consolidated financial statements for the year ended December 31, 2018, we
identified errors in our previously issued 2017 consolidated financial statements related to the presentation of certain crude oil
purchase and sale arrangements. Specifically, although we previously presented the transactions on a net basis in oil and gas
revenues, we were required to present these purchase and sale arrangements on a gross basis in purchased oil and gas expenses
and purchased oil and gas sales. We have revised the 2017 annual consolidated financial statements to reflect the correction of
errors, which had no effect on our net income. Management’s Discussion and Analysis of Financial Condition and Results of
Operations set forth below reflects the effects of the revision. Please see Note 2 of our consolidated financial statements in “Item
8—Financial Statements and Supplementary Data" for more information related to the revision.
Highlights
• We increased our production guidance twice in 2018, which was adjusted for divestitures. Our production volumes
averaged 88,288 barrels of oil equivalent per day (“Boepd”) (76.2% oil) in the fourth quarter of 2018, in-line with
midpoint guidance. Our production volumes averaged 82,525 Boepd (76.5% oil) for the year ended December 31, 2018;
• We lowered our lease operating expenses (“LOE”) per barrels of oil equivalent (“Boe”) by over 12% year over year to
$6.44 per Boe for the year ended December 31, 2018;
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• We completed and placed on production 121 gross (85.3 net) operated wells, including 114 gross (79.0 net) operated
wells in the Williston Basin and 7 gross (6.3 net) operated wells in the Delaware Basin, while investing $942.2 million of
exploration and production capital expenditures, which excludes acquisitions, other capital and midstream capital, during
2018;
• We closed and integrated the Permian Basin Acquisition of approximately 22,000 net core acres in the over-pressured oil
window of the Delaware Basin. Additionally, we purchased adjacent acreage at attractive pricing, bringing our total
position to over 23,000 net acres in the Delaware Basin;
•
OMP completed the construction and startup of a second natural gas plant in Wild Basin, making us the second largest
natural gas processor in North Dakota;
• We successfully executed a divestiture “dropdown” of additional interests in midstream subsidiaries to OMP for $251.4
million, which increased our holdings of OMP common units and reduced debt;
• We high-graded our portfolio since announcing the Permian Basin Acquisition, including non-strategic divestitures of
$340.0 million, which helped reduce financial leverage during the year ended December 31, 2018; and
•
Net cash provided by operating activities was $996.4 million for the year ended December 31, 2018. Adjusted EBITDA,
a non-GAAP financial measure, was $958.7 million for the year ended December 31, 2018. For a definition of Adjusted
EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) including non-controlling interests and net cash
provided by operating activities, see “Non-GAAP Financial Measures” below.
Results of Operations
Revenues
Our oil and gas revenues are derived from the sale of oil and natural gas production. These revenues do not include the effects of
derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or
changes in commodity prices. Our purchased oil and gas sales are derived from the sale of oil and gas purchased through our
marketing activities primarily to optimize transportation costs or for blending. Revenues and expenses from the sales and
purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the
purchased oil or gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with the same
counterparty in contemplation of one another, and these transactions are recorded on a net basis.
Our midstream revenues are primarily derived from produced and flowback water pipeline transport, produced and flowback
water disposal, natural gas gathering and processing, fresh water sales and crude oil gathering and transportation. Our well
services revenues are derived from well services, product sales and equipment rentals. The majority of our midstream revenues
and all of our well services revenues are from services for third-party working interest owners in OPNA’s operated wells.
Intercompany revenues for work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and
are therefore not included in midstream and well services revenues.
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The following table summarizes our revenues and production data for the periods presented:
Operating results (in thousands)
Revenues
Oil revenues(1)
Natural gas revenues
Purchased oil and gas sales(1)
Midstream revenues
Well services revenues
Total revenues
Production data
Williston Basin
Oil (MBbls)
Natural gas (MMcf)
Oil equivalents (MBoe)
Average daily production (Boe per day)
Delaware Basin
Oil (MBbls)
Natural gas (MMcf)
Oil equivalents (MBoe)
Average daily production (Boe per day)
Average sales prices
Year ended December 31,
2018
2017
2016
$
1,425,409 $
912,806 $
586,308
164,615
551,808
119,040
61,075
121,828
133,542
72,752
52,791
38,925
10,272
35,406
33,754
$
2,321,947 $
1,293,719 $
704,665
21,786
40,550
28,544
78,203
1,264
1,880
1,578
4,322
18,818
31,946
24,143
66,144
—
—
—
—
15,174
19,573
18,436
50,372
—
—
—
—
38.64
46.68
1.99
1.99
Oil, without derivative settlements (per Bbl)
Oil, with derivative settlements (per Bbl)(2)
Natural gas, without derivative settlements (per Mcf)(3)
Natural gas, with derivative settlements (per Mcf)(2)(3)
$
61.84 $
48.51 $
52.65
3.88
3.84
47.99
3.81
3.86
__________________
(1) We have revised the Consolidated Statements of Operations to correct the presentation of certain purchase and sale
arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and
gas revenues, by increasing purchased oil and gas sales and purchased oil and gas expenses by $45.6 million and $45.3
million, respectively, and decreasing oil and gas revenues by $0.3 million for the year ended December 31, 2017. See
Note 2 to our consolidated financial statements for more information on this revision.
(2)
Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for or
were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and
losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to
acquire or modify the derivative instruments that were settled.
(3)
Natural gas prices include the value for natural gas and natural gas liquids.
Year ended December 31, 2018 as compared to year ended December 31, 2017
Oil and gas revenues. Our oil and gas revenues increased $555.4 million, or 54%, to $1,590.0 million during the year ended
December 31, 2018 as compared to the year ended December 31, 2017. The higher oil and natural gas production amounts sold
increased revenues by $302.4 million, coupled with a $253.0 million increase due to higher oil and natural gas sales prices year
over year. Average oil sales prices, without derivative settlements, increased by $13.33 per barrel to an average of $61.84 per
barrel, and average natural gas sales prices, without derivative settlements and which include the value for natural gas and natural
gas liquids, increased by $0.07 per Mcf to an average of $3.88 per Mcf for the year ended December 31, 2018 as compared to the
year ended December 31, 2017. Average daily production sold increased by 16,381 Boe per day to 82,525 Boe per day during the
year ended December 31, 2018 as compared to the year ended December 31, 2017. The increase in average daily production sold
was primarily a result of our well completions during the year coupled with the Permian Basin Acquisition, offset by our
divestitures. During the year ended December 31, 2018, we completed 79.2 total net wells in the Williston Basin. Since the
closing of the Permian Basin Acquisition on February 14, 2018, we completed 6.3 total net wells in
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the Delaware Basin during the year ended December 31, 2018. See Note 10 to our consolidated financial statements for a
description of our acquisitions.
Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize
transportation costs or for blending at our crude oil terminal, increased $418.3 million to $551.8 million for the year
ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to higher volumes purchased and
sold driven by increased market opportunities in the Williston Basin and in the Delaware Basin.
Midstream revenues. Midstream revenues were $119.0 million for the year ended December 31, 2018, which was a $46.3 million
increase year over year. This increase was driven by a $25.8 million increase related to higher natural gas volumes gathered,
compressed and processed, coupled with a $17.9 million increase related to higher water service volumes driven by an increase in
producing wells and a $2.7 million increase related to higher oil volumes gathered, stabilized and transported.
Well services revenues. Well services revenues increased by $8.3 million to $61.1 million for the year ended December 31,
2018 as compared to the year ended December 31, 2017, which was due to a $6.6 million increase in well completion revenue
due to the increased activity as a result of increasing the pace of our well completions and adding a second fracturing fleet in late
2017, coupled with a $0.8 million increase in equipment rentals and a $0.7 million increase in product sales to third parties.
Year ended December 31, 2017 as compared to year ended December 31, 2016
Oil and gas revenues. Our oil and gas revenues increased $409.4 million, or 65% to $1,034.6 million during the year ended
December 31, 2017 as compared to the year ended December 31, 2016. The higher oil and natural gas production amounts sold
increased revenues by $224.0 million, coupled with a $185.7 million increase due to higher oil and natural gas sales prices during
the year ended December 31, 2017 as compared to the year ended December 31, 2016. Average oil sales prices, without
derivative settlements, increased by $9.87 per barrel to an average of $48.51 per barrel, and average natural gas sales prices,
without derivative settlements and which include the value for natural gas and natural gas liquids, increased by $1.82 per Mcf to
an average of $3.81 per Mcf for the year ended December 31, 2017 as compared to the year ended December 31, 2016. Average
daily production sold increased by 15,772 Boe per day to 66,144 Boe per day during the year ended December 31, 2017 as
compared to the year ended December 31, 2016. The increase in average daily production sold was primarily a result of our
acquisition completed on December 1, 2016 of approximately 55,000 net acres in the Williston Basin (the “Williston Basin
Acquisition”) and our 63.0 total net well completions in the Williston Basin during the year ended December 31, 2017.
Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased for blending
at our crude oil terminal, which began in late 2016, or to optimize transportation costs, increased $123.3 million to $133.5 million
for the year ended December 31, 2017 as compared to the year ended December 31, 2016.
Midstream revenues. Midstream revenues were $72.8 million for the year ended December 31, 2017, which was a $37.4 million
increase year over year. This increase was driven by a $24.9 million increase related to higher natural gas volumes gathered,
compressed and processed, coupled with a $10.4 million increase related to higher oil volumes gathered, stabilized and
transported as a result of the start up of our first natural gas processing plant and our oil gathering system in the second half of
2016, respectively.
Well services revenues. In 2017, we increased the pace of our well completions and added a second fracturing fleet as well as third
party crews. As a result, our well services revenues increased by $19.0 million to $52.8 million for the year ended December 31,
2017 as compared to the year ended December 31, 2016, which was due to a $10.7 million increase in well completion revenue
due to the increased activity as a result of adding the second fracturing fleet, coupled with a $7.7 million increase in product sales
to third parties.
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Expenses and other income
The following table summarizes our operating expenses, gain on sale of properties, other income and expenses and net income
attributable to non-controlling interests for the periods presented:
Operating expenses
Lease operating expenses
Midstream operating expenses
Well services operating expenses(1)
Marketing, transportation and gathering expenses(2)
Purchased oil and gas expenses(3)
Production taxes
Depreciation, depletion and amortization
Exploration expenses
Impairment
General and administrative expenses(1)
Total operating expenses
Gain (loss) on sale of properties
Operating income (loss)
Other income (expense)
Net gain (loss) on derivative instruments
Interest expense, net of capitalized interest
Gain (loss) on extinguishment of debt
Other income (expense)
Total other expense
Loss before income taxes
Income tax benefit
Net income (loss) including non-controlling interests
Less: Net income attributable to non-controlling interests(4)
Net income (loss) attributable to Oasis
Costs and expenses (per Boe of production)
Lease operating expenses
Marketing, transportation and gathering expenses(2)
Production taxes
__________________
(1)
Year ended December 31,
2018
2017
2016
(In thousands, except per Boe of production)
$
193,912 $
177,134 $
135,444
31,912
41,200
107,193
554,307
133,696
636,296
27,432
384,228
121,346
17,589
37,228
55,740
134,615
88,133
530,802
11,600
6,887
91,797
2,231,522
1,151,525
28,587
119,012
28,457
(159,085)
(13,848)
121
(71,657)
(146,837)
—
(1,332)
(144,355)
(219,826)
(25,343)
5,843
(19,500)
15,796
(75,858)
203,304
127,446
3,650
9,003
20,675
30,108
10,258
56,565
476,331
1,785
4,684
89,342
834,195
(1,303)
(105,317)
(140,305)
4,741
160
(240,721)
(371,554)
128,538
(243,016)
—
1,774
143,968
(130,833)
$
$
(35,296) $
123,796 $
(243,016)
6.44 $
3.56
4.44
7.34 $
2.31
3.65
7.35
1.63
3.07
For the year ended December 31, 2017, certain well services direct field labor compensation expenses are included in well
services operating expenses on our Consolidated Statements of Operations, which were previously recognized in general
and administrative expenses on our Consolidated Statements of Operations. For the year ended December 31, 2016, well
services operating expenses has been adjusted to include $2.9 million, which was previously recognized in general and
administrative expenses on our Consolidated Statements of Operations.
(2)
Prior to the first quarter of 2017, marketing, transportation and gathering expenses included purchased oil and gas
expenses related to blending at our crude oil terminal on our Consolidated Statements of Operations. Prior periods have
been adjusted retrospectively to reflect these expenses in purchased oil and gas expenses on our Consolidated Statements
of Operations. For the year ended December 31, 2016, marketing, transportation and gathering expenses has been adjusted
to exclude $10.3 million of purchased oil and gas expenses.
(3) We have revised the Consolidated Statements of Operations to correct the presentation of certain purchase and sale
arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and
gas revenues, by increasing purchased oil and gas sales and purchased oil and gas expenses by $45.6 million and
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(4)
$45.3 million, respectively, and decreasing oil and gas revenues by $0.3 million for the year ended December 31, 2017.
See Note 2 to our consolidated financial statements for more information on this revision.
As OMP completed its initial public offering on September 25, 2017, net income attributable to non-controlling interests
represents the OMP interest owned by the public for the period from September 25, 2017 through December 31, 2017. As
of November 19, 2018, net income attributable to non-controlling interests represents the OMP interest owned by the
public following the OMP Dropdown. See Note 3 to our consolidated financial statements for more information on the
OMP Dropdown.
Year ended December 31, 2018 as compared to year ended December 31, 2017
Lease operating expenses. Lease operating expenses increased $16.8 million to $193.9 million for the year ended December 31,
2018 as compared to the year ended December 31, 2017. The increase was primarily due to an increase in produced and flowback
water disposal volumes being transported and injected into produced and flowback water disposal wells. In addition, lease
operating expenses increased due to higher costs associated with operating an increased number of producing wells as a result of
the Permian Basin Acquisition and our well completions, coupled with an increase in workover costs during the year ended
December 31, 2018. We completed and placed on production 79.2 total net wells in the Williston Basin during the year ended
December 31, 2018 as compared to 63.0 total net wells completed and placed on production during the year ended December 31,
2017. Since the closing of the Permian Basin Acquisition, we completed and placed on production 6.3 total net wells in the
Delaware Basin during the year ended December 31, 2018. Lease operating expenses per Boe decreased from $7.34 per Boe to
$6.44 per Boe primarily due to higher production volumes driven by improved downtime period over period.
Midstream operating expenses. Midstream operating expenses represent third-party working interest owners’ share of operating
expenses incurred by OMS. The $14.3 million increase for the year ended December 31, 2018 as compared to the year ended
December 31, 2017 was primarily related to the $8.0 million increase in gas gathering, compression and processing expenses
driven by increased production, coupled with a $4.1 million increase related to higher water service volumes driven by an
increase in producing wells and a $2.1 million increase related to higher oil volumes gathered, stabilized and transported.
Well services operating expenses. Well services operating expenses represent third-party working interest owners’ share of
completion service costs, cost of goods sold and operating expenses incurred by OWS. The $4.0 million increase for the year
ended December 31, 2018 as compared to the year ended December 31, 2017 was primarily attributable to increased well
completion activity, coupled with increased trucking and maintenance expenses due to the addition of a second fracturing fleet in
late 2017.
Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $51.5 million year
over year, or a $1.25 increase per Boe, which was primarily attributable to higher oil gathering and transportation expenses
related to increased throughput on the Dakota Access Pipeline, which began operations in the second quarter of 2017, and our oil
gathering system, which has been ramping up throughput since it began operations in the second half of 2016. In addition, natural
gas gathering and processing expenses increased due to additional well connections on OMS infrastructure and the start up of our
natural gas processing plants in the second half of 2016 and in the fourth quarter of 2018. Excluding non-cash valuation
adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $3.41 for the year ended
December 31, 2018 as compared to $2.34 for the year ended December 31, 2017 primarily due to the higher aforementioned
costs.
Purchased oil and gas expenses. Purchased oil and gas expenses, which represent the crude oil purchased primarily to optimize
transportation costs or for blending at our crude oil terminal, increased $419.7 million to $554.3 million for the year ended
December 31, 2018 as compared to December 31, 2017 primarily due to higher volumes purchased and sold driven by increased
market opportunities in both the Williston Basin and the Delaware Basin.
Production taxes. Our production taxes for the years ended December 31, 2018 and 2017 were 8.4% and 8.5%, respectively, as a
percentage of oil and natural gas sales. The production tax rate decreased year over year primarily due to a lower oil production
mix, coupled with the addition of Delaware Basin assets following the Permian Basin Acquisition in February 2018 which bear a
lower average production tax rate of approximately 4.8% as compared to 8.6% for the Williston Basin assets. North Dakota’s
natural gas production tax is $0.0705 per Mcf, while its crude oil tax structure is based on a 5% production tax and a 5% oil
extraction tax, resulting in a combined tax rate of 10% of crude oil revenues.
Depreciation, depletion and amortization (“DD&A”). DD&A expense increased $105.5 million to $636.3 million for the year
ended December 31, 2018 as compared to the year ended December 31, 2017. The increase in DD&A expense for the year ended
December 31, 2018 was primarily due to production increases from our wells completed during the year ended December 31,
2018 coupled with the Permian Basin Acquisition, offset by a decrease in the average DD&A rate to $21.12 per Boe for the year
ended December 31, 2018 as compared to $21.99 per Boe for the year ended December 31, 2017. The decrease in the DD&A rate
was primarily due to lower costs and higher estimated ultimate recoveries on our more recently completed wells than our
historical averages, coupled with the removal of the divested non-strategic oil and gas properties (see Note 11 - Divestitures).
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Exploration expenses. Exploration expenses increased $15.8 million to $27.4 million for the year ended December 31, 2018 as
compared to the year ended December 31, 2017. This increase was primarily due to write-off of costs of $19.4 million related to
exploratory well locations that are no longer in our current development plan, offset by a $4.4 million decrease in geological and
geophysical expenses.
Impairment. During the years ended December 31, 2018 and 2017, we recorded total impairment charges of $384.2 million and
$6.9 million, respectively. During the year ended December 31, 2018, we recorded an impairment loss of $383.4 million to adjust
the carrying value of our properties for the Foreman Butte Divestiture to their estimated fair value, determined based on the
expected sales price less costs to sell (see Note 11 — Divestitures). There were no impairment charges of proved oil and gas or
other properties recorded during the year ended December 31, 2017, and no other impairment charges of proved oil and gas or
other properties recorded during the year ended December 31, 2018. As a result of periodic assessments of our unproved
properties not held-by-production, we recorded an impairment loss on our unproved oil and natural gas properties of $0.9 million
and $6.6 million for the years ended December 31, 2018 and 2017, respectively, related to acreage expiring in future periods
because there were no current plans to drill or extend the leases prior to their expiration. For the year ended December 31, 2017,
we also recorded non-cash impairment charges of $0.3 million for unproved properties due to leases that expired during the
period. There were no such impairment charges recorded during year ended December 31, 2018. In determining the amount of
non-cash impairment charges for such periods, we considered the application of the factors described under “Critical accounting
policies and estimates—Impairment of proved properties” and “Critical accounting policies and estimates—Impairment of
unproved properties.”
General and administrative (“G&A”) expenses. Our G&A expenses increased $29.5 million for the year ended December 31,
2018 from $91.8 million for the year ended December 31, 2017. E&P G&A increased $24.9 million year over year primarily due
to increased employee compensation expenses as a result of organizational growth, coupled with increased costs related to
the Permian Basin Acquisition. OMS G&A increased $4.7 million year over year primarily due to increased shared services
allocations to our OMS segment, coupled with increased employee compensation expenses as a result of organizational growth
within this segment. OWS G&A was $6.8 million and $6.9 million for the years ended December 31, 2018 and 2017,
respectively. Consolidated G&A expenses included non-cash amortization for equity-based compensation of $29.3 million and
$26.5 million in 2018 and 2017, respectively. Our full-time employee headcount increased 24% year over year.
Gain (loss) on sale of properties. For the year ended December 31, 2018, we recognized a $28.6 million net gain primarily related
to three separate divestitures to sell certain non-strategic oil and gas properties in the Williston Basin (see Note 11 —
Divestitures). For the year ended December 31, 2017, we recognized a $1.8 million net gain related to the sale of certain non-
operated wells.
Derivatives. As a result of entering into derivative contracts and the effect of the forward strip oil and gas price changes, we
incurred a $28.5 million net gain on derivative instruments, including net cash settlement payments of $213.5 million, for the year
ended December 31, 2018, and a $71.7 million net loss on derivative instruments, including net cash settlement payments of $8.3
million, for the year ended December 31, 2017. Cash settlements represent the cumulative gains and losses on our derivative
instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative
instruments that were settled.
Interest expense. Interest expense increased $12.3 million to $159.1 million for the year ended December 31, 2018 as compared to
the year ended December 31, 2017 primarily due to interest expense related to the borrowings under our Revolving Credit
Facilities and an increase in debt discount amortization related to our senior unsecured convertible notes. These increases in
interest expense were partially offset by an increase in capitalized interest of $4.4 million due to higher costs for work in progress
assets and a decrease in interest expense related to the repurchase of an aggregate principal amount of $390.6 million of
outstanding senior unsecured notes and the issuance of $400.0 million senior unsecured notes due in 2026 at a lower interest rate
of 6.25% in 2018. For the year ended December 31, 2018, the weighted average debt outstanding under the Oasis Credit Facility
and the OMP Credit Facility were $554.7 million and $166.2 million, respectively, and the weighted average interest rates
incurred on the outstanding borrowings were 3.9% and 3.8%, respectively. For the year ended December 31, 2017, the weighted
average debt outstanding under the Oasis Credit Facility and the OMP Credit Facility were $416.2 million and $9.1 million,
respectively, and the weighted average interest rates incurred on the outstanding borrowings were 2.8% and 3.1%, respectively.
We capitalized $17.2 million and $12.8 million of interest costs for the years ended December 31, 2018 and 2017, respectively,
which will be amortized over the life of the related assets.
Loss on extinguishment of debt. During the year ended December 31, 2018, we repurchased an aggregate principal amount of
$413.5 million of our outstanding senior unsecured notes for an aggregate cost of $423.1 million, including fees. For the year
ended December 31, 2018, we recognized a pre-tax loss related to the repurchase of $13.8 million, which included unamortized
deferred financing costs write-offs of $4.0 million. During the year ended December 31, 2017, we did not repurchase any portion
of our outstanding senior unsecured notes.
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Income tax benefit. Our income tax benefit for the years ended December 31, 2018 and 2017 was recorded at 23.1% and 268.0%,
respectively, of pre-tax loss. The 244.9% decrease in the effective tax rate recorded is primarily due to (i) the change in tax rate
under the Tax Act in 2017, (ii) the impact of non-deductible executive compensation, (iii) the impact of equity-based
compensation shortfalls in 2018 as compared to equity-based compensation windfalls in 2017 and (iv) an increase in the valuation
allowance recorded against our Montana net operating loss carryforwards in 2018. These decreases were partially offset by (i) the
impact of OMP’s earnings attributable to the non-controlling public limited partners which are not taxable to us and (ii) the
impact of a change in the state rate at which deferred taxes are recorded.
Year ended December 31, 2017 as compared to year ended December 31, 2016
Lease operating expenses. Lease operating expenses increased $41.7 million to $177.1 million for the year ended December 31,
2017 as compared to the year ended December 31, 2016. The increase was primarily due to higher costs associated with operating
an increased number of producing wells as a result of our well completions and the Williston Basin Acquisition, coupled with an
increase in workover costs during the year ended December 31, 2017. We completed and placed on production 63.0 total net wells
in the Williston Basin during the year ended December 31, 2017 as compared to 38.1 total net wells completed and placed on
production during the year ended December 31, 2016. Lease operating expenses per Boe remained relatively flat year over year.
Midstream operating expenses. Midstream operating expenses represent third-party working interest owners’ share of operating
expenses incurred by OMS. The $8.6 million increase for the year ended December 31, 2017 as compared to the year ended
December 31, 2016 was primarily related to the start up of our first natural gas processing plant and our oil gathering system
during 2016.
Well services operating expenses. Well services operating expenses represent third-party working interest owners’ share of
completion service costs, cost of goods sold and operating expenses incurred by OWS. The $16.6 million increase for the year
ended December 31, 2017 as compared to the year ended December 31, 2016 was primarily attributable to increased well
completion product sales, coupled with increased trucking costs, maintenance and direct labor expenses due to the addition of a
second fracturing fleet and higher well completion activity during 2017.
Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $25.6 million year
over year, or a $0.68 increase per Boe, which was primarily attributable to higher oil gathering and transportation expenses
related to the start up of the Dakota Access Pipeline in 2017 and the start up of our oil gathering system in the second half of
2016. In addition, natural gas gathering and processing expenses increased due to additional well connections on OMS
infrastructure and the start up of our first natural gas processing plant in the second half of 2016. Excluding non-cash valuation
adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $2.34 for the year ended
December 31, 2017 as compared to $1.60 for the year ended December 31, 2016 primarily due to the higher aforementioned
costs.
Purchased oil and gas expenses. Purchased oil and gas expenses, which represent the crude oil purchased primarily for blending
at our crude oil terminal, which began in late 2016, or to optimize transportation costs, increased $124.4 million to $134.6 million
for the year ended December 31, 2017 as compared to the year ended December 31, 2016.
Production taxes. Our production taxes for the years ended December 31, 2017 and 2016 were 8.5% and 9.1%, respectively, as a
percentage of oil and natural gas sales. The production tax rate decreased year over year primarily due to a lower oil production
mix. North Dakota’s natural gas production tax is $0.0555 per Mcf, while its crude oil tax structure is based on a 5% production
tax and a 5% oil extraction tax, resulting in a combined tax rate of 10% of crude oil revenues.
Depreciation, depletion and amortization. DD&A expense increased $54.5 million to $530.8 million for the year ended
December 31, 2017 as compared to the year ended December 31, 2016. The increase in DD&A expense for the year ended
December 31, 2017 was primarily due to production increases from our wells completed during the year ended December 31,
2017 coupled with the Williston Basin Acquisition, offset by a decrease in the average DD&A rate to $21.99 per Boe for the year
ended December 31, 2017 as compared to $25.84 per Boe for the year ended December 31, 2016. The decrease in the DD&A rate
was primarily due to lower well costs for wells completed during the second half of 2016 and the first half of 2017.
Exploration expenses. Exploration expenses increased $9.8 million to $11.6 million for the year ended December 31, 2017 as
compared to the year ended December 31, 2016. This increase was primarily due to a $7.5 million increase in geological and
geophysical expenses coupled with a $2.1 million write-off of costs primarily related to exploratory well locations that are no
longer in our current development plan.
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Impairment. During the years ended December 31, 2017 and 2016, we recorded total impairment charges of $6.9 million and $4.7
million, respectively. For the year ended December 31, 2016, we recorded impairment charges of $3.6 million to adjust the
carrying value of our properties held for sale to their estimated fair value, determined based on the expected sales price less costs
to sell. No other impairment charges of proved oil and gas or other properties were recorded in 2017 or 2016. We also recorded
non-cash impairment charges of $0.3 million and $0.2 million during the years ended December 31, 2017 and 2016, respectively,
for unproved properties due to leases that expired during the period. As a result of periodic assessments of our unproved
properties not held-by-production, we recorded an impairment loss on our unproved oil and natural gas properties of $6.6 million
and $0.9 million for the years ended December 31, 2017 and 2016, respectively, related to acreage expiring in future periods
because there were no current plans to drill or extend the leases prior to their expiration. In determining the amount of non-cash
impairment charges for such periods, we considered the application of the factors described under “Critical accounting policies
and estimates—Impairment of proved properties” and “Critical accounting policies and estimates—Impairment of unproved
properties.”
General and administrative expenses. Our G&A expenses increased $2.5 million for the year ended December 31, 2017 from
$89.3 million for the year ended December 31, 2016. OMS G&A increased $4.2 million year over year primarily due
to increased employee compensation as a result of organizational growth within this segment due to the start up of our first
natural gas processing plant in the third quarter of 2016, coupled with expenses incurred related to the initial public offering of
OMP. E&P G&A was $77.6 million and $79.0 million and OWS G&A was $6.9 million and $7.2 million for the years
ended December 31, 2017 and 2016, respectively. Consolidated G&A expenses included non-cash amortization for equity-based
compensation of $26.5 million and $24.1 million in 2017 and 2016, respectively. Our full-time employee headcount increased
23% year over year.
Gain (loss) on sale of properties. For the year ended December 31, 2017, we recognized a $1.8 million gain related to the sale of
certain non-operated wells. For the year ended December 31, 2016, we recognized a $1.3 million loss related to the sale of certain
legacy wells that have been producing from conventional reservoirs such as the Madison, Red River and other formations in the
Williston Basin other than the Bakken or Three Forks formations.
Derivatives. As a result of entering into derivative contracts and the effect of the forward strip oil and gas price changes, we
incurred a $71.7 million net loss on derivative instruments, including net cash settlement payments of $8.3 million, for the year
ended December 31, 2017, and a $105.3 million net loss on derivative instruments, including net cash settlement receipts of
$122.0 million, for the year ended December 31, 2016. Cash settlements represent the cumulative gains and losses on our
derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the
derivative instruments that were settled.
Interest expense. Interest expense increased $6.5 million to $146.8 million for the year ended December 31, 2017 as compared to
the year ended December 31, 2016 primarily due to interest expense related to our senior unsecured convertible notes issued in
September 2016, which includes debt discount amortization, and the borrowings under our Revolving Credit Facilities, coupled
with a decrease in capitalized interest due to lower costs for work in progress assets as a result of the completion of our first
natural gas processing plant in the third quarter of 2016. These increases were offset by the repurchase of an aggregate principal
amount of $447.0 million of outstanding senior unsecured notes in 2016, which resulted in a $16.2 million decrease in interest
costs. For the year ended December 31, 2017, the weighted average debts outstanding under the Oasis Credit Facility and the
OMP Credit Facility were $416.2 million and $9.1 million, respectively, and the weighted average interest rates incurred on the
outstanding borrowings were 2.8% and 3.1%, respectively. For the year ended December 31, 2016, the weighted average debt
outstanding under the Oasis Credit Facility was $116.1 million, and the weighted average interest rate incurred on the outstanding
borrowings thereunder was 2.2%. We capitalized $12.8 million and $16.8 million of interest costs for the years ended December
31, 2017 and 2016, respectively, which will be amortized over the life of the related assets.
Gain on extinguishment of debt. During the year ended December 31, 2016, we repurchased an aggregate principal amount of
$447.0 million of our outstanding senior unsecured notes for an aggregate cost of $435.9 million, including accrued interest and
fees. For the year ended December 31, 2016, we recognized a pre-tax gain related to the repurchase of $4.7 million, which
included unamortized deferred financing costs write-offs of $6.4 million. During the year ended December 31, 2017, we did not
repurchase any portion of our outstanding senior unsecured notes.
Income tax benefit. Our income tax benefit for the years ended December 31, 2017 and 2016 was recorded at 268.0% and 34.6%,
respectively, of pre-tax loss. The 233.4% increase in the effective tax rate recorded is primarily due to (i) the change in tax rate
under the Tax Act in 2017, (ii) the impact of non-deductible executive compensation, (iii) the impact of equity-based
compensation windfalls in 2017 as compared to equity-based compensation shortfalls in 2016 and (iv) the impact of OMP’s
earnings attributable to the non-controlling public limited partners which are not taxable to us.
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Liquidity and Capital Resources
Our primary sources of liquidity as of the date of this report have been cash flows from operations, borrowings under our
Revolving Credit Facilities, proceeds from our Senior Notes (as defined below), proceeds from the sale of certain non-strategic
oil and gas properties and proceeds from public equity offerings. Our primary uses of cash have been for the acquisition and
development of oil and natural gas properties and midstream infrastructure, interest payments on outstanding debt and
repurchases of our Senior Notes (as defined below). We continually monitor potential capital sources, including equity and debt
financings and potential asset monetization opportunities, in order to enhance liquidity and decrease leverage. Our future success
in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.
Our cash flows for the years ended December 31, 2018, 2017 and 2016 are presented below:
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Net change in cash and cash equivalents
Year ended December 31,
2018
2017
(In thousands)
2016
$
$
996,421 $
507,876 $
228,018
(1,613,536)
622,585
(714,760)
212,378
5,470 $
5,494 $
(1,070,828)
844,306
1,496
Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and
exploration activities as well as future acquisitions. Prices for oil declined significantly since mid-2014, which substantially
decreased our cash flows provided by operating activities for the year ended December 31, 2016. During 2017 and the majority of
2018, prices for oil began to show upward movements resulting in increased cash flows provided by operating activities. We
actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oil
and natural gas prices on a portion of our production, thereby mitigating our exposure to oil and natural gas price declines, but
these transactions may also limit our cash flow in periods of rising oil and natural gas prices. As of December 31, 2018, our
derivative contracts in place cover 15.4 MMBbls of crude oil and 11.0 Bcf of natural gas in 2019.
On February 14, 2018, we borrowed $502.0 million under the Oasis Credit Facility to fund cash due at closing of the Permian
Basin Acquisition and we also issued 46,000,000 shares of our common stock to Forge Energy to fund a portion of the Permian
Basin Acquisition (see Note 10 – Acquisitions).
Our existing Revolving Credit Facilities provide additional liquidity. The Oasis Credit Facility has a current borrowing base of
$1,600.0 million and an elected commitment amount of $1,350.0 million. The next redetermination of the borrowing base for the
Oasis Credit Facility is scheduled for April 1, 2019. The OMP Credit Facility has a current borrowing capacity of $400.0 million.
We believe we have adequate liquidity to fund planned 2019 capital expenditures and to meet our near-term future obligations.
For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative
Disclosures about Market Risk.”
Cash flows provided by operating activities
Net cash provided by operating activities was $996.4 million, $507.9 million and $228.0 million for the years ended December
31, 2018, 2017 and 2016, respectively. The increase in cash flows provided by operating activities for the year ended December
31, 2018 as compared to 2017 was primarily the result of a 22% increase in oil production, a 27% increase in realized oil prices, a
33% increase in natural gas production and a 2% increase in realized natural gas prices. The increase in cash flows provided by
operating activities for the year ended December 31, 2017 as compared to 2016 was primarily the result of a 26% increase in
realized prices for oil, a 24% increase in oil production, a 92% increase in realized prices for natural gas and a 63% increase in
natural gas production, coupled with increases in natural gas gathering and processing, produced and flowback pipeline transport
and produced and flowback water disposal and increases in well services activity.
Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes,
capital spending to fund our exploratory and development initiatives and acquisitions and the impact of our outstanding derivative
instruments. We had a working capital deficit of $57.6 million at December 31, 2018, however, we believe we have adequate
liquidity to meet our working capital requirements. As of December 31, 2018, we had $972.2 million of liquidity available,
including $22.2 million in cash and cash equivalents and $950.0 million of aggregate unused borrowing base committed capacity
available under our Revolving Credit Facilities. As of December 31, 2017, we had a working capital deficit of $215.6 million.
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Cash flows used in investing activities
We had net cash flows used in investing activities of $1,613.5 million, $714.8 million and $1,070.8 million during the years ended
December 31, 2018, 2017 and 2016, respectively, primarily as a result of our capital expenditures for acquisition, drilling and
development costs. The increase in cash used in investing activities for the year ended December 31, 2018 as compared to the
year ended December 31, 2017 was primarily attributable to an increase in cash used for acquisitions year over year, primarily
due to the Permian Basin Acquisition, and a 77% increase in cash capital expenditures primarily for drilling and development
costs. Net cash used in investing activities during the year ended December 31, 2018 was primarily attributable to $1,149.0
million in other capital expenditures for the development of our properties, including E&P capital, the second natural gas
processing plant and other midstream infrastructure, coupled with $581.7 million in acquisitions, primarily for the Permian Basin
Acquisition and an acquisition to acquire certain exploration and production assets adjacent to the our existing Delaware position
(“Other Delaware Acquisition”) and $213.5 million for derivative settlements paid as a result of higher crude oil prices, partially
offset by $333.2 million for proceeds from sale of properties. Net cash used in investing activities during the year ended
December 31, 2017 was primarily attributable to $647.3 million in other capital expenditures for the development of our
properties, including E&P capital, the second natural gas processing plant, and other midstream infrastructure coupled with $61.9
million for acquisitions, including the deposit of $47.3 million paid as part of the Permian Basin Acquisition, and $8.3 million for
derivative settlements paid as a result of higher crude oil prices, partially offset by $5.8 million for proceeds from sale of
properties. Net cash used in investing activities during the year ended December 31, 2016 was primarily attributable to $781.5
million for acquisitions, $426.3 million in other capital expenditures for the development of our properties, including E&P
capital, the first natural gas processing plant and other midstream infrastructure, partially offset by $122.0 million for derivative
settlements received as a result of lower crude oil prices.
Expenditures for the acquisition and development of oil and natural gas properties are the primary use of our capital resources.
Our capital expenditures for the years ended December 31, 2018, 2017 and 2016 are summarized in the following table:
Capital expenditures
E&P
Well services
Other capital expenditures(1)
Total capital expenditures before acquisitions and
midstream
Midstream(2)
Total capital expenditures before acquisitions
Acquisitions
Total capital expenditures(3)
Year ended December 31,
2018
2017
(In thousands)
2016
$
$
$
942,179 $
517,329 $
7,831
23,947
12,537
17,215
208,437
680
20,502
973,957
$
547,081
$
229,619
277,626
1,251,583
951,870
235,090
782,171
54,033
170,386
400,005
781,522
2,203,453 $
836,204
$
1,181,527
__________________
(1)
Other capital expenditures include such items as administrative capital and capitalized interest.
(2)
(3)
Midstream capital expenditures attributable to OMP was $116.6 million for the year ended December 31, 2018.
Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts for capital
expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because
amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital
expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. In addition, for
the year ended December 31, 2018, total capital expenditures (including acquisitions) reflected in the table includes
consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition. See
Note 10 to our consolidated financial statements for more information on the Permian Basin Acquisition.
In 2018, we spent $2,203.5 million on capital expenditures, which represented a 164% increase as compared to the $836.2 million
spent during 2017. This increase was primarily due to $951.9 million for acquisitions in 2018, including the Permian Basin
Acquisition and the Other Delaware Acquisition. See Note 10 to our consolidated financial statements for more information on
acquisitions. Excluding acquisitions, capital expenditures increased 60% as compared to 2017. The increase was attributable to
increased drilling and completion activity as a result of higher commodity prices in 2018, coupled with higher capital
expenditures for midstream, primarily related to the second natural gas processing plant constructed in our Wild Basin area in
North Dakota and the development of additional midstream infrastructure in the Wild Basin area in North Dakota.
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During 2018, we participated in 137 gross wells (85.5 net) that were completed and placed on production, and, as operator, we
completed and placed on production 121 gross (85.3 net) of these wells. In addition, as of December 31, 2018, we had 64 gross
operated wells awaiting completion in the Bakken and Three Forks formations in the Williston Basin and 4 gross operated wells
awaiting completion in the Wolfcamp and Bone Spring formations in the Delaware Basin. Our land leasing and acquisition
activity is focused in and around our existing core consolidated land positions in the Williston Basin as well as our acquired
acreage in the Delaware Basin.
