UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☑Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2019
or
☐Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-31539
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware
41-0518430
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
80203
(Zip Code)
(303) 861-8140
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common stock, $.01 par value
Trading Symbol(s)
Name of each exchange on which registered
SM
New York Stock 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 ☑ 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 ☑
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 ☑ 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 ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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
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 ☑
The aggregate market value of the 111,242,033 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common
stock on June 28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, of $12.52 per share, as reported on the New York Stock
Exchange, was $1,392,750,253. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding
common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive
determination for other purposes.
As of February 6, 2020, the registrant had 112,988,364 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule
14A relating to its 2020 annual meeting of stockholders to be filed within 120 days after December 31, 2019.
1
Item
Page
TABLE OF CONTENTS
Cautionary Information about Forward-Looking Statements
Glossary of Oil and Gas Terms
Part I
Items 1. and 2.
Business and Properties
General
Strategy
Significant Developments in 2019
Outlook for 2020
Areas of Operation
Reserves
Production
Productive Wells
Drilling and Completion Activity
Acreage
Delivery Commitments
Major Customers
Employees and Office Space
Title to Properties
Seasonality
Competition
Government Regulations
Available Information
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
Market For Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Part II
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview of the Company
Financial Results of Operations and Additional Comparative Data
Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017
Overview of Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Accounting Matters
Environmental
Non-GAAP Financial Measures
2
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
4
4
7
7
7
7
7
8
8
9
13
13
14
15
15
15
16
16
16
17
17
20
20
36
36
36
37
37
39
41
41
45
48
52
56
59
59
60
Item
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
TABLE OF CONTENTS
(Continued)
Quantitative and Qualitative Disclosures About Market Risk (included within the content of Item 7)
Consolidated Financial Statements and Supplementary Data
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers, and Corporate Governance
Executive Compensation
Part III
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Exhibits and Consolidated Financial Statement Schedules
Form 10-K Summary
Part IV
3
Page
62
63
107
107
111
111
111
111
112
113
113
114
114
117
Cautionary Information about Forward-Looking Statements
This Annual Report on Form 10-K (“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”). All statements, other than
statements of historical facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations,
business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of
management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,”
“forecast,” “intend,” “pending,” “plan,” “potential,” “project,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-
looking statements appear throughout this report, and include statements about such matters as:
•
•
•
•
•
•
•
•
•
•
•
the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (the
“Credit Agreement”);
our outlook on future crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this document)
prices, well costs, service costs, lease operating costs, and general and administrative costs;
the drilling of wells and other exploration and development activities, the ability to obtain permits and governmental approvals, and plans by us, our
joint development partners, and/or other third-party operators;
possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;
oil, gas, and NGL reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with
those reserve estimates;
future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;
cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;
business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital
investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;
plans, objectives, expectations and intentions; and
other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II,
Item 7 of this report.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends,
current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to
known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or
performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects
or economic performance to differ from expectations include the factors discussed in Part I, Item 1A, Risk Factors - Risks Related to Our Business below and
elsewhere in this report. The forward-looking statements in this report speak as of the filing of this report. Although, we may from time to time voluntarily update
our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.
Glossary of Oil and Gas Terms
The oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves, exploratory well, field,
proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X. The entire definitions
of those terms under Rule 4-10(a) of Regulation S-X can be located through the Securities and Exchange Commission’s (“SEC”) website at www.sec.gov.
Ad valorem tax. A tax based on the value of real estate or personal property.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs, water, or other liquid hydrocarbons.
BBtu. One billion British thermal units.
Bcf. One billion cubic feet, used in reference to gas.
4
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas to one Bbl of oil or NGLs.
Btu. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Developed reserves. Reserves 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.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil, gas, and/or NGLs in commercial quantities.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or
stratigraphic condition.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.
Lease operating expenses. The expenses incurred in the lifting of oil, gas, and/or NGLs from a producing formation to the surface, constituting part of the current
operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other
expenses incidental to production, but not including lease acquisition, drilling, or completion costs.
MBbl. One thousand barrels of oil, NGLs, water, or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet, used in reference to gas.
MMBbl. One million barrels of oil, NGLs, water, or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet, used in reference to gas.
Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.
NGLs. The combination of ethane, propane, isobutane, normal butane, and natural gasoline that when removed from gas become liquid under various levels of
higher pressure and lower temperature.
NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for oil.
NYMEX Henry Hub. New York Mercantile Exchange Henry Hub, a common industry benchmark price for gas.
OPIS. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.
5
PV-10 (Non-GAAP). PV-10 is a non-GAAP measure. The present value of estimated future revenue to be generated from the production of estimated net
proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the
date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as
general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual
discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted
future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies
and from period to period.
Productive well. A well that is producing oil, gas, and/or NGLs or that is capable of commercial production of those products.
Proved reserves. Those quantities of oil, gas, and NGLs 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. Existing economic conditions include prices and costs at which economic producibility
from a reservoir is to be determined, and the price to be used is 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.
Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed.
Reserve life index. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-
month period.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil, gas, and/or associated liquid resources that is
confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resource play. A term used to describe an accumulation of oil, gas, and/or associated liquid resources known to exist over a large areal expanse, which when
compared to a conventional play typically has lower expected geological risk.
Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from oil, gas, and NGLs produced and
sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.
Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil, gas, and NGL production free of costs of exploration, development,
and production operations.
Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface
rock formations.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Standardized measure of discounted future net cash flows. The discounted future net cash flows related to estimated proved reserves based on prices used in
estimating the reserves, year end costs, and statutory tax rates, at a 10 percent annual discount rate. The information for this calculation is included in
Supplemental Oil and Gas Information (unaudited) located in Part II, Item 8 of this report.
Track record. Current year conversions of proved undeveloped reserves to proved developed reserves, divided by beginning of the year proved undeveloped
reserves.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of
oil, gas, and NGLs regardless of whether such acreage contains estimated net proved reserves.
Undeveloped reserves. 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. The applicable SEC definition of undeveloped reserves provides that 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.
Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the
production, sales, and costs.
6
When we use the terms “SM Energy,” the “Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and its subsidiaries unless the
context otherwise requires. We have included certain technical terms important to an understanding of our business in the Glossary of Oil and Gas Terms
section of this report. Throughout this document we make statements and projections that address future expectations, possibilities, or events, all of which may
be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this report for an explanation of
these types of statements and the associated risks and uncertainties.
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of
Texas. SM Energy was founded in 1908, incorporated in Delaware in 1915, and our initial public offering of common stock