As a result of current oil prices, we have decreased our planned 2019 capital expenditures as compared to 2018 capital
expenditures, excluding acquisitions. We anticipate investing between $690 million and $730 million in 2019 as follows:
E&P and other capital(1)
Midstream capital(2)
Total capital expenditures
Plan for the year ended December 31, 2019
(In thousands)
$540,000 - $560,000
150,000 - 170,000
$690,000 - $730,000
__________________
(1)
E&P and other capital expenditures include OWS and administrative capital and excludes capitalized interest of
approximately $15 million.
(2)
Midstream capital expenditures include approximately $19 million to $21 million for midstream capital expenditures
attributable to Oasis.
While we have planned approximately $690 million to $730 million for total capital expenditures in 2019, the ultimate amount of
capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results
as the year progresses. Furthermore, if we acquire additional acreage, our capital expenditures may be higher than planned. We
believe that cash on hand, including cash flows from operating activities, proceeds from cash settlements under our derivative
contracts and availability under our Revolving Credit Facilities should be sufficient to fund our 2019 capital expenditure plan
and to meet our future obligations. However, because the operated wells funded by our 2019 drilling plan represent only a small
percentage of our potential drilling locations, we will be required to generate or raise multiples of this amount of capital to
develop our entire inventory of potential drilling locations should we elect to do so.
Our capital plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital
expenditures is largely discretionary and within our control. If oil prices decline substantially or for an extended period of time,
we could defer a significant portion of our planned capital expenditures until later periods to prioritize capital projects that we
believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our
capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions,
the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations,
internally generated cash flows and other factors both within and outside our control. We actively review acquisition opportunities
on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt
financing, which we may not be able to obtain on terms acceptable to us or at all.
Cash flows provided by financing activities
Net cash provided by financing activities was $622.6 million, $212.4 million and $844.3 million for the years ended December
31, 2018, 2017 and 2016, respectively. For the year ended December 31, 2018, cash sourced through financing activities was
provided by the borrowings under our Revolving Credit Facilities, proceeds from the issuance of senior unsecured notes and net
proceeds from the sale of OMP common units (see Note 3 – Oasis Midstream Partners LP), net of offering costs, offset by
principal payments on our Revolving Credit Facilities and the repurchase of a portion of our Senior Notes. For the year ended
December 31, 2017, cash sourced through financing activities was provided by net proceeds from the issuance of our common
stock (see Note 16 – Common Stock), net of offering costs, and net proceeds from the sale of OMP common units (see Note 3 –
Oasis Midstream Partners LP), net of offering costs, partially offset by principal payments on our Revolving Credit Facilities. For
the year ended December 31, 2016, cash sourced through financing activities was provided by net proceeds from the issuance of
our common stock, the issuance of our Senior Convertible Notes and the borrowings under the Oasis Credit Facility, partially
offset by the repurchase of a portion of our Senior Notes.
Senior secured revolving line of credit. We have the Oasis Credit Facility, which has an overall senior secured line of credit of
$3,000.0 million as of December 31, 2018. The Oasis Credit Facility is restricted to a borrowing base, which is reserve-based and
subject to semi-annual redeterminations on April 1 and October 1 of each year. The maturity date of the Oasis Credit Facility is
the earlier of (i) October 16, 2023, (ii) 90 days prior to the maturity date of our 2022 and 2023 Senior Notes, of which $1,267.6
million is outstanding, to the extent such 2022 and 2023 Senior Notes are not retired or refinanced to have a maturity date at least
90 days after October 16, 2023 and (iii) 90 days prior to the maturity date of our 2023 Senior Convertible
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Notes (as defined below), of which $300.0 million is outstanding, to the extent such 2023 Senior Convertible Notes are not
retired, converted, redeemed or refinanced to have a maturity date at least 90 days after October 16, 2023.
On February 26, 2018, we entered into an amendment to the Oasis Credit Facility, resulting in the aggregate elected commitment
being increased from $1,150.0 million to $1,350.0 million and two new lenders being added to the bank group. On April 19,
2018, the lenders under the Oasis Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the
borrowing base scheduled for April 1, 2018, resulting in us entering into the Twelfth Amendment to the Second Amended and
Restated Credit Agreement to the Oasis Credit Facility, which (i) reaffirmed the borrowing base and the aggregate elected
commitment at $1,600.0 million and $1,350.0 million, respectively, (ii) removed the legacy anti-cash hoarding provisions,
(iii) reduced the coverage threshold with respect to mortgaged properties and (iv) amended the asset sale covenant to give
additional flexibility to trade oil and gas properties. In addition, in connection with such amendment, OP Permian became a
guarantor under the Oasis Credit Facility.
On October 16, 2018, we entered into a third amended and restated credit agreement (the “Third Amended Credit Facility”) for
the Oasis Credit Facility. In connection with entry into the Third Amended Credit Facility, the semi-annual redetermination of the
borrowing base was completed on October 16, 2018, which reaffirmed the borrowing base and the aggregate elected commitment
at $1,600.0 million and $1,350.0 million, respectively, and the overall credit facility increased from $2,500.0 million to $3,000.0
million. Pursuant to the Third Amended Credit Facility, the credit facility was extended from April 2020 to October 2023,
provided that our 2022 and 2023 Notes (as defined below) are retired or refinanced 90 days prior to their respective maturities.
All other significant rates, terms and conditions of the Third Amended Credit Facility remained the same. The next
redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2019.
As of December 31, 2018, the Oasis Credit Facility contains covenants that include, among others:
•
•
•
•
•
•
•
•
•
•
a prohibition against incurring debt, subject to permitted exceptions;
a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
a prohibition against making investments, loans and advances, subject to permitted exceptions;
restrictions on creating liens and leases on our assets and our subsidiaries, subject to permitted exceptions;
restrictions on merging and selling assets outside the ordinary course of business;
restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
a provision limiting oil and natural gas derivative financial instruments;
a requirement that we maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility) to
consolidated Interest Expense (as defined in the Oasis Credit Facility) of no less than 2.5 to 1.0 for the four quarters
ended on the last day of each quarter;
a requirement that we maintain a Current Ratio (as defined in the Oasis Credit Facility) of consolidated current
assets (including unused borrowing base committed capacity and with exclusions as described in the Oasis Credit
Facility) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility) of no less than
1.0 to 1.0 as of the last day of any fiscal quarter; and
if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility) exceed 85% of the effective
borrowing base (“Trigger”), we are required to maintain a ratio of total debt (as defined in the Oasis Credit Facility)
to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage Ratio will
be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be tested as long
as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and shall not exceed
4.25 to 1.00 for the first two quarters and 4.00 to 1.00 for each fiscal quarter thereafter.
The Oasis Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may
declare all amounts outstanding under the Oasis Credit Facility to be immediately due and payable.
As of December 31, 2018, we had $468.0 million of borrowings at a weighted average interest rate of 4.2% and $14.0 million of
outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of
$868.0 million. As of December 31, 2017, we had $70.0 million of borrowings at a weighted average interest rate of 3.1% and
$10.5 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base
committed capacity of $1,069.5 million. We were in compliance with the financial covenants of the Oasis Credit Facility as of
/
December 31, 2018 and 2017. Given the fluctuation in commodity prices, we continue to closely monitor our financial covenants
and do not anticipate a covenant violation in the next twelve months.
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OMP Operating LLC revolving line of credit. OMP has the OMP Credit Facility, which has an overall revolving credit facility of
$400.0 million as of December 31, 2018. The OMP Credit Facility has a maturity date of September 25, 2022 and is available to
fund working capital and to finance acquisitions and other capital expenditures of OMP.
On August 27, 2018, OMP entered into an amendment to its revolving credit facility (the “First Amended OMP Credit
Agreement”) in order to (i) increase the aggregate amount of commitments from $200.0 million to $250.0 million, (ii) provide for
the ability to further increase commitments and (iii) add six new lenders to the bank group. On November 19, 2018, in connection
with the OMP Dropdown (see Note 3 – Oasis Midstream Partners LP), and pursuant to the terms of the First Amended OMP
Credit Agreement, the aggregate amount of commitments increased from $250.0 million to $400.0 million, and OMP was
provided the ability to further increase the borrowing capacity for the OMP Credit Facility to $600.0 million, subject to certain
conditions.
The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. All
obligations of OMP Operating LLC, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and
several basis by OMP, OMP Operating LLC and Bighorn DevCo LLC.
The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated
total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as
described in the OMP Credit Agreement).
As of December 31, 2018, we had $318.0 million of borrowings outstanding at a weighted average interest rate of 4.2% under the
OMP Credit Facility, resulting in an unused borrowing base committed capacity of $82.0 million. As of December 31, 2017, we
had $78.0 million of borrowings outstanding at a weighted average interest rate of 3.2% under the OMP Credit Facility, resulting
in an unused borrowing base committed capacity of $122.0 million. OMP Operating LLC was in compliance with the financial
covenants of the OMP Credit Facility at December 31, 2018 and 2017.
Senior unsecured notes. As of December 31, 2018, our long-term debt includes outstanding senior unsecured note obligations of
$1,739.4 million for senior unsecured notes (the “Senior Notes”), including $71.8 million of 6.50% senior unsecured notes due
November 1, 2021 (the “2021 Notes”), $901.5 million of 6.875% senior unsecured notes due March 15, 2022 (the “2022 Notes”),
$366.1 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes”) and $400.0 million of 6.25% senior
unsecured notes due May 1, 2026 (the “2026 Notes”).
On May 14, 2018, we completed our offering of $400.0 million in aggregate principal amount of the 2026 Notes. We used the net
proceeds of $394.4 million from the 2026 Notes to fund the repurchase of certain outstanding senior notes (the “Tender Offers”),
as described below.
On May 25, 2018, we completed the Tender Offers and, as a result of the Tender Offers, we repurchased an aggregate principal
amount of $390.6 million of our outstanding Senior Notes, consisting of $31.3 million principal amount of the 7.25% senior
unsecured notes due 2019 (the “2019 Notes”), $323.7 million principal amount of the 2021 Notes and $35.6 million principal
amount of the 2022 Notes, for an aggregate cost of $402.0 million, including accrued interest and fees.
On May 29, 2018, we paid $23.0 million to redeem all of the remaining outstanding 2019 Notes, which payment consisted of
the 100% redemption price plus all accrued and unpaid interest on the 2019 Notes. We financed the redemption with borrowings
under the Oasis Credit Facility. As a result of the Tender Offers and the 2019 Notes redemption, we recognized a pre-tax loss
of $13.8 million, which was net of unamortized deferred financing costs write-offs of $4.0 million, and is reflected in loss on
extinguishment of debt in our Consolidated Statements of Operations for the year ended December 31, 2018. As of December 31,
2018, no 2019 Notes remained outstanding.
Prior to certain dates, we have the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to
a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the
redemption date. We may from time to time seek to retire or purchase our outstanding Senior Notes through cash purchases
and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise.
Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual
restrictions and other factors. The amounts involved may be material.
The indentures governing the Senior Notes restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional
debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make
certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company;
and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any
time when our Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings
Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and
we will cease to be subject to such covenants. We were in compliance with the terms of the indentures for the Senior Notes as of
December 31, 2018.
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Senior unsecured convertible notes. At December 31, 2018, we had $300.0 million of 2.625% senior unsecured convertible notes
due September 2023 (the “Senior Convertible Notes”). The Senior Convertible Notes will mature on September 15, 2023 unless
earlier converted in accordance with their terms.
We have the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common
stock at out election. Our intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to
March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar
quarter commencing after the calendar quarter ending on September 30, 2016 (and only during such calendar quarter), if the last
reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30
consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to
130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive
trading day period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible
Notes for each trading day of the Measurement Period is less than 98% of the product of the last reported sale price of our
common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or
after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day
immediately preceding the September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial
conversion rate of 76.3650 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial
conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be
adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date
or a notice of redemption, we will increase the conversion rate for a holder who elects to convert the Senior Convertible Notes in
connection with such corporate event or redemption in certain circumstances. As of December 31, 2018, none of the contingent
conditions allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, we were in
compliance with the terms of the indentures for the Senior Convertible Notes as of December 31, 2018.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The
Notes are guaranteed on a senior unsecured basis by our material subsidiaries.
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Obligations and commitments
We have the following contractual obligations and commitments as of December 31, 2018:
Contractual obligations
Senior unsecured notes(1)
Interest payments on senior unsecured notes(1)
Borrowings under Oasis Credit Facility(1)
Borrowings under OMP Credit Facility(1)
Interest payments on borrowings under Oasis
Credit Facility(1)
Interest payments on borrowings under OMP
Credit Facility(1)
Asset retirement obligations(2)
Drilling rig commitments
Operating leases(3)
Volume commitment agreements(3)
Total
Within 1
year
Payments due by period
1-3 years
3-5 years
(In thousands)
More than
5 years
$ 2,039,409 $
— $
71,835 $ 1,567,574 $
400,000
584,018
468,000
318,000
493
442
52,450
1,293
44,362
124,690
249,510
—
—
493
442
271
1,293
8,723
—
—
—
—
2,117
—
13,014
147,318
468,000
318,000
—
—
62,500
—
—
—
—
1,137
48,925
—
9,491
—
13,134
190,396
627,960
82,083
180,283
175,198
Total contractual cash obligations
$ 4,136,427 $
217,995 $
516,759 $ 2,686,718 $
714,955
__________________
(1)
See Note 12 to our consolidated financial statements for a description of our senior unsecured notes, Revolving Credit
Facilities and related interest payments. As of December 31, 2018, we had $468.0 million of borrowings and $14.0 million
of outstanding letters of credit issued under the Oasis Credit Facility and $318.0 million of borrowings under the OMP
Credit Facility.
(2)
Amounts represent the present value of estimated costs expected to be incurred in the future to plug, abandon and
remediate our oil and gas properties and produced and flowback water disposal wells at the end of their productive lives.
Because these costs typically extend many years into the future, estimating these future costs requires management to
make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of
inflation, changing technology and the political and regulatory environment. See Note 13 to our consolidated financial
statements.
(3)
See Note 20 to our consolidated financial statements for a description of our operating leases and volume commitment
agreements.
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our audited consolidated financial
statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements
requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and
related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an
extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or
if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on
historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial
statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments used in
preparation of our consolidated financial statements below. See Note 2 to our consolidated financial statements for a discussion of
additional accounting policies and estimates made by management.
Method of accounting for oil and natural gas properties
Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this
method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending
determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of
drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
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The provision for DD&A of oil and natural gas properties is calculated using the unit-of-production method. All capitalized well
costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved
developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel
equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production
DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of
estimated salvage values.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of
proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate in which case a
gain or loss is recognized currently.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as
incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts.
Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their
estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed
reserves.
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are
capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense
the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in our Consolidated
Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties
and depleted on a unit-of-production basis.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the
proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are
accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent reserve engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future
net revenues. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only
proved reserves in this Annual Report on Form 10-K. The SEC’s rules define proved reserves as the quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible
from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government
regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract
the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a
reasonable time. Our independent reserve engineers and technical staff must make a number of subjective assumptions based on
their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent
production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process
of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors,
including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or
geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and
natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions
are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may
be material.
Revenue recognition
In the first quarter of 2018, we adopted Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, and
a series of related accounting standards updates incorporated into GAAP as Accounting Standards Codification Topic 606 (“ASC
606”) using the modified retrospective method. The unit of account in ASC 606 is a performance obligation, which is a promise
in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods
or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of
consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to
be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue
when (point in time) or as (over time) the performance obligation is satisfied.
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Oil and gas revenues from our interests in producing wells are recognized when we satisfy a performance obligation by
transferring control of a product to a customer. Substantially all of our production is sold to purchasers under short-term (less than
twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other
related deductions. These deductions are based on contractual or historical data and do not require significant judgment.
Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a
ready market for oil and natural gas, we sell the majority of our production soon after it is produced at various locations. As a
result, we maintain a minimum amount of product inventory in storage.
Our purchased oil and gas sales are derived from the sale of oil and gas purchased from a third party. Revenues and expenses
from these sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming
control of the purchased oil or gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with
the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with
Accounting Standards Codification 845, Nonmonetary Transactions.
Midstream revenues consist of revenues from midstream services provided through OMS, including (i) crude oil gathering,
stabilization, blending, storage and transportation, (ii) natural gas gathering, gas lift, compression and processing, (iii) produced
and flowback water gathering and disposal and (iv) freshwater supply and distribution. Midstream revenues are earned through
fee-based arrangements, under which we receive fees for midstream services it provides to customers and recognizes revenue
based upon the transaction price at month-end under the right to invoice practical expedient, or through purchase arrangements,
under which we take control of the product prior to sale and act as the principal in the transaction, and therefore, recognize
revenues and expenses on a gross basis. Well services revenues result from well services, product sales and equipment rentals
provided by OWS primarily for OPNA’s operated wells. Midstream and well services revenues are recognized when services have
been performed or related volumes or products have been delivered. The revenues related to OPNA’s working interests are
eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in our
Consolidated Statements of Operations.
Impairment of proved properties
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in
the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil
and natural gas properties by field and compare such undiscounted future cash flows to the carrying amount of the oil and natural
gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the
estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value.
The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales
prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using
estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various
discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows
projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved
oil and natural gas properties will be recorded. Please see “Overview” for a discussion of potential future impairment charges.
Impairment of unproved properties
The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our
unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results
or future plans to develop acreage.
We recognize impairment expense for unproved properties at the time when the lease term has expired or sooner based on
management’s periodic assessments. We consider the following factors in our assessment of the impairment of unproved
properties:
•
•
•
•
•
the remaining amount of unexpired term under our leases;
our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend
leases that may be close to expiration;
our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and
development;
our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
our evaluation of the continuing successful results from the application of completion technology in the Bakken and
Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Delaware Basin
by us or by other operators in areas adjacent to or near our unproved properties.
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Business combinations
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for
identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and
integration costs associated with business combinations are expensed as incurred.
We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-
based measurement, it is determined based on the assumptions that market participants would use. The most significant
assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these
properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant
inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a
market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to
additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and
natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a
willing buyer and seller would enter into in exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the
estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase.
Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated
deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss
carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Asset retirement obligations
We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can
be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset.
For oil and gas properties, this is the period in which the well is drilled or acquired. The asset retirement obligation (“ARO”)
represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives,
in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are
amortized on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and
amortization in our Consolidated Statements of Operations.
Some of our midstream assets, including certain pipelines and our natural gas processing plants, have contractual or regulatory
obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned.
We are not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement
dates are indeterminable given our expected continued use of the assets with proper maintenance. We will record asset retirement
obligations for these assets in the periods in which the settlement dates are reasonably determinable.
We determine the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the
future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what
constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the
ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments. If actual results are not consistent with our assumptions and estimates or our
assumptions and estimates change due to new information, we may be exposed to future revisions, which could result in an
increase to the existing ARO liability and could ultimately result in a higher potential impact on our operations and cash flows for
settlement charges. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a
corresponding adjustment is made to the related asset.
Derivatives
We record all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated
fair value. The significant inputs used to estimate fair value are crude oil prices, volatility, skew, discount rate and the contract
terms of the derivative instruments. Derivative assets and liabilities arising from derivative contracts with the same counterparty
are reported on a net basis, as all counterparty contracts provide for net settlement. We have not designated any derivative
instruments as hedges for accounting purposes, and we do not enter into such instruments for speculative trading purposes. Gains
and losses from valuation changes in commodity derivative instruments are reported under other income (expense) in our
Consolidated Statements of Operations. Our cash flow is only impacted when the actual settlements under the derivative contracts
result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and
losses on our derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative
instruments that were settled. Cash settlements are reflected as investing activities in our Consolidated Statements of Cash Flows.
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Equity-based compensation
Restricted stock awards. We recognize compensation expense for all restricted stock awards made to employees and directors.
Equity-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as
expense on a straight-line basis over the requisite service period, which is generally the vesting period. The fair value of restricted
stock grants is based on the value of our common stock on the date of grant. Any such changes could result in different valuations
and thus impact the amount of equity-based compensation expense recognized. Equity-based compensation expense recorded for
restricted stock awards is included in general and administrative expenses on our Consolidated Statements of Operations.
Forfeitures associated with restricted stock awards granted are accounted for when they occur.
Performance share units. We recognize compensation expense for our performance share units (“PSUs”) granted to our officers.
The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlo simulation
model uses assumptions regarding random projections and must be repeated numerous times to achieve a probable assessment
(see Note 15 to our consolidated financial statements for a description of the inputs used in this model). Equity-based
compensation expense recorded for PSUs is included in general and administrative expenses on our Consolidated Statements of
Operations. Forfeitures associated with awards granted under PSUs are accounted for when they occur.
OMP Phantom Unit Awards. We recognize compensation expense for all OMP phantom unit awards (collectively, the “OMP
Phantom Unit Awards,” and each an “OMP Phantom Unit”) granted to employees. The OMP Phantom Unit Awards are accounted
for as liability-classified awards since the awards will settle in cash. The OMP Phantom Unit Awards vest in equal amounts each
year over a three-year period, and compensation expense will be recognized over the requisite service period and is included in
general and administrative expenses on the Company’s Consolidated Statements of Operations. Compensation cost is remeasured
each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay,
or will reimburse OMP, for the cash settlement amount of these awards. Forfeitures associated with awards granted under the
OMP LTIP are accounted for when they occur.
Income taxes
Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting
for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax
consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those
temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities
of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is
established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary
course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual
outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position,
results of operations and cash flows.
We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a
recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative
guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax
position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.
For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest
benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
Recent accounting pronouncements
Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which
established a right-of-use (“ROU”) model that requires a lessee to recognize an operating lease asset and lease liability on the
balance sheet, with the exception of short-term leases (as described below). Accounting Standards Codification 842, Leases
(“ASC 842”), was subsequently amended by Accounting Standards Update No. 2018-01, Land easement practical expedient for
transition to Topic 842 (“ASU 2018-01”); Accounting Standards Update No. 2018-10, Codification Improvements to Topic 842;
and Accounting Standards Update No. 2018-11, Targeted Improvements.
The new standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The effective
date and transition requirements for the amendments are the same as the effective date for ASU 2016-02. A modified
retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application. An
entity may choose to use either (i) its effective date or (ii) the beginning of the earliest comparative period presented in the
financial statements as its date of initial application.
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We will adopt the new standard as of January 1, 2019 using the required modified retrospective approach and plan to elect the
option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings
in the period of adoption, rather than recognizing in the earliest period presented. Prior period amounts will not be adjusted.
ASU 2018-01 provides a number of optional practical expedients in transition. We expect to elect the package of practical
expedients, which permits us not to reassess under the new standard prior conclusions about lease identification, lease
classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient pertaining to land easements,
which provides an option to not evaluate under ASC 842 existing or expired land easements that were previously accounted for as
leases under Accounting Standards Codification 840, Leases; and the practical expedient pertaining to combining lease and non-
lease components. In addition, under the new standard, an entity may elect not to apply the recognition requirements of ASC 842
to short-term leases, which are leases with terms of one year or less. We expect to make this election, and as such, recognition of
lease payments for short-term leases will be recognized in net income on a straight line basis.
We expect this new standard will have a material effect on the consolidated financial statements. While we continue to assess all
of the effects of adoption, we believe the most significant effects relate to (i) the recognition of new ROU assets and lease
liabilities on the consolidated balance sheet and (ii) providing significant new disclosures about our leasing activities. The new
ROU assets and lease liabilities, which will be recognized on the consolidated balance sheet, consist primarily of offices, man-
camps, rigs and vehicles.
We plan to modify our business processes and controls to support the adoption of the new standard, including implementing a
new lease accounting software to assess the portfolio of leases, assist in the quantification of the expected impact on the
consolidated financial statements and facilitate the calculations of the related accounting entries and disclosures. We do not expect
a significant change in leasing activities as a result of this adoption.
Financial instruments. In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement
(Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”),
which improves the effectiveness of the disclosure requirements for fair value measurements. The changes affect all companies
that are required to include fair value measurement disclosures. ASU 2018-13 is effective for fiscal years beginning after
December 15, 2019, including interim periods within those years. An entity is permitted to early adopt the removed or modified
disclosures upon the issuance of ASU 2018-13 and may delay adoption of the additional disclosures until their effective date. We
do not expect the adoption of this guidance to have an impact on our financial position, cash flows or results of operations, but it
may result in changes to our disclosures.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of
operations for the years ended December 31, 2018, 2017 and 2016. Although the impact of inflation has been insignificant in
recent years, it is still a factor in the United States economy, and in the past, we have tended to experience inflationary pressure on
the cost of midstream and oilfield services and equipment as increasing oil and natural gas prices increased drilling activity in our
areas of operations. We expect service costs to increase in 2018 due to higher demand resulting from the recent improvement in
oil prices.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter
into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated
financial statements in accordance with GAAP. See “Obligations and commitments” above and Note 20 to our consolidated
financial statements for a description of our commitments and contingencies.
Non-GAAP Financial Measures
E&P Cash G&A, Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and
Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share are supplemental non-GAAP financial measures that are used
by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
These non-GAAP measures should not be considered in isolation or as a substitute for interest expense, net income (loss),
operating income (loss), net cash provided by (used in) operating activities, earnings (loss) per share or any other measures
prepared under GAAP. Because Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to
Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share exclude some but not all items that affect net income
(loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.
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E&P Cash G&A
We define E&P Cash G&A as the total general and administrative expenses included in our exploration and production segment
less non-cash equity-based compensation expenses included in our exploration and production segment. E&P Cash G&A is not a
measure of general and administrative expenses as determined by GAAP. Management believes that the presentation of E&P
Cash G&A provides useful additional information to investors and analysts to assess our operating costs in comparison to peers
without regard to equity-based compensation programs, which can vary substantially from company to company.
The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses included in
our exploration and production segment to the non-GAAP financial measure of E&P Cash G&A for the periods presented:
Exploration and Production
Year Ended December 31,
2018
2017
2016
(In thousands)
$
$
102,482 $
(27,910)
74,572 $
77,560 $
(25,436)
52,124 $
78,995
(23,346)
55,649
General and administrative expenses
Equity-based compensation expenses
E&P Cash G&A
Cash Interest
We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs
and debt discounts included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP.
Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for
assessing the interest charges incurred on our debt, excluding non-cash amortization, and our ability to maintain compliance with
our debt covenants.
The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial
measure of Cash Interest for the periods presented:
Interest expense
Capitalized interest
Amortization of deferred financing costs
Amortization of debt discount
Cash Interest
Adjusted EBITDA and Free Cash Flow
Year Ended December 31,
2018
2017
2016
$
$
(In thousands)
159,085 $
146,837
$
17,226
(7,590)
(11,120)
12,797
(6,907)
(10,080)
140,305
16,848
(9,757)
(2,709)
157,601 $
142,647 $
144,687
We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other
similar non-cash or nonrecurring charges. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by
GAAP. Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and
analysts for assessing our results of operations, financial performance and our ability to generate cash from our business
operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our
debt covenants.
We define Free Cash Flow as Adjusted EBITDA less Cash Interest and capital expenditures, excluding capitalized interest. Free
Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the
presentation of Free Cash Flow provides useful additional information to investors and analysts for assessing our financial
performance as compared to our peers and our ability to generate cash from our business operations after interest and capital
spending. In addition, Free Cash Flow excludes changes in operating assets and liabilities that relate to the timing of cash receipts
and disbursements, which we may not control, and changes in operating assets and liabilities may not relate to the period in which
the operating activities occurred.
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The following table presents reconciliations of the GAAP financial measures of net income (loss) including non-controlling
interests and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Free Cash
Flow for the periods presented:
Net income (loss) including non-controlling interests
$
(19,500) $
127,446
$
(243,016)
Year Ended December 31,
2018
2017
(In thousands)
2016
(Gain) loss on sale of properties
(Gain) loss on extinguishment of debt
Net (gain) loss on derivative instruments
Derivative settlements(1)
Interest expense, net of capitalized interest
Depreciation, depletion and amortization
Impairment
Exploration expenses
Equity-based compensation expenses
Income tax benefit
Other non-cash adjustments
Adjusted EBITDA
Adjusted EBITDA attributable to non-controlling interests
Adjusted EBITDA attributable to Oasis
Cash Interest
Capital expenditures(2)
Capitalized interest
Free Cash Flow
Net cash provided by operating activities
Derivative settlements(1)
Interest expense, net of capitalized interest
Exploration expenses
Deferred financing costs amortization and other
Current tax expense
Changes in working capital
Other non-cash adjustments
Adjusted EBITDA
Adjusted EBITDA attributable to non-controlling interests
Adjusted EBITDA attributable to Oasis
Cash Interest
Capital expenditures(2)
Capitalized interest
Free Cash Flow
(28,587)
13,848
(28,457)
(213,528)
159,085
636,296
384,228
27,432
29,273
(5,843)
4,435
958,682
21,703
936,979
(157,601)
(2,203,453)
17,226
(1,774)
—
71,657
(8,264)
146,837
530,802
6,887
11,600
26,534
(203,304)
(745)
707,676
3,904
703,772
(142,647)
(836,204)
12,797
1,303
(4,741)
105,317
121,977
140,305
476,331
4,684
1,785
24,103
(128,538)
790
500,300
—
500,300
(144,687)
(1,181,527)
16,848
$
$
(1,406,849) $
(262,282) $
(809,066)
996,421 $
507,876
$
(213,528)
159,085
27,432
(29,057)
23
13,871
4,435
958,682
21,703
936,979
(157,601)
(2,203,453)
17,226
(8,264)
146,837
11,600
(18,311)
(421)
69,104
(745)
707,676
3,904
703,772
(142,647)
(836,204)
12,797
228,018
121,977
140,305
1,785
(14,334)
—
21,759
790
500,300
—
500,300
(144,687)
(1,181,527)
16,848
$
(1,406,849) $
(262,282) $
(809,066)
____________________
(1)
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do
not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)
Capital expenditures (including acquisitions) reflected in the table above differ from the amounts shown in the statements
of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued
liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash
flows are presented on a cash basis. Acquisitions totaled $951.9 million, $54.0 million and $781.5 million for the years
ended December 31, 2018, 2017 and 2016, respectively. In addition, capital expenditures
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(including acquisitions) reflected in the table includes consideration paid through the issuance of common stock in
connection with the Permian Basin Acquisition for the year ended December 31, 2018. See Note 10 to our consolidated
financial statements for more information on the Permian Basin Acquisition.
The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes including non-
controlling interests to the non-GAAP financial measure of Adjusted EBITDA for our three reportable business segments on a
gross basis for the periods presented:
Exploration and Production
Year Ended December 31,
2018
2017
2016
(In thousands)
Loss before income taxes including non-controlling interests
$
(167,292) $
(179,129) $
(436,469)
(Gain) loss on sale of properties
(Gain) loss on extinguishment of debt
Net (gain) loss on derivative instruments
Derivative settlements(1)
Interest expense, net of capitalized interest
Depreciation, depletion and amortization
Impairment
Exploration expenses
Equity-based compensation expenses
Other non-cash adjustments
Adjusted EBITDA
(38,188)
13,848
(28,457)
(213,528)
156,742
618,402
384,228
27,432
27,910
4,331
(1,774)
—
71,657
(8,264)
146,818
519,853
6,887
11,600
25,436
(812)
1,661
(4,741)
105,317
121,977
140,305
467,894
2,253
1,785
23,346
718
$
785,428 $
592,272 $
424,046
____________________
(1)
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do
not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Midstream Services
Year Ended December 31,
2018
2017
2016
(In thousands)
Income before income taxes including non-controlling interests $
141,001 $
102,340 $
68,394
(Gain) loss on sale of properties
Interest expense, net of capitalized interest
Depreciation, depletion and amortization
Impairment
Equity-based compensation expenses
Other non-cash adjustments
9,622
2,343
29,282
—
1,547
—
—
19
15,999
—
1,461
—
(358)
—
8,525
2,431
911
10
Adjusted EBITDA
$
183,795
$
119,819
$
79,913
Well Services
Year Ended December 31,
2018
2017
2016
(In thousands)
Income before income taxes including non-controlling interests $
31,023 $
15,091 $
Depreciation, depletion and amortization
Equity-based compensation expenses
Other non-cash adjustments
15,698
1,588
104
12,939
1,264
67
Adjusted EBITDA
$
48,413 $
29,361 $
85
3,471
14,892
1,515
62
19,940
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Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share
We define Adjusted Net Income (Loss) Attributable to Oasis as net income (loss) after adjusting for (1) the impact of certain non-
cash items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash charges,
or non-recurring items, (2) the impact of net income attributable to non-controlling interests and (3) the non-cash and non-
recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items, excluding net income
attributable to non-controlling interests, in the same period. Adjusted Net Income (Loss) Attributable to Oasis is not a measure of
net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share as
Adjusted Net Income (Loss) Attributable to Oasis divided by diluted weighted average shares outstanding. Adjusted Diluted
Earnings (Loss) Attributable to Oasis Per Share is not a measure of diluted earnings (loss) as determined by GAAP. Management
believes that the presentation of Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss)
Attributable to Oasis Per Share provides useful additional information to investors and analysts for evaluating our operational
trends and performance in comparison to our peers. This measure is more comparable to earnings estimates provided by securities
analysts, and charges or amounts excluded cannot be reasonably estimated and are excluded from guidance provided by us.
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The following table presents reconciliations of the GAAP financial measure of net income (loss) attributable to Oasis to the non-
GAAP financial measure of Adjusted Net Income (Loss) Attributable to Oasis and the GAAP financial measure of diluted
earnings (loss) attributable to Oasis per share to the non-GAAP financial measure of Adjusted Diluted Earnings (Loss)
Attributable to Oasis Per Share for the periods presented:
Net income (loss) attributable to Oasis
$
(35,296)
$
123,796
$
(243,016)
Year Ended December 31,
2018
2017
2016
(In thousands, except per share data)
Tax reform rate change adjustments
(Gain) loss on sale of properties
(Gain) loss on extinguishment of debt
Net (gain) loss on derivative instruments
Derivative settlements(1)
Impairment
Amortization of deferred financing costs
Amortization of debt discount
Other non-cash adjustments
Tax impact(2)
Adjusted Net Income (Loss) Attributable to Oasis
Diluted earnings (loss) attributable to Oasis per share
$
$
Tax reform rate change adjustments
(Gain) loss on sale of properties
(Gain) loss on extinguishment of debt
Net (gain) loss on derivative instruments
Derivative settlements(1)
Impairment
Amortization of deferred financing costs
Amortization of debt discount
Other non-cash adjustments
Tax impact(2)
—
(28,587)
13,848
(28,457)
(213,528)
384,228
7,591
11,120
4,435
(35,759)
(171,900)
(1,774)
—
71,657
(8,264)
6,887
6,907
10,080
(745)
(31,696)
79,595
$
4,948
$
(0.11)
$
—
(0.09)
0.04
(0.09)
(0.69)
1.24
0.02
0.04
0.01
(0.11)
0.52
$
(0.72)
(0.01)
—
0.30
(0.03)
0.03
0.03
0.04
—
(0.14)
Adjusted Diluted Earnings (Loss) Attributable to Oasis Per
Share
$
0.26
$
0.02
$
—
1,303
(4,741)
105,317
121,977
4,684
9,757
2,709
790
(90,480)
(91,700)
(1.32)
—
0.01
(0.03)
0.57
0.66
0.03
0.05
0.01
—
(0.48)
(0.50)
Diluted weighted average shares outstanding(3)
310,860
237,875
183,615
Effective tax rate applicable to adjustment items
____________________
(1)
Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do
not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
23.7%
37.4%
37.4%
(2)
The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-
recurring items. The tax impact was not computed for the tax reform rate change adjustments.
(3) We included 3,379,000 and 2,889,000 of unvested stock awards for the years ended December 31, 2018 and 2017,
respectively, in computing Adjusted Diluted Income Attributable to Oasis Per Share due to the dilutive effect under the
treasury stock method. No unvested stock awards were included in computing Adjusted Diluted Loss Attributable to Oasis
Per Share for the year ended December 31, 2016 because the effect was anti-dilutive due to Adjusted Net Loss
Attributable to Oasis.
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk.
We address these risks through a program of risk management, including the use of derivative instruments.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about
our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas,
natural gas liquids, and oil prices, and interest rates. The disclosures are not meant to be precise indicators of expected future
losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view
and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging
purposes, rather than for speculative trading.
Commodity price exposure risk. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes
in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into
derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our
future production.
We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. Our crude oil contracts
will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”), the average
Intercontinental Exchange, Inc. Brent crude oil index price (“ICE Brent”), the average Argus WTI Midland crude oil index price
(“Midland”) and the average Argus WTI Houston crude oil index price. Our natural gas contracts will settle monthly based on the
average NYMEX Henry Hub natural gas index price (“NYMEX HH”) and the average Inside FERC Northern Natural Gas
Ventura natural gas index price (“IF NNG Ventura”).
As of December 31, 2018, we utilized fixed price swaps, basis swaps and two-way and three-way costless collars to reduce the
volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. Our fixed price
swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor), which we will
receive for the volumes under contract. A basis swap transaction has an established fixed basis differential corresponding to two
floating index prices. Depending on the difference of the two floating index prices in relation to the fixed basis differential, we
either receive an amount from its counterparty, or pay an amount to its counterparty, equal to the difference multiplied by the
contract volume. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a
minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A
three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a
minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be
the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a
maximum price (ceiling) we will receive for the volumes under contract.
We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the
fair value amounts recognized on our Consolidated Balance Sheets. Derivative assets and liabilities arising from our derivative
contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement.
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The following is a summary of our outstanding commodity derivative instruments as of December 31, 2018:
Commodity
Settlement
Period
Derivative
Instrument
Index
Volumes
Weighted Average Prices
Fixed
Price
Swaps
Basis
Swaps
Sub-
Floor
Floor
Ceiling
Fair Value
Assets
(Liability)
(In thousands)
Crude oil
2019
Crude oil
2019
Crude oil
2019
Crude oil
2019
Crude oil
2019
Crude oil
2020
Crude oil
2020
Crude oil
2020
Natural
gas
Natural
gas
2019
2019
Fixed
price
swaps
Basis
swaps
Basis
swaps
Two-way
collars
Three-way
collars
Fixed
price
swaps
Two-way
collars
Three-way
collars
Fixed
price
swaps
Basis
swaps
NYMEX WTI
5,690,500
Bbl
$ 53.63
$
33,827
NYMEX WTI-
ICE BRENT
Midland-
NYMEX WTI
424,000 Bbl
605,000 Bbl
$ (9.68)
$ (7.19)
NYMEX WTI
3,937,500 Bbl
$ 58.47 $ 77.03
NYMEX WTI
3,702,000 Bbl
$ 40.49 $ 50.94 $ 67.97
NYMEX WTI
403,000
Bbl
$ 53.47
NYMEX WTI
341,000 Bbl
$ 58.18 $ 77.65
NYMEX WTI
310,000 Bbl
$ 40.00 $ 50.50 $ 67.10
NYMEX HH
6,446,000
MMBtu
$ 3.15
IF NNG
VENTURA-
NYMEX HH
4,525,000
MMBtu
$ 0.02
673
(865)
48,320
16,528
1,928
3,982
1,035
1,303
40
$
106,771
A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $46.3 million, while
a 10% decrease in crude oil prices would increase the fair value by approximately $47.7 million.
Interest rate risk. At December 31, 2018, we had (i) $71.8 million of senior unsecured notes at a fixed cash interest rate of 6.50%
per annum, (ii) $1,267.6 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum, (iii) $300.0 million
of senior unsecured convertible notes at a fixed cash interest rate of 2.625% per annum outstanding and (iv) $400.0 million of
senior unsecured notes at a fixed cash interest rate of 6.25% per annum.
At December 31, 2018, we had $468.0 million of borrowings and $14.0 million of outstanding letters of credit issued under the
Oasis Credit Facility, which were subject to varying rates of interest based on (i) the total outstanding borrowings (including the
value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a LIBOR loan or a domestic
bank prime interest rate loan (defined in each of the Revolving Credit Facilities as an Alternate Based Rate or “ABR” loan). At
December 31, 2018, the outstanding borrowings under the Oasis Credit Facility bore interest at LIBOR plus a 1.75% margin. On
a quarterly basis, we also pay a commitment fee that can range from 0.375% to 0.500% on the average amount of borrowing base
capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during
the quarter.
At December 31, 2018, we had $318.0 million of borrowings issued under the OMP Credit Facility, which were subject to a per
annum interest rate equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted
LIBO Rate (as defined in the OMP Credit Agreement) or (ii) with respect to ABR loans, the greatest of (A) the Prime Rate in
effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate
for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Agreement). The applicable margin
for borrowings under the OMP Credit Facility is based on OMP’s most recently tested consolidated total leverage ratio and varies
from (a) in the case of Eurodollar Loans, 1.75% to 2.75%, and (b) in the case of ABR loans or swingline loans, 0.75% to 1.75%.
The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%. At December 31,
2018, the outstanding borrowings under the OMP Credit Facility bore interest at LIBOR plus a 1.75% margin.
We do not currently, but may in the future, utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce
interest rate expense related to debt issued under the Oasis Credit Facility or the OMP Credit Facility. Interest rate derivatives
would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
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Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells
we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We
have limited ability to control participation in our wells. For the year ended December 31, 2018, we recorded $1.5 million in bad
debt expense as a result of our assessment that it is probable certain receivables may not be collected. We are also subject to credit
risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our
significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We monitor our exposure to counterparties on oil and natural gas sales primarily by reviewing credit ratings, financial statements
and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not
generally required our counterparties to provide collateral to secure oil and natural gas sales receivables owed to us. Historically,
our credit losses on oil and natural gas sales receivables have been immaterial.
In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by
counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with
counterparties that are high credit-quality financial institutions. Most of the counterparties on our derivative instruments currently
in place are Lenders under the Oasis Credit Facility with investment grade ratings. We are likely to enter into any future
derivative instruments with these or other Lenders under the Oasis Credit Facility, which also carry investment grade ratings. This
risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under
individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting
provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts
due to and from the counterparties under the derivative contracts. We had a net derivative asset position of $106.9 million and a
net derivative liability position of $0.1 million at December 31, 2018.
As permitted under our investments policy, we may purchase commercial paper instruments from high credit quality
counterparties. These counterparties may include issuers in a variety of industries including the domestic and foreign financial
sector. This risk is managed by our investment policy including minimum credit ratings thresholds and maximum counterparty
exposure values. Although we do not anticipate any of our commercial paper issuers failing to pay us upon maturity, we take a
risk in purchasing the commercial paper instruments available in the marketplace. If an issuer fails to repay us at maturity from
commercial paper proceeds, it could take a significant amount of time to recover a portion of or all of the assets originally
invested. Our commercial paper balance was $36,000 at December 31, 2018.
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Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2018 and December 31, 2017
Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
1. Organization and Operations of the Company
2. Summary of Significant Accounting Policies
3. Oasis Midstream Partners LP
4. Revenue Recognition
5. Inventory
6. Additional Balance Sheet Information
7. Fair Value Measurements
8. Derivative Instruments
9. Property, Plant and Equipment
10. Acquisitions
11. Divestitures
12. Long-Term Debt
13. Asset Retirement Obligations
14. Income Taxes
15. Equity-Based Compensation
16. Common Stock
17. Earnings (Loss) Per Share
18. Business Segment Information
19. Significant Concentrations
20. Commitments and Contingencies
21. Subsequent Events
22. Condensed Consolidating Financial Information
23. Supplemental Oil and Gas Disclosures
24. Supplemental Oil and Gas Reserve Information — Unaudited
25. Quarterly Financial Data — Unaudited
91
92
94
95
96
97
98
98
108
109
114
114
115
116
119
120
122
123
127
127
129
132
132
133
135
136
138
139
148
149
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Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Oasis Petroleum Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Oasis Petroleum Inc. and its subsidiaries (the “Company”) as
of December 31, 2018 and 2017, and the related consolidated statements of operations, changes in stockholders’ equity, and cash
flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as
the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of
December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position
of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of
America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial
reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
COSO because a material weakness in internal control over financial reporting existed as of that date related to the ineffective
design and maintenance of controls over the presentation and disclosure of certain crude oil purchase and sale arrangements
included in oil and gas revenue, purchased oil and gas sales and purchased oil and gas expenses and the related accounts
receivable and accrued liabilities accounts.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there
is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or
detected on a timely basis. The material weakness referred to above is described in Management's report on internal control over
financial reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent
of audit tests applied in our audit of the 2018 consolidated financial statements, and our opinion regarding the effectiveness of the
Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in
Management's report referred to above. Our responsibility is to express opinions on the Company’s consolidated financial
statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm
registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent
with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material
respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of
the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as
well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.
Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our
audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of
the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the
92
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company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2019
We have served as the Company’s auditor since 2007.
93
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Oasis Petroleum Inc.
Consolidated Balance Sheets
$
$
$
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable, net
Inventory
Prepaid expenses
Derivative instruments
Intangible assets, net
Other current assets
Total current assets
Property, plant and equipment
Oil and gas properties (successful efforts method)
Other property and equipment
Less: accumulated depreciation, depletion, amortization and
impairment
Total property, plant and equipment, net
Derivative instruments
Long-term inventory
Other assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable
Revenues and production taxes payable
Accrued liabilities
Accrued interest payable
Derivative instruments
Advances from joint interest partners
Other current liabilities
Total current liabilities
Long-term debt
Deferred income taxes
Asset retirement obligations
Derivative instruments
Other liabilities
Total liabilities
Commitments and contingencies (Note 20)
Stockholders’ equity
Common stock, $0.01 par value: 900,000,000 and 450,000,000
shares authorized at December 31, 2018 and December 31, 2017,
respectively; 320,469,049 shares issued and 318,377,161 shares
outstanding at December 31, 2018 and 270,627,014 shares issued
and 269,295,466 shares outstanding at December 31, 2017
Treasury stock, at cost: 2,091,888 and 1,331,548 shares at
December 31, 2018 and December 31, 2017, respectively
Additional paid-in capital
December 31,
2018
2017
(In thousands, except share data)
22,190 $
387,602
33,128
10,997
99,930
125
183
554,155
8,912,189
1,151,772
(3,036,852)
7,027,109
6,945
12,260
25,673
16,720
371,379
19,367
7,631
344
—
193
415,634
7,838,955
868,746
(2,534,215)
6,173,486
9
12,200
21,600
7,626,142 $
6,622,929
20,166 $
216,695
331,651
38,040
84
5,140
—
611,776
2,735,276
300,055
52,384
20
7,751
13,370
213,995
244,279
38,963
115,716
4,916
40
631,279
2,097,606
305,921
48,511
19,851
6,182
3,707,262
3,109,350
3,157
2,668
(29,025)
3,077,755
(22,179)
2,677,217
/
Retained earnings
Oasis share of stockholders’ equity
Non-controlling interests
Total stockholders’ equity
682,689
3,734,576
184,304
3,918,880
Total liabilities and stockholders’ equity
$
7,626,142 $
The accompanying notes are an integral part of these consolidated financial statements.
717,985
3,375,691
137,888
3,513,579
6,622,929
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Oasis Petroleum Inc.
Consolidated Statements of Operations
Revenues
Oil and gas revenues
Purchased oil and gas sales
Midstream revenues
Well services revenues
Total revenues
Operating expenses
Lease operating expenses
Midstream operating expenses
Well services operating expenses
Marketing, transportation and gathering expenses
Purchased oil and gas expenses
Production taxes
Depreciation, depletion and amortization
Exploration expenses
Impairment
General and administrative expenses
Total operating expenses
Gain (loss) on sale of properties
Operating income (loss)
Other income (expense)
Net gain (loss) on derivative instruments
Interest expense, net of capitalized interest
Gain (loss) on extinguishment of debt
Other income (expense)
Total other expense
Loss before income taxes
Income tax benefit
Year Ended December 31,
2018
2017
2016
(In thousands, except per share data)
$
1,590,024 $
1,034,634 $
625,233
551,808
119,040
61,075
133,542
72,752
52,791
2,321,947
1,293,719
193,912
31,912
41,200
107,193
554,307
133,696
636,296
27,432
384,228
121,346
177,134
17,589
37,228
55,740
134,615
88,133
530,802
11,600
6,887
91,797
2,231,522
1,151,525
28,587
119,012
28,457
(159,085)
(13,848)
121
1,774
143,968
(71,657)
(146,837)
—
(1,332)
(144,355)
(219,826)
(25,343)
5,843
(19,500)
15,796
(75,858)
203,304
127,446
3,650
10,272
35,406
33,754
704,665
135,444
9,003
20,675
30,108
10,258
56,565
476,331
1,785
4,684
89,342
834,195
(1,303)
(130,833)
(105,317)
(140,305)
4,741
160
(240,721)
(371,554)
128,538
(243,016)
—
(35,296) $
123,796 $
(243,016)
(0.11) $
(0.11)
0.53 $
0.52
307,480
234,986
(1.32)
(1.32)
183,615
183,615
/
Net income (loss) including non-controlling interests
Less: Net income attributable to non-controlling interests
Net income (loss) attributable to Oasis
Earnings (loss) attributable to Oasis per share:
Basic (Note 17)
Diluted (Note 17)
Weighted average shares outstanding:
Basic (Note 17)
$
$
Diluted (Note 17)
237,875
The accompanying notes are an integral part of these consolidated financial statements.
307,480
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Table of Contents
Oasis Petroleum Inc.
Consolidated Statements of Changes in Stockholders’ Equity
Attributable to Oasis
Common Stock
Treasury Stock
Shares
Amount
Shares
Amount
Additional
Paid-in-
Capital
Retained
Earnings
(Deficit)
Non-
controlling
Interests
Total
Stockholders’
Equity
(In thousands)
Balance as of December 31, 2015 139,076 $
1,376
508 $ (13,620) $ 1,497,065 $ 834,521 $
— $ 2,319,342
Issuance of common stock, net of
offering costs
94,300
943
—
—
765,727
Equity-based compensation
3,317
12
—
—
25,759
Equity component of senior
unsecured convertible notes, net
Treasury stock - tax withholdings
Net loss
—
(349)
—
—
—
—
—
—
56,720
349
—
(2,330)
—
—
—
—
—
—
—
(243,016)
Balance as of December 31, 2016 236,344
2,331
857
(15,950)
2,345,271
591,505
Cumulative-effect adjustment for
adoption of ASU 2016-09 (Note
14)
Fees (2016 issuance of common
stock)
Issuance of common stock, net of
offering costs
—
—
—
—
32,000
320
—
—
—
—
—
—
2,040
2,684
(55)
301,871
—
—
—
766,670
—
—
—
—
—
—
—
—
25,771
56,720
(2,330)
(243,016)
2,923,157
4,724
(55)
302,191
Equity-based compensation
1,426
17
—
—
28,090
—
53
28,160
Issuance of Oasis Midstream
common units, net of offering
costs
Treasury stock - tax withholdings
Net income
—
—
—
—
(475)
—
—
—
475
—
(6,229)
—
—
—
—
—
134,185
134,185
—
—
(6,229)
123,796
3,650
127,446
Balance as of December 31, 2017 269,295
2,668
1,332
(22,179)
2,677,217
717,985
137,888
3,513,579
Permian Basin Acquisition
issuance
Other (2017 issuance of common
stock and Oasis Midstream
common units)
46,000
460
—
—
—
—
—
—
370,760
(881)
—
—
—
371,220
(125)
(1,006)
Equity-based compensation
3,842
29
—
—
30,659
—
356
31,044
Issuance of Oasis Midstream
common units, net of offering
costs
Distributions to non-controlling
interest owners
Treasury stock - tax withholdings
Net income (loss)
—
—
—
—
—
—
—
—
(760)
—
—
—
760
—
(6,846)
—
—
—
—
—
—
—
44,503
44,503
(14,114)
(14,114)
—
—
(35,296)
15,796
(6,846)
(19,500)
Balance as of December 31, 2018 318,377 $
3,157
2,092 $ (29,025) $ 3,077,755 $ 682,689 $ 184,304 $ 3,918,880
The accompanying notes are an integral part of these consolidated financial statements.
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Oasis Petroleum Inc.
Consolidated Statements of Cash Flows
Cash flows from operating activities:
Net income (loss) including non-controlling interests
$
(19,500) $
127,446 $
(243,016)
Adjustments to reconcile net income (loss) including non-controlling
interests to net cash provided by operating activities:
Year Ended December 31,
2018
2017
2016
(In thousands)
Depreciation, depletion and amortization
(Gain) loss on extinguishment of debt
(Gain) loss on sale of properties
Impairment
Deferred income taxes
Derivative instruments
Equity-based compensation expenses
Deferred financing costs amortization and other
Working capital and other changes:
Change in accounts receivable, net
Change in inventory
Change in prepaid expenses
Change in other current assets
Change in long-term inventory and other assets
Change in accounts payable, interest payable and accrued
liabilities
Change in other current liabilities
Change in other liabilities
636,296
13,848
(28,587)
384,228
(5,866)
(28,457)
29,273
29,057
(23,508)
(14,346)
(2,354)
10
(144)
530,802
—
(1,774)
6,887
(202,884)
71,657
26,534
18,311
(166,386)
(2,501)
(838)
148
(12,143)
476,331
(4,741)
1,303
4,684
(128,538)
105,317
24,103
14,334
(11,923)
254
(295)
(305)
(151)
26,116
123,107
(13,839)
(40)
395
(10,450)
(40)
4,490
10
Net cash provided by operating activities
996,421
507,876
228,018
Cash flows from investing activities:
Capital expenditures
Acquisitions
Proceeds from sale of properties
Costs related to sale of properties
Derivative settlements
Advances from joint interest partners
(1,148,961)
(581,650)
333,229
(2,850)
(213,528)
224
(647,349)
(61,874)
5,774
(366)
(8,264)
(2,681)
(426,256)
(781,522)
12,333
(310)
121,977
2,950
Net cash used in investing activities
(1,613,536)
(714,760)
(1,070,828)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities
3,224,000
1,162,000
1,407,000
Principal payments on Revolving Credit Facilities
(2,586,000)
(1,377,000)
(1,182,000)
Repurchase of senior unsecured notes
Proceeds from issuance of senior unsecured notes
Deferred financing costs
Proceeds from sale of common stock, net of offering costs
Proceeds from sale of Oasis Midstream common units, net of
offering costs
Purchases of treasury stock
Distributions to non-controlling interests
Other
Net cash provided by financing activities
Increase in cash and cash equivalents
Cash and cash equivalents:
(423,340)
400,000
(13,862)
—
—
—
(2,714)
302,191
(435,907)
300,000
(9,127)
766,670
44,503
134,185
—
(6,846)
(14,114)
(1,756)
622,585
5,470
(6,229)
(2,330)
—
(55)
—
—
212,378
844,306
5,494
1,496
/
Beginning of period
End of period
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest
Cash paid for income taxes
Cash received for income tax refunds
Supplemental non-cash transactions:
Change in accrued capital expenditures
Change in asset retirement obligations
Note receivable from divestiture
Installment notes from acquisition
16,720
11,226
22,190 $
16,720 $
9,730
11,226
141,196 $
129,463 $
138,248
38
25
12
281
—
5
68,946 $
83,508 $
(43,415)
$
$
$
3,880
—
—
(789)
—
4,875
—
3,810
4,000
—
—
Issuance of shares in connection with the Permian Basin Acquisition
371,220
The accompanying notes are an integral part of these consolidated financial statements.
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Oasis Petroleum Inc.
Notes to Consolidated Financial Statements
1. Organization and Operations of the Company
Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and
was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and
production company focused on the acquisition and development of onshore, unconventional oil and natural gas resources in the
United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct the
Company’s exploration and production activities and own its proved and unproved oil and natural gas properties located in the
North Dakota and Montana regions of the Williston Basin and the Texas region of the Delaware Basin, respectively.
The Company also operates a midstream services business through OMS Holdings LLC (“OMS”) and a well services business
through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to
the Company’s primary development and production activities. The midstream services business is conducted by Oasis
Midstream Partners LP (“OMP” or “Oasis Midstream”), which completed an initial public offering on September 25, 2017. The
Company owns the general partner and a majority of the outstanding units of OMP.
2. Summary of Significant Accounting Policies
Basis of Presentation
Consolidation. The accompanying consolidated financial statements of the Company include the accounts of Oasis, the accounts
of its wholly owned subsidiaries, and the accounts of OMP, which is a subsidiary of OMS and is considered a variable interest
entity (“VIE”) for which the Company is the primary beneficiary. All intercompany balances and transactions have been
eliminated upon consolidation. These statements have been prepared in accordance with accounting principles generally accepted
in the United States of America (“GAAP”). Certain reclassifications of prior year balances have been made to conform such
amounts to current year classifications. These reclassifications have no impact on net income.
In the third quarter of 2017, OMP completed its initial public offering (“IPO”) of common units representing limited partner
interests. As a result, the Company’s consolidated financial statements present a non-controlling interest section, which represents
the public’s ownership in OMP. See Note 3 – Oasis Midstream Partners LP for further discussion of the OMP IPO.
Consolidated VIE. The Company has determined that the partners with equity at risk in OMP lack the authority, through voting
rights or similar rights, to direct the activities that most significantly impact OMP’s economic performance. Therefore, as the
limited partners of OMP do not have substantive kick-out or substantive participating rights over OMP GP LLC (“OMP GP”), the
general partner to OMP, OMP is a VIE. Through the Company’s ownership interest in OMP GP, the Company has the authority
to direct the activities that most significantly affect economic performance and the right to receive benefits that could be
potentially significant to OMP. Therefore, the Company is considered the primary beneficiary and consolidates OMP and records
a non-controlling interest for the interest owned by the public as of December 31, 2018.
Revision of Prior Period Financial Statements. In connection with the preparation of the Company’s consolidated financial
statements for the year ended December 31, 2018, the Company identified errors in its previously issued 2017 annual
consolidated financial statements and in each of the interim periods within 2018 and 2017. These prior period errors related to the
manner in which it accounted for certain crude oil purchase and sale arrangements. Specifically, although the Company
previously reported the transactions on a net basis, the Company was required to account for these purchase and sale
arrangements on a gross basis, in accordance with Accounting Standards Codification 606, Revenue from Contracts with
Customers (“ASC 606”) in 2018 and Accounting Standards Codification 605, Revenue Recognition (“ASC 605”) in 2017, as
these transactions were not subject to Accounting Standards Codification 845, Nonmonetary Transactions (“ASC 845”). In
addition, the Company identified certain assets and liabilities related to these arrangements that were reported on a net basis on
the balance sheet, but did not meet all of the criteria for a right of setoff specified in Accounting Standards Codification 210,
Balance Sheet. The correction of these errors had no effect on the reported consolidated net income (loss) attributable to Oasis or
earnings (loss) attributable to Oasis per share data for the year ended December 31, 2017 or for any of the interim periods within
2018 and 2017 or to Oasis share of stockholders’ equity at December 31, 2017.
In accordance with Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior
Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, the Company evaluated the errors
and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to the
Company’s consolidated financial statements for any prior annual or interim period. Therefore, amendments of previously filed
reports are not required. In accordance with Accounting Standards Codification 250, Accounting Changes and Error Corrections,
the Company has corrected the errors for the year ended December 31, 2017 by revising the consolidated financial statements
appearing herein. Periods not presented herein will be revised, as applicable, in future filings.
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For the year ended December 31, 2017, the revision did not impact the Company’s cash flows from operations, and the impacts to
the Company's Consolidated Statement of Operations and Consolidated Balance Sheet were as follows:
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Net income attributable to Oasis
Earnings attributable to Oasis per share:
Basic
Diluted
Accounts receivable, net
Total current assets
Total assets
Accrued liabilities
Total current liabilities
Total liabilities
Oasis share of stockholders’ equity
$
$
$
$
Year Ended December 31, 2017
As Reported
Revision
As Revised
(In thousands, except share data)
(258) $
1,034,892 $
87,989
1,248,424
89,320
1,106,230
123,796
45,553
45,295
45,295
45,295
—
1,034,634
133,542
1,293,719
134,615
1,151,525
123,796
0.53 $
0.52 $
— $
— $
0.53
0.52
363,580 $
7,799 $
407,835
6,615,130
236,480
623,480
3,101,551
3,375,691
7,799
7,799
7,799
7,799
7,799
—
371,379
415,634
6,622,929
244,279
631,279
3,109,350
3,375,691
The accompanying notes to the consolidated financial statements reflect the impact of this revision. The Company has also
reflected the impact of this revision in the applicable unaudited quarterly financial results shown in Note 25 — Quarterly
Financial Data — Unaudited.
Use of Estimates
Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain
to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of
future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and
expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require
assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ
from those estimates.
Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently
uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective
process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy
of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and
judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and
development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could
materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and
impairment expense.
Risks and Uncertainties
As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the
prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as
economic, political and regulatory developments and competition from other energy sources. The energy markets have
historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations
in the future. As a result of current commodity prices, the Company plans to decrease its 2019 capital expenditures, excluding
acquisitions, as compared to 2018, while continuing to concentrate its drilling activities in its core acreage, including
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in the Bakken and Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Delaware
Basin.
A substantial or extended decline in commodity prices in oil and, to a lesser extent, natural gas, could have a material adverse
effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may
be economically produced.
Cash Equivalents
The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or
cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such
investments with original maturity dates less than 90 days as cash equivalents.
In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU
2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash
flows. ASU 2016-15 was applied on a retrospective basis. The adoption of ASU 2016-15 did not result in a material impact to the
Company’s financial position, cash flows or results of operations.
Accounts Receivable
Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-
term maturities. The Company’s accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest
owners on properties the Company operates.
The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability. The
Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be
collected and the amount of such reserve may be reasonably estimated. For receivables from joint interest owners, the Company
typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the
Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. At
December 31, 2018 and 2017, the Company had an allowance for doubtful accounts of $1.5 million and $1.6 million,
respectively.
Inventory
Crude oil inventory includes oil in tank. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well
equipment to be used in future drilling or repair operations and well fracturing equipment. Crude oil inventory and equipment and
materials are included in Inventory on the Company’s Consolidated Balance Sheets (see Note 5 — Inventory).
The minimum volume of product in a pipeline system that enables the system to operate is known as linefill and is generally not
available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil and
gas linefill in third-party pipelines, which is included in Long-term inventory on the Company’s Consolidated Balance Sheets (see
Note 5 — Inventory).
Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average
cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any
adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s
estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis.
Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the
timing of a sale can materially impact net realizable value.
Joint Interest Partner Advances
The Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital
intensive nature of oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling
operations may request advance payments from other working interest partners for their share of the costs. The Company expects
such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within
90 days from when the advance is paid. Advances to joint interest partners are included in other current assets on the Company’s
Consolidated Balance Sheets.
Property, Plant and Equipment
Proved Oil and Gas Properties
Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this
method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending
determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of
drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
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The provision for DD&A of oil and natural gas properties is calculated using the unit-of-production method. All capitalized well
costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved
developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel
equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production
DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of
estimated salvage values.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of
proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a
gain or loss is recognized currently.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as
incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts.
Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their
estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed
reserves.
The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a
decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future
cash flows of its oil and natural gas properties by field and compares such undiscounted future cash flows to the carrying amount
of the oil and natural gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying
amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural
gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and
include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of
estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production
estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions
associated with realizing the expected cash flows projected.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are
capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time
the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as
impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are
reclassified to proved properties and depleted on a unit-of-production basis.
The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining
lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of
the impairment of unproved properties:
•
•
•
•
•
the remaining amount of unexpired term under its leases;
its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases
that may be close to expiration;
its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and
development;
its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
its evaluation of the continuing successful results from the application of completion technology in the Bakken and
Three Forks formations in the Williston Basin and Bone Springs and Wolfcamp formations in the Delaware Basin by the
Company or by other operators in areas adjacent to or near the Company’s unproved properties.
For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the
proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are
accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Capitalized Interest
The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined
by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual
interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation
begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company
capitalized $17.2 million, $12.8 million and $16.8 million of interest costs for the years ended December 31, 2018, 2017 and
2016, respectively. These amounts are amortized over the life of the related assets.
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Other Property and Equipment
The Company’s produced and flowback water disposal facilities, natural gas processing plants, pipelines, buildings, furniture,
software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on
expected lives of the individual assets. The Company uses estimated lives of 30 years for its produced and flowback water
disposal facilities, natural gas processing plants and pipelines, 20 years for its buildings, two to seven years for its furniture,
software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A
method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement,
restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated
accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale
or disposal included in the Company’s Consolidated Statements of Operations.
Exploration Expenses
Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped
acreage, are charged to expense as incurred.
Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be
unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a
determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells
that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in
areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These
costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or
the necessary approvals are actively being sought.
Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented:
Beginning of period
Exploratory well cost additions (pending determination of proved
reserves)
Exploratory well cost reclassifications (successful determination
of proved reserves)
Exploratory well dry hole costs (unsuccessful in adding proved
reserves)
End of period
$
$
2018
December 31,
2017
(In thousands)
2016
— $
2,097 $
2,097
26,497
(22,040)
10
(571)
—
(1,536)
—
—
—
4,457 $
— $
2,097
As of December 31, 2018, the Company had no exploratory well costs that were capitalized for a period of greater than one year
after the completion of drilling.
Business Combinations
The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company
recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values.
Transaction and integration costs associated with business combinations are expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is
a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant
assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these
properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant
inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a
market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to
additional project-specific risking factors. In addition, when appropriate, the Company reviews comparable purchases and sales of
oil and natural gas properties within the same regions and uses that data as a proxy for fair market value; for example, the amount
a willing buyer and seller would enter into in exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the
estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase.
Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated
deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed
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and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information
becomes known.
In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2017-01, Clarifying the Definition of a
Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted
for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an
integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated
against the framework. ASU 2017-01 was applied on a prospective basis and prior periods were not retrospectively adjusted. The
adoption of ASU 2017-01 did not result in a material impact to the Company’s financial position, cash flows or results of
operations.
Assets Held for Sale
The Company occasionally markets non-core oil and natural gas properties. At the end of each reporting period, the Company
evaluates the properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria
include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer
exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale;
and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as
held-for-sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair
value less costs to sell. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model,
valuations performed by third parties, earnings multiples, or indicative bids, when available. Management considers historical
experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized
upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial
statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the
related financing using the straight-line method, which approximates the effective interest method. The amortization expense is
recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. The deferred financing
costs related to the Company’s senior unsecured notes as well as the Revolving Credit Facilities are included in long-term debt
and other assets, respectively, on the Company’s Consolidated Balance Sheets.
Asset Retirement Obligations
In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations
(“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the
liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of
the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO
represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their
productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the
capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of
depreciation, depletion and amortization in the Company’s Consolidated Statements of Operations.
Some of the Company’s midstream assets, including certain pipelines and the natural gas processing plants, have contractual or
regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are
abandoned. The Company is not able to reasonably estimate the fair value of the asset retirement obligations for these assets
because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The
Company will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably
determinable.
The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the
future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what
constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the
ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 7 — Fair
Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a
corresponding adjustment is made to the related asset.
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Revenue Recognition
In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2014-09, Revenue from Contracts with
Customers, and a series of related accounting standards updates incorporated into GAAP as ASC 606 using the modified
retrospective method. The adoption of ASC 606 did not result in a material impact to the Company’s financial position, cash
flows or results of operations. The Company has also modified current processes and controls to apply the requirements of the
new standard and does not believe such modifications are material to its internal controls over financial reporting. Enhanced
disclosures in accordance with ASC 606 have been provided in Note 4 — Revenue Recognition.
The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a
distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time.
ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled
in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the
contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the
performance obligation is satisfied.
Oil and gas revenues from the Company’s interests in producing wells are recognized when it satisfies a performance obligation
by transferring control of a product to a customer. Substantially all of the Company’s production is sold to purchasers under short-
term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for
transportation and other related deductions. These deductions are based on contractual or historical data and do not require
significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party
documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is
produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.
The Company’s purchased oil and gas sales are derived from the sale of oil and gas purchased from a third party. Revenues and
expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these
transactions by assuming control of the purchased oil or gas before it is transferred to the customer. In certain cases, the Company
enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on
a net basis in accordance with ASC 845.
Midstream revenues consist of revenues from midstream services provided through OMS, including (i) crude oil gathering,
stabilization, blending, storage and transportation, (ii) natural gas gathering, gas lift, compression and processing, (iii) produced
and flowback water gathering and disposal and (iv) freshwater supply and distribution. Well services revenues result from well
services, product sales and equipment rentals provided by OWS primarily for OPNA’s operated wells. Midstream and well
services revenues are recognized when services have been performed or related volumes or products have been delivered. The
revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working
interest owners in OPNA’s wells are included in the Company’s Consolidated Statements of Operations. Midstream revenues are
earned through fee-based arrangements, under which the Company receives fees for midstream services it provides to customers
and recognizes revenue based upon the transaction price at month-end under the right to invoice practical expedient, or through
purchase arrangements, under which the Company takes control of the product prior to sale and is the principal in the transaction,
and therefore, recognizes revenues and expenses on a gross basis.
Revenues and Production Taxes Payable
The Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual
provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.
Concentrations of Market and Credit Risk
The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The
availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of
the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines
and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory
environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.
The current global oversupply of crude oil has caused a sharp decline in oil prices since mid-2014, though recently oil prices have
been improving. A substantial or extended decline in the price of oil could have a material adverse effect on the Company’s
financial position, cash flows and results of operations.
The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s
receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint interest
partners for their respective portions of operating expenses and exploration and development costs. While certain of these
customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of
the oil or natural gas industry, including the current period of low commodity prices, the Company believes that its level of
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credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of
operations over the long-term. In addition, a portion of the Company’s trade receivables are collateralized.
The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not
required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk
consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash
equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced
any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial
institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of
business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit
risk.
Risk Management
The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of
December 31, 2018, the Company utilized fixed price swaps, basis swaps and two-way and three-way costless collar options to
reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production (see
Note 8 — Derivative Instruments).
The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at
their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are
reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative
instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains
and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the
Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under
the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the
cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of
costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing
activities in the Company’s Consolidated Statements of Cash Flows.
Derivative financial instruments that hedge the price of oil and natural gas are executed with major financial institutions that
expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of
counterparties. The Company has derivatives in place with nine counterparties. Although notional amounts are used to express the
volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are
substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of
nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from
its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.
The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master
Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs
include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not
required to provide any credit support to its counterparties other than cross collateralization with the properties securing the
Revolving Credit Facilities (see Note 12 — Long-Term Debt). The Company has limitations under the Revolving Credit
Facilities, including a provision limiting the total amount of production that may be hedged by the Company to certain
percentages of forecasted and current production amounts. As of December 31, 2018, the Company was in compliance with these
limitations.
In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of
Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair
value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the
fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to
equity method investments or investments in consolidated subsidiaries. The adoption of ASU 2016-01 did not result in a material
impact to the Company’s financial position, cash flows or results of operations.
Environmental Costs
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures
that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed.
Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation
activities are probable and the costs can be reasonably estimated.
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Equity-Based Compensation
In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2017-09, Scope of Modification Accounting
(“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award
require an entity to apply modification accounting. ASU 2017-09 was applied on a prospective basis and prior periods were not
retrospectively adjusted. The adoption of ASU 2017-09 did not result in a material impact to the Company’s financial position,
cash flows or results of operations.
Restricted Stock Awards
The Company has granted restricted stock awards to employees and directors under its Amended and Restated 2010 Long Term
Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the value
of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service
period. Equity-based compensation expense recorded for restricted stock awards is included in general and administrative
expenses on the Company’s Consolidated Statements of Operations. Forfeitures associated with restricted stock awards granted
are accounted for when they occur.
Performance Share Units
The Company recognizes compensation expense for its performance share units (“PSUs”) granted to its officers under its
Amended and Restated 2010 Long Term Incentive Plan. The fair value of the PSUs is based on the calculation derived from a
Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be
repeated numerous times to achieve a probable assessment (see Note 15 — Equity-Based Compensation for a description of the
inputs used in this model). Equity-based compensation expense recorded for PSUs is included in general and administrative
expenses on the Company’s Consolidated Statements of Operations. Forfeitures associated with awards granted under PSUs are
accounted for when they occur.
OMP Phantom Unit Awards
The Company has granted OMP phantom unit awards (collectively, the “OMP Phantom Unit Awards,” and each an “OMP
Phantom Unit”) to employees under its Amended and Restated 2010 Long Term Incentive Plan and under OMP GP’s Oasis
Midstream Partners LP 2017 Long Term Incentive Plan (“OMP LTIP”). The OMP Phantom Unit Awards are accounted for as
liability-classified awards since the awards will settle in cash, and equity-based compensation cost is accounted for under the fair
value method in accordance with GAAP. The OMP Phantom Unit Awards vest in equal amounts each year over a three-year
period, and compensation expense will be recognized over the requisite service period. Compensation cost is remeasured each
reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay, or
will reimburse OMP, for the cash settlement amount of these awards. Forfeitures associated with awards granted under the OMP
LTIP are accounted for when they occur.
Associated Excess Tax Benefits
Any excess tax benefit arising from the Company’s equity-based compensation plan is recognized as a credit to income tax
expense or benefit in the Company’s Consolidated Statements of Operations.
Treasury Stock
Treasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from
employees upon the vesting of restricted stock awards. The Company includes the withheld shares as treasury stock on its
Consolidated Balance Sheets and separately pays the payroll tax obligation. These retained shares are not part of a publicly
announced program to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not
have a publicly announced program to repurchase shares of its common stock.
Income Taxes
The Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes in
accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities
for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets
and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the
years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation
allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During
the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain.
The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact
its financial position, results of operations and cash flows.
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The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by
prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return.
Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial
statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the
position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial
statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant
tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability for the
years ended December 31, 2018 and 2017. All deferred tax assets and liabilities, along with any related valuation allowance, are
classified as noncurrent on the Company’s Consolidated Balance Sheets.
In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2016-16, Intra-Entity Transfers of Assets
Other Than Inventory (“ASU 2016-16”), to improve the accounting for the income tax consequences of intra-entity transfers of
assets other than inventory. The adoption of ASU 2016-16 did not result in a material impact to the Company’s financial position,
cash flows or results of operations.
In the third quarter of 2018, the Company finalized the accounting related to Accounting Standards Update No. 2018-05, Income
Taxes (Topic 740) - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118. This standard amends
Accounting Standards Codification 740, Income Taxes (“ASC 740”), to provide guidance on accounting for the tax effects of the
Tax Cuts and Jobs Act (the “Tax Act”) pursuant to Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the
Tax Cuts and Jobs Act (“SAB 118”). See Note 14 — Income Taxes for the total impact as a result of adoption.
Recent Accounting Pronouncements
Leases
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which established a
right-of-use (“ROU”) model that requires a lessee to recognize an operating lease asset and lease liability on the balance sheet,
with the exception of short-term leases. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended
by Accounting Standards Update No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”);
Accounting Standards Update No. 2018-10, Codification Improvements to Topic 842; and Accounting Standards Update No.
2018-11, Targeted Improvements.
The new standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The effective
date and transition requirements for the amendments are the same as the effective date for ASU 2016-02. A modified
retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application. An
entity may choose to use either (i) its effective date or (ii) the beginning of the earliest comparative period presented in the
financial statements as its date of initial application.
The Company will adopt the new standard as of January 1, 2019 using the required modified retrospective approach and plans to
elect the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained
earnings in the period of adoption, rather than recognizing in the earliest period presented. Prior period amounts will not be
adjusted.
ASU 2018-01 provides a number of optional practical expedients in transition. The Company expects to elect the package of
practical expedients, which permits the Company not to reassess under the new standard prior conclusions about lease
identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient
pertaining to land easements, which provides an option to not evaluate under ASC 842 existing or expired land easements that
were previously accounted for as leases under Accounting Standards Codification 840, Leases; and the practical expedient
pertaining to combining lease and non-lease components. In addition, under the new standard, an entity may elect not to apply the
recognition requirements of ASC 842 to short-term leases, which are leases with terms of one year or less. The Company expects
to make this election, and as such, recognition of lease payments for short-term leases will be recognized in net income on a
straight line basis.
The Company expects this new standard will have a material effect on the consolidated financial statements. While the Company
continues to assess all of the effects of adoption, the Company believes the most significant effects relate to (i) the recognition of
new ROU assets and lease liabilities on the consolidated balance sheet and (ii) providing significant new disclosures about the
Company’s leasing activities. The new ROU assets and lease liabilities, which will be recognized on the consolidated balance
sheet, consist primarily of offices, man-camps, rigs and vehicles.
The Company plans to modify its business processes and controls to support the adoption of the new standard, including
implementing a new lease accounting software to assess the portfolio of leases, assist in the quantification of the expected impact
on the consolidated financial statements and facilitate the calculations of the related accounting entries and disclosures.
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The changes to controls will not materially affect the Company’s internal control over financial reporting, and the Company does
not expect a significant change in its leasing activities as a result of this adoption.
Financial instruments
In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement (Topic 820): Disclosure
Framework—Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the
effectiveness of the disclosure requirements for fair value measurements. The changes affect all companies that are required to
include fair value measurement disclosures. ASU 2018-13 is effective for fiscal years beginning after December 15, 2019,
including interim periods within those years. An entity is permitted to early adopt the removed or modified disclosures upon the
issuance of ASU 2018-13 and may delay adoption of the additional disclosures until their effective date. The Company does not
expect the adoption of this guidance to have an impact on its financial position, cash flows or results of operations, but it may
result in changes to disclosures.
3. Oasis Midstream Partners LP
Oasis Midstream Partners LP
OMP is a growth-oriented, fee-based master limited partnership formed by the Company to own, develop, operate and acquire a
diversified portfolio of midstream assets in North America that are integral to the oil and natural gas operations of Oasis and are
strategically positioned to capture volumes from other producers.
Initial public offering of Oasis Midstream Partners LP
On September 25, 2017, OMP completed its IPO of 7,500,000 common units representing limited partner interests in OMP at a
price of $17.00 per unit. Additionally, on October 10, 2017, OMP issued an additional 1,125,000 common units pursuant to the
underwriters’ exercise in full of their option to purchase additional common units at the same price and on the same terms. OMP
received net proceeds from the IPO of $134.2 million after deducting underwriting discounts, structuring fees and offering
expenses. OMP distributed $132.1 million of the net proceeds to Oasis. The OMP common units are traded on the New York
Stock Exchange under the symbol OMP.
In exchange for contributed assets, Oasis received 5,125,000 common units and 13,750,000 subordinated units, representing a
68.6% limited partner interest in OMP and the right to receive cash distributions from OMP. In addition to and concurrent with
the closing of the IPO, OMP GP retained a non-economic general partnership interest and was issued incentive distribution rights
in OMP.
Oasis Midstream Partners LP public offering and dropdown
On November 14, 2018, OMP completed a public offering of 2,300,000 common units (including 300,000 common units issued
pursuant to the underwriters’ option to purchase additional common units) representing limited partnership interests, at a price to
the public of $20.00 per common unit. OMP received net proceeds from the public offering of $44.5 million, after deducting
underwriting discounts, commissions and offering costs, which were used to fund a portion of its acquisition of additional
ownership interest in Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”).
In connection with the OMP public offering, on November 19, 2018, OMP acquired an additional 15% ownership interest in
Bobcat DevCo increasing its ownership to 25% and an additional 30% ownership interest in Beartooth DevCo increasing its
ownership to 70% in exchange for consideration of $251.4 million (“OMP Dropdown”).
The $251.4 million consideration consisted of $172.4 million in cash and 3,950,000 common units representing limited partner
interests in OMP. OMP funded the cash portion of the consideration with a combination of borrowings under the revolving credit
facility among OMP, as parent, OMP Operating LLC (“OMP Operating”), a subsidiary of OMP, as borrower, Wells Fargo Bank,
N.A., as administrative agent and the lenders party thereto (the “OMP Credit Facility”) and proceeds from its public offering of
common units. As a result of the OMP Dropdown, OMS now owns 75% of the non-controlling interests of Bobcat DevCo and
30% of the non-controlling interests of Beartooth DevCo. The effective date of the OMP Dropdown was July 1, 2018, and the
OMP Dropdown closed on November 19, 2018. The OMP Dropdown did not have a material impact on the Company’s
consolidated financial statements.
Class B units in OMP GP
On May 22, 2017, OMP GP granted restricted Class B Units to certain employees, including OMP’s executive officers, as
consideration for services to Oasis, which vest over a ten-year period. The restricted Class B Units represent 10% of the
outstanding units of OMP GP. Compensation expense is recognized ratably over the requisite service period.
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Contractual arrangements
In connection with the OMP IPO, the Company entered into several 15-year, fee-based contractual arrangements with OMP for
midstream services, including (i) gas gathering, compression, processing and gas lift services; (ii) crude gathering, stabilization,
blending, storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv)
freshwater supply and distribution services. In addition, the Company provides substantial labor and overhead support for OMP.
Upon completion of the OMP IPO, the Company entered into a 15-year services and secondment agreement with OMP pursuant
to which the Company provides all personnel, equipment, electricity, chemicals and services (including third-party services)
required for OMP to operate such assets, and OMP reimburses the Company for its share of the actual costs of operating such
assets. In addition, pursuant to the services and secondment agreement, the Company performs centralized corporate, general and
administrative services for OMP, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing,
business development, treasury, insurance administration and claims processing, risk management, health, safety and
environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal
audit, taxes and engineering. The Company has also seconded to OMP certain of its employees to operate, construct, manage and
maintain its assets, and OMP reimburses the Company for direct general and administrative expenses incurred by the Company
for the provision of the above services. The expenses of executive officers and non-executive employees are allocated to OMP
based on the amount of time spent managing its business and operations.
Assignment of contract for construction of natural gas processing plant
On November 6, 2017, OMS agreed to assign to Bighorn DevCo LLC (“Bighorn DevCo”), an indirect, wholly owned subsidiary
of OMP, the construction of a second gas processing plant to support Oasis’s production. Pursuant to this assignment, Bighorn
DevCo has agreed to assume (i) a fixed price agreement for engineering, procurement and construction of a 200 million standard
cubic feet per day natural gas processing plant (the “EPC Agreement” and “Gas Plant II,” respectively), (ii) title to Gas Plant II
and the ancillary equipment being constructed under the EPC Agreement, and (iii) a master service agreement and work orders
pursuant to which the contractor has agreed to provide mechanical refrigeration units to support Gas Plant II’s operation. In
addition, OMP reimbursed OMS for all capital expenditures previously made under the EPC Agreement or otherwise in respect of
Gas Plant II totaling $66.7 million. OMP funded the reimbursement with proceeds from the OMP Credit Facility. Finally, the Gas
Gathering, Compression, Processing, and Gas Lift Agreement by and among OPNA, OPM, OMS and OMP, dated as of
September 25, 2017, was amended to reflect the Gas Plant II’s additional processing capacity.
2019 Capital Expenditures Arrangement
On February 22, 2019, the Company entered into a memorandum of understanding (the “MOU”) with OMP regarding the
funding of Bobcat DevCo’s expansion capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures
Arrangement”). Pursuant to the MOU, in exchange for increasing its percentage ownership interest in Bobcat DevCo, OMP
agreed to make up to $80 million of the capital contributions to Bobcat DevCo that OMS would otherwise be required to
contribute. In connection with this arrangement, OMS’s percentage ownership interest in Bobcat DevCo is expected to decrease
from 75% to between approximately 64% and 66% by the end of the 2019 calendar year. See Note 21 — Subsequent Events for a
description of the 2019 Capital Expenditures Arrangement.
4. Revenue Recognition
In May 2014, the FASB issued a new accounting standard related to revenue recognition, ASC 606. This standard was effective in
the first quarter of 2018 and the Company adopted the new standard using the modified retrospective method. The Company
applied ASC 606 to all new contracts entered into after January 1, 2018 and all existing contracts for which all (or substantially
all) of the revenue has not been recognized under legacy revenue guidance as of December 31, 2017. ASC 606 supersedes
previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer
of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in
exchange for those goods or services.
In accordance with the adoption of ASC 606, management evaluated its contracts with customers to apply the five-step revenue
recognition model. The adoption of ASC 606 did not result in a material impact to the Company’s financial position, cash flows
or results of operations.
The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a
distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time.
ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled
in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the
contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the
performance obligation is satisfied.
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Exploration and production revenues
The Company’s exploration and production revenues are derived from contracts for oil, natural gas and natural gas liquids
(“NGL”) sales, as described below. Generally, for the majority of these contracts: (i) each unit (barrel (“bbl”), mcf, gallon, etc.) of
commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity
product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable
each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer
that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s
standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the
customer obtains control of the commodity product and the Company’s performance obligation is satisfied. The sales of oil,
natural gas and NGLs as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of
revenues net of royalties and excluding revenue interests owned by others. When selling oil, natural gas and NGLs on behalf of
royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the
extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or
information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded.
The Company’s contracts with customers typically require payments for oil, natural gas and NGL sales within 30 days following
the calendar month of delivery.
Oil revenues. The Company sells a substantial majority of its oil through bulk sales at delivery points on crude oil gathering
systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold
to the customer at a specified delivery point. The customer pays a market-based transaction price, which incorporates differentials
that include, but are not limited to, transportation costs.
Natural gas revenues. The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales. Unprocessed gas is
sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its
sale of the bifurcated NGLs and residue gas, less any associated fees. Revenue is recorded on a net basis, with processing fees
deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point. Residue gas
is sold from the tailgate of the Company’s gas processing plants located in Wild Basin or transported and sold at other
downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.
Purchased oil and gas sales. The Company’s purchased oil and gas sales are derived from the sale of oil and gas purchased from
a third party. The Company sells the purchased commodities to a variety of customers under short-term contracts that include
specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point. The
customer pays a market-based transaction price, which is based on the price index applicable for the location of the sale.
Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal
in these transactions by assuming control of the purchased oil or gas before it is transferred to the customer. In certain cases, the
Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are
recorded on a net basis in accordance with ASC 845.
NGL revenues. NGLs are sold from the Company’s gas processing plant complexes located in Wild Basin or trucked and sold at
other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities
sold.
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Prior period performance obligations. For sales of oil, purchased oil, natural gas, purchased gas and NGLs, the Company records
revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received
for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of
production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company
records the differences between estimates and the actual amounts received for product sales once payment is received from the
purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties’
historical performance, spot market prices and other factors as the basis for these estimates. For the year ended December 31,
2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
Revenues associated with contracts with customers for oil, natural gas and NGL sales were as follows for the years ended
December 31, 2018, 2017 and 2016:
Exploration and Production Revenues
Oil revenues
Purchased oil sales
Natural gas revenues
Purchased gas sales
NGL revenues
Year Ended December 31,
2018
2017
(In thousands)
2016
$
1,425,409 $
540,633
113,095
6,078
51,520
912,806 $
132,331
79,823
1,211
42,005
586,308
10,272
33,988
—
4,937
Total exploration and production revenues
$
2,136,735 $
1,168,176 $
635,505
Midstream revenues
The Company’s midstream revenues are derived from its contracts with customers for midstream services and product sales under
the following arrangements:
Fee-based arrangements. Under fee-based arrangements, the Company receives a fee for midstream services it provides to its
customers, and revenues are recognized using the output method for measuring the satisfaction of performance obligations.
Revenues earned under fee-based arrangements are generally directly related to the volume of crude oil, natural gas and produced
and flowback water that flows through the Company’s systems, and the Company does not take ownership to the volumes it
handles for its customers. Payments under fee-based arrangements are generally due 30 days after receipt of invoice. The
Company generates revenues under fee-based arrangements as follows:
•
Crude oil and natural gas revenues. The Company is party to certain contracts for crude oil gathering, stabilization,
blending, storage and transportation, as well as gas gathering, compression, processing and gas lift services. Under these
customer contracts, the Company provides daily integrated midstream services on a stand ready basis over a period of
time, which represents a single performance obligation since the customer simultaneously receives and consumes the
benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day
of service is completed, which directly corresponds with its right to consideration from the customer. Revenues
associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice
practical expedient.
• Water revenues. The Company is party to certain contracts with customers for produced and flowback water gathering
and disposal services, under which it provides daily integrated midstream services on a stand ready basis over a period of
time, which represents a single performance obligation since the customer simultaneously receives and consumes the
benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day
of service is completed, which directly corresponds with its right to consideration from the customer. Revenues
associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice
practical expedient.
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Purchase arrangements. Under purchase arrangements, revenues and expenses are recognized on a gross basis since the
Company takes control of the product prior to sale and is the principal in the transaction. Revenues are recognized using the
output method for measuring the satisfaction of performance obligations based upon the volume of natural gas, NGLs or
freshwater delivered to customers. Payments under purchase arrangements are generally due 30 days after receipt of invoice. The
Company generates revenues under purchase arrangements as follows:
•
•
Purchased oil sales. The Company purchases and sells crude oil at various delivery points on crude oil gathering systems
to a variety of customers under short-term contracts that include a specified quantity of crude oil to be sold and delivered
to the customer at a specified delivery point. The Company purchases and sells the crude oil to different counterparties at
market-based prices. Market-based pricing is based on the price index applicable for the location of the sale.
Purchased gas sales. The Company is party to certain purchase arrangements with third parties pursuant to which the
Company purchases natural gas from third parties at a connection point and obtains control prior to performing services
and is the principal in the transaction. The Company gathers, compresses and/or processes the gas and then redelivers the
residue gas and NGLs to different counterparties at market-based prices.
• Water revenues. Under its customer contracts for freshwater supply and distribution, the Company supplies and
distributes freshwater to its customers for hydraulic fracturing and production optimization. These contracts contain
multiple distinct performance obligations since each freshwater barrel can be sold separately and is not dependent nor
highly interrelated with other barrels. Revenue associated with freshwater supply and distribution services is recognized
at a point-in-time based upon the transaction price when title, control and risk of loss transfers to the customer, which
occurs at the delivery point.
Revenues associated with contracts with customers for midstream services were as follows for the years ended December 31,
2018, 2017 and 2016:
Crude oil and natural gas revenues
Purchased oil sales
Purchased gas sales
Water revenues
Total midstream revenues
Midstream Revenues(1)
Year Ended December 31,
2018
2017
2016
$
$
(In thousands)
73,028 $
37,369 $
3,633
1,464
46,012
124,137 $
—
—
35,383
72,752 $
5,186
—
—
30,220
35,406
__________________
(1)
Represents midstream revenues excluding all intercompany revenues for work performed by the midstream services
business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included
in midstream services revenues.
Well services revenues
Hydraulic fracturing service revenues. Hydraulic fracturing revenue is recognized upon the completion of each hydraulic
fracturing of a well. These services are composed of various components, such as personnel, equipment and hydraulic fracturing
materials, but management determined that each component is not distinct, as it cannot be used on its own or together with a
resource readily available to the customer. Revenue is recognized when the performance obligations of hydraulic fracturing a well
in its totality are completed; generally, this is over a period of time due to all work being performed for a customer occurring on
the customer’s property, where the customer has control over the work in process as it is being performed. In addition, the
Company’s assets being used to perform the obligations have no alternative use at the time of performance and the Company has
the right to payment for performance to date. Payments from customers are generally received by the Company within one month
after the month in which services are provided. In addition, revenue from product sales to third parties is generated when OPNA
requests that third-party hydraulic fracturing companies hydraulic fracture OPNA’s wells. Although the labor is provided by the
third-party hydraulic fracturing company, the materials (e.g., sand, chemicals, etc.) used in the hydraulic fracturing of the wells
are provided by OWS. The third-party hydraulic fracturing company or OPNA pays OWS for the materials delivered to the wells.
Revenue is recognized once the performance obligations to transfer hydraulic fracturing materials are completed.
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Equipment rental revenues. Equipment rental revenue is generated when OPNA or a third-party hydraulic fracturing company
rents equipment from OWS. This equipment is used in the preparation stage of hydraulic fracturing services or after the hydraulic
fracturing services have been completed. Equipment rental revenues are calculated based on the equipment’s daily rental rate and
the number of days that the equipment was rented by the customer. OWS’s performance obligation is satisfied when the entire
rental period is completed. Equipment rental revenues are recognized over a period of time due to the customer simultaneously
receiving and consuming the benefits of the rental equipment provided by OWS on a daily basis. Satisfaction of the Company’s
performance obligation is measured at the completion of each day’s rental period, which directly corresponds with its right to
consideration from the customer. Revenues associated with these contracts are recognized at the time of invoicing for the entire
rental period under the right to invoice practical expedient. Payments from customers are generally received by the Company
within one month after the month in which services are provided.
Revenues associated with contracts with customers for hydraulic fracturing services and equipment rental sales were as follows
for the years ended December 31, 2018, 2017 and 2016:
Hydraulic fracturing service revenues
Equipment rental revenues
Total well services revenues
Well Services Revenues(1)
Year Ended December 31,
2018
2017
2016
$
$
(In thousands)
56,620 $
4,455
61,075 $
49,266 $
3,525
52,791 $
30,965
2,789
33,754
__________________
(1)
Represents well services revenues excluding all intercompany revenues for work performed by the well services business
segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in well
services revenues.
Contract balances
Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract
liabilities are recorded for consideration received from customers related to temporary deficiency quantities under minimum
volume commitments, which are expected to be made up in a future period. This consideration is subsequently recognized as
revenue when the customer makes up the volumes or the deficiency makeup period expires. The Company does not recognize
contract assets or contract liabilities under its customer contracts for which invoicing occurs once the Company’s performance
obligations have been satisfied and payment is unconditional. No contract balances were recorded in the Consolidated Balance
Sheets as of December 31, 2018.
Remaining performance obligations
ASC 606 requires presentation of information about partially and wholly unsatisfied performance obligations under contracts that
exist as of the end of the period. The following table presents estimated revenue allocated to remaining performance obligations
for contracted revenues that are unsatisfied (or partially satisfied) as of December 31, 2018:
2019
2020
2021
2022
2023
Thereafter
Total
$
(In thousands)
24,879
26,909
25,656
19,263
12,642
14,642
$
123,991
The partially and wholly unsatisfied performance obligations presented in the table above are generally limited to customer
contracts which have fixed pricing and fixed volume terms and conditions, which generally include customer contracts with
minimum volume commitment payment obligations.
The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance
obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated
entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer
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a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or
less; and (iii) contracts for which the Company recognizes revenue under the right to invoice practical expedient.
5. Inventory
The following table sets forth the Company’s inventory:
Inventory
Crude oil inventory
Equipment and materials
Total inventory
Long-term inventory
Linefill in third-party pipelines
Long-term inventory
Total
6. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
Accounts receivable, net
Trade accounts
Joint interest accounts
Other accounts
Total
Allowance for doubtful accounts
Total accounts receivable, net
Revenues and production taxes payable
Revenue suspense
Royalties payable
Production taxes payable
Total revenue and production taxes payable
Accrued liabilities
Accrued capital costs
Accrued lease operating expenses
Accrued oil and gas purchases
Accrued general and administrative expenses
Accrued midstream and well services operating expenses
Other accrued liabilities
Total accrued liabilities
$
$
$
$
$
$
$
$
$
$
$
December 31,
2018
2017
(In thousands)
14,933 $
18,195
33,128 $
12,260 $
12,260 $
45,388 $
December 31,
2018
2017
(In thousands)
234,231 $
93,939
60,958
389,128
(1,526)
387,602 $
75,685 $
124,884
16,126
216,695 $
216,079 $
26,988
32,713
23,901
17,521
14,449
331,651 $
10,427
8,940
19,367
12,200
12,200
31,567
241,459
73,588
57,905
372,952
(1,573)
371,379
68,015
126,761
19,219
213,995
154,625
26,215
21,394
17,915
15,293
8,837
244,279
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7. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities
are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents,
accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market
values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note
13 — Asset Retirement Obligations) and proved oil and natural gas properties upon impairment (see Note 9 — Property, Plant
and Equipment), at fair value on a non-recurring basis.
As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability
in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company
utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions
about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market
corroborated or generally unobservable.
The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements)
and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as
follows:
Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date.
Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or
indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other
valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including
quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying
instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the
marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable
levels at which transactions are executed in the marketplace.
Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation
methodologies that result in management’s best estimate of fair value.
Financial Assets and Liabilities
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation
of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level
within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring
basis:
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Assets:
Money market funds
Commodity derivative instruments (see Note 8)
Total assets
Liabilities:
Commodity derivative instruments (see Note 8)
Total liabilities
Assets:
Money market funds
Commodity derivative instruments (see Note 8)
Total assets
Liabilities:
Commodity derivative instruments (see Note 8)
Total liabilities
$
$
$
$
$
$
$
$
Fair value at December 31, 2018
Level 1
Level 2
Level 3
Total
(In thousands)
143 $
—
— $
106,875
143 $
106,875 $
— $
— $
104 $
104 $
— $
—
— $
— $
— $
Fair value at December 31, 2017
Level 1
Level 2
Level 3
Total
(In thousands)
— $
353
353 $
142 $
—
142 $
— $
— $
135,567 $
135,567 $
— $
—
— $
— $
— $
143
106,875
107,018
104
104
142
353
495
135,567
135,567
The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the
Company’s Consolidated Balance Sheets at December 31, 2018 and 2017. The Company’s money market funds represent cash
equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market
funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments
can be obtained, and there are active markets for the underlying investments.
The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil and natural
gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party
preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement
purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily
available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer
performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The
significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments.
However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or
third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements,
investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and
natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit
adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in an
asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability
position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to
reduce the fair value of its net derivative asset by $0.2 million at December 31, 2018 and an adjustment to reduce the fair value of
its net derivative liability by $2.8 million at December 31, 2017.
There were no transfers between fair value levels during the years ended December 31, 2018 and 2017.
8. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. The
Company’s crude oil contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price
(“NYMEX WTI”), the average Intercontinental Exchange, Inc. Brent crude oil index price (“ICE Brent”), the average Argus WTI
Midland crude oil index price (“Midland”) and the average Argus WTI Houston crude oil index price (“Houston”). The
Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX
HH”) and the average Inside FERC Northern Natural Gas Ventura natural gas index price (“IF NNG Ventura”).
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At December 31, 2018, the Company utilized fixed price swaps, basis swaps and two-way and three-way costless collars to
reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. The
Company’s fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and
floor), which the Company will receive for the volumes under contract. A basis swap transaction has an established fixed basis
differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relation to
the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty,
equal to the difference multiplied by the contract volume. A two-way collar is a combination of options: a sold call and a
purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the
Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put
and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-
floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the
sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under
contract.
All derivative instruments are recorded on the Company’s Consolidated Balance Sheets as either assets or liabilities measured at
their fair value (see Note 7 — Fair Value Measurements). The Company has not designated any derivative instruments as hedges
for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify
as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the
Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is
only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment
from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments
and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash
settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.
At December 31, 2018, the Company had the following outstanding commodity derivative instruments:
Ceiling
Fair Value
Assets
(Liability)
(In thousands)
$
33,827
Commodity
Settlement
Period
Derivative
Instrument
Index
Volumes
Weighted Average Prices
Fixed
Price
Swaps
Basis
Swaps
Sub-
Floor
Floor
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Natural gas
2019
2019
2019
2019
2019
2020
2020
2020
2019
NYMEX WTI
NYMEX WTI-
ICE BRENT
Midland-NYMEX
WTI
NYMEX WTI
NYMEX WTI
NYMEX WTI
NYMEX WTI
NYMEX WTI
Fixed price
swaps
Basis swaps
Basis swaps
Two-way
collars
Three-way
collars
Fixed price
swaps
Two-way
collars
Three-way
collars
Fixed price
swaps
5,690,500 Bbl
$ 53.63
424,000 Bbl
605,000 Bbl
3,937,500 Bbl
3,702,000 Bbl
$ (9.68)
$ (7.19)
$ 58.47 $ 77.03
$ 40.49 $ 50.94 $ 67.97
403,000 Bbl
$ 53.47
341,000 Bbl
310,000 Bbl
$ 58.18 $ 77.65
$ 40.00 $ 50.50 $ 67.10
NYMEX HH
6,446,000 MMBtu $ 3.15
Natural gas
2019
Basis swaps
IF NNG
VENTURA-
NYMEX HH
4,525,000
MMBtu
$ 0.02
117
673
(865)
48,320
16,528
1,928
3,982
1,035
1,303
40
$
106,771
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Subsequent to December 31, 2018, the Company entered into additional swaps, basis swaps and two-way and three-way costless
collars. As of March 1, 2019, the Company had the following outstanding commodity derivative contracts:
Commodity
Settlement
Period
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Natural gas
2019
2019
2019
2019
2019
2019
2020
2020
2020
2021
2019
Derivative
Instrument
Fixed price
swaps
Basis swaps
Basis swaps
Basis swaps
Two-way
collar
Three-way
collar
Fixed price
swaps
Two-way
collar
Three-way
collar
Three-way
collar
Fixed price
swaps
Index
Volumes
Fixed Price
Swaps
Basis
Swaps
Sub-
Floor
Floor
Ceiling
Weighted Average Prices
NYMEX WTI
5,690,500 Bbl
$
53.63
NYMEX WTI-ICE
BRENT
Midland-NYMEX
WTI
Houston-NYMEX
WTI
424,000 Bbl
755,000 Bbl
549,000 Bbl
NYMEX WTI
4,454,500 Bbl
NYMEX WTI
4,008,000 Bbl
$
$
$
(9.68)
(6.83)
4.55
NYMEX WTI
403,000 Bbl
$
53.47
NYMEX WTI
372,000 Bbl
NYMEX WTI
1,224,000 Bbl
NYMEX WTI
62,000 Bbl
NYMEX HH
9,196,000 MMBtu $
3.08
$ 58.01 $
74.77
$ 40.45 $ 51.40 $
67.13
$ 58.08 $
76.05
$ 40.00 $ 55.55 $
60.11
$ 40.00 $ 57.37 $
57.37
Natural gas
2019
Basis swaps
IF NNG
VENTURA-
NYMEX HH
4,820,000
MMBtu
$
0.05
The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative
instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented:
Statement of Operations Location
2018
2017
2016
Year Ended December 31,
(In thousands)
Net gain (loss) on derivative instruments
$
28,457 $
(71,657) $
(105,317)
In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is
required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of
financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The
Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty
contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross
amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheets.
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The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the
Company’s Consolidated Balance Sheets:
Commodity
Balance Sheet Location
December 31, 2018
Gross
Recognized
Assets/Liabilities
Gross Amount
Offset
(In thousands)
Net Recognized
Fair Value
Assets/Liabilities
Derivatives assets:
Commodity contracts
Derivative instruments — current assets
$
110,729 $
(10,799) $
Commodity contracts
Derivative instruments — non-current assets
8,251
(1,306)
99,930
6,945
Total derivatives
assets
Derivatives liabilities:
$
118,980 $
(12,105) $
106,875
Commodity contracts
Derivative instruments — current liabilities
$
Commodity contracts
Derivative instruments — non-current liabilities
Total derivatives liabilities
$
84 $
20
104 $
— $
—
— $
84
20
104
Commodity
Balance Sheet Location
Derivatives assets:
Commodity contracts
Derivative instruments — current assets
Commodity contracts
Derivative instruments — non-current assets
Total derivatives
assets
Derivatives liabilities:
December 31, 2017
Gross
Recognized
Assets/Liabilities
Gross Amount
Offset
(In thousands)
Net Recognized
Fair Value
Assets/Liabilities
$
$
344 $
9
— $
—
353 $
— $
344
9
353
Commodity contracts
Derivative instruments — current liabilities
$
117,629 $
(1,913) $
115,716
Commodity contracts
Derivative instruments — non-current liabilities
20,035
(184)
19,851
Total derivatives liabilities
$
137,664 $
(2,097) $
135,567
9. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
Proved oil and gas properties(1)
Less: Accumulated depreciation, depletion, amortization and
impairment
Proved oil and gas properties, net
Unproved oil and gas properties
Other property and equipment(2)
Less: Accumulated depreciation
Other property and equipment, net
Total property, plant and equipment, net
$
$
December 31,
2018
2017
(In thousands)
7,878,104 $
(2,853,353)
5,024,751
1,034,085
1,151,772
(183,499)
968,273
7,027,109 $
7,058,782
(2,395,153)
4,663,629
780,173
868,746
(139,062)
729,684
6,173,486
__________________
(1)
Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $40.5 million and
$38.4 million at December 31, 2018 and 2017, respectively.
(2)
Included in the Company’s other property and equipment are estimates of future asset retirement costs of $1.3 million and
$1.5 million at December 31, 2018 and 2017, respectively.
/
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Impairment. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances
indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected
undiscounted future cash flows of its proved oil and natural gas properties by field and then compares such amount to the carrying
amount of the proved oil and natural gas properties in the applicable field to determine if the carrying amount is recoverable. If
the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the
proved oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment
and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash
flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future
production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market
conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further
discussed under Note 7 — Fair Value Measurements.
As of December 31, 2018, the Company sold certain proved and unproved oil and natural gas properties (see Note 11 –
Divestitures). For the year ended December 31, 2018, the Company recorded an impairment loss of $383.4 million, which was
included in its exploration and production segment to adjust the carrying amount of these assets, net of the associated ARO
liabilities, to their estimated fair value. For the year ended, December 31, 2017, the Company did not record impairment of
proved oil and gas properties. As of December 31, 2016, the Company sold certain proved oil and natural gas properties and other
midstream properties. For the year ended December 31, 2016, the Company recorded an impairment loss of $3.6 million, of
which $2.4 million was included in its midstream services segment and $1.1 million was included in its exploration and
production segment, to adjust the carrying amount of these assets, net of the associated ARO liabilities, to their estimated fair
value.
In addition, as a result of expiring leases and periodic assessments of unproved properties, the Company recorded non-cash
impairment charges on its unproved oil and gas properties of $0.9 million, $6.9 million and $1.1 million for the years ended
December 31, 2018, 2017 and 2016, respectively.
10. Acquisitions
Permian Basin Acquisition. On February 14, 2018, the Company and Oasis Petroleum Permian LLC (“OP Permian”), a wholly
owned subsidiary of the Company, acquired from Forge Energy, LLC (“Forge Energy”) approximately 22,000 net acres in the
Delaware Basin (the “Permian Basin Acquisition”) for aggregate consideration consisting of approximately $549.8 million in
cash, inclusive of a $47.3 million deposit paid to Forge Energy in December 2017, and 46,000,000 shares of the Company’s
common stock (the “Purchase Price”), including customary post close adjustments. In connection with the closing of the Permian
Basin Acquisition, the Company and Forge Energy entered into a Registration Rights Agreement that granted the equity holders
of Forge Energy certain customary registration rights for the stock portion of the Purchase Price. The Company funded the cash
portion of the Purchase Price with borrowings under a senior secured revolving line of credit among OPNA, as Borrower, Wells
Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “Oasis Credit Facility,” and, together with the OMP
Credit Facility, the “Revolving Credit Facilities”), and proceeds from the Company’s December 2017 issuance of its common
stock.
The Permian Basin Acquisition represents the Company’s initial entry into the Delaware Basin. The assets underlying the
Permian Basin Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across
Ward, Winkler, Loving and Reeves Counties, Texas.
The Permian Basin Acquisition qualified as a business combination. As such, the Company estimated the fair value of the assets
acquired and liabilities assumed as of the February 14, 2018 acquisition date. The fair value is the price that would be received to
sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit
price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model
and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves,
expectations for timing and amount of future development and operating costs, projections of future rates of production, expected
recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 7 —
Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the Permian Basin Acquisition at
their estimated fair value of $921.0 million, which the Company considers to be representative of the price paid by a typical
market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The Permian Basin
Acquisition is considered a taxable transaction; therefore, no deferred tax amounts were recognized at the acquisition date as the
tax basis of the assets acquired and liabilities assumed were also recorded at fair value.
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The following table summarizes the consideration paid for the Company’s acquisition and the fair value of the assets acquired and
liabilities assumed as of the acquisition date.
Consideration paid to Forge Energy:
Cash
Common stock: 46,000,000 shares issued
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties
Proved undeveloped properties
Unproved lease acquisition costs
Inventory
Intangible assets
Asset retirement obligations
At February 14, 2018
(In thousands)
$
$
$
$
549,770
371,220
920,990
110,325
166,552
645,068
293
1,000
(2,248)
920,990
The results of operations for the Permian Basin Acquisition have been included in the Company’s consolidated financial
statements since the February 14, 2018 closing date, including $71.7 million of total revenue and $15.6 million of operating
income for the year ended December 31, 2018.
The Company also recorded a $1.0 million finite-lived intangible asset on the Company’s Consolidated Balance Sheets for a non-
compete agreement with a one-year life. Intangible assets are amortized on a straight-line basis over the useful life, and the
Company includes the amortization in depreciation, depletion and amortization expenses on the Company’s Consolidated
Statements of Operations. For the year ended December 31, 2018, amortization expense recognized for this non-compete
agreement was approximately $0.9 million.
Summarized below are the consolidated results of operations for the year ended December 31, 2018, on an unaudited pro forma
basis, as if the acquisition and related financing had occurred on January 1, 2017. The unaudited pro forma financial information
was derived from the historical consolidated statements of operations of the Company and the statement of revenues and direct
operating expenses for the Permian Basin Acquisition properties, which were derived from the historical accounting records of
Forge Energy. The unaudited pro forma financial information does not purport to be indicative of results of operations that would
have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative
of the Company’s expected future results of operations.
Revenues
Net income (loss) attributable to Oasis
Net income (loss) attributable to Oasis per share:
Basic
Diluted
Year Ended December 31,
2018
2017
(In thousands)
Unaudited
2,327,476 $
(30,754)
1,337,468
159,838
(0.10) $
(0.10)
0.57
0.56
$
$
Other Delaware Acquisition. On September 12, 2018, the Company completed the initial closing with undisclosed sellers to
acquire certain exploration and production assets adjacent to the Company’s existing Delaware position (the “Other Delaware
Acquisition”) for total cash consideration of $59.5 million. The final closing statement was finalized in January 2019, subsequent
to the year ended December 31, 2018. Based on the FASB’s authoritative guidance, the acquisition qualified as a business
combination, and as such, the Company estimated the fair value of the assets acquired as of the acquisition date. The Company
recorded the oil and gas properties acquired at their estimated fair value of $59.5 million, which the Company considers to be
representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase
being recognized.
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Midstream Assets Acquisition. On April 25, 2017, the Company completed purchase and sale agreements with two undisclosed
private sellers to acquire certain midstream assets in McKenzie County, North Dakota (the “Midstream Assets Acquisition”) for
total consideration of $12.7 million, which includes $4.9 million of installment notes payable. Based on the FASB’s authoritative
guidance, the acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets
acquired as of the acquisition date. The Company recorded the assets acquired at their estimated fair value of $12.7 million,
which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in
no goodwill or bargain purchase being recognized.
The results of operations for the Other Delaware Acquisition and the Midstream Assets Acquisition have been included in the
Company’s consolidated financial statements since the closing date. Pro forma information is not presented as the pro forma
results would not be materially different from the information presented in the Company’s Consolidated Statement of Operations.
Acquisitions. The Company actively reviews acquisition opportunities on an ongoing basis and acquires additional acreage and
producing assets to supplement its existing operations. In addition to the Permian Basin Acquisition and Other Delaware
Acquisition in 2018 and the Midstream Assets Acquisition in 2017, the Company spent $18.7 million and $6.1 million to
purchase certain acreage and producing assets through multiple transactions during the years ended December 31, 2018 and 2017,
respectively.
11. Divestitures
Williston Non-Op Divestiture. On July 10, 2018, the Company completed the initial closing for the sale of certain non-operated oil
and gas properties in the Williston Basin (the “Williston Non-Op Divestiture”). The transaction had an effective date of March 1,
2018, and the final closing statement was completed in the fourth quarter of 2018. The Company recognized a $18.1 million net
gain on sale of properties, which includes customary post close adjustments, in its Consolidated Statements of Operations for the
year ended December 31, 2018. The divested properties were in the Company’s exploration and production segment.
Foreman Butte Divestiture. On July 31, 2018, the Company completed the initial closing for the sale of oil and gas properties and
certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin (the “Foreman Butte
Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in January
2019. During the second quarter of 2018, the Company recorded an impairment loss of $383.4 million, which was included in
impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying value of these assets to their
estimated fair value, determined based on the expected sales price as negotiated with the purchaser, less costs to sell. The
Company recognized a $10.7 million net loss on sale of properties, which includes customary post close adjustments, in its
Consolidated Statements of Operations for the year ended December 31, 2018. The Foreman Butte Divestiture consisted of oil
and gas properties in the Company’s exploration and production segment and included certain other property and equipment in
the Company’s midstream segment.
Other Williston Divestiture. On August 17, 2018, the Company completed the initial closing for the sale of additional non-
strategic oil and gas properties in the Williston Basin (the “Other Williston Divestiture”). The transaction had an effective date of
March 1, 2018, and the final closing statement will be completed in March 2019. The Company recognized a $19.0 million net
gain on sale of properties, which includes, and is subject to further, customary post close adjustments, in its Consolidated
Statements of Operations for the year ended December 31, 2018. The divested properties were in the Company’s exploration and
production segment.
The Company determined that the Williston Non-Op Divestiture, Foreman Butte Divestiture and Other Williston Divestiture did
not represent a strategic shift in its operations or have a significant impact on its financial position or results of operations;
therefore, the Company did not account for these divestitures as discontinued operations.
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12. Long-Term Debt
The Company’s long-term debt consists of the following:
December 31,
2018
2017
Oasis Credit Facility
OMP Credit Facility
Senior unsecured notes
$
(In thousands)
468,000 $
318,000
7.25% senior unsecured notes due February 1, 2019
6.50% senior unsecured notes due November 1, 2021
6.875% senior unsecured notes due March 15, 2022
6.875% senior unsecured notes due January 15, 2023
6.25% senior unsecured notes due May 1, 2026
2.625% senior unsecured convertible notes due September 15, 2023
Total principal of senior unsecured notes
Less: unamortized deferred financing costs on senior unsecured notes
Less: unamortized debt discount on senior unsecured convertible notes
—
71,835
901,480
366,094
400,000
300,000
2,039,409
(20,865)
(69,268)
70,000
78,000
54,275
395,501
937,080
366,094
—
300,000
2,052,950
(22,956)
(80,388)
Total long-term debt
$
2,735,276 $
2,097,606
The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2018 is
$2,735.3 million, which includes $2,039.4 million of senior unsecured notes, reductions for the unamortized debt discount related
to the equity component of the senior unsecured convertible notes and the unamortized deferred financing costs on the senior
unsecured notes of $69.3 million and $20.9 million, respectively, $468.0 million of borrowings under the Oasis Credit Facility
and $318.0 million under the OMP Credit Facility. The Revolving Credit Facilities are recorded at values that approximate fair
value since their variable interest rates are tied to current market rates. The fair value of the Company’s senior unsecured notes,
which are publicly traded and therefore categorized as Level 1 liabilities, was $1,830.4 million at December 31, 2018.
The Company has $71.8 million, $901.5 million, $666.1 million and $400.0 million of Notes maturing in 2021, 2022, 2023 and
2026, respectively, and indebtedness under the Oasis Credit Facility and the OMP Credit Facility that become due in 2023 and
2022, respectively. The Company does not have any other debt that matures within the five years ending December 31, 2023.
Senior secured revolving line of credit. The Company has the Oasis Credit Facility with an overall senior secured line of credit of
$3,000.0 million as of December 31, 2018, which has a maturity date of the earlier of (i) October 16, 2023, (ii) 90 days prior to
the maturity date of the Company’s 2022 and 2023 Senior Notes, of which $1,267.6 million is outstanding, to the extent such
2022 and 2023 Senior Notes are not retired or refinanced to have a maturity date at least 90 days after October 16, 2023 and (iii)
90 days prior to the maturity date of the Company’s 2023 Senior Convertible Notes, of which $300.0 million is outstanding, to the
extent such 2023 Senior Convertible Notes are not retired, converted, redeemed or refinanced to have a maturity date at least 90
days after October 16, 2023.
The Oasis Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on
April 1 and October 1 of each year. On February 26, 2018, the Company entered into an amendment to the Oasis Credit Facility,
resulting in the aggregate elected commitment being increased from $1,150.0 million to $1,350.0 million and two new lenders
being added to the bank group. On April 19, 2018, the lenders under the Oasis Credit Facility (the “Lenders”) completed their
regular semi-annual redetermination of the borrowing base scheduled for April 1, 2018, resulting in the Company entering into
the Twelfth Amendment to the Second Amended and Restated Credit Agreement to the Oasis Credit Facility, which (i) reaffirmed
the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively, (ii) removed the
legacy anti-cash hoarding provisions, (iii) reduced the coverage threshold with respect to mortgaged properties and (iv) amended
the asset sale covenant to give the Company additional flexibility to trade oil and gas properties. In addition, in connection with
such amendment, OP Permian became a guarantor under the Oasis Credit Facility.
On October 16, 2018, the Company entered into a third amended and restated credit agreement (the “Third Amended Credit
Facility”). In connection with entry into the Third Amended Credit Facility, the semi-annual redetermination of the Company’s
borrowing base was completed on October 16, 2018, which reaffirmed the borrowing base and the aggregate elected commitment
at $1,600.0 million and $1,350.0 million, respectively, and the overall credit facility increased from $2,500.0 million to $3,000.0
million. Pursuant to the Third Amended Credit Facility, the credit facility was extended from April
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2020 to October 2023, provided that the Company’s 2022 and 2023 Notes (as defined below) are retired or refinanced 90 days
prior to their respective maturities. All other significant rates, terms and conditions of the Third Amended Credit Facility
remained the same. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2019.
Borrowings under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially
all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least 90% (as of December 31,
2018) of the reserve value as determined by reserve reports.
Borrowings under the Oasis Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings
(including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a London
interbank offered rate (“LIBOR”) loan or a domestic bank prime interest rate loan (defined in the Oasis Credit Facility as an
Alternate Based Rate or “ABR” loan). As of December 31, 2018, any outstanding LIBOR and ABR loans would have borne their
respective interest rates plus the applicable margin indicated in the following table:
Total Commitment Utilization Percentage
Less than 25%
Greater than or equal to 25% but less than 50%
Greater than or equal to 50% but less than 75%
Greater than or equal to 75% but less than 90%
Greater than or equal to 90%
Applicable Margin
for LIBOR Loans
Applicable Margin
for ABR Loans
1.50%
1.75%
2.00%
2.25%
2.50%
0.00%
0.25%
0.50%
0.75%
1.00%
A loan may be repaid at any time before the scheduled maturity of the Oasis Credit Facility upon the Company providing advance
notification to the Lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of
the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a
LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the
maximum available loan term is six months for LIBOR-based loans (or twelve months with the consent of each leader). Interest
for LIBOR loans is paid at the end of the applicable interest period for each loan or every three months for LIBOR loans that have
loan terms greater than three months. At the end of a LIBOR loan term, the Oasis Credit Facility allows the Company to elect to
repay the borrowing, continue a LIBOR loan with the same or differing loan term or convert the borrowing to an ABR loan.
On a quarterly basis, the Company also pays a commitment fee that can range from 0.375% to 0.500% on the average amount of
borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances
outstanding during the quarter.
As of December 31, 2018, the Oasis Credit Facility contained covenants that included, among others:
•
•
•
•
•
•
•
•
•
a prohibition against incurring debt, subject to permitted exceptions;
a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
a prohibition against making investments, loans and advances, subject to permitted exceptions;
restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted
exceptions;
restrictions on merging and selling assets outside the ordinary course of business;
restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
a provision limiting oil and natural gas derivative financial instruments;
a requirement that the Company maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility)
to consolidated Interest Expense (as defined in the Oasis Credit Facility) of no less than 2.5 to 1.0 for the four
quarters ended on the last day of each quarter;
a requirement that the Company maintain a Current Ratio (as defined in the Oasis Credit Facility) of consolidated
current assets (including unused borrowing base committed capacity and with exclusions as described in the Oasis
Credit Facility) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility) of no
less than 1.0 to 1.0 as of the last day of any fiscal quarter; and
/
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•
if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility) exceed 85% of the effective
borrowing base (“Trigger”), the Company is required to maintain a ratio of total debt (as defined in the Oasis Credit
Facility) to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage
Ratio will be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be
tested as long as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and
shall not exceed 4.25 to 1.00 for the first two quarters and 4.00 to 1.00 for each fiscal quarter thereafter.
The Oasis Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may
declare all amounts outstanding under the Oasis Credit Facility to be immediately due and payable.
As of December 31, 2018, the Company had $468.0 million of borrowings and $14.0 million of outstanding letters of credit
issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $868.0 million. As of
December 31, 2017, the Company had $70.0 million of borrowings and $10.5 million of outstanding letters of credit issued under
the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $1,069.5 million. As of December 31,
2018 and 2017, the weighted average interest rate on borrowings under the Oasis Credit Facility was 4.2% and 3.1%, respectively.
The Company was in compliance with the financial covenants of the Oasis Credit Facility as of December 31, 2018 and 2017.
OMP Operating LLC revolving line of credit. On September 25, 2017, OMP entered into a credit agreement (the “OMP Credit
Agreement”) for the OMP Credit Facility, which has a maturity date of September 25, 2022. The OMP Credit Facility is available
to fund working capital and to finance acquisitions and other capital expenditures of OMP.
On August 27, 2018, OMP entered into an amendment to its revolving credit facility (the “First Amended OMP Credit
Agreement”) in order to (i) increase the aggregate amount of commitments from $200.0 million to $250.0 million, (ii) provide for
the ability to further increase commitments and (iii) add six new lenders to the bank group. On November 19, 2018, in connection
with the OMP Dropdown (see Note 3 – Oasis Midstream Partners LP), and pursuant to the terms of the First Amended OMP
Credit Agreement, the aggregate amount of commitments increased from $250.0 million to $400.0 million, and OMP was
provided the ability to further increase the borrowing capacity for the OMP Credit Facility to $600.0 million, subject to certain
conditions.
The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. All
obligations of OMP Operating, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and
several basis by OMP, OMP Operating and Bighorn DevCo.
Borrowings under the OMP Credit Facility bear interest at a rate per annum equal to the applicable margin (as described below)
plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the OMP Credit Agreement) or (ii) with respect
to ABR loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day
plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in
the OMP Credit Agreement). The applicable margin for borrowings under the OMP Credit Facility is determined in accordance
with the OMP Credit Agreement as follows:
Consolidated Total Leverage Ratio
Less than or equal to 3.00 to 1.00
Greater than 3.00 to 1.00 but less than or equal to 3.50 to 1.00
Greater than 3.50 to 1.00 but less than or equal to 4.00 to 1.00
Greater than 4.00 to 1.00 but less than or equal to 4.50 to 1.00
Greater than 4.50 to 1.00
Applicable Margin
for Eurodollar Loans
Applicable Margin
for ABR Loans
1.75%
2.00%
2.25%
2.50%
2.75%
Commitment Fee Rate
0.375%
0.75%
1.00%
1.25%
1.50%
1.75%
0.375%
0.500%
0.500%
0.500%
The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated
total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as
described in the OMP Credit Agreement).
At December 31, 2018, the Company had $318.0 million of borrowings outstanding under the OMP Credit Facility, resulting in
an unused borrowing capacity of $82.0 million. As of December 31, 2018 and 2017, the weighted average interest rate on
borrowings under the OMP Credit Facility was 4.2% and 3.2%, respectively. OMP Operating was in compliance with the
financial covenants of the OMP Credit Facility as of December 31, 2018.
Senior unsecured notes. At December 31, 2018, the Company had $1,739.4 million principal amount of senior unsecured notes
outstanding with maturities ranging from November 2021 to May 2026 and coupons ranging from 6.25% to 6.875% (the “Senior
Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at
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certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and
accrued and unpaid interest to the redemption date.
On May 14, 2018, the Company completed its offering of $400.0 million in aggregate principal amount of its 6.25% senior
unsecured notes due 2026 (the “2026 Notes”). The Company used the net proceeds of $394.4 million from the 2026 Notes to fund
the repurchase of certain outstanding senior notes (the “Tender Offers”), as described below.
On May 25, 2018, the Company completed the Tender Offers and, as a result of the Tender Offers, the Company repurchased an
aggregate principal amount of $390.6 million of its outstanding Senior Notes, consisting of $31.3 million principal amount of
its 7.25% senior unsecured notes due 2019 (the “2019 Notes”), $323.7 million principal amount of its 6.50% senior unsecured
notes due 2021 and $35.6 million principal amount of its 6.875% senior unsecured notes due 2022, for an aggregate cost
of $402.0 million, including accrued interest and fees.
On May 29, 2018, the Company paid $23.0 million to redeem all of the remaining outstanding 2019 Notes, which payment
consisted of the 100% redemption price plus all accrued and unpaid interest on the 2019 Notes. The Company financed
the redemption with borrowings under the Oasis Credit Facility. As a result of the Tender Offers and the redemption, the
Company recognized a pre-tax loss of $13.8 million, which was net of unamortized deferred financing costs write-offs of $4.0
million, and is reflected in loss on extinguishment of debt in the Company’s Consolidated Statements of Operations for the year
ended December 31, 2018. As of December 31, 2018, no 2019 Notes remained outstanding.
The indentures governing the Senior Notes restrict the Company’s ability and the ability of certain of the Company’s subsidiaries
to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity
interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with
another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and
qualifications. If at any time when the Company’s Senior Notes are rated investment grade by both Moody’s Investors Service,
Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of
such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with
the terms of the indentures for the Senior Notes as of December 31, 2018.
Senior unsecured convertible notes. At December 31, 2018, the Company had $300.0 million of 2.625% senior unsecured
convertible notes due September 2023 (the “Senior Convertible Notes”). The Company has the option to settle conversions of
these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent
is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior
Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after
the calendar quarter ending on September 30, 2016 (and only during such calendar quarter), if the last reported sale price of the
Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading
days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the
conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day
period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for
each trading day of the Measurement Period is less than 98% of the product of the last reported sale price of the Company’s
common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events,
including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be
convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity
date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common
stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of
approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued
and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption,
the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with
such corporate event or redemption in certain circumstances. As of December 31, 2018, none of the contingent conditions
allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, the Company was in
compliance with the terms of the indentures for the Senior Convertible Notes as of December 31, 2018.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The
Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which
are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors,
subject to certain customary release provisions. The indentures governing the Notes contain customary events of default.
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Deferred financing costs. As of December 31, 2018, the Company had $31.2 million of deferred financing costs related to the
Notes and the Revolving Credit Facilities. Deferred financing costs of $20.9 million related to the Notes are included in long-term
debt on the Company’s Consolidated Balance Sheets as of December 31, 2018, and are being amortized over the respective terms
of the Notes. Deferred financing costs of $7.9 million and $2.4 million related to the Oasis Credit Facility and OMP Credit
Facility, respectively, are included in other assets on the Company’s Consolidated Balance Sheets at December 31, 2018, and are
being amortized over the term of the Oasis Credit Facility and the OMP Credit Facility. Amortization of deferred financing costs
recorded for the year ended December 31, 2018, 2017 and 2016 was $7.6 million, $7.0 million and $9.8 million, respectively.
These costs are included in interest expense on the Company’s Consolidated Statements of Operations. For the year ended
December 31, 2018, the Company’s interest expense also included $0.3 million for unamortized deferred financing costs related
to the Oasis Credit Facility, which were written off in proportion to the two lenders leaving the bank group. For the year ended
December 31, 2016, the Company’s interest expense also included $1.8 million for unamortized deferred financing costs related
to the Oasis Credit Facility, which were written off in proportion to the decrease in the borrowing base. No deferred financing
costs related to the Revolving Credit Facilities were written off during the year ended December 31, 2017. Aforementioned, the
gain (loss) on extinguishment of debt in the Company’s Consolidated Statements of Operations included unamortized deferred
financing costs write-offs of $4.0 million and $6.4 million related to the repurchased Notes for the years ended December 31,
2018 and 2016, respectively. No deferred financing costs related to the Notes were written off during the year ended
December 31, 2017.
13. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the years ended December 31, 2018 and 2017:
Asset retirement obligation — beginning of period
Liabilities incurred during period(1)
Liabilities settled during period(2)
Accretion expense during period(1)(3)
Revisions to estimates
Asset retirement obligation — end of period
Year Ended December 31,
2018
2017
(In thousands)
48,799 $
5,854
(4,944)
2,657
83
52,449 $
49,687
2,449
(5,743)
2,621
(215)
48,799
$
$
__________________
(1)
Includes costs for wells acquired in the Permian Basin Acquisition (see Note 10 – Acquisitions) as of December 31, 2018.
(2)
Liabilities settled during the years ended December 31, 2018 and 2017 included ARO related to sold properties (see Note
11 – Divestitures).
(3)
Included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations.
At December 31, 2018 and 2017, the current portion of the total ARO balance was approximately $0.1 million and $0.3 million,
respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.
14. Income Taxes
On December 22, 2017, the U.S. government enacted the Tax Act, which made broad and complex changes to the U.S. tax code.
Due to the complexities involved in the accounting for the enactment of the new law, the SEC issued SAB 118, which provides
guidance on the accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend
beyond one year from the Tax Act enactment date to complete the accounting under ASC 740, Income Taxes. In accordance
with SAB 118, the Company was able to make reasonable estimates on certain effects of the Tax Act in the consolidated financial
statements for the year ended December 31, 2017. During the third quarter of 2018, the Company completed the accounting under
the Tax Act and ASC 740. Based on additional guidance issued by the Internal Revenue Service regarding the grandfather
provisions related to certain performance-based compensation awards outstanding as of November 2, 2017, the Company wrote
off $1.9 million of deferred tax assets for which the Company will not receive a future tax deduction.
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The Company’s income tax benefit consists of the following:
Year Ended December 31,
2018
2017
(In thousands)
2016
Current:
Federal
State
Deferred:
Federal
State
$
(70) $
93
23
(420) $
—
(420)
(3,553)
(2,313)
(5,866)
(199,370)
(3,514)
(202,884)
Total income tax benefit
$
(5,843) $
(203,304) $
—
—
—
(117,781)
(10,757)
(128,538)
(128,538)
The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the
years ended December 31, 2018, 2017 and 2016, is set forth below:
Year Ended December 31,
2018
2017
2016
(%)
(In thousands)
(%)
(In thousands)
(%)
(In thousands)
U.S. federal tax statutory rate
21.00 % $
(5,322)
35.00 % $
(26,550)
35.00 % $
(130,044)
State income taxes, net of federal
income tax benefit
2.08 %
(527)
2.59 %
(1,966)
2.27 %
(8,435)
Effects of non-controlling interest
13.09 %
(3,317)
1.68 %
(1,278)
— %
Non-deductible executive
compensation
Equity-based compensation windfall
(shortfall)
State deferred tax rate change
Change in valuation allowance
Impact of U.S. tax reform
Other
(9.50)%
2,408
1.05 %
(792)
(0.21)%
(3.68)%
932
0.87 %
(659)
(1.83)%
6,808
13.73 %
(6.74)%
(7.34)%
0.41 %
(3,479)
1,707
0.36 %
— %
(270)
—
1,859
226.61 %
(171,900)
— %
— %
— %
—
—
—
(104)
(0.15)%
111
(0.64)%
2,337
—
796
Annual effective tax benefit
23.05 % $
(5,843)
268.01 % $
(203,304)
34.59 % $
(128,538)
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Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2018 and 2017, were as follows:
Deferred tax assets
Net operating loss carryforward
Bonus and equity-based compensation
Derivative instruments
Other tax attribute carryovers
Total deferred tax assets
Less: Valuation allowance
Net deferred tax assets
Deferred tax liabilities
Oil and natural gas properties
Derivative instruments
Investment in partnerships
Other deferred tax liabilities
Total deferred tax liabilities
Year Ended December 31,
2018
2017
(In thousands)
$
177,745 $
8,436
—
856
187,037
(2,863)
184,174
423,270
22,834
22,450
15,675
484,229
300,055 $
182,633
10,100
30,397
1,099
224,229
(1,159)
223,070
485,132
—
25,490
18,369
528,991
305,921
Total net deferred tax liabilities
$
As of December 31, 2018, the Company had federal net operating loss carryforwards of $744.2 million, which expire between
2033 and 2037, and $600.2 million of state net operating loss carryforwards, which expire between 2020 and 2037. The tax
benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to
be more likely than not, and when the future utilization of some portion of the carryforwards is determined not to be more likely
than not a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2018 and
2017, the Company’s valuation allowance balance was $2.9 million and $1.2 million, respectively, against Montana net operating
loss carryforwards and certain other tax attribute carryforwards as the benefit for those is not expected to be realized prior to their
expiration due to their short carryover periods, current economic conditions and expectations for the future. The net increase of
$1.7 million of valuation allowance in 2018 is primarily related to additional valuation allowance on deferred tax assets for
Montana net operating loss carryforwards. No valuation allowances are required for U.S. federal and North Dakota tax net
operating loss carryforwards as they are expected to be fully utilized before their expiration.
Due to the adoption of ASU 2016-09, unrealized excess tax benefits of $10.6 million were realized in the cumulative-effect
adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet in the first quarter of 2017 and
increased the deferred tax asset.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial
statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2018,
the Company had no unrecognized tax benefits. With respect to income taxes, the Company’s policy is to account for interest
charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The Company files
income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. The statute of limitation for the year
ended December 31, 2018 will expire in 2022. The Company’s earliest open year in its key jurisdictions is 2015 for both the U.S.
federal jurisdiction and various U.S. states, however, net operating losses originating in 2010 and all subsequent periods are
subject to examination when utilized.
15. Equity-Based Compensation
Restricted stock awards. The Company has granted restricted stock awards to employees and directors under its Amended and
Restated 2010 Long Term Incentive Plan, the majority of which vest over a three-year period. The maximum number of shares
available for grant under the Amended and Restated 2010 Long Term Incentive Plan is 16,050,000. The fair value of restricted
stock grants is based on the closing sales price of the Company’s common stock on the date of grant. Compensation expense is
recognized ratably over the requisite service period.
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The following table summarizes information related to restricted stock held by the Company’s employees and directors for the
periods presented:
Non-vested shares outstanding December 31, 2017
Granted
Vested
Forfeited
Non-vested shares outstanding December 31, 2018
Shares
3,741,898 $
3,546,280
(1,826,855)
(324,767)
5,136,556 $
Weighted Average
Grant Date
Fair Value per Share
10.78
10.20
9.71
10.03
10.81
Equity-based compensation expense recorded for restricted stock awards was $20.1 million, $19.5 million and $20.0 million for
each of the years ended December 31, 2018, 2017 and 2016, respectively, and is included in general and administrative expenses
on the Company’s Consolidated Statements of Operations. The fair value of awards vested was $17.3 million, $22.0 million and
$6.9 million for the years ended December 31, 2018, 2017 and 2016, respectively. The weighted average grant date fair value of
restricted stock awards granted was $10.20 per share, $15.03 per share and $5.63 per share for the years ended December 31,
2018, 2017 and 2016, respectively. Unrecognized expense as of December 31, 2018 for all outstanding restricted stock awards
was $34.2 million and will be recognized over a weighted average period of 2.0 years.
Performance share units. The Company has granted PSUs to officers of the Company under its Amended and Restated 2010
Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to
receive one share of the Company’s common stock.
The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based
payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total
shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a
defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined
peer group, award recipients will earn between 0% and 200% of the initial PSUs granted. All compensation expense related to the
PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.
The following table summarizes information related to PSUs held by the Company’s officers for the periods presented:
Non-vested PSUs at December 31, 2017
Granted
Vested
Forfeited
Non-vested PSUs at December 31, 2018
Units
Weighted Average
Grant Date
Fair Value per Unit
1,872,710 $
854,400
(564,068)
(130,830)
2,032,212 $
11.10
12.71
7.01
41.71
10.94
Equity-based compensation expense recorded for PSUs for the years ended December 31, 2018, 2017 and 2016 was $8.5 million,
$6.7 million and $4.2 million, respectively, and is included in general and administrative expenses on the Company’s
Consolidated Statements of Operations. The fair value of PSUs vested was $5.3 million and $1.0 million for the years ended
December 31, 2018 and 2016, respectively. No PSUs vested during the year ended December 31, 2017. The weighted average
grant date fair value of PSUs granted was $12.71 per share, $16.89 per share and $3.00 per share for the years ended December
31, 2018, 2017 and 2016, respectively. Unrecognized expense as of December 31, 2018 for all outstanding PSUs was $10.0
million and will be recognized over a weighted average period of 2.8 years.
The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The
Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a
probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free
interest rate, volatility and correlation coefficients. The risk-free interest rate is the U.S. Treasury bond rate on the date of grant
that corresponds to the total performance period. The initial value is the average of the volume weighted average prices for the 30
trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation
of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation
coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated
based on historical stock price data.
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The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-
based compensation expense of the PSUs granted during the periods presented:
Forecast period (years)
Risk-free interest rate
Oasis stock price volatility
2018
2 - 4
2017
2 - 4
2.08% - 2.31%
1.18% - 1.66%
72.88%
17.16%
2016
4
1.25%
59.38%
Associated tax benefit. For the years ended December 31, 2018, 2017 and 2016, the Company had an associated tax benefit of
$6.8 million, $6.3 million and $8.3 million, respectively, related to all equity-based compensation.
OMP phantom unit awards. The Company has granted OMP Phantom Unit Awards to employees under its Amended and
Restated 2010 Long Term Incentive Plan in 2018, and under the OMP LTIP in 2017.
As of December 31, 2018, the aggregate number of common units that may be issued pursuant to any and all awards under the
OMP LTIP is equal to 2,117,618 common units, subject to adjustment due to recapitalization or reorganization, or related to
forfeitures or expiration of awards, as provided under the OMP LTIP. On January 1 of each calendar year following the adoption
and prior to the expiration of the OMP LTIP, the total number of common units that may be issued pursuant to the OMP LTIP
automatically increases by a number of common units equal to one percent of the number of common units outstanding on a fully
diluted basis as of the close of business on the immediately preceding December 31 (calculated by adding to the number of
common units outstanding, all outstanding securities convertible into common units on such date on an as converted basis). As a
result of this adjustment, an additional 337,790 common units were reserved for issuance pursuant to awards under the OMP LTIP
on January 1, 2019.
Each OMP Phantom Unit represents the right to receive, upon vesting of the award, a cash payment equal to the fair market value
of one OMP common unit on the day prior to the date it vests (the “Vesting Date”). Award recipients are also entitled to
Distribution Equivalent Rights (“DER”) with respect to each OMP Phantom Unit received. Each DER represents the right to
receive, upon vesting of the award, a cash payment equal to the value of the distributions paid on one OMP common unit between
the Grant Date and the applicable Vesting Date. The OMP Phantom Unit Awards vest in equal amounts each year over a three-
year period, and compensation expense will be recognized over the requisite service period and is included in general and
administrative expenses on the Company’s Consolidated Statements of Operations.
The OMP Phantom Unit Awards are accounted for as liability-classified awards since the awards will settle in cash, and equity-
based compensation cost is accounted for under the fair value method in accordance with GAAP. Under the fair value method for
liability-classified awards, compensation cost is remeasured each reporting period at fair value based upon the closing price of a
publicly traded common unit. The Company will directly pay, or will reimburse OMP, for the cash settlement amount of these
awards.
The following table summarizes information related to OMP Phantom Unit Awards held by certain employees of Oasis for the
periods presented:
Non-vested units outstanding December 31, 2017
Granted
Vested
Forfeited
Non-vested units outstanding December 31, 2018
Phantom Units
99,100 $
87,480
(29,254)
(14,237)
143,089 $
Weighted Average Grant
Date Fair Value per Unit
16.40
23.91
16.40
17.86
20.85
Equity-based compensation expense recorded for the OMP Phantom Unit Awards for the years ended December 31, 2018 and
2017 was $0.5 million and $0.1 million, respectively. The Company did not record any equity-based compensation expenses
related to the OMP Phantom Unit Awards for the year ended December 31, 2016 because these awards were first granted in the
fourth quarter of 2017. The fair value of OMP Phantom Unit Awards vested was $0.6 million for the year ended December 31,
2018. No OMP Phantom Unit Awards vested during the years ended December 31, 2017 and 2016. For the years ended
December 31, 2018 and 2017, the weighted average grant date fair value of OMP Phantom Unit Awards granted was $16.40 per
unit for both periods. As of December 31, 2018, unrecognized compensation cost for all outstanding OMP Phantom Unit Awards
was $2.1 million, which is expected to be recognized over a weighted average period of 2.3 years.
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OMP restricted unit awards. OMP has granted to independent directors of the general partner restricted unit awards under the
OMP LTIP, which vest over a one-year period. These awards are accounted for as equity-classified awards since the awards will
settle in common units upon vesting. Equity-based compensation expense is accounted for under the fair value method in
accordance with GAAP. Under the fair value method for equity-classified awards, equity-based compensation expense is
measured at the grant date based on the fair value of the award and is recognized over the vesting period.
The following table summarizes information related to restricted units held by certain directors of OMP for the periods presented:
Non-vested units outstanding December 31, 2017
Granted
Vested
Forfeited
Non-vested units outstanding December 31, 2018
Restricted Units
11,766 $
17,260
(11,766)
—
17,260 $
Weighted Average Grant
Date Fair Value per Unit
17.00
17.55
17.00
—
17.55
Equity-based compensation expense recorded for OMP restricted unit awards for the years ended December 31, 2018 and 2017
was $0.4 million and $0.1 million, respectively, and is included in general and administrative expenses on the Company’s
Consolidated Statements of Operations. The Company did not record any equity-based compensation related to the OMP
restricted unit awards during the year ended December 31, 2016 because these awards were first granted in the third quarter of
2017. The fair value of OMP restricted unit awards vested was $0.3 million for the year ended December 31, 2018. No OMP
restricted unit awards vested during the years ended December 31, 2017 and 2016. The weighted average grant date fair value of
OMP restricted unit awards granted was $17.55 per unit and $17.00 per unit for the years ended December 31, 2018 and 2017,
respectively. Unrecognized expense as of December 31, 2018 for all outstanding OMP restricted unit awards was $0.1 million,
and will be recognized over a weighted average period of 0.4 years.
16. Common Stock
On December 13, 2017, the Company completed a public offering of 32,000,000 shares of its common stock at a purchase price
to the public of $9.55 per share. Net proceeds from the offering were $302.6 million, after deducting underwriting discounts and
commissions, of which $0.3 million is included in common stock and $302.3 million is included in additional paid-in capital on
the Company’s Consolidated Balance Sheets. The Company used the net proceeds to fund a portion of the Permian Basin
Acquisition, but was initially used to repay borrowings from the Oasis Credit Facility prior to the close of the Permian Basin
Acquisition. Upon closing on February 14, 2018, the Company also issued 46,000,000 shares of its common stock to Forge
Energy to fund a portion of the Permian Basin Acquisition (see Note 10 – Acquisitions).
This public offering was made pursuant to effective shelf registration statements on Forms S-3 filed with the SEC on July 15,
2014 and July 14, 2017, as applicable.
Dividends. The Company has not paid any cash dividends since its inception. Covenants contained in the Revolving Credit
Facilities and the indentures governing the Company’s Senior Notes restrict the payment of cash dividends on its common stock.
The Company currently intends to retain all future earnings for the development of its business, and the Company does not
anticipate declaring or paying any cash dividends to holders of its common stock in the foreseeable future.
17. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis common stockholders by the
weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share
includes the potential dilutive impact of unvested restricted stock awards, contingently issuable shares related to PSUs and senior
convertible notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income (loss)
attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share.
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The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented:
Basic weighted average common shares outstanding
Dilutive effect of restricted stock awards and PSUs(1)
Diluted weighted average common shares outstanding
Year Ended December 31,
2018
2017
(In thousands)
2016
307,480
—
307,480
234,986
2,889
237,875
183,615
—
183,615
__________________
(1)
No unvested stock awards were included in computing loss per share for the years ended December 31, 2018 and 2016
because the effect was anti-dilutive.
During the years ended December 31, 2018 and 2016, the Company incurred a net loss, and therefore the diluted loss per share
calculation for those periods excludes the anti-dilutive effect of unvested stock awards. In addition, the diluted earnings per share
calculation for the year ended December 31, 2017 excludes the dilutive effect of unvested stock awards that were anti-dilutive
under the treasury stock method. The following is a calculation of weighted average common shares excluded from diluted
earnings (loss) per share due to the anti-dilutive effect:
Restricted stock awards and PSUs
Year Ended December 31,
2018
2017
(In thousands)
2016
6,980
2,881
5,075
The Company issued its Senior Convertible Notes in September 2016 (see Note 12 — Long-Term Debt). The Company has the
option to settle conversions of its Senior Convertible Notes with cash, shares of common stock or a combination of cash and
common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon
conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes
(conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of December
31, 2018, 2017 and 2016, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no
impact to diluted earnings per share for years ended December 31, 2018, 2017 and 2016.
18. Business Segment Information
The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas
properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The
Company’s midstream services business segment (“OMS”) performs produced and flowback water gathering and disposal
services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other
midstream services for the Company’s oil and natural gas wells operated by OPNA and other third-party operators. Revenues for
the midstream segment are primarily derived from produced and flowback water pipeline transport, produced and flowback water
disposal, fresh water sales, natural gas gathering and processing and crude oil gathering, blending, stabilization and
transportation. The Company’s well services business segment (“OWS”) performs completion services for the Company’s oil and
natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product
sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working
interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are
included in the Company’s Consolidated Statements of Operations. These segments represent the Company’s three operating
units, each offering different products and services. The Company’s corporate activities have been allocated to the supported
business segments accordingly. Management evaluates the performance of the Company’s business segments based on operating
income, which is defined as segment operating revenues less operating expenses, including depreciation, depletion and
amortization (“DD&A”).
For the year ended December 31, 2017, the Company has revised the consolidated financial statements and business segment
financial information to reflect the correction of errors, which are included in the Company’s exploration and production segment
and had no effect on operating income. Please see Note 2 — Summary of Significant Accounting Policies for more information
related to the revision.
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The following table summarizes financial information for the Company’s three business segments for the periods presented:
Exploration and
Production
Midstream
Services
Well Services
(In thousands)
Eliminations
Consolidated
Year Ended December 31, 2018
Revenues from external customers
$
2,136,735 $
124,137 $
61,075 $
— $
2,321,947
Inter-segment revenues
Total revenues
Operating income (loss)
Other income (expense)
Income (loss) before income taxes
including non-controlling interests
Total assets(1)
$
$
Property, plant and equipment, net
Capital expenditures(2)
Depreciation, depletion and
amortization
General and administrative
Equity-based compensation
Impairment
Year Ended December 31, 2017
—
2,136,735
(25,027)
(142,265)
162,505
286,642
143,126
(2,125)
144,544
205,619
30,988
35
(307,049)
—
(307,049)
2,321,947
(30,075)
—
119,012
(144,355)
(167,292)
$
141,001
$
31,023
$
(30,075)
$
(25,343)
6,838,987 $
920,619 $
48,150 $
(181,614) $
7,626,142
6,311,566
1,948,076
893,285
277,626
38,871
7,831
(216,613)
(30,080)
7,027,109
2,203,453
618,402
29,282
15,698
(27,086)
102,482
27,910
384,228
24,700
1,547
—
23,282
1,588
—
(29,118)
(1,772)
—
636,296
121,346
29,273
384,228
Revenues from external customers
$
1,168,176 $
72,752 $
52,791 $
— $
1,293,719
Inter-segment revenues
Total revenues
Operating income
Other income (expense)
Income (loss) before income taxes
including non-controlling interests
Total assets(1)
$
$
—
1,168,176
40,694
(219,823)
113,047
185,799
102,377
(37)
95,345
148,136
15,057
34
(208,392)
—
(208,392)
1,293,719
(14,160)
—
143,968
(219,826)
(179,129)
$
102,340
$
15,091
$
(14,160)
$
(75,858)
6,058,054 $
663,614 $
52,800 $
(151,539) $
6,622,929
Property, plant and equipment, net
Capital expenditures(2)
5,663,323
602,734
649,923
235,090
46,779
12,537
(186,539)
6,173,486
(14,157)
836,204
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Depreciation, depletion and
amortization
General and administrative
Equity-based compensation
Impairment
Year Ended December 31, 2016
519,853
15,999
12,939
(17,989)
530,802
77,560
25,436
6,887
19,583
1,461
—
24,359
1,264
—
(29,705)
(1,627)
—
91,797
26,534
6,887
Revenues from external customers
$
635,505 $
35,406 $
33,754 $
— $
704,665
Inter-segment revenues
Total revenues
Operating income (loss)
Other income (expense)
$
$
Income (loss) before income taxes
Total assets(1)
Property, plant and equipment, net
Capital expenditures(2)
Depreciation, depletion and
amortization
General and administrative
Equity-based compensation
Impairment
__________________
(1)
—
635,505
(196,179)
(240,290)
85,447
120,853
68,868
(474)
59,595
93,349
3,428
43
(145,042)
(145,042)
(6,950)
—
(436,469) $
68,394 $
3,471 $
(6,950) $
—
704,665
(130,833)
(240,721)
(371,554)
5,868,747 $
431,095 $
51,167 $
(172,377) $
6,178,632
5,620,558
1,017,411
424,197
170,386
47,189
(172,377)
680
(6,950)
5,919,567
1,181,527
467,894
8,525
14,892
(14,980)
476,331
78,995
23,346
2,253
12,112
911
2,431
24,427
1,515
—
(26,192)
(1,669)
—
89,342
24,103
4,684
Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to)
parent and not included in total assets.
(2)
Capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures
and acquisitions of oil and gas properties shown in the Company’s Consolidated Statements of Cash Flows because
amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital
expenditures, while the amounts presented in the Consolidated Statements of Cash Flows are presented on a cash basis.
Acquisitions totaled $951.9 million, $54.0 million and $781.5 million for the years ended December 31, 2018, 2017 and
2016, respectively, in the exploration and production segment. Additionally, capital expenditures (including acquisitions)
reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian
Basin Acquisition for the year ended December 31, 2018.
19. Significant Concentrations
Major customers. For the year ended December 31, 2018, no purchaser accounted for more than 10% of the Company’s total
sales. For the year ended December 31, 2017, sales to Shell Trading (US) Company accounted for approximately 16% of the
Company’s total sales. For the year ended December 31, 2016, sales to PBF Holding Company LLC accounted for approximately
10% of the Company’s total sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years
ended December 31, 2017 and 2016. Total sales include revenues from the Company’s exploration and production segment only,
as OMS and OWS provide services to OPNA.
Substantially all of the Company’s accounts receivable result from sales of oil and natural gas as well as joint interest billings
(“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company.
Burlington Resources Oil & Gas LP accounted for approximately 11% of the Company’s JIB receivables balance at December 31,
2018. Continental Resources, Inc. accounted for approximately 13% of the Company’s JIB receivables balance at December 31,
2017.
This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or
negatively, in that these entities may be similarly affected by changes in economic or other conditions, including the current
downturn in oil prices. Management believes that the loss of any of these purchasers would not have a material adverse effect on
the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing
regions.
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20. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of December 31, 2018. The commitments under
these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent
undiscounted cash flows on a gross basis and no inflation elements have been applied.
Lease obligations. The Company has operating leases for office space and other property and equipment used in its operations,
which it accounts for as operating leases in accordance with GAAP. For the years ended December 31, 2018, 2017 and 2016, the
Company incurred operating rental expenses of $10.6 million, $6.9 million and $6.3 million, respectively, which were included in
general and administrative expenses on its Consolidated Statements of Operations.
Future minimum annual rental commitments under non-cancelable leases at December 31, 2018 are as follows:
2019
2020
2021
2022
2023
Thereafter
(In thousands)
8,723
7,009
6,005
5,130
4,361
13,134
44,362
$
$
Volume commitment agreements. As of December 31, 2018, the Company had certain agreements with an aggregate requirement
to deliver, transport or purchase a minimum quantity of approximately 46.1 MMBbl of crude oil, 42.8 MMBbl of natural gas
liquids, 879.5 Bcf of natural gas and 28.0 MMBbl of water, prior to any applicable volume credits, within specified timeframes,
all of which are ten years or less. For the years ended December 31, 2018, 2017 and 2016, the Company incurred transportation
and purchase costs of $21.1 million, $14.8 million and $16.1 million, respectively, related to these agreements. The future
commitments under certain agreements cannot be estimated as they are based on fixed differentials relative to a commodity index
price under the agreements as compared to the differential relative to a commodity index price for the Williston Basin for the
production month.
The estimable future commitments under these volume commitment agreements as of December 31, 2018 are as follows:
2019
2020
2021
2022
2023
Thereafter
(In thousands)
82,083
74,523
105,760
96,693
78,505
190,396
627,960
$
$
Subsequent to December 31, 2018, the Company entered into new agreements to deliver, transport, or purchase additional
volumes of 12.0 MMBbl of water, 9.1 MMBbl of crude oil and 0.2 Bcf of natural gas within specified timeframes, all of which
are less than seven years. The estimable future commitments under these volume commitment agreements were approximately
$72.9 million. The future commitments under certain agreements cannot be estimated as they are based on fixed differentials
relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for
the Williston Basin for the production month.
The Company enters into long-term contracts to provide production flow assurance in over-supplied basins and/or areas with
limited infrastructure. This strategic tactic provides for optimization of transportation and processing costs. As properties are
undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production
volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments
in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include
any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted
with accuracy the amount and timing of any such penalties incurred.
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Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course
of business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, the Company believes
that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate,
will not have a material adverse effect on its financial condition, results of operations or cash flows. When the Company
determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for
such contingencies based on its best estimate using information available at the time. The Company discloses contingencies
where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy
Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and Oasis Midstream Services LLC, seeking monetary
damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum
North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada
asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically,
Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s
midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under
certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain
Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) overstating the estimated costs of proposed
well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at
Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and
Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding
proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well
at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the
Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right
to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and
gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the
Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the
midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by
charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be
paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for
midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings,
Mirada alleged new legal theories for being entitled to enforce the underlying contracts and added Bighorn DevCo, Bobcat
DevCo and Beartooth DevCo as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual
obligations owed to Mirada.
On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests
in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition
that added Oasis Midstream Partners LP as a defendant, asserting that it was created in bad faith in an effort to avoid contractual
obligations owed to Mirada.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the
applicable agreements and that some of Mirada’s claims are grounded in agreements that do not apply to the Company. The
Company filed answers denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims.
OMP has not yet filed an answer because it has not yet been served with process. Discovery is ongoing, and each of the parties
has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the
claim. Trial was previously scheduled for May 2019, but, in connection with a request by the parties to continue the trial until a
later date, the trial is now scheduled for February 20, 2020. The Company cannot predict or guarantee the ultimate outcome or
resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were
forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the
Company’s business, financial condition, results of operations or cash flows. Such an adverse determination could materially
impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on
its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations
could materially reduce the interests of the Company in their current assets and future midstream opportunities and related
revenues in Wild Basin. In addition, the Company has agreed to indemnify OMP for any losses resulting from this litigation under
the omnibus agreement it entered into with OMP at the time of OMP’s initial public offering.
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21. Subsequent Events
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required
recognition or disclosure in the financial statements, other than as previously disclosed or disclosed below.
2019 Capital Expenditures Arrangement
On February 22, 2019, the Company entered into the MOU with OMP regarding the 2019 Capital Expenditures Arrangement,
which outlines the funding of Bobcat DevCo’s expansion capital expenditures for the 2019 calendar year. As of December 31,
2018, OMS owned a 75% interest in Bobcat DevCo and OMP indirectly owned the remaining 25% interest. Pursuant to the
Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC, as amended (the “First A&R Bobcat
LLCA”), OMS and OMP are each required to make pro-rata capital contributions to Bobcat DevCo in accordance with their
respective percentage interests in Bobcat DevCo.
Pursuant to the MOU, OMP agreed to make up to $80 million of the capital contributions to Bobcat DevCo that OMS would
otherwise be required to contribute under the First A&R Bobcat LLCA. In connection with execution of the MOU, OMS and
OMP have amended the First A&R Bobcat LLCA and entered into the Second Amended and Restated Limited Liability
Company Agreement of Bobcat DevCo (the “Second A&R Bobcat LLCA”). The Second A&R Bobcat LLCA includes provisions
applicable to the disproportionate capital contributions that OMP will make to Bobcat DevCo in connection with the 2019 Capital
Expenditures Arrangement.
Pursuant to the Second A&R Bobcat LLCA, upon the occurrence of a disproportionate capital contribution, OMS’s percentage
interest and OMP’s percentage interest in Bobcat DevCo will be adjusted to take into account the amount of the disproportionate
capital contribution and the fair market value of Bobcat DevCo’s assets at the time of any such contribution. Under the MOU, the
Company and OMS have also agreed to a fair market value of Bobcat DevCo’s assets that will be used for the purposes of
redetermining percentage interests in connection with the 2019 Capital Expenditures Arrangement. While the Second A&R
Bobcat LLCA also contains provisions allowing a member to convert a disproportionate capital contribution to a pro-rata
contribution in certain circumstances, OMS has agreed to waive its right to make such an election during the 2019 calendar year
in the MOU. As a result of the 2019 Capital Expenditures Arrangement, the Company expects OMS’s percentage interest
ownership in Bobcat DevCo to decrease from 75% to between approximately 64% and 66% by the end of the 2019 calendar year.
The 2019 Capital Expenditures Arrangement did not have a material impact on the Company’s consolidated financial statements.
Separate from the 2019 Capital Expenditures Arrangement and the agreements contained in the MOU, OMS and OMP may from
time to time agree to fund certain special projects of Bobcat DevCo (“Bobcat Special Projects”) at ratios other than that reflected
by their respective percentage interest ownership in Bobcat DevCo and without readjustments to their respective percentage
interests. In general, OMP might agree to fund a Bobcat Special Project in excess of its pro-rata share of the relevant capital
expenditures to the extent OMP expects to receive a disproportionate benefit from such capital expenditures. The Second A&R
Bobcat LLCA also amended the First A&R Bobcat LLCA to include provisions related to the funding of any Bobcat Special
Projects.
The terms of the 2019 Capital Expenditures Arrangement were approved by the Board of Directors of the general partner of OMP
following a unanimous recommendation for approval from the conflicts committee of the Board of Directors of the general
partner of OMP, which consists entirely of independent directors. The conflicts committee was advised by Baird on financial
matters and Richards, Layton & Finger, P.A. on legal matters. Oasis was advised by Vinson and Elkins L.L.P. on legal matters.
Amended and restated bylaws
On February 22, 2019, the Board of Directors amended and restated the Company’s bylaws to implement “proxy access” bylaw
provisions. Under the new proxy access provisions, eligible shareholders, or an eligible group of up to 20 shareholders, owning
3% or more of the Company’s outstanding common stock continuously for at least three years will have the ability to nominate
and include in the Company’s proxy materials for annual meetings occurring after the 2019 annual meeting qualifying director
nominees constituting up to the greater of two directors and 20% of the number of directors currently serving on the Board,
provided that the shareholder(s) and the nominee(s) satisfy the requirements specified in the amended and restated bylaws. This
description is qualified in its entirety by reference to the text of the amended and restated bylaws, which is incorporated by
reference as Exhibit 3.2 to this Annual Report on Form 10-K.
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22. Condensed Consolidating Financial Statements
The Notes (see Note 12 — Long-Term Debt) are guaranteed on a senior unsecured basis by the Guarantors, which are 100%
owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the
Company’s operating units, including OMP (see Note 3 – Oasis Midstream Partners LP), which is accounted for on a
consolidated basis, do not guarantee the Notes (“Non-Guarantor Subsidiaries”).
The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc.
(“Issuer”), its Guarantors on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity
basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation
S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the
Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each
of the Guarantors because it believes such financial and narrative information would not provide any additional information that
would be material in evaluating the sufficiency of the Guarantors.
For the year ended December 31, 2017, the Company has revised the condensed consolidating financial statements to reflect the
correction of errors, which had no effect on the Company’s net income. All impacts of the revision are included in the Combined
Guarantor Subsidiaries financial information. Please see Note 2 — Summary of Significant Accounting Policies for more
information related to the revision.
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ASSETS
Current assets
Cash and cash equivalents
Accounts receivable, net
Condensed Consolidating Balance Sheet
December 31, 2018
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Combined Non-
guarantor
Subsidiaries
Intercompany
Eliminations
Consolidated
(In thousands, except share data)
$
179 $
15,362 $
6,649 $
— $
22,190
—
385,121
2,481
—
387,602
Accounts receivable - affiliates
643,382
Inventory
Prepaid expenses
Derivative instruments
Intangible assets, net
Other current assets
Total current assets
Property, plant and equipment
Oil and gas properties (successful efforts
method)
—
373
—
—
—
76,127
33,106
9,206
99,930
125
183
80,805
(800,314)
22
1,418
—
—
—
—
—
—
—
—
—
33,128
10,997
99,930
125
183
643,934
619,160
91,375
(800,314)
554,155
—
8,923,291
—
(11,102)
8,912,189
Other property and equipment
—
218,617
933,155
—
1,151,772
Less: accumulated depreciation, depletion,
amortization and impairment
Total property, plant and equipment, net
—
(2,974,122)
(62,730)
—
(3,036,852)
—
6,167,786
870,425
(11,102)
7,027,109
Investments in and advances to subsidiaries
4,910,111
367,141
Derivative instruments
Deferred income taxes
Long-term inventory
Other assets
Total assets
LIABILITIES AND STOCKHOLDERS’
EQUITY
Current liabilities
Accounts payable
Accounts payable - affiliates
Revenues and production taxes payable
Accrued liabilities
Accrued interest payable
Derivative instruments
Advances from joint interest partners
Total current liabilities
Long-term debt
Deferred income taxes
Asset retirement obligations
Derivative instruments
Other liabilities
Total liabilities
Stockholders’ equity
—
219,670
—
—
6,945
—
12,260
23,221
—
—
—
—
2,452
(5,277,252)
—
(219,670)
—
—
—
6,945
—
12,260
25,673
$ 5,773,715 $ 7,196,513 $
964,252 $ (6,308,338) $ 7,626,142
$
— $
18,567 $
1,599 $
— $
20,166
43,113
—
71
37,096
—
—
724,187
216,114
273,923
502
84
5,140
33,014
(800,314)
581
57,657
442
—
—
—
—
—
—
—
—
216,695
331,651
38,040
84
5,140
80,280
1,238,517
93,293
(800,314)
611,776
1,949,276
—
—
—
—
468,000
519,725
50,870
20
7,751
318,000
—
2,735,276
—
(219,670)
1,514
—
—
—
—
—
300,055
52,384
20
7,751
2,029,556
2,284,883
412,807
(1,019,984)
3,707,262
Capital contributions from affiliates
—
3,226,837
177,049
(3,403,886)
—
Common stock, $0.01 par value: 900,000,000
shares authorized; 320,469,049 shares issued
and 318,377,161 shares outstanding
3,157
—
—
—
3,157
/
Treasury stock, at cost: 2,091,888 shares
Additional paid-in-capital
Retained earnings
(29,025)
3,078,203
—
8,295
—
—
—
(29,025)
(8,743)
3,077,755
691,824
1,492,194
61,581
(1,562,910)
682,689
Oasis share of stockholders’ equity
3,744,159
4,727,326
238,630
(4,975,539)
3,734,576
Non-controlling interests
Total stockholders’ equity
—
184,304
312,815
(312,815)
184,304
3,744,159
4,911,630
551,445
(5,288,354)
3,918,880
Total liabilities and stockholders’ equity
$ 5,773,715 $ 7,196,513 $
964,252 $ (6,308,338) $ 7,626,142
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Condensed Consolidating Balance Sheet
December 31, 2017
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Combined Non-
guarantor
Subsidiaries
Intercompany
Eliminations
Consolidated
(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable, net
$
178 $
15,659 $
—
370,545
Accounts receivable - affiliates
425,668
—
267
—
—
46,020
19,367
6,586
344
193
883 $
834
— $
—
85,818
(557,506)
—
778
—
—
—
—
—
—
16,720
371,379
—
19,367
7,631
344
193
426,113
458,714
88,313
(557,506)
415,634
—
7,840,921
—
(1,966)
7,838,955
Inventory
Prepaid expenses
Derivative instruments
Other current assets
Total current assets
Property, plant and equipment
Oil and gas properties (successful efforts
method)
Other property and equipment
—
214,818
653,928
—
868,746
Less: accumulated depreciation, depletion,
amortization and impairment
—
(2,499,867)
(34,348)
—
(2,534,215)
Total property, plant and equipment, net
—
5,555,872
619,580
(1,966)
6,173,486
Investments in and advances to subsidiaries
4,790,976
422,132
Derivative instruments
Deferred income taxes
Long-term inventory
Other assets
Total assets
LIABILITIES AND STOCKHOLDERS’
EQUITY
Current liabilities
Accounts payable
Accounts payable - affiliates
Revenues and production taxes payable
Accrued liabilities
Accrued interest payable
Derivative instruments
Advances from joint interest partners
Other current liabilities
Total current liabilities
Long-term debt
Deferred income taxes
Asset retirement obligations
Derivative instruments
Other liabilities
Total liabilities
Stockholders’ equity
—
183,568
—
—
9
—
12,200
19,587
—
—
—
—
2,013
(5,213,108)
—
(183,568)
—
9
—
—
—
12,200
21,600
$
5,400,657 $
6,468,514 $
709,906 $ (5,956,148) $
6,622,929
$
— $
13,370 $
— $
— $
13,370
34,382
—
216
38,796
—
—
—
511,486
213,995
185,245
53
115,716
4,916
40
11,638
(557,506)
—
58,818
114
—
—
—
—
—
—
—
—
—
—
213,995
244,279
38,963
115,716
4,916
40
73,394
1,044,821
1,949,606
—
—
—
—
70,000
489,489
47,195
19,851
6,182
70,570
78,000
(557,506)
631,279
—
2,097,606
—
(183,568)
305,921
1,316
—
—
—
—
—
48,511
19,851
6,182
2,023,000
1,677,538
149,886
(741,074)
3,109,350
Capital contributions from affiliates
—
3,264,691
234,935
(3,499,626)
Common stock, $0.01 par value:
450,000,000 shares authorized;
2,668
—
—
—
—
2,668
/
270,627,014 shares issued and 269,295,466
shares outstanding
Treasury stock, at cost: 1,331,548 shares
Additional paid-in-capital
Retained earnings
(22,179)
2,677,217
—
8,922
—
—
—
(22,179)
(8,922)
2,677,217
719,951
1,379,475
11,639
(1,393,080)
717,985
Oasis share of stockholders’ equity
3,377,657
4,653,088
246,574
(4,901,628)
3,375,691
Non-controlling interests
Total stockholders’ equity
—
137,888
313,446
(313,446)
137,888
3,377,657
4,790,976
560,020
(5,215,074)
3,513,579
Total liabilities and stockholders’ equity $
5,400,657 $
6,468,514 $
709,906 $ (5,956,148) $
6,622,929
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Condensed Consolidating Statement of Operations
Revenues
Oil and gas revenues
Purchased oil and gas sales
Midstream revenues
Well services revenues
Total revenues
Operating expenses
Lease operating expenses
Midstream operating expenses
Well services operating expenses
Marketing, transportation and gathering expenses
Purchased oil and gas expenses
Production taxes
Depreciation, depletion and amortization
Exploration expenses
Impairment
Year Ended December 31, 2018
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Combined Non-
guarantor
Subsidiaries
Intercompany
Eliminations
Consolidated
(In thousands)
$
— $ 1,590,024 $
— $
— $ 1,590,024
—
—
—
—
—
—
—
—
—
—
—
—
—
550,363
1,445
—
3,156
270,178
(154,294)
61,075
—
—
551,808
119,040
61,075
2,204,618
271,623
(154,294)
2,321,947
246,672
2,636
41,200
131,340
553,521
133,696
623,354
27,432
384,228
79,742
—
69,710
—
—
846
—
(52,760)
(40,434)
—
(24,147)
(60)
—
28,404
(15,462)
—
—
—
—
23,897
(12,296)
193,912
31,912
41,200
107,193
554,307
133,696
636,296
27,432
384,228
121,346
General and administrative expenses
30,003
Total operating expenses
30,003
2,223,821
122,857
(145,159)
2,231,522
Gain on sale of properties
Operating income (loss)
Other income (expense)
Equity in earnings of subsidiaries
Net gain on derivative instruments
Interest expense, net of capitalized interest
Loss on extinguishment of debt
Other income (expense)
Total other income (expense)
Income (loss) before income taxes
Income tax benefit (expense)
Net income (loss) including non-controlling
interests
Less: Net income attributable to non-controlling
interests
—
28,587
—
—
(30,003)
9,384
148,766
(9,135)
28,587
119,012
103,586
146,409
—
(131,134)
(13,848)
1
28,457
(25,608)
—
134
—
—
(2,343)
—
(14)
(249,995)
—
—
—
—
—
28,457
(159,085)
(13,848)
121
(41,395)
149,392
(2,357)
(249,995)
(144,355)
(71,398)
36,102
158,776
(30,259)
146,409
(259,130)
(25,343)
—
—
5,843
(35,296)
128,517
146,409
(259,130)
(19,500)
—
15,796
96,354
(96,354)
15,796
Net income (loss) attributable to Oasis
$
(35,296) $
112,721 $
50,055 $
(162,776) $
(35,296)
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Table of Contents
Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Combined Non-
guarantor
Subsidiaries
(In thousands)
Intercompany
Eliminations
Consolidated
$
— $
1,034,634 $
— $
—
— $
1,034,634
—
133,542
59,821
(33,718)
—
—
72,752
52,791
1,267,616
59,821
(33,718)
1,293,719
—
—
—
—
—
—
—
—
—
—
—
—
—
133,542
46,649
52,791
189,548
11,117
37,228
61,571
134,615
88,133
528,615
11,600
6,887
61,513
Revenues
Oil and gas revenues
Purchased oil and gas sales
Midstream revenues
Well services revenues
Total revenues
Operating expenses
Lease operating expenses
Midstream operating expenses
Well services operating expenses
Marketing, transportation and gathering
expenses
Purchased oil and gas expenses
Production taxes
Depreciation, depletion and amortization
Exploration expenses
Impairment
Total operating expenses
Gain on sale of properties
Operating income (loss)
Other income (expense)
Other income (expense)
Total other income (expense)
Income (loss) before income taxes
Income tax benefit (expense)
Net income including non-controlling
interests
Less: Net income attributable to non-
controlling interests
Net income attributable to Oasis
General and administrative expenses
27,616
Equity in earnings of subsidiaries
Net loss on derivative instruments
323,953
—
Interest expense, net of capitalized interest
(131,329)
—
15,098
—
—
—
—
(12,414)
(8,626)
—
(5,831)
—
—
4,626
(2,439)
—
—
(2,442)
—
—
5,110
24,834
—
177,134
17,589
37,228
55,740
134,615
88,133
530,802
11,600
6,887
91,797
27,616
1,130,827
—
1,774
(31,752)
1,151,525
—
1,774
(27,616)
138,563
34,987
(1,966)
143,968
34,968
(71,657)
(15,489)
(1,333)
(53,511)
85,052
244,517
—
—
(19)
—
(19)
(358,921)
—
—
—
—
(71,657)
(146,837)
(1,332)
(358,921)
(219,826)
34,968
(360,887)
—
—
(75,858)
203,304
1
192,625
165,009
(41,213)
123,796
329,569
34,968
(360,887)
127,446
—
3,650
23,329
(23,329)
3,650
$
123,796 $
325,919 $
11,639 $
(337,558) $
123,796
143
/
Table of Contents
Condensed Consolidating Statement of Operations
Revenues
Oil and gas revenues
Purchased oil and gas sales
Midstream revenues
Well services revenues
Total revenues
Operating expenses
Lease operating expenses
Midstream operating expenses
Well services operating expenses
Marketing, transportation and gathering expenses
Purchased oil and gas expenses
Production taxes
Depreciation, depletion and amortization
Exploration expenses
Impairment
General and administrative expenses
Total operating expenses
Loss on sale of properties
Operating loss
Other income (expense)
Equity in loss of subsidiaries
Net loss on derivative instruments
Interest expense, net of capitalized interest
Gain on extinguishment of debt
Other income
Total other expense
Loss before income taxes
Income tax benefit
Net loss
Year Ended December 31, 2016
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Intercompany
Eliminations
Consolidated
(In thousands)
$
— $
625,233 $
— $
625,233
—
—
—
—
—
—
—
—
—
—
—
—
—
25,356
25,356
10,272
35,406
33,754
704,665
135,444
9,003
20,675
30,108
10,258
56,565
476,331
1,785
4,684
63,986
808,839
—
(1,303)
(25,356)
(105,477)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
10,272
35,406
33,754
704,665
135,444
9,003
20,675
30,108
10,258
56,565
476,331
1,785
4,684
89,342
834,195
(1,303)
(130,833)
(140,978)
—
140,978
—
—
(105,317)
(130,356)
(9,949)
4,741
137
—
23
—
—
—
—
(105,317)
(140,305)
4,741
160
(266,456)
(115,243)
140,978
(240,721)
(291,812)
(220,720)
140,978
(371,554)
48,796
79,742
—
128,538
$
(243,016) $
(140,978) $
140,978 $
(243,016)
144
/
Table of Contents
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2018
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Combined Non-
guarantor
Subsidiaries
(In thousands)
Intercompany
Eliminations
Consolidated
$
(35,296)
$
128,517
$
146,409
$
(259,130)
$
(19,500)
Cash flows from operating activities:
Net income (loss) including non-
controlling interests
Adjustments to reconcile net income (loss)
including non-controlling interests to net
cash provided by (used in) operating
activities:
Equity in earnings of subsidiaries
(103,586)
(146,409)
—
249,995
—
Change in accounts receivable
(217,714)
Depreciation, depletion and
amortization
Loss on extinguishment of debt
Gain on sale of properties
Impairment
Deferred income taxes
Derivative instruments
Equity-based compensation expenses
Deferred financing costs amortization
and other
Working capital and other changes:
Change in inventory
Change in prepaid expenses
Change in other current assets
Change in long-term inventory and
other assets
Change in accounts payable, interest
payable and accrued liabilities
Change in other current liabilities
Change in other liabilities
Net cash provided by (used in)
operating activities
Cash flows from investing activities:
Capital expenditures
Acquisitions
Proceeds from sale of properties
Costs related to sale of properties
Derivative settlements
Advances from joint interest partners
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from Revolving Credit
Facilities
Principal payments on Revolving Credit
Facilities
—
623,354
28,404
(15,462)
636,296
13,848
—
—
(36,102)
—
27,456
—
(28,587)
384,228
30,236
(28,457)
1,461
16,069
13,507
—
—
—
—
—
356
(519)
—
—
—
—
—
—
—
—
(106)
—
—
(52,013)
(14,324)
(1,608)
10
(144)
3,411
242,808
(22)
(640)
—
—
—
—
—
—
13,848
(28,587)
384,228
(5,866)
(28,457)
29,273
29,057
(23,508)
(14,346)
(2,354)
10
(144)
6,886
234,425
27,613
(242,808)
26,116
—
—
(40)
395
—
—
—
—
(40)
395
(328,545)
1,144,551
205,012
(24,597)
996,421
—
—
—
—
—
—
—
—
—
(872,151)
(276,810)
(581,650)
333,229
(2,850)
(213,528)
224
—
—
—
—
—
(1,336,726)
(276,810)
2,949,000
275,000
(2,551,000)
(35,000)
—
—
—
—
—
—
—
—
—
(1,148,961)
(581,650)
333,229
(2,850)
(213,528)
224
(1,613,536)
3,224,000
(2,586,000)
Repurchase of senior unsecured notes
(423,340)
Proceeds from issuance of senior
unsecured convertible notes
400,000
—
—
—
—
—
(423,340)
—
400,000
/
Deferred financing costs
(6,908)
(5,988)
(966)
—
(13,862)
Proceeds from issuance of Oasis
Midstream common units, net of offering
costs
—
—
44,503
Purchases of treasury stock
(6,846)
—
—
Distributions to non-controlling interests
—
114,789
(128,903)
—
—
—
44,503
(6,846)
(14,114)
Investment in subsidiaries / capital
contributions from parent
Other
Net cash provided by financing
activities
Increase (decrease) in cash and cash
equivalents
Cash and cash equivalents at beginning of
period
365,602
(313,129)
(77,070)
24,597
—
38
(1,794)
—
—
(1,756)
328,546
191,878
77,564
24,597
622,585
1
178
(297)
5,766
15,659
883
—
—
5,470
16,720
Cash and cash equivalents at end of period
$
179 $
15,362 $
6,649 $
— $
22,190
145
/
Table of Contents
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Combined Non-
guarantor
Subsidiaries
(In thousands)
Intercompany
Eliminations
Consolidated
$
123,796
$
329,569
$
34,968
$
(360,887)
$
127,446
Cash flows from operating activities:
Net income including non-controlling
interests
Adjustments to reconcile net income
including non-controlling interests to net
cash provided by operating activities:
Equity in earnings of subsidiaries
(323,953)
(34,968)
—
358,921
—
Change in accounts receivable
(173,668)
(216,982)
(53,623)
277,887
(166,386)
Depreciation, depletion and
amortization
Gain on sale of properties
Impairment
Deferred income taxes
Derivative instruments
Equity-based compensation expenses
Deferred financing costs amortization
and other
Working capital and other changes:
Change in inventory
Change in prepaid expenses
Change in other current assets
Change in long-term inventory and
other assets
Change in accounts payable, interest
payable and accrued liabilities
Change in other current liabilities
Change in other liabilities
Net cash provided by (used in)
operating activities
Cash flows from investing activities:
Capital expenditures
Acquisitions
Proceeds from sale of properties
Costs related to sale of properties
Derivative settlements
Advances from joint interest partners
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from Revolving Credit
Facilities
Principal payments on Revolving Credit
Facilities
528,615
4,626
(2,439)
530,802
—
—
—
(1,774)
6,887
41,213
(244,097)
—
25,436
71,657
1,045
—
—
—
—
53
15,392
2,794
125
—
—
—
—
—
—
(1,774)
6,887
(202,884)
71,657
26,534
18,311
—
9
—
—
(2,501)
(98)
148
(12,143)
—
(749)
—
—
—
—
—
—
(2,501)
(838)
148
(12,143)
7,074
337,319
56,601
(277,887)
123,107
—
—
(10,450)
(40)
—
—
—
—
(10,450)
(40)
(284,701)
754,981
42,001
(4,405)
507,876
—
—
—
—
—
—
—
—
—
(594,945)
(61,874)
72,453
(366)
(8,264)
(2,681)
(52,404)
(66,679)
—
—
—
—
(595,677)
(119,083)
1,084,000
78,000
(1,377,000)
—
—
66,679
(66,679)
—
—
—
—
—
—
—
—
(647,349)
(61,874)
5,774
(366)
(8,264)
(2,681)
(714,760)
1,162,000
(1,377,000)
(2,714)
302,191
Deferred financing costs
—
(577)
(2,137)
Proceeds from sale of common stock, net
of offering costs
Proceeds from issuance of Oasis
Midstream common units, net of offering
302,191
—
—
—
—
134,185
—
134,185
/
costs
Purchases of treasury stock
(6,229)
—
—
—
(6,229)
Investment in subsidiaries / capital
contributions from parent
Other
Net cash provided by (used in)
financing activities
(11,194)
138,872
(132,083)
4,405
(55)
—
—
—
—
(55)
284,713
(154,705)
77,965
4,405
212,378
Increase in cash and cash equivalents
12
4,599
883
Cash and cash equivalents at beginning of
period
166
11,060
—
—
—
5,494
11,226
Cash and cash equivalents at end of period
$
178 $
15,659 $
883 $
— $
16,720
146
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Table of Contents
Condensed Consolidating Statement of Cash Flows
Cash flows from operating activities:
Net loss
Adjustments to reconcile net loss to net cash provided by (used
in) operating activities:
Year Ended December 31, 2016
Parent/
Issuer
Combined
Guarantor
Subsidiaries
Intercompany
Eliminations
Consolidated
(In thousands)
$
(243,016) $
(140,978) $
140,978 $
(243,016)
Equity in loss of subsidiaries
140,978
—
(140,978)
Depreciation, depletion and amortization
—
476,331
Gain on extinguishment of debt
Loss on sale of properties
Impairment
Deferred income taxes
Derivative instruments
Equity-based compensation expenses
Deferred financing costs amortization and other
Working capital and other changes:
Change in accounts receivable
Change in inventory
Change in prepaid expenses
Change in other current assets
Change in long-term inventory and other assets
Change in accounts payable, interest payable and accrued
liabilities
Change in other current liabilities
Change in other liabilities
(4,741)
—
—
(48,796)
—
23,346
9,107
—
1,303
4,684
(79,742)
105,317
757
5,227
—
476,331
(4,741)
1,303
4,684
(128,538)
105,317
24,103
14,334
—
—
—
—
—
—
—
—
(250,737)
207,931
30,883
(11,923)
—
3
—
100
254
(298)
(305)
(251)
—
—
—
—
254
(295)
(305)
(151)
(230,518)
247,562
(30,883)
(13,839)
—
—
4,490
10
Net cash provided by (used in) operating activities
(604,274)
832,292
Cash flows from investing activities:
Capital expenditures
Acquisitions
Proceeds from sale of properties
Costs related to sale of properties
Derivative settlements
Advances from joint interest partners
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from Oasis Credit Facility
Principal payments on Oasis Credit Facility
Repurchase of senior unsecured notes
Proceeds from issuance of senior unsecured convertible notes
Deferred financing costs
Proceeds from sale of common stock, net of offering costs
Purchases of treasury stock
Investment in subsidiaries / capital contributions from parent
Net cash provided by financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
—
—
—
—
—
—
—
(426,256)
(781,522)
12,333
(310)
121,977
2,950
(1,070,828)
—
—
1,407,000
(1,182,000)
(435,907)
300,000
(8,197)
766,670
(2,330)
(16,573)
—
—
(930)
—
—
16,573
603,663
240,643
(611)
777
2,107
8,953
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4,490
10
228,018
(426,256)
(781,522)
12,333
(310)
121,977
2,950
(1,070,828)
1,407,000
(1,182,000)
(435,907)
300,000
(9,127)
766,670
(2,330)
—
844,306
1,496
9,730
Cash and cash equivalents at end of period
$
166 $
11,060 $
— $
11,226
/
147
/
Table of Contents
23. Supplemental Oil and Gas Disclosures
The supplemental data presented below reflects information for all of the Company’s oil and natural gas producing activities.
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities:
Proved oil and gas properties(1)
Less: Accumulated depreciation, depletion, amortization and impairment
Proved oil and gas properties, net
Unproved oil and gas properties
Total oil and gas properties, net
At December 31,
2018
2017
(In thousands)
7,878,104 $
7,058,782
(2,853,353)
(2,395,153)
5,024,751
1,034,085
6,058,836 $
4,663,629
780,173
5,443,802
$
$
__________________
(1)
Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $40.5 million and
$38.4 million at December 31, 2018 and 2017, respectively.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods presented:
Acquisition costs:
Proved oil and gas properties
Unproved oil and gas properties
Exploration costs
Development costs
Asset retirement costs
Total costs incurred
Year Ended December 31,
2018
2017
(In thousands)
2016
$
260,034 $
61,874 $
781,522
696,293
53,928
923,562
5,804
5,424
11,600
511,905
(2,965)
672
1,792
207,766
26,795
$
1,939,621 $
587,838 $
1,018,547
Results of Operations for Oil and Natural Gas Producing Activities
The following table sets forth the results of operations for oil and natural gas producing activities, which exclude straight-line
depreciation, general and administrative expenses and interest expense, for the periods presented:
Year Ended December 31,
2018
2017
2016
Revenues
Production costs
Depreciation, depletion and amortization
Exploration costs
Impairment
Income tax expense (benefit)
$
1,590,024 $
1,034,634 $
(In thousands)
434,801
613,928
27,432
384,228
30,770
321,007
515,600
11,600
6,887
67,148
Results of operations for oil and natural gas producing activities
$
98,865 $
112,392 $
148
625,233
222,117
462,320
1,785
2,252
(23,665)
(39,576)
/
Table of Contents
24. Supplemental Oil and Gas Reserve Information — Unaudited
The reserve estimates at December 31, 2018, 2017 and 2016 presented in the table below are based on reports prepared by
DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative
guidance on oil and gas reserve estimation and disclosures. At December 31, 2018, 2017 and 2016, all of the Company’s oil and
natural gas producing activities were conducted within the continental United States.
The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped
locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these
estimates are expected to change as future information becomes available.
Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating
conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are
proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods
being utilized at the time the estimates were made.
149
/
Table of Contents
Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited
The following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at
December 31, 2018, 2017 and 2016:
Oil
(MBbl)
Gas
(MMcf)
MBoe(1)
2016
Proved reserves
Beginning balance
Revisions of previous estimates
Extensions, discoveries and other additions
Sales of reserves in place
Purchases of reserves in place
Production
Net proved reserves at December 31, 2016
Proved developed reserves, December 31, 2016
Proved undeveloped reserves, December 31, 2016
2017
Proved reserves
Beginning balance
Revisions of previous estimates
Extensions, discoveries and other additions
Sales of reserves in place
Purchases of reserves in place
Production
Net proved reserves at December 31, 2017
Proved developed reserves, December 31, 2017
Proved undeveloped reserves, December 31, 2017
2018
Proved reserves
Beginning balance
Revisions of previous estimates
Extensions, discoveries and other additions
Sales of reserves in place
Purchases of reserves in place
Production
Net proved reserves at December 31, 2018
Proved developed reserves, December 31, 2018
Proved undeveloped reserves, December 31, 2018
184,928
11,713
10,790
(5,828)
50,164
(15,174)
236,593
152,337
84,256
236,593
(28,323)
36,238
(1,196)
466
(18,818)
224,960
150,628
74,332
224,960
(17,352)
30,640
(12,470)
25,688
(23,050)
228,416
144,533
83,883
199,828
116,539
24,520
(10,839)
100,629
(19,573)
411,104
229,568
181,536
411,104
54,726
89,489
(1,147)
1,230
(31,946)
523,456
301,101
222,355
523,456
3,019
46,309
(20,735)
43,107
(42,430)
552,726
339,444
213,282
218,233
31,136
14,876
(7,635)
66,936
(18,436)
305,110
190,598
114,512
305,110
(19,200)
51,153
(1,387)
671
(24,143)
312,204
200,812
111,392
312,204
(16,850)
38,358
(15,926)
32,873
(30,122)
320,537
201,107
119,430
__________________
(1)
Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.
Revisions of Previous Estimates
In 2018, the Company had net negative revisions of 16.9 MMBoe, or 5% of the beginning of the year estimated net proved
reserves balance. These net negative revisions were attributable to negative revisions of 42.3 MMBoe due to well performance
and 9.4 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 14.7 MMBoe for the
addition of proved undeveloped reserves (“PUDs”) that were previously removed from the five-year development plan, 14.4
MMBoe due to higher realized prices and 5.4 MMBoe for ownership adjustments. The proved developed net negative revisions
of 20.2 MMBoe were primarily due to negative revisions of 33.0 MMBoe for performance revisions largely related to higher than
anticipated decline rates in recently developed spacing units, partially offset by positive revisions of 12.2 MMBoe due to higher
realized prices. The proved undeveloped revisions were primarily due to positive revisions of 14.7 MMBoe for the addition of
PUDs that were previously removed from the five-year development plan, 5.6 MMBoe for ownership adjustments and 2.2
MMBoe due to higher realized prices, offset by negative revisions of 9.4 MMBoe associated with
/
150
/
Table of Contents
alignment to the anticipated five-year development plan and 9.3 MMBoe for performance largely related to the associated impact
of higher than anticipated decline rates in recently developed spacing units.
In 2017, the Company had net negative revisions of 19.2 MMBoe, or 6% of the beginning of the year estimated net proved
reserves balance. These net negative revisions were attributable to negative revisions of 39.1 MMBoe associated with well
performance and 2.1 MMBoe for alignment to the anticipated five-year development plan, offset by positive revisions of 16.1
MMBoe due to higher realized prices and 2.5 MMBoe for ownership adjustments. The proved developed negative revisions of
14.2 MMBoe were primarily due to negative revisions of 29.7 MMBoe for performance revisions largely related to higher than
anticipated decline rates in recently developed spacing units, offset by positive revisions of 14.1 MMBoe from increased realized
prices. The proved undeveloped negative revisions of 5.0 MMBoe were primarily due to negative revisions of 9.4 MMBoe for
performance revisions largely related to the associated impact of higher than anticipated decline rates in recently developed
spacing units and negative 1.8 MMBoe revisions associated with alignment to the five-year development plan, offset by positive
revisions of 2.6 MMBoe for ownership adjustments and 2.0 MMBoe from increased realized prices.
In 2016, the Company had net positive revisions of 31.1 MMBoe, or 14% of the beginning of the year estimated net proved
reserves balance. These net positive revisions were attributable to positive revisions of 30.4 MMBoe due to well performance and
larger completion designs, 8.2 MMBoe due to a higher gas to oil ratio and 8.2 MMBoe due to ownership adjustments, offset by
9.5 MMBoe due to the removal of proved undeveloped reserves that were no longer aligned with the Company’s anticipated five-
year drilling plan and 8.2 MMBoe due to lower commodity prices.
Extensions, Discoveries and Other Additions
In 2018, the Company had a total of 38.4 MMBoe of additions due to extensions and discoveries. An estimated 9.0 MMBoe of
these extensions and discoveries were associated with new producing wells at December 31, 2018, with 77% of these reserves
from wells producing in the Bakken or Three Forks formations and 23% of reserves from wells producing in the Delaware Basin,
respectively. An additional 29.4 MMBoe of proved undeveloped reserves were added in the Williston and Delaware Basins
associated with the Company’s anticipated five-year development plan, with 76% of these proved undeveloped reserves in the
Bakken or Three Forks formations in the Williston Basin and 24% of proved undeveloped reserves in the Delaware Basin.
In 2017, the Company had a total of 51.2 MMBoe of additions due to extensions and discoveries. An estimated 17.9 MMBoe of
these extensions and discoveries were associated with new producing wells at December 31, 2017, with 100% of these reserves
from wells producing in the Bakken or Three Forks formations. An additional 33.3 MMBoe of proved undeveloped reserves were
added in the Williston Basin associated with the Company’s anticipated five-year development plan, with 100% of these proved
undeveloped reserves in the Bakken or Three Forks formations.
In 2016, the Company had a total of 14.9 MMBoe of additions due to extensions and discoveries. An estimated 6.2 MMBoe of
these extensions and discoveries were associated with new producing wells at December 31, 2016, with 100% of these reserves
from wells producing in the Bakken or Three Forks formations. An additional 6.5 MMBoe of proved undeveloped reserves were
added in the Williston Basin associated with the Company’s 2016 operated and non-operated drilling program and anticipated
five-year drilling plan, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.
Sales of Reserves in Place
In 2018, the Company divested 15.9 MMBoe of reserves associated with reservoirs in the Bakken or Three Forks formations (see
Note 11 – Divestitures). In 2017, the Company divested 1.4 MMBoe of reserves associated with reservoirs other than the Bakken
or Three Forks formations. In 2016, the Company divested 7.6 MMBoe of reserves associated with its traded acreage and sold
wells.
Purchases of Reserves in Place
In 2018, the Company purchased estimated net proved reserves of 32.9 MMBoe from acquisitions in the Delaware Basin (see
Note 10 – Acquisitions). In 2017, the Company purchased estimated net proved reserves of 0.7 MMBoe from acquisitions of
additional working interests in its existing properties in the Williston Basin. In 2016, the Company purchased 66.9 MMBoe of
estimated net proved reserves from acquisitions.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited
The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and
natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted
at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition,
exploration and development costs.
151
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The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using
index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of
the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $65.66 per Bbl
for oil and $3.16 per MMBtu for natural gas, $51.34 per Bbl for oil and $2.99 per MMBtu for natural gas and $42.60 per Bbl for
oil and $2.47 per MMBtu for natural gas for the years ended December 31, 2018, 2017 and 2016, respectively. These prices were
adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors
affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs
as of each year-end.
The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the
Company’s estimated net proved reserves at December 31, 2018, 2017 and 2016:
Future cash inflows
Future production costs
Future development costs
Future income tax expense
Future net cash flows
2018
At December 31,
2017
(In thousands)
2016
$
16,652,405 $
11,636,126 $
9,426,963
(6,609,097)
(4,458,418)
(3,996,657)
(1,701,672)
(968,466)
(992,271)
(580,481)
(784,727)
(279,345)
7,373,170
5,604,956
4,366,234
10% annual discount for estimated timing of cash flows
(3,322,864)
(2,304,261)
(1,883,169)
Standardized measure of discounted future net cash flows
$
4,050,306 $
3,300,695 $
2,483,065
The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to
estimated net proved reserves for the periods presented:
January 1
Net changes in prices and production costs
Net changes in future development costs
Sales of oil and natural gas, net
Extensions
Purchases of reserves in place
Sales of reserves in place
Revisions of previous quantity estimates
Previously estimated development costs incurred
Accretion of discount
Net change in income taxes
Changes in timing and other
December 31
2018
2017
(In thousands)
2016
$
3,300,695 $
2,483,065 $
1,914,330
1,003,008
(89,304)
(1,155,223)
461,196
385,763
(197,867)
(115,015)
303,364
368,374
881,742
(60,929)
(769,367)
661,467
6,518
(9,024)
(78,942)
157,386
262,776
(240,908)
(238,354)
26,223
4,357
(367,527)
69,992
(403,739)
165,926
533,505
(57,770)
333,398
91,518
202,272
(36,303)
37,463
$
4,050,306 $
3,300,695 $
2,483,065
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25. Quarterly Financial Data — Unaudited
The following tables set forth the Company’s results of operations by quarter for the years ended December 31, 2018 and 2017,
including effects of the revision discussed within Note 2 — Summary of Significant Accounting Policies to the 2018 and 2017
previously issued unaudited quarterly financial results. The 2018 quarterly revisions will be adjusted in connection with the future
2019 unaudited interim condensed consolidated financial statement filings on Form 10-Q.
Total revenues
Operating income (loss)
Net income (loss) including non-controlling interests
Net income (loss) attributable to Oasis
Earnings (loss) attributable to Oasis per share:
First Quarter(1)
For the Year Ended December 31, 2018
Third Quarter(1)
Second Quarter(1)
Fourth Quarter
$
473,812 $
573,751 $
674,629 $
(In thousands, except per share data)
112,985
3,712
590
(242,674)
(316,301)
(320,204)
179,045
66,223
62,341
599,755
69,656
226,866
221,977
Basic
Diluted
$
$
0.00 $
0.00 $
(1.02) $
(1.02) $
0.20 $
0.20 $
0.71
0.70
Total revenues
Operating income
Net income (loss) including non-controlling interests
Net income (loss) attributable to Oasis
Earnings (loss) attributable to Oasis per share:
Basic
Diluted
__________________
(1)
First Quarter(1)
For the Year Ended December 31, 2017
Third Quarter(1)
Second Quarter(1)
Fourth Quarter(1)
$
277,752 $
260,809 $
320,283 $
(In thousands, except per share data)
20,092
23,825
23,825
5,379
16,568
16,568
32,394
(41,064)
(41,214)
434,875
86,103
128,117
124,617
$
$
0.10 $
0.10 $
0.07 $
0.07 $
(0.18) $
(0.18) $
0.52
0.52
For the quarters during the years ended December 31, 2018 and 2017, the impacts of the revision to the Company's
Consolidated Statements of Operations are presented in the following tables:
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Operating income
Net income including non-controlling interests
Net income attributable to Oasis
Earnings attributable to Oasis per share:
Basic
Diluted
Quarter Ended March 31, 2018
As Reported
Revision
As Revised
(In thousands, except per share data)
$
363,671 $
2,924 $
18,037
421,216
17,998
308,231
112,985
3,712
590
49,672
52,596
52,596
52,596
—
—
—
$
$
0.00 $
0.00 $
— $
— $
153
366,595
67,709
473,812
70,594
360,827
112,985
3,712
590
0.00
0.00
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Table of Contents
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Operating loss
Net loss including non-controlling interests
Net loss attributable to Oasis
Loss attributable to Oasis per share:
Basic
Diluted
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Operating income
Net income including non-controlling interests
Net income attributable to Oasis
Earnings attributable to Oasis per share:
Basic
Diluted
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Operating income
Net income including non-controlling interests
Net income attributable to Oasis
Earnings attributable to Oasis per share:
Basic
Diluted
Quarter Ended June 30, 2018
As Reported
Revision
As Revised
(In thousands, except per share data)
$
395,921 $
1,928 $
57,578
501,337
57,165
745,965
(242,674)
(316,301)
(320,204)
70,486
72,414
72,414
72,414
—
—
—
397,849
128,064
573,751
129,579
818,379
(242,674)
(316,301)
(320,204)
$
$
(1.02) $
(1.02) $
— $
— $
(1.02)
(1.02)
Quarter Ended September 30, 2018
As Reported
Revision
As Revised
(In thousands, except per share data)
$
452,643 $
1,552 $
46,356
546,448
46,088
404,272
179,045
66,223
62,341
$
$
0.20 $
0.20 $
126,629
128,181
128,181
128,181
—
—
—
— $
— $
454,195
172,985
674,629
174,269
532,453
179,045
66,223
62,341
0.20
0.20
Quarter Ended March 31, 2017
As Reported
Revision
As Revised
(In thousands, except per share data)
$
237,252 $
(7) $
27,631
285,116
28,002
265,024
20,092
23,825
23,825
(7,357)
(7,364)
(7,364)
(7,364)
—
—
—
0.10 $
0.10 $
— $
— $
$
$
154
237,245
20,274
277,752
20,638
257,660
20,092
23,825
23,825
0.10
0.10
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Table of Contents
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Operating income
Net income including non-controlling interests
Net income attributable to Oasis
Earnings attributable to Oasis per share:
Basic
Diluted
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Operating income
Net loss including non-controlling interests
Net loss attributable to Oasis
Loss attributable to Oasis per share:
Basic
Diluted
Oil and gas revenues
Purchased oil and gas sales
Total revenues
Purchased oil and gas expenses
Total operating expenses
Operating income
Net income including non-controlling interests
Net income attributable to Oasis
Earnings attributable to Oasis per share:
Basic
Diluted
Quarter Ended June 30, 2017
As Reported
Revision
As Revised
(In thousands, except per share data)
$
218,633 $
(110) $
8,091
254,091
7,980
248,712
5,379
16,568
16,568
6,828
6,718
6,718
6,718
—
—
—
$
$
0.07 $
0.07 $
— $
— $
218,523
14,919
260,809
14,698
255,430
5,379
16,568
16,568
0.07
0.07
Quarter Ended September 30, 2017
As Reported
Revision
As Revised
(In thousands, except per share data)
$
248,648 $
(72) $
21,195
304,748
21,701
272,354
32,394
(41,064)
(41,214)
15,607
15,535
15,535
15,535
—
—
—
$
$
(0.18) $
(0.18) $
— $
— $
248,576
36,802
320,283
37,236
287,889
32,394
(41,064)
(41,214)
(0.18)
(0.18)
Quarter Ended December 31, 2017
As Reported
Revision
As Revised
(In thousands, except per share data)
$
330,359 $
(69) $
31,072
404,469
31,637
320,140
86,103
128,117
124,617
30,475
30,406
30,406
30,406
—
—
—
$
$
0.52 $
0.52 $
— $
— $
330,290
61,547
434,875
62,043
350,546
86,103
128,117
124,617
0.52
0.52
/
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures
As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief
Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial
officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2018. Based on that evaluation, and as described below,
management identified a material weakness in the Company’s internal control over financial reporting.
Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by
us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management,
including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. As a result of this material
weakness, our CEO and CFO concluded that the Company’s disclosure controls and procedures were not effective as of
December 31, 2018.
Management’s report on internal control over financial reporting
Management, including our CEO and CFO, is responsible for establishing and maintaining adequate internal control over
financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial
reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation
of our financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a control deficiency, or combination of control deficiencies, in internal control over financial reporting,
such that there is a reasonable possibility that a material misstatement in the annual or interim financial statements will not be
prevented or detected on a timely basis.
As of December 31, 2018, management assessed the effectiveness of our internal control over financial reporting. In making this
assessment, management, including our CEO and CFO, used the criteria set forth by the Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment,
our CEO and CFO have concluded that a material weakness in internal control over financial reporting existed as of December
31, 2018, as described below:
We did not design and maintain effective controls over the presentation and disclosure of certain crude oil purchase and
sale arrangements included in oil and gas revenues, purchased oil and gas sales and purchased oil and gas expenses and
the related accounts receivable and accrued liabilities accounts. Specifically, we did not design effective controls to
determine gross or net basis accounting for these crude oil purchase and sale arrangements. We previously reported these
transactions on a net basis; however, we were required to present these purchase and sale arrangements on a gross basis.
This material weakness resulted in an audit adjustment to the consolidated financial statements as of and for the year
ended December 31, 2018 and the revision of the consolidated financial statements as of and for the year ended
December 31, 2017 and the unaudited financial information for fiscal years 2018 and 2017.
Additionally, this material weakness could result in a misstatement of oil and gas revenues, purchased oil and gas sales, purchase
oil and gas expenses, accounts receivable and accrued liabilities that would result in a material misstatement to the annual or
interim consolidated financial statements that would not be prevented or detected. Because of the material weakness, management
has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2018.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial
statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial
reporting as of December 31, 2018 and has issued an adverse report on the effectiveness of our internal control over financial
reporting as of December 31, 2018. Please see their “Report of Independent Registered Public Accounting Firm” included in
Item 8 – Financial Statements and Supplementary Data.
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Management’s remediation plan
In response to the material weakness identified in “Management’s report on internal control over financial reporting” above, the
Company has developed a plan (the “Remediation Plan”) with oversight from the Audit Committee of the Board of Directors to
remediate the material weakness, and has begun working on that remediation plan. The Remediation Plan implements certain
changes to our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act),
including, but not limited to, the following efforts:
•
•
•
Enhancement of the controls over all purchase and sale arrangements;
Revision and communication of the accounting controls, policies and procedures relating to the application of ASC 845;
and
Enhancement of integration and documentation of standards within and between accounting, marketing and other key
departments to timely identify transactions that are subject to ASC 845.
Due to the material weakness described above, management performed additional analyses and procedures in order to conclude
that our consolidated financial statements for the year ended December 31, 2018 are fairly presented, in all material respects, in
accordance with generally accepted accounting principles.
Changes in internal control over financial reporting
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the
Exchange Act) that occurred during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely
to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in
our definitive proxy statement for our 2019 Annual Meeting of Stockholders.
The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial
Officer and Controller (the “Code of Ethics”) can be found on the Company’s website located at
http://www.oasispetroleum.investorroom.com/corporate-governance. Any stockholder may request a printed copy of the Code of
Ethics by submitting a written request to the Company’s Corporate Secretary.
If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the
Company will disclose the information on its website. The waiver information will remain on the website for at least 12 months
after the initial disclosure of such waiver. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to
amendments to or waivers from any provision of the Code of Ethics applicable to such persons by posting such information on
our website.
Item 11. Executive Compensation
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in
our definitive proxy statement for our 2019 Annual Meeting of Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in
our definitive proxy statement for our 2019 Annual Meeting of Stockholders.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in
our definitive proxy statement for our 2019 Annual Meeting of Stockholders.
Item 14. Principal Accountant Fees and Services
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in
our definitive proxy statement for our 2019 Annual Meeting of Stockholders.
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PART IV
Item 15. Exhibits, Financial Statement Schedules
a. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:
(1) Financial Statements:
See Item 8. Financial Statements and Supplementary Data.
(2) Financial Statement Schedules:
None.
(3) Exhibits:
The following documents are included as exhibits to this report:
Exhibit No.
Description of Exhibit
2.1
2.2
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
Purchase and Sale Agreement, dated December 11, 2017, between the Company and Forge Energy, LLC (filed
as Exhibit 2.1 to the Company’s Current Report on Form 8-K on December 11, 2017 and incorporated herein
by reference).
Contribution Agreement, dated November 7, 2018, between Oasis Midstream Partners LP, OMS Holdings
LLC, Oasis Midstream Services LLC, OMP GP LLC, OMP Operating LLC and, for certain limited purposes
set forth therein, Oasis Petroleum Inc. (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on
November 8, 2018, and incorporated herein by reference).
Conformed version of Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc., as amended
by amendment filed on July 25, 2018 (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q on
August 7, 2018, and incorporated herein by reference).
Amended and Restated Bylaws of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report
on Form 8-K on February 28, 2019, and incorporated herein by reference).
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-
1/A on May 19, 2010, and incorporated herein by reference).
Indenture dated as of February 2, 2011 among the Company and U.S. Bank National Association, as trustee
(filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on February 2, 2011, and incorporated
herein by reference).
First Supplemental Indenture dated as of February 2, 2011 among the Company, the Guarantors and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on
February 2, 2011, and incorporated herein by reference).
Second Supplemental Indenture dated as of September 19, 2011 among the Company, the Guarantors and U.S.
Bank National Association, as trustee (filed as Exhibit 4.4 to the Company’s Registration Statement on Form S-
4 on September 23, 2011, and incorporated herein by reference).
Indenture dated as of November 10, 2011 among the Company, the Guarantors and U.S. Bank National
Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on November 10,
2011, and incorporated herein by reference).
First Supplemental Indenture dated as of November 10, 2011 among the Company, the Guarantors and U.S.
Bank National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on
November 10, 2011, and incorporated herein by reference).
Second Supplemental Indenture dated as of July 2, 2012 among the Company, the Guarantors and U.S. Bank
National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on July 2,
2012, and incorporated herein by reference).
Third Supplemental Indenture (to the Indenture dated as of February 2, 2011) dated as of June 18, 2013 among
the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the
Company’s Quarterly Report on Form 10-Q on August 7, 2013, and incorporated herein by reference).
Third Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of June 18, 2013
among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the
Company’s Quarterly Report on Form 10-Q on August 7, 2013, and incorporated herein by reference).
/
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Exhibit No.
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
10.1
10.2
Description of Exhibit
Fourth Supplemental Indenture dated as of September 24, 2013 among the Company, the Guarantors and U.S.
Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed
on September 25, 2013, and incorporated herein by reference).
Fifth Supplemental Indenture (to the Indenture dated as of February 2, 2011) dated as of October 26, 2015
among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the
Company’s Current Report on Form 8-K filed on October 30, 2015, and incorporated herein by reference).
Fourth Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of October 26, 2015
among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the
Company’s Current Report on Form 8-K filed on October 30, 2015, and incorporated herein by reference).
Fifth Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of October 26, 2015
among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.3 to the
Company’s Current Report on Form 8-K filed on October 30, 2015, and incorporated herein by reference).
Sixth Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of September 19,
2016 to Senior Indenture among the Company, the Guarantors and U.S. Bank National Association, as trustee
(filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on September 19, 2016, and incorporated
herein by reference).
Sixth Supplemental Indenture (to the Indenture dated as of February 2, 2011) dated as of October 25, 2017
among the Company, the Guarantors and U.S. Bank National Association, as trustee. (filed as Exhibit 4.15 to
the Company’s Annual Report on Form 10-K on February 28, 2018, and incorporated herein by reference).
Seventh Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of October 25,
2017 among the Company, the Guarantors and U.S. Bank National Association, as trustee. (filed as Exhibit
4.16 to the Company’s Annual Report on Form 10-K on February 28, 2018, and incorporated herein by
reference).
Registration Rights Agreement, dated February 14, 2018, between the Oasis Petroleum Inc. and Forge Energy,
LLC (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on February 16, 2018, and
incorporated herein by reference).
Seventh Supplemental Indenture (to the Indenture dated as of February 2, 2011) dated as of April 27, 2018
among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the
Company’s Quarterly Report on Form 10-Q on May 8, 2018, and incorporated herein by reference).
Eighth Supplemental Indenture (to the Indenture dated as of November 10, 2011) dated as of April 27, 2018
among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.3 to the
Company’s Quarterly Report on Form 10-Q on May 8, 2018, and incorporated herein by reference).
Indenture, dated as of May 14, 2018, among the Company, the Guarantors and U.S. Bank National Association,
as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on May 18, 2018, and
incorporated herein by reference).
Eighth Supplemental Indenture, dated as of May 14, 2018, among the Company, the Guarantors and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on May
18, 2018, and incorporated herein by reference).
Ninth Supplemental Indenture, dated as of May 14, 2018, among the Company, the Guarantors and U.S. Bank
National Association, as trustee (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K on May
18, 2018, and incorporated herein by reference).
Second Amended and Restated Credit Agreement, dated as of April 5, 2013, among Oasis Petroleum Inc., as
parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo
Bank, N.A., as administrative agent and the lenders party thereto (filed as Exhibit 10.1 to the Company’s
Current Report on Form 8-K on April 9, 2013, and incorporated herein by reference).
First Amendment to Second Amended and Restated Credit Agreement dated as of September 3, 2013 among
Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties
thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as Exhibit 10.1
to the Company’s Current Report on Form 8-K on September 5, 2013, and incorporated herein by reference).
/
10.3**
Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.1 to the
Company’s Quarterly Report on Form 10-Q on August 6, 2014, and incorporated herein by reference).
159
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Exhibit No.
10.4**
10.5**
10.6**
10.7**
10.8**
10.9**
10.10**
10.11**
10.12
10.13
10.14**
10.15**
10.16**
10.17**
10.18
10.19
Description of Exhibit
Form of Indemnification Agreement between Oasis Petroleum Inc. and each of the directors and executive
officers thereof (filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K on February 27, 2014,
and incorporated herein by reference).
Amended and Restated 2010 Annual Incentive Compensation Plan of Oasis Petroleum Inc. (filed as
Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on August 6, 2014, and incorporated herein by
reference).
Form of Notice of Grant of Restricted Stock (filed as Exhibit 10.10 to the Company’s Registration Statement
on Form S-1/A on May 19, 2010, and incorporated herein by reference).
Form of Restricted Stock Agreement (filed as Exhibit 10.11 to the Company’s Registration Statement on Form
S-1/A on May 19, 2010, and incorporated herein by reference).
Form of Notice of Grant of Restricted Stock Unit (filed as Exhibit 10.12 to the Company’s Registration
Statement on Form S-1/A on May 19, 2010, and incorporated herein by reference).
Form of Notice of Grant of Performance Share Units (filed as Exhibit 10.1 to the Company’s Current Report on
Form 8-K on August 3, 2012, and incorporated herein by reference).
Form of Performance Share Unit Agreement (filed as Exhibit 10.2 to the Company’s Current Report on Form
8-K on August 3, 2012, and incorporated herein by reference).
Amended and Restated Executive Change in Control and Severance Benefit Plan dated as of March 1, 2012
(filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on March 2, 2012, and incorporated
herein by reference).
Second Amendment to Second Amended and Restated Credit Agreement dated as of September 30, 2014
among Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit
Parties thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as
Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 2, 2014, and incorporated herein by
reference).
Letter Agreement dated as of March 4, 2015 between the Company and SPO Advisory Corp. (filed as Exhibit
10.1 to the Company’s Current Report on Form 8-K on March 9, 2015, and incorporated herein by reference).
Third Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis
Petroleum Inc. and Thomas B. Nusz (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on
March 20, 2015, and incorporated herein by reference).
Fourth Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis
Petroleum Inc. and Taylor L. Reid (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on
March 20, 2015, and incorporated herein by reference).
Second Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis
Petroleum Inc. and Michael H. Lou (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on
March 20, 2015, and incorporated herein by reference).
Second Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis
Petroleum Inc. and Nickolas J. Lorentzatos (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-
K on March 20, 2015, and incorporated herein by reference).
Third Amendment to Second Amended and Restated Credit Agreement dated as of April 13, 2015 among
Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties
party thereto, Wells Fargo Bank, N.A., as Administrative Agent, and the Lenders party thereto (filed as Exhibit
10.1 to the Company's Current Report on Form 8-K on April 14, 2015, and incorporated herein by reference).
Fourth Amendment to Second Amended and Restated Credit Agreement dated as of November 13, 2015
among Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit
Parties party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as
Exhibit 10.1 to the Company’s Current Report on Form 8-K on November 18, 2015, and incorporated herein by
reference).
/
10.20**
First Amendment to the Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed
as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 6, 2015 and incorporated herein by
reference).
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Exhibit No.
10.21
Description of Exhibit
Fifth Amendment to Second Amended and Restated Credit Agreement dated as of February 23, 2016 among
Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties
party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as
Exhibit 10.35 to the Company’s Annual Report on Form 10-K on February 25, 2016, and incorporated herein
by reference).
10.22**
Form of Notice of Grant of Performance Share Units (filed as Exhibit 10.2 to the Company’s Quarterly Report
on Form 10-Q on May 10, 2016, and incorporated herein by reference).
10.23**
10.24
Second Amendment to the Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc.
(filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 10, 2016 and incorporated herein
by reference).
Sixth Amendment to Second Amended and Restated Credit Agreement dated as of August 8, 2016 among
Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties
party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as
Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on August 9, 2016, and incorporated herein by
reference).
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
Seventh Amendment to Second Amended and Restated Credit Agreement dated as of October 14, 2016 among
Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties
party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as Exhibit
10.1 to the Company’s Current Report on Form 8-K on October 18, 2016, and incorporated herein by
reference).
Eighth Amendment to Second Amended and Restated Credit Agreement, dated as of April 10, 2017, among
Oasis Petroleum Inc., as Parent, Oasis Petroleum North America LLC, as Borrower, the Other Credit Parties
party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as
Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 13, 2017, and incorporated herein by
reference).
Contribution Agreement, dated as of September 25, 2017, by and among Oasis Midstream Partners LP, Oasis
Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLC and OMP Operating
LLC (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on September 29, 2017, and
incorporated herein by reference).
Omnibus Agreement, dated as of September 25, 2017, by and among Oasis Midstream Partners LP, the
Company, Oasis Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLC and
OMP Operating LLC (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on September 29,
2017, and incorporated herein by reference).
Ninth Amendment to Second Amended and Restated Credit Agreement, dated as of September 25, 2017, by
and among Oasis Petroleum North America LLC, as borrower, the guarantors party thereto, Wells Fargo Bank,
N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.3 to the Company’s Current
Report on Form 8-K on September 29, 2017, and incorporated herein by reference).
Services and Secondment Agreement, dated as of September 25, 2017, by and between Oasis Midstream
Partners LP and the Company (filed as Exhibit 10.4 to the Company's Current Report on Form 8-K on
September 29, 2017 and incorporated herein by reference).
Tenth Amendment to Second Amended and Restated Credit Agreement, dated as of November 7, 2017, by and
among Oasis Petroleum North America LLC, as borrower, the guarantors party thereto, Wells Fargo Bank,
N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.5(a) to the Company’s
Quarterly Report on Form 10-Q on November 9, 2017 and incorporated herein by reference).
Eleventh Amendment to Second Amended and Restated Credit Agreement, dated as of February 26, 2018, by
and among Oasis Petroleum North America LLC, as borrower, the guarantors party thereto, Wells Fargo Bank,
N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current
Report on Form 8-K on February 28, 2018 and incorporated herein by reference).
10.33
Twelfth Amendment to Second Amended and Restated Credit Agreement, dated as of April 19, 2018, by and
/
among Oasis Petroleum North America LLC, as borrower, the guarantors party thereto, Wells Fargo Bank,
N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.2 to the Company’s Quarterly
Report on Form 10-Q on May 8, 2018, and incorporated herein by reference).
10.34**
Form of Restricted Stock Award Grant Notice (filed as Exhibit 10.2 to the Company’s Quarterly Report on
Form 10-Q on August 7, 2018, and incorporated herein by reference).
161
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Exhibit No.
10.35**
10.36
10.37**
10.38**
10.39**
10.40**
Description of Exhibit
Form of Restricted Stock Award Agreement (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form
10-Q on August 7, 2018, and incorporated herein by reference).
Third Amended and Restated Credit Agreement, dated as of October 16, 2018, by and among Oasis Petroleum
Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties thereto, Wells Fargo
Bank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s
Current Report on Form 8-K filed on October 19, 2018, and incorporated herein by reference).
Fourth Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis
Petroleum Inc. and Thomas B. Nusz (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on
March 22, 2018, and incorporated herein by reference).
Fifth Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis Petroleum
Inc. and Taylor L. Reid (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 22,
2018, and incorporated herein by reference).
Third Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis
Petroleum Inc. and Michael H. Lou (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on
March 22, 2018, and incorporated herein by reference).
Third Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis
Petroleum Inc. and Nickolas J. Lorentzatos (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-
K on March 22, 2018, and incorporated herein by reference).
10.41**
Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.2 to the
Company’s Quarterly Report on Form 10-Q on May 4, 2018, and incorporated herein by reference).
10.42
10.43
10.44
Form of Notice of Grant of Performance Share Units.
Form of Phantom Unit Award Grant Notice.
Form of Phantom Unit Award Agreement.
12.1(a)
Computation of Ratio of Earnings to Fixed Charges.
21.1(a)
List of Subsidiaries of Oasis Petroleum Inc.
23.1(a)
Consent of PricewaterhouseCoopers LLP.
23.2(a)
Consent of DeGolyer and MacNaughton.
31.1(a)
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
99.1
Report of DeGolyer and MacNaughton.
101.INS(a)
XBRL Instance Document.
101.SCH(a)
XBRL Schema Document.
101.CAL(a)
XBRL Calculation Linkbase Document.
101.DEF(a)
XBRL Definition Linkbase Document.
101.LAB(a)
XBRL Labels Linkbase Document.
XBRL Presentation Linkbase Document.
101.PRE(a)
__________________
Filed herewith.
(a)
/
Furnished herewith.
(b)
** Management contract or compensatory plan or arrangement.
162
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Item 16. Form 10-K Summary
None.
163
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Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized, on March 1, 2019.
SIGNATURES
OASIS PETROLEUM INC.
By:
/s/ Thomas B. Nusz
Thomas B. Nusz
Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacity and on the dates indicated:
Signature
Title
Date
/s/ Thomas B. Nusz
Thomas B. Nusz
/s/ Taylor L. Reid
Taylor L. Reid
/s/ Michael H. Lou
Michael H. Lou
/s/ William J. Cassidy
William J. Cassidy
/s/ John E. Hagale
John E. Hagale
/s/ Michael McShane
Michael McShane
/s/ Bobby S. Shackouls
Bobby S. Shackouls
/s/ Paula D. Polito
Paula D. Polito
Chairman of the Board and Chief Executive Officer
March 1, 2019
(Principal Executive Officer)
Director, President and Chief Operating Officer
March 1, 2019
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting
Officer)
Director
Director
Director
Director
Director
164
March 1, 2019
March 1, 2019
March 1, 2019
March 1, 2019
March 1, 2019
March 1, 2019
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Table of Contents
The terms defined in this section are used throughout this Annual Report on Form 10-K:
GLOSSARY OF OIL AND NATURAL GAS TERMS
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas
liquids or fresh water.
“Bcf.” One billion cubic feet of natural gas.
“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.
“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing
equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a
new well.
“Development well.” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon
known to be productive.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of
such production exceed production expenses and taxes.
“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the
operation.
“Environmental assessment.” An environmental assessment, a study that can be required pursuant to federal law to assess the
potential direct, indirect and cumulative impacts of a project.
“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir
in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological
structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and
the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then
drilled at a right angle within a specified interval.
“MBbl.” One thousand barrels of crude oil, condensate, natural gas liquids or fresh water.
“MBoe.” One thousand barrels of oil equivalent.
“Mcf.” One thousand cubic feet of natural gas.
“MMBbl.” One million barrels of crude oil, condensate, natural gas liquids or fresh water.
“MMBoe.” One million barrels of oil equivalent.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet of natural gas.
“NYMEX.” The New York Mercantile Exchange.
“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who
has 50% interest in 100 acres owns 50 net acres.
“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated
from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices
and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses,
discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission.
165
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Table of Contents
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from
the sale of the production exceed production expenses and taxes.
“Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods.
“Proved reserves.” Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic
methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved
includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir
that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the
basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are
limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance
data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well
penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data
and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically
through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved
classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using
reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based;
and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The
price shall be the average price during the 12-month period prior to the ending date of the period covered by the report,
determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless
prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“Proved undeveloped reserves.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from
existing wells where a relatively major expenditure is required for recompletion.
“Reasonable certainty.” A high degree of confidence.
“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new
reservoirs in an attempt to establish or increase existing production.
“Reserves.” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically
producible as of a given date by application of development prospects to known accumulations.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or
oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-
acre spacing, and is often established by regulatory agencies.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development
and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or
borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals.
The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the
production of hydrocarbons.
166
/
EXHIBIT 10.42
NOTICE OF GRANT OF PERFORMANCE SHARE UNITS
Pursuant to the terms and conditions of the Oasis Petroleum Inc. Amended and Restated 2010 Long Term
Incentive Plan, as amended (the “Plan”), and the associated Performance Share Unit Agreement (the
“Agreement”), you are hereby granted an award of Performance Share Units, whereby each Performance
Share Unit that becomes earned, as determined by the Committee in its sole and absolute discretion,
represents the right to receive one share of common stock of the Company, par value $0.001 per share
(“Stock”), plus rights to certain Dividend Equivalents described in Section 3 of the Agreement, under the
terms and conditions set forth below, in the Agreement, and in the Plan (the “Performance Share Units”).
Capitalized terms used but not defined herein shall have the meanings set forth in the Plan or the
Agreement.
Date of Grant:
, 20 (“Date of Grant”)
Number of Performance
Share Units:
The number of shares of Stock that may be deliverable in respect of this Award may range from 0% to
200% of the number of Performance Share Units awarded to you as shown on the Morgan Stanley
Smith Barney (MSSB) Benefits Access Online Award Acceptance website (the “Initial Performance
Units”).
Performance Cycle:
The Performance Cycle applicable to the Performance Share Units begins on , 20 and
ends on:
(a) , 20 (24 months) for one third of the Initial Performance Units,
(b) , 20 (36 months) for one third of the Initial Performance Share Units, and
(c) , 20 (48 months) for the final third of the Initial Performance Share Units
(each such period, a “Performance Cycle” and the period from , 20 (the Date of Grant)
to , 20 , the “Grant Cycle”).
/
Vesting Requirements:
Your right to receive Stock in respect of Performance Share Units is generally contingent, in whole or
in part, upon (a) except as otherwise provided below, your continuous active service with the Company
through the end of the applicable Performance Cycle (the “Continuous Service Requirement”), and
(b) the level of achievement of the TSR Vesting Objective as outlined below and in Appendix A, which
summarizes the TSR Vesting Objective.
The “TSR Vesting Objective” means the Company’s relative ranking in respect of the applicable
Performance Cycle with regard to Total Shareholder Return (as defined in Appendix A) as compared to
Total Shareholder Return of the Peer Companies (as defined in Appendix A). The level of achievement
of the TSR Vesting Objective shall be determined in accordance with Appendix A. After the end of
each applicable Performance Cycle, the Committee will determine the Company’s Total Shareholder
Return as compared to Total Shareholder Return of the Peer Companies and will certify the level of
achievement with respect to the TSR Vesting Objective and what percentage of the Initial Performance
Units eligible to vest for such Performance Cycle have been earned in accordance with the table set
forth in Appendix A (such number of Performance Share Units that become earned shall hereinafter be
called the “Earned Performance Units”), subject to your satisfaction of the Continuous Service
Requirement.
Notwithstanding anything to the contrary herein, in the Agreement, in the Plan or in any other
arrangement between you and the Company (including any employment agreement or the Amended
and Restated Executive Change in Control and Severance Benefit Plan, if you participate in such plan):
(a) if a Change in Control occurs prior to the end of the Grant Cycle (the date of such
occurrence, the “Change in Control Date”) and you have remained in continuous service with the
Company through the Change in Control Date, then, upon the occurrence of such Change in Control,
with respect to any Initial Performance Units eligible to vest for a Performance Cycle that has not
ended prior to the Change in Control Date, you shall be deemed to have earned a number of
Performance Share Units equal to the number of Earned Performance Units you would have earned in
accordance with Appendix A, but assuming that (i) each such Performance Cycle occurring during the
Grant Cycle ended on the Change in Control Date, (ii) the determination of whether, and to what
extent, the TSR Vesting Objective is achieved shall be based on actual performance against the stated
criteria through the Change in Control Date, and (iii) the Closing Value (as defined in Appendix A) for
the Company is equal to the Change in Control Price instead of calculating the Closing Value in
accordance with Appendix A. For purposes of this Award, (A) “Change in Control” shall have the
meaning given such term in the Plan; provided, that, in the event of any Business Combination
following which both Thomas B. Nusz and Taylor L. Reid remain as Chief Executive Officer and
President, respectively, and as members of the board of directors or similar governing body, of the
entity resulting from such Business Combination (not including any subsidiary thereof), the Board of
the pre-Business Combination Company may determine, in its sole discretion, that no Change in
Control has occurred for purposes of this Award; and (B) “Change in Control Price” shall equal the
amount determined in the following clause (1), (2), (3), (4) or (5), whichever is applicable, as follows:
(1) the price per share offered to holders of Stock in any merger or consolidation, (2) the per share Fair
Market Value of the Stock immediately before the Change in Control, without regard to assets sold in
the Change in Control and assuming the Company has received the consideration paid for the assets in
the case of a sale of assets, (3) the amount distributed per share of Stock in a dissolution transaction,
(4) the price per share offered to holders of Stock in any tender offer or exchange offer whereby a
Change in Control takes place, or (5) if such Change in Control occurs other than pursuant to a
transaction described in clauses (1), (2), (3), or (4), the volume weighted average of the Company’s
Stock price on each trading day in the 30-day period preceding the Change in Control Date.
(b) if your employment or service relationship with the Company or any of its Subsidiaries is
terminated due to your death or Disability prior to the end of the Grant Cycle, then you shall be
deemed to have earned, with respect to any Initial Performance Units eligible to vest for a Performance
Cycle that has not ended prior to your termination date, a number of Performance Share Units equal to
200% of the Initial Performance Units eligible to vest with respect to such Performance Cycle. For
purposes of this Award, “Disability” shall have the meaning given such term in any employment
agreement between you and the Company; provided, however, that if there is no existing employment
agreement between you and the Company, the term “Disability” shall mean your inability to perform
the essential functions of your position with or without reasonable accommodation, if required by law,
due to physical or mental impairment. The existence of any such Disability shall be certified, at the
Company’s discretion, by either the Company’s disability carrier or a physician acceptable to both you
/
and the Company. If the parties are not able to agree on the choice of physician, each party shall select
a physician who, in turn, shall select a third physician to render such certification. In no event will your
employment be terminated as a result of Disability, unless otherwise agreed to by you and the
Company, until at least 180 consecutive days of leave have elapsed and the Company has provided you
with written notice of termination.
(c) if your employment or service relationship with the Company or any of its Subsidiaries is
terminated prior to the end of the Grant Cycle by the Company or a Subsidiary without “Cause” or by
you for “Good Reason” (in each case, as such terms are defined in any employment agreement
between you and the Company or in the Amended and Restated Executive Change in Control and
Severance Benefit Plan, if you participate in such plan), then you shall be deemed to have earned, with
respect to any Initial Performance Units eligible to vest for a Performance Cycle that has not ended
prior to your termination date, the number of Earned Performance Units that you would have actually
earned in accordance with Appendix A as of the end of each such Performance Cycle had you
remained employed through the end of the Performance Cycle.
Any of your Performance Share Units that are eligible to be earned but that do not become Earned
Performance Units as of the end of the applicable Performance Cycle shall terminate and be cancelled
upon the expiration of such Performance Cycle.
2
/
Date of Settlement:
Payment in respect of Earned Performance Units shall be made no later than March 15 of the calendar
year following the calendar year in which the last day of the applicable Performance Cycle occurs,
except that (a) in the event of your death or Disability, payments in respect of Earned Performance
Units shall be made no later than the 30th day following your death or termination for Disability; and
(b) in the event of a Change in Control, payments in respect of Earned Performance Units shall be
made no later than five (5) business days after the Change in Control Date (in each case, the “Date of
Settlement”).
All payments with respect to Earned Performance Units shall be made in freely transferable shares of
Stock.
Upon full settlement of the Performance Share Units hereunder and pursuant to Section 3 of the
Agreement, no additional payments will be made pursuant to this Award and the Award shall
terminate.
By your acceptance of this document, you and the Company hereby acknowledge receipt of the
Performance Share Units issued on the Date of Grant indicated above, which have been granted under the
terms and conditions contained herein and in the Plan and the Agreement. Alternatively, you acknowledge
your agreement to be bound to the terms of this Notice, the Agreement and the Plan in connection with your
acceptance of the Performance Share Units issued hereby through procedures, including electronic
procedures, provided by or on behalf of the Company.
You acknowledge and agree that (a) you are not relying upon any written or oral statement or
representation of the Company, its affiliates, or any of their respective employees, directors, officers,
attorneys or agents (collectively, the “Company Parties”) regarding the tax effects associated with your
execution of this Notice of Grant of Performance Share Units and your receipt and holding of and the
vesting of the Performance Share Units, and (b) in deciding to enter into this Agreement, you are relying on
your own judgment and the judgment of the professionals of your choice with whom you have consulted.
You hereby release, acquit and forever discharge the Company Parties from all actions, causes of actions,
suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any nature whatsoever,
known or unknown, on account of, arising out of, or in any way related to the tax effects associated with
your execution of the Agreement and your receipt and holding of and the vesting of the Performance Share
Units.
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You further acknowledge receipt of a copy of the Plan and the Agreement and agree to all of the
terms and conditions of the Plan and the Agreement, which are incorporated herein by reference.
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OASIS PETROLEUM INC.,
a Delaware corporation
By:
Name:
Title:
Attachment: Appendix A – Total Shareholder Return Vesting Objective
Appendix A
Total Shareholder Return Vesting Objective
The TSR Vesting Objective for the Performance Share Units is outlined in this Appendix A below.
The “TSR Vesting Objective” means the Company’s relative ranking in respect of the applicable
Performance Cycle with regard to Total Shareholder Return as compared to the Total Shareholder Return of
the Peer Companies. The Committee shall have the sole discretion for determining the level of achievement
with respect to the TSR Vesting Objective and the number of Earned Performance Units for each
Performance Cycle and any such determinations shall be conclusive.
1. Defined Terms.
(a) “Total Shareholder Return” means, as to the Company and each of the Peer
Companies, the annualized rate of return shareholders receive through stock price changes and the assumed
reinvestment of dividends paid over the applicable Performance Cycle. Dividends per share paid other than
in the form of cash shall have a value equal to the amount of such dividends reported by the issuer to its
shareholders for purposes of Federal income taxation. For purposes of determining the Total Shareholder
Return for the Company and each of the Peer Companies, the change in the price of the Company’s Stock
and of the common stock of each Peer Company, as the case may be, shall be based upon the volume
weighted average of the stock prices of the Company and each such Peer Company on each trading day in
the 30-day period preceding each of the start (the “Initial Value”) and the end (the “Closing Value”) of the
applicable Performance Cycle. The Initial Value of the Stock to be used to determine Total Shareholder
Return over each Performance Cycle is [$______].
(b) “Peer Company” means a company that is listed below.
• Antero Resources Corporation
• PDC Energy, Inc.
• Cabot Oil & Gas Corporation
• QEP Resources Inc.
• Carrizo Oil & Gas, Inc.
• Range Resources Corporation
• Centennial Resource Development
• SM Energy Co.
• Cimarex Energy Co.
• Whiting Petroleum Corporation
/
• Matador Resources Company
• WPX Energy, Inc.
• Parsley Energy, Inc.
In addition, the Standard & Poor’s Oil & Gas Exploration & Production Select Industry Index, weighted as
a single company, shall also be included as a Peer Company.
If, prior to the end of any Performance Cycle, a company listed above ceases to have a class of common
equity securities listed to trade on a national securities exchange which is registered with the Commission
under Section 6 of the Exchange Act (a “national securities exchange”), then for purposes of determining
the Total Shareholder Return for such Peer Company for the Performance Cycle in which such company
ceases to have a class of common equity securities listed to trade on a national securities exchange, the
change in the price of the Peer Company’s common stock shall be based upon the volume weighted average
of the stock price of such Peer Company on each trading day in the 30-day period preceding the start of the
applicable Performance Cycle (the “Initial Value”) and (i) if, following the cessation of trading on a
national securities exchange, such Peer Company’s class of common equity securities is publicly traded on
another market, exchange or quotation system, the volume weighted average of the stock price, on whatever
market, exchange or quotation system on which the Peer Company’s common equity securities is publicly
traded, of such Peer Company on each trading day in the 30-day period preceding the end of the applicable
Performance Cycle (the “Closing Value”) or (ii) if, following the cessation of trading on a national
securities exchange, such Peer Company’s class of common equity securities is not publicly traded on
another market, exchange or quotation system, the stock price of the Peer Company on the last day during
the Performance Cycle that such Peer Company had a class of common equity securities which was publicly
traded on another market, exchange or quotation system (the “Closing Value”). Following the end of any
Performance Cycle in which such company ceases to have a class of common equity securities listed to
trade on a national securities exchange, such company shall not be a Peer Company for purposes of
calculating the Company’s TSR Vesting Objective under this Appendix A for any other Performance Cycle
which has not ended previously within the Grant Cycle.
If, prior to the end of any Performance Cycle, a company listed above is acquired or merged and, thus,
ceases to have a class of common equity securities listed to trade on a national securities exchange or
publicly traded on another market, exchange or quotation system, then for purposes of determining the Total
Shareholder Return for such Peer Company for the Performance Cycle in which such company is so
acquired or merged, the change in the price of the Peer Company’s common stock shall be based upon the
volume weighted average of the stock price of such Peer Company on each trading day in the 30-day period
preceding the start of the applicable Performance Cycle (the “Initial Value”) and the stock price on the last
day during the Performance Cycle that such Peer Company had a class of common equity securities listed to
trade on a national securities exchange or publicly traded on another market, exchange or quotation system
before the closing of the merger or acquisition (the “Closing Value”). Following the end of any
Performance Cycle in which such company ceases to have a class of common equity securities listed to
trade on a national securities exchange due to an acquisition or merger, such company shall not be a Peer
Company for purposes of calculating the Company’s TSR Vesting Objective under this Appendix A for any
other Performance Cycle which has not ended previously within the Grant Cycle.
2. Calculation of Ranking; Earned Performance Units.
(a) After the end of each Performance Cycle, the Committee will:
(i)
(ii)
calculate the Company’s Total Shareholder Return and the Total Shareholder
Return of each Peer Company;
rank, from highest to lowest, the Total Shareholder Return of the Company
and each Peer Company;
(iii)
calculate the percentage of Initial Performance Units that will become Earned
/
Performance Units for each corresponding TSR rank, where (i) 200% Initial
Performance Units become Earned Performance Units if the Company TSR
Rank is 1, (ii) 0% Initial Performance Units become Earned if the Company
TSR rank is in the bottom three, and (iii) the percentage of Initial Performance
Units that become Earned corresponding to the remaining TSR rankings will
be determined by distributing linearly between the highest and lowest ranking
percentages between 200% and 0%, provided that the percentage of Initial
Performance Units that become Earned corresponding to two rankings above
the lowest ranking will be reduced to 0%; and
(iv) certify the level of achievement with respect to the TSR Vesting Objective and
determine the number of Earned Performance Units for the Performance Cycle.
The following table is provided as an example of the above determination, which depends on the number of
Peer Companies remaining at the end of the Performance Cycle:
Total Shareholder
Return Rank
(TSR Vesting
Objective)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
% of Initial Performance
Units eligible to vest for
the Performance Cycle
that will become Earned
Performance Units
200%
186%
171%
157%
143%
129%
114%
100%
86%
71%
57%
43%
0%
0%
0%
% of Initial Performance
Units eligible to vest for
the Performance Cycle
that will become Earned
Performance Units
200%
185%
169%
154%
138%
123%
108%
92%
77%
62%
46%
0%
0%
0%
% of Initial
Performance Units
eligible to vest for the
Performance Cycle
that will become
Earned Performance
Units
200%
183%
167%
150%
133%
117%
100%
83%
67%
50%
0%
0%
0%
(b) Notwithstanding the foregoing:
(i)
if the Company’s Initial Value is greater than its Closing Value for any
Performance Cycle, the greatest percentage of Performance Share Units that may
become Earned Performance Units for that Performance Cycle is 100%;
(ii) if the per share Fair Market Value of the Stock on the last day of the applicable
Performance Cycle is greater than $25, the number of Performance Share Units
that will become Earned Performance Units will be equal to the number of
Performance Share Units that would otherwise become Earned Performance
Units pursuant to this Appendix A multiplied by a fraction, the numerator of
/
which is 25 and the denominator of which is the Fair Market Value of the stock
on the last day of the applicable Performance Cycle; and
(iii) no Performance Share Units will become Earned Performance Units for a
Performance Cycle unless you also satisfy the applicable Continuous Service
Requirement in accordance with the terms of the Agreement and the Notice of
Grant.
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EXHIBIT 10.43
OASIS PETROLEUM INC.
AMENDED AND RESTATED
2010 LONG TERM INCENTIVE PLAN
PHANTOM UNIT AWARD GRANT NOTICE
Pursuant to the terms and conditions of the Oasis Petroleum Inc. Amended and Restated 2010 Long
Term Incentive Plan, attached as Appendix A (the “Plan”), and the associated Phantom Unit Award
Agreement, attached as Appendix B (the “Agreement”), Oasis Petroleum Inc., a Delaware corporation (the
“Company”), hereby grants to the individual listed below (“you” or “Service Provider”) the number of
Phantom Units set forth below. Capitalized terms used but not defined herein shall have the meanings set
forth in the Plan. This Phantom Unit Award (as defined below) is subject to the terms and conditions set
forth herein as a well as the terms and conditions set forth in the Agreement and the Plan, each of which is
incorporated herein by reference.
/
Date of Grant:
, 2019 (“Date of Grant”)
Number of Phantom Units
Granted:
(the “Phantom Unit Award”)
Vesting Schedule:
The restrictions with respect to the Phantom Unit Award will expire and such
Phantom Units will become vested and nonforfeitable as to one-third (1/3) of
the Phantom Unit Award on the first business day following the date on which
Oasis Midstream Partners LP, a Delaware
(the
“Partnership”) makes a distribution for the quarters ending on each of
December 31, 2019, 2020 and 2021. If no distributions are made by the
Partnership as of the September 1 first following any such quarter, the portion
of the Phantom Units scheduled to vest that year will vest and become
nonforfeitable on September 30 of the applicable year; provided, however, that
the restrictions will expire on such dates only if you remain a service provider
to the Company or its Affiliates continuously from the Date of Grant through
the applicable vesting date.
limited partnership
Notwithstanding anything to the contrary herein or in the Agreement, if your
service relationship with the Company or any of its Affiliates is terminated due
to your death or Disability, then the Forfeiture Restrictions on the Phantom
Unit Award shall immediately lapse, and the Phantom Unit Award will be fully
vested as of such termination. For purposes of this Phantom Unit Award,
“Disability” shall have the meaning given such term in any employment
agreement between you and the Company or its Affiliates. Provided, however,
that if there is no existing employment agreement between you and the
Company or its Affiliates, the term “Disability” shall mean your inability to
perform the essential functions of your position with or without reasonable
accommodation, if required by law, due to physical or mental impairment. The
existence of any such Disability shall be certified at the Company’s discretion
by either the disability carrier of the Company or a physician chosen by the
Company, in its sole discretion. In no event will your employment be
terminated as a result of Disability, unless otherwise agreed to by you and the
Company, until the disability carrier or physician chosen by the Company (as
applicable) certifies that the physical or mental condition can be expected to
result in death or can be expected to last for a continuous period of not less
than 180 consecutive days and the Company has provided you with written
notice of termination.
By your signature and the signature of the Company’s representative below, you and the Company
hereby acknowledge receipt of the Phantom Unit Award issued on the Date of Grant indicated above, which
has been issued under the terms and conditions of the Plan, the Agreement and this Phantom Unit Award
Grant Notice, and you agree to be bound to the terms of each such document.
Additionally, you are consenting to receive documents from the Company, and any plan
administrator by means of electronic delivery, provided that such delivery complies with the rules,
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regulations and guidance issued by any applicable government agency. This consent shall be effective for
the entire time that you are a participant in the Plan.
You acknowledge and agree that (a) you are not relying upon any determination by the Company, its
Affiliates, or any of their respective employees, directors, officers, attorneys, or agents (collectively, the
“Company Parties”) of the Fair Market Value (as defined in the Agreement) of the Units (as defined in the
Agreement) on the Date of Grant, (b) you are not relying upon any written or oral statement or
representation of the Company Parties regarding the tax effects associated with your execution of the
Agreement and your receipt, holding and vesting of the Phantom Unit Award, and (c) in deciding to enter
into this Agreement, you are relying on your own judgment and the judgment of the professionals of your
choice with whom you have consulted. You hereby release, acquit and forever discharge the Company
Parties from all actions, causes of actions, suits, debts, obligations, liabilities, claims, damages, losses, costs
and expenses of any nature whatsoever, known or unknown, on account of, arising out of, or in any way
related to the tax effects associated with your execution of the Agreement and your receipt, holding and
exercise of the Phantom Unit Award.
You further acknowledge receipt of a copy of the Plan and the Agreement and agree to all of the
terms and conditions of the Plan and the Agreement.
Note: To accept the Phantom Unit Award, execute this form and return an executed copy to the Vice
President, Human Resources at LTIP@oasispetroleum.com (the “Designated Recipient”) by March 1,
2019. Failure to return the executed copy to the Designated Recipient by such date will render this
issuance invalid.
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Oasis Petroleum Inc.,
a Delaware corporation
By: /s/ Michael Lou
Name: Michael Lou
Title: Executive Vice President and
Chief Financial Officer
Accepted by:
**Please sign and return the Award document provided by your supervisor**
[Name of Grantee]
Date:
/s/ Karla Lundquist
Vice President, Human Resources
Date Received:
Attachments:
Appendix A – Oasis Petroleum Inc. Amended and Restated 2010 Long Term Incentive
Plan
Appendix B – Phantom Unit Award Agreement
SIGNATURE PAGE
TO
PHANTOM UNIT AWARD GRANT NOTICE
/
Appendix A
Oasis Petroleum Inc. Amended and Restated 2010 Long Term Incentive Plan
A-1
/
Appendix B
Phantom Unit Award Agreement
B-1
/
EXHIBIT 10.44
OASIS PETROLEUM INC.
AMENDED AND RESTATED
2010 LONG TERM INCENTIVE PLAN
PHANTOM UNIT AWARD AGREEMENT
This Phantom Unit Award Agreement (this “Agreement”) is made and entered into as of the Date of
Grant set forth in the Phantom Unit Award Grant Notice (“Notice of Grant”) by and between Oasis
Petroleum Inc., a Delaware corporation (the “Company”), and you (“you” or “Service Provider”).
Capitalized terms used but not specifically defined herein shall have the meanings specified in the Notice of
Grant or the Oasis Petroleum Inc. Amended and Restated 2010 Long Term Incentive Plan (the “Plan”), as
applicable.
WHEREAS, the Company has adopted the Plan under which the Company is authorized to grant
Other Stock-Based Awards (including Awards valued by reference to the value of securities of, or the
performance of, subsidiaries of the Company) to Eligible Persons, including certain employees and service
providers of the Company;
WHEREAS, the Company, in order to induce you to enter into and to continue to dedicate service to the
Company and its subsidiaries, including Oasis Midstream Partners LP, a Delaware limited partnership (the
“Partnership”) and to materially contribute to the success of the Company and the Partnership, agrees to
grant you an Award of phantom units (“Phantom Units”), the value of which is equal to the value of the
common units (“Units”) of the Partnership (the “Phantom Unit Award”);
WHEREAS, a copy of the Plan and the Notice of Grant have both been furnished to you and shall be
deemed a part of this Agreement as if fully set forth herein; and
WHEREAS, you desire to accept the Phantom Unit Award made pursuant to this Agreement.
NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for other
valuable consideration hereinafter set forth, the parties agree as follows:
1. The Grant. Subject to the conditions set forth below, the Company hereby grants you effective as
of the Date of Grant set forth in the Notice of Grant, as a matter of separate inducement but not in lieu of
any salary or other compensation for your services to the Company and the Partnership, an Award
consisting of the aggregate number of Phantom Units set forth in the Notice of Grant in accordance with the
terms and conditions set forth in this Agreement, the Notice of Grant, and the Plan, whereby each Phantom
Unit represents the right to receive a cash payment equal to the value of one Unit on the date the Forfeiture
Restrictions expire with respect to such Phantom Unit.
2. Phantom Unit Account. The Company shall establish and maintain a bookkeeping account on its
records for you (a “Phantom Unit Account”) and shall record in such Phantom Unit Account:
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(a) the number of Phantom Units granted to you, (b) the amount deliverable to you at settlement on account
of Phantom Units that have vested and (c) the amount of any distribution equivalent rights credited to you in
accordance with Section 4 hereof. You shall not have any interest in any fund or specific assets of the
Company or the Partnership by reason of this Award or the Phantom Unit Account established for you.
3. Rights of Service Provider. No Units shall be issued to you at the time the grant is made, and you
shall not be, nor have any of the rights and privileges of, a shareholder of the Company or a unitholder or
limited partner of the Partnership with respect to any Phantom Units recorded in the Phantom Unit Account.
You shall have no voting rights with respect to the Phantom Units.
4. Distribution Equivalent Rights. The Company hereby grants to you the right to receive an
amount in cash with respect to each Phantom Unit granted pursuant to this Agreement equal in value to the
distributions made by the Partnership with respect to a Unit during the period such Phantom Unit remains
outstanding (“DERs”). The DERs awarded to you under this Section 4 shall be subject to the same vesting
schedule as the Phantom Unit to which it relates and shall be paid to you in cash on the date that the
Phantom Unit to which it relates is settled in accordance with Section 9 hereof. No interest shall be payable
or otherwise owed with respect to such DERs for the period of time beginning on the date a distribution is
paid to the Partnership’s unitholders and ending on the date the DERs are paid to you pursuant to this
Agreement. Any DERs which relate to a Phantom Unit that do not become vested shall be forfeited at the
same time the related Phantom Unit is forfeited.
5. Restrictions; Forfeiture. Except as provided in the Plan, the Phantom Unit award is restricted in
that it may not be sold, transferred or otherwise alienated or hypothecated until these restrictions are
removed or expire as contemplated in Section 6 of this Agreement and as described in the Notice of Grant.
The Phantom Unit Award is also restricted in the sense that it may be forfeited to the Company (the
“Forfeiture Restrictions”) as described in Section 7 of this Agreement.
6. Expiration of Restrictions and Risk of Forfeiture. The Forfeiture Restrictions will expire and the
Phantom Unit Award will become nonforfeitable as set forth in the Notice of Grant, provided that you
remain a service provider to the Company or its Affiliates continuously from the Date of Grant until the
applicable dates set forth therein.
7.
Terminations of Services.
a. Termination Generally. Except as otherwise provided in the Notice of Grant and subject
to Section 7(b) below, if your service relationship with the Company or any of its Affiliates is
terminated for any reason, then the portion of the Phantom Unit Award (and any associated DERs)
for which the Forfeiture Restrictions have not lapsed as of the date of termination shall become null
and void and such Phantom Units shall be forfeited. The portion of the Phantom Unit Award for
which the Forfeiture Restrictions have lapsed as of the date of such termination shall not be
forfeited.
b. Effect of Employment Agreement or Plan. Notwithstanding any provision herein to the
contrary, in the event of any inconsistency between Section 7(a) and the terms of (i)
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any employment agreement entered into by and between you and the Company or its Affiliates, (ii)
the Oasis Petroleum Inc. Executive Change in Control and Severance Benefit Plan, to the extent you
are a participant, or (iii) any similar or successor plan, to the extent you are a participant, the terms
of such applicable agreement or plan shall control to the extent such agreement or plan addresses the
Phantom Unit Award.
8. Leave of Absence. With respect to the Phantom Unit Award, the Company may, in its sole
discretion, determine that if you are on a leave of absence for any reason, you will be considered to still be a
service provider to the Company or its Affiliates; provided, that rights to the Phantom Unit Award during a
leave of absence will be limited to the extent to which those rights were earned or vested when the leave of
absence began.
9. Settlement Date; Manner of Settlement. Promptly following the expiration of the Forfeiture
Restrictions and upon receipt by the Company of any tax withholding as may be required pursuant to
Section 10, but in no event later than the first March 15 following the date the Forfeiture Restrictions expire
with respect to a Phantom Unit, the Company shall deliver to you an amount of cash in an amount equal to
the sum of (i) the product of (a) the number of Phantom Units as to which the Forfeiture Restrictions have
lapsed and (b) the Fair Market Value of a Unit on the day prior to the vesting date, and (ii) the DERs that
relate to the Phantom Units as to which the Forfeiture Restrictions have lapsed. The amounts deliverable
pursuant to this Section 9 shall not bear any interest owing to the passage of time. For purposes of this
Section 9, “Fair Market Value” means, on any relevant date, the closing sales price of a Unit on the
principal national securities exchange or other market in which trading in Units occurs (or, if there is no
trading in the Units on such date, on the next preceding day on which there was trading) as reported in The
Wall Street Journal (or other reporting service approved by the Committee). If the Units are not traded on a
national securities exchange or other market at the time a determination of Fair Market Value is required to
be made hereunder, the determination of Fair Market Value shall be made by the Committee in good faith
using a “reasonable application of a reasonable valuation method” within the meaning of Section 409A
(specifically, Section 1.409A-1(b)(5)(iv)(B) of the Treasury regulations).
10.
Payment of Taxes. The Company may require you to pay to the Company (or a Company
Affiliate if you are a service provider to a Company Affiliate) an amount the Company deems necessary to
satisfy its (or its Affiliate’s) current or future obligation to withhold federal, state or local income or other
taxes that you incur as a result of the Phantom Unit Award. With respect to any required tax withholding,
the Company (or its Affiliate) will withhold from the amount deliverable to you under this Agreement the
amount necessary to satisfy the Company’s (or its Affiliate’s) obligation to withhold taxes.
11. Clawback. Notwithstanding any provisions in the Plan or this Agreement to the contrary, any
portion of the payments and benefits provided under this Agreement shall be subject to any clawback policy
adopted by the Company, including any such policy adopted to conform to the Dodd-Frank Wall Street
Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and
Exchange Commission, and including any such clawback policies adopted with retroactive effect.
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12. Right of the Company and its Affiliates to Terminate Services. Nothing in this Agreement
confers upon you the right to continue as a service provider for the Company or its Affiliates, or interfere in
any way with the rights of the Company or its Affiliates to terminate your service relationship at any time.
13.
Furnish Information. You agree to furnish to the Company all information requested by the
Company to enable it to comply with any reporting or other requirements imposed upon the Company by or
under any applicable statute or regulation.
14. No Liability for Good Faith Determinations. The Company and the members of the Board
shall not be liable for any act, omission or determination taken or made in good faith with respect to this
Agreement or the Phantom Unit Award.
15.
Executions of Receipts and Releases. Any payment of cash or other property to you, or to your
legal representative, heir, legatee or distributee in accordance with the provisions hereof, shall, to the extent
thereof, be in full satisfaction of all claims of such Persons hereunder. The Company may require you or
your legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance,
to execute a release and receipt therefor in such form as it shall determine.
16. No Guarantee of Interests. The Board and the Company do not guarantee the Phantom Units
from loss or depreciation.
17. Company Records. Records of the Company or its Affiliates regarding your period of service,
termination of service and the reason(s) therefor, leaves of absence, re-employment, and other matters shall
be conclusive for all purposes hereunder, unless determined by the Company to be incorrect.
18. Notice. All notices required or permitted under this Agreement must be in writing and
personally delivered or sent by mail and shall be deemed to be delivered on the date on which it is actually
received by the Person to whom it is properly addressed or if earlier, the date it is sent via certified United
States mail or reputable overnight delivery service (charges prepaid).
19. Waiver of Notice. Any Person entitled to notice hereunder may waive such notice in writing.
20.
Successors. The Company may assign any of its rights under this Agreement without your
consent. This Agreement shall be binding upon and inure to the benefit of the successors and assigns of the
Company. Subject to the restrictions on transfer set forth herein and in the Plan, this Agreement and the
Forfeiture Restrictions shall be binding upon and enforceable against you and your beneficiaries, executors,
administrators and the person(s) to whom the Phantom Unit Award may be transferred by will or the laws of
descent or distribution.
21.
Severability. If any provision of this Agreement is held to be illegal or invalid for any reason,
the illegality or invalidity shall not affect the remaining provisions hereof, but such provision
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shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid
provision had never been included herein.
22. Company or Committee Action. Any action required of the Company shall be by resolution of
the Board or Committee or by a Person or entity authorized to act by resolution of the Board or Committee.
23. Headings. The titles and headings of Sections are included for convenience of reference only
and are not to be considered in construction of the provisions hereof.
24. Governing Law. All questions arising with respect to the provisions of this Agreement shall be
determined by application of the laws of the State of Delaware, without giving any effect to any conflict of
law provisions thereof, except to the extent Delaware state law is preempted by federal law.
25. Consent to Jurisdiction and Venue. You hereby consent and agree that state courts located in
Harris County, Texas and the United States District Court for the Southern District of Texas each shall have
personal jurisdiction and proper venue with respect to any dispute between you and the Company (or its
Affiliate) arising in connection with the Phantom Unit Award or this Agreement. In any dispute with the
Company (or its Affiliate), you will not raise, and you hereby expressly waive, any objection or defense to
any such jurisdiction as an inconvenient forum.
26. Amendment. This Agreement may be amended by the Board or by the Committee at any time
in a manner consistent with Section 10(c) of the Plan.
27.
Terms of Agreement. This Agreement is subject to all the terms, conditions, limitations and
restrictions contained in this Agreement, the Plan, and the Notice of Grant. Except as provided in Section
7(b) of this Agreement, together, the Agreement, Plan, and Notice of Grant constitute the entire agreement
of the parties with regard to the subject matter hereof, and contain all the covenants, promises,
representations, warranties and agreements between the parties with respect to the Phantom Units granted
hereby. Without limiting the scope of the preceding sentence, all prior understandings and agreements, if
any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further
force and effect.
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Oasis Petroleum Inc.
Computation of Ratio of Earnings to Fixed Charges
EXHIBIT 12.1
Year Ended December 31,
2014
2015
2016
(In thousands, except for ratios)
2017
2018
Earnings
Income (loss) before income taxes
$
814,468 $
(56,371) $
(371,554) $
(75,858) $
(25,343)
Add: Fixed charges
167,890
170,624
159,260
161,336
Add: Amortization of capitalized interest
Less: Capitalized interest
Total earnings
Fixed charges
Interest expense
Capitalized interest
Rental expense attributable to interest
1,718
(8,850)
3,315
(18,582)
4,935
(16,848)
7,346
(12,797)
$
975,226 $
98,986 $
(224,207) $
80,027 $
148,474
$
158,390 $
149,648 $
140,305 $
146,837 $
159,085
8,850
650
18,582
2,394
16,848
2,107
12,797
1,702
17,226
3,547
179,858
11,185
(17,226)
Total fixed charges
$
167,890 $
170,624 $
159,260 $
161,336 $
179,858
Ratio of earnings to fixed charges(1)(2)
5.81
—
—
—
—
(1)
(2)
For purposes of calculating the ratios of consolidated earnings to fixed charges, earnings consist of income before income
taxes and fixed charges. Fixed charges consist of interest expensed and capitalized, amortized deferred financing costs and
an estimate of interest within rental expense.
Due to our net pre-tax losses for the years ended December 31, 2018, 2017, 2016 and 2015, the ratio coverage was less
than 1:1. The Company would have needed additional earnings of $31.4 million, $81.3 million, $383.5 million and $71.6
million for the year ended December 31, 2018, 2017, 2016 and 2015, respectively, to achieve a coverage of 1:1.
/
List of Subsidiaries of Oasis Petroleum Inc.
Name of Subsidiary
Oasis Petroleum LLC
Jurisdiction of Incorporation or Organization
Delaware
Exhibit 21.1
Oasis Petroleum North America LLC
Oasis Petroleum Marketing LLC
Oasis Well Services LLC
Oasis Petroleum Permian LLC
Oasis Midstream Services LLC
OMS Holdings LLC
OMP GP LLC
Oasis Midstream Partners LP
OMP Operating LLC
Bobcat DevCo LLC
Beartooth DevCo LLC
Bighorn DevCo LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
/
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (No. 333-219302) and Form S-8
(No. 333-167664, No. 333-206025, No. 333-213118 and No. 333-227021) of Oasis Petroleum Inc. of our report dated March 1,
2019 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this
Form 10-K.
EXHIBIT 23.1
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2019
/
DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
March 1, 2019
Exhibit 23.2
Oasis Petroleum Inc.
1001 Fannin Street, Suite 1500
Houston, Texas 77002
Ladies and Gentlemen:
We hereby consent to the reference to DeGolyer and MacNaughton and to the incorporation of the estimates
contained in our reports entitled “Report as of December 31, 2018 on Reserves and Revenue of Certain Properties
with interests attributable to Oasis Petroleum Inc.” (our Report) in Part 1 and in the “Notes to Consolidated Financial
Statements” portion of the Annual Report on Form 10-K of Oasis Petroleum Inc. for the year ended December 31,
2018 (the Annual Report). We further consent to the incorporation of estimates contained in our reports entitled
“Report as of December 31, 2017 on Reserves and Revenue of Certain Properties owned by Oasis Petroleum Inc.”
and “Report as of December 31, 2016 on Reserves and Revenue owned by Oasis Petroleum Inc.” In addition, we
hereby consent to the incorporation by reference of our Report of Third Party dated January 31, 2019, in the
“Exhibits, Financial Statement Schedules” portion of the Annual Report. We further consent to the incorporation by
reference of references to DeGolyer and MacNaughton and to our Report in Oasis Petroleum Inc.’s Registration
Statements on Form S-3 (File No. 333-219302) and Form S-8 (File No. 333-167664, File No. 333-206025, File No.
333-213118 and File No. 333-227021).
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
/
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Thomas B. Nusz, certify that:
1.
I have reviewed this annual report on Form 10-K of Oasis Petroleum Inc. (the “registrant”);
EXHIBIT 31.1
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting
to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize
and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: March 1, 2019
/s/ Thomas B. Nusz
Thomas B. Nusz
Chairman and Chief Executive Officer
(Principal Executive Officer)
/
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Michael H. Lou, certify that:
1.
I have reviewed this annual report on Form 10-K of Oasis Petroleum Inc. (the “registrant”);
EXHIBIT 31.2
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting
to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize
and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: March 1, 2019
/s/ Michael H. Lou
Michael H. Lou
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
/
/
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
EXHIBIT 32.1
In connection with the annual report of Oasis Petroleum Inc. (the “Company”) on Form 10-K for the year ended
December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas B. Nusz,
Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
(1)
(2)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
The information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.
Date: March 1, 2019
/s/ Thomas B. Nusz
Thomas B. Nusz
Chairman and Chief Executive Officer
(Principal Executive Officer)
/
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
EXHIBIT 32.2
In connection with the annual report of Oasis Petroleum Inc. (the “Company”) on Form 10-K for the year ended
December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael H. Lou,
Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
(1)
(2)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
The information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.
Date: March 1, 2019
/s/ Michael H. Lou
Michael H. Lou
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
/
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
This is a digital representation of a DeGolyer and MacNaughton report.
Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is
subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and
data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report
should be considered the only authoritative source of such information.
/
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
January 31, 2019
Oasis Petroleum Inc.
1001 Fannin, Suite 1500
Houston, Texas 77002
Ladies and Gentlemen:
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31,
2018, of the extent and value of the estimated net proved oil, condensate, and gas reserves of certain properties in
which Oasis Petroleum Inc. (Oasis) has represented it holds an interest. This evaluation was completed on January 31,
2019. The properties evaluated herein consist of working and royalty interests located in the States of Montana, North
Dakota, and Texas. Oasis has represented that these properties account for 100 percent on a net equivalent barrel basis
of Oasis’s net proved reserves as of December 31, 2018. The net proved reserves estimates have been prepared in
accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the Securities and Exchange
Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item
1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Oasis.
Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total
estimated petroleum remaining to be produced from these properties after December 31, 2018. Net reserves are
defined as that portion of the gross reserves attributable to the interests held by Oasis after deducting all interests held
by others.
/
DeGolyer and MacNaughton
3
Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue,
and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from
the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes,
ad valorem taxes, operating expenses, capital costs, and abandonment costs from future gross revenue. Operating
expenses include field operating expenses, transportation and processing expenses, and an allocation of overhead that
directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field
maintenance costs. Abandonment costs are represented by Oasis to be inclusive of those costs associated with the
removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the
request of Oasis, future income taxes were not taken into account in the preparation of these estimates. Present worth
is defined as future net revenue discounted at the arbitrary nominal discount rate of 10 percent per year compounded
monthly over the expected period of realization. Present worth should not be construed as fair market value because
no consideration was given to additional factors that influence the prices at which properties are bought and sold.
Estimates of reserves and revenue should be regarded only as estimates that may change as further production
history and additional information become available. Not only are such estimates based on that information which is
currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental
factors in interpreting such information.
Information used in the preparation of this report was obtained from Oasis and from public sources. In the
preparation of this report we have relied, without independent verification, upon information furnished by Oasis with
respect to the property interests being evaluated, production from such properties, current costs of operation and
development, current prices for production, agreements relating to current and future operations and sale of
production, and various other information and data that were accepted as represented. A field examination of the
properties was not considered necessary for the purposes of this report.
/
DeGolyer and MacNaughton
Definition of Reserves
4
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated
for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-
10(a) (1)-(32) of Regulation S-X of the SEC. Reserves are judged to be economically producible in future years from
known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory
practices using conventional production methods and equipment. In the analyses of production-decline curves,
reserves were estimated only to the limit of economic rates of production under existing economic and operating
conditions using prices and costs consistent with the effective date of this report, including consideration of changes
in existing prices provided only by contractual arrangements but not including escalations based upon future
conditions. The petroleum reserves are classified as follows:
Proved oil and gas reserves - Proved oil and gas reserves are those quantities of oil and gas, which, by
analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible-from a given date forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulations-prior to the time at which contracts providing the right to
operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain that it will commence the project within a
reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled
portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to
contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest
known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance
data and reliable technology establishes a lower contact with reasonable certainty.
/
DeGolyer and MacNaughton
5
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation
and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally
higher portions of the reservoir only if geoscience, engineering, or performance data and reliable
technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques
(including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than
in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous
reservoir, or other evidence using reliable technology establishes the reasonable certainty of the
engineering analysis on which the project or program was based; and (B) The project has been approved
for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a
reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the
ending date of the period covered by the report, determined as an unweighted arithmetic average of the
first-day-of-the-month price for each month within such period, unless prices are defined by contractual
arrangements, excluding escalations based upon future conditions.
Developed oil and gas reserves - Developed oil and gas reserves are reserves of any category that can be
expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the
required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves
estimate if the extraction is by means not involving a well.
Undeveloped oil and gas reserves - Undeveloped oil and gas reserves are reserves of any category that are
expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
/
DeGolyer and MacNaughton
6
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas
that are reasonably certain of production when drilled, unless evidence using reliable technology exists
that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has
been adopted indicating that they are scheduled to be drilled within five years, unless the specific
circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for
which an application of fluid injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir,
as defined in [section 210.4-10 (a) Definitions], or by other evidence using reliable technology
establishing reasonable certainty.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and
evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of
Regulation S-X of the SEC and with practices generally recognized by the petroleum industry as presented in the
publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of
Oil and Gas Reserves Information (Revision as of February 19, 2007)” and in Monograph 3 and Monograph 4
published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the
analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and
completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development plans provided by
Oasis, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
Oasis has represented that its senior management is committed to the development plan provided by Oasis
and that Oasis has the financial capability to execute the development plan, including the drilling and completion of
wells and the installation of equipment and facilities.
/
DeGolyer and MacNaughton
7
A performance-based methodology integrating the appropriate geology and petroleum engineering data was
utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (1)
production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on the
availability of data). Production diagnostics include data quality control, identification of flow regimes, and
characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate
profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of
data, model‑based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir
and fracture parameters on well performance, and complex situations sourced by the nature of unconventional
reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of
development, quality and completeness of basic data, production history, and appropriate reserves definitions.
In the evaluation of non-producing and undeveloped reserves, type-well analysis was performed using well
data from analogous reservoirs for which more complete historical performance data were available.
Data provided by Oasis from wells drilled through December 31, 2018, and made available for this evaluation
were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly
production data available for certain properties only through October 2018. Estimated cumulative production, as of
December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This
required that production be estimated for up to 2 months.
Oil and condensate reserves estimated herein are those to be recovered by normal field separation. Oil and
condensate reserves included herein are expressed in barrels (bbl) representing 42 United Sates gallons per barrel. For
reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed
quantity.
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced
from the reservoirs, measured at the point of delivery, after reduction for fuel use and shrinkage resulting from field
separation and processing. Gas reserves estimated herein are reported as sales gas. All gas reserves are expressed at a
temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the reserves are located.
Gas reserves included in this report are expressed in thousands of cubic feet (Mcf).
/
DeGolyer and MacNaughton
8
Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas
is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and
solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone.
Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both
associated and nonassociated gas.
At the request of Oasis, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of
6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by Oasis.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and
evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum
industry, which are presented in the publication of the Society of Petroleum Engineers PRMS and publications of the
Society of Petroleum Evaluation Engineers Monograph III and IV.
A performance-based methodology integrating the appropriate geology and petroleum engineering data was
utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (1)
production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of
data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well
performance behavior. Analysis was performed for all well groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate
profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of
data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir
and fracture parameters on well performance, and complex situations sourced by the nature of unconventional
reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of
development, quality and completeness of basic data, production history, and the appropriate reserves definitions.
In certain cases, when the previously named methods could not be used, reserves were estimated by analogy
with similar wells or reservoirs for which more complete data were available.
/
DeGolyer and MacNaughton
9
Based on the current stage of field development, production performance, the development plans provided by
Oasis, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as
proved.
Oasis has represented that its senior management is committed to the development plan provided by Oasis
and that Oasis has the financial capability to drill the locations as scheduled in its development plan.
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced
from the reservoirs, measured at the point of delivery, after reduction for fuel use, flare, and shrinkage resulting from
field separation and processing. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit and at a
pressure base of 14.73 pounds per square inch absolute. Gas reserves included herein are expressed in thousands of
cubic feet (Mcf). Oil reserves estimated herein are those to be recovered by conventional lease separation. Oil
reserves included herein are expressed in barrels (bbl) representing 42 United States gallons per barrel.
At the request of Oasis, sales gas reserves estimated herein were converted to oil equivalent using an energy
equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by
Oasis.
Primary Economic Assumptions
Revenue values in this report were estimated using initial prices, expenses, and costs provided by Antero.
Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board
(FASB). The following economic assumptions were used for estimating the revenue values reported herein:
Oil and Condensate Prices
Oasis has represented that the oil and condensate prices were based on West Texas Intermediate (WTI)
pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting period, unless prices are defined by
contractual agreements. The oil and condensate prices were calculated using differentials furnished by
Oasis to the reference price of $65.66 per barrel and held constant thereafter. The volume-weighted
average price attributable to the estimated proved reserves over the lives of the properties was $62.78 per
barrel of oil and condensate.
/
DeGolyer and MacNaughton
Gas Prices
10
Oasis has represented that the gas prices were based on Henry Hub pricing, calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to
the end of the reporting period, unless prices are defined by contractual agreements. The gas prices were
calculated for each property using differentials furnished by Oasis to the reference price of $3.16 per
million British thermal units ($/MMBtu) and held constant thereafter. These price differentials include
revenue from the sale of natural gas liquids attributable to Oasis. British thermal unit factors provided by
Oasis were used to convert prices from $/MMBtu to dollars per thousand cubic feet. The volume-
weighted average price attributable to the estimated proved reserves over the lives of the properties was
$4.183 per thousand cubic feet of gas.
Production and Ad Valorem Taxes
Production taxes were calculated using rates provided by Oasis. Ad valorem taxes were calculated using
rates provided by Oasis based on recent payments.
Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses, provided by Oasis and based on current expenses, were held constant for
the lives of the properties. Future capital expenditures were estimated using 2018 values, provided by
Oasis, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower
than current expenditures, may have been used because of anticipated changes in operating conditions,
but no general escalation that might result from inflation was applied. Abandonment costs, which are
those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration
associated with the abandonment, were provided by Oasis for all properties and were not adjusted for
inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in
determining the economic viability of non-producing and undeveloped reserves estimated herein.
/
DeGolyer and MacNaughton
11
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from
proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas of
the properties evaluated by us contained in this report has been prepared in accordance with Paragraphs 932‑235-50-4,
932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932‑235-50-31(a), (b), and (e) of the Accounting
Standards Update 932-235-50, Extractive Industries - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and
Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10(a) (1)-(32) of Regulation S-
X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the Securities and
Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in
estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed
and proved undeveloped reserves are not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting
or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described
information is in accordance therewith or sufficient therefor.
Summary of Conclusions
The estimated net proved reserves, as of December 31, 2018, of the properties evaluated herein were based on
the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl),
millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):
Estimated by DeGolyer and MacNaughton
Net Proved Reserves
as of December 31, 2018
Oil and Condensate
(Mbbl)
Sales Gas
(MMcf)
Oil Equivalent
(Mboe)
Proved Developed
Proved Undeveloped
Total Proved
144,533
83,883
228,416
339,444
213,282
552,726
201,107
119,430
320,537
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of
6,000 cubic feet of gas per 1 barrel of oil equivalent.
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DeGolyer and MacNaughton
12
The estimated future revenue to be derived from the production and sale of the net proved reserves, as of
December 31, 2018, of the properties evaluated using the guidelines established by the SEC is summarized as follows,
expressed in thousands of dollars (M$):
Proved Developed
(M$)
Proved Undeveloped
(M$)
Total Proved
(M$)
Future Gross Revenue
Production Taxes
Operating Expenses
Capital Costs
Abandonment Costs
Future Net Revenue
Present Worth at 10 Percent
10,636,915
918,518
3,781,555
17,975
76,165
5,842,702
3,573,515
6,015,491
504,418
1,404,607
1,592,242
15,290
2,498,934
1,100,744
16,652,406
1,422,936
5,186,162
1,610,217
91,455
8,341,636
4,674,259
Note: Future income taxes have not been taken into account in the preparation of these estimates.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an
industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would
restrict the recovery of the December 31, 2018, estimated reserves.
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DeGolyer and MacNaughton
13
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing
petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any
financial interest, including stock ownership, in Oasis. Our fees were not contingent on the results of our evaluation.
This letter report has been prepared at the request of Oasis. DeGolyer and MacNaughton has used all assumptions,
data, procedures, and methods that it considers necessary and appropriate to prepare this report.
Submitted,
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DeGolyer and MacNaughton
CERTIFICATE of QUALIFICATION
I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800
East, Dallas, Texas, 75244 U.S.A., hereby certify:
1. That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of
third party addressed to Oasis dated January 31, 2019, and that I, as Senior Vice President, was responsible
for the preparation of this report of third party.
2. That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in
Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas;
that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation
Engineers; and that I have in excess of 34 years of experience in oil and gas reservoir studies and reserves
evaluations.
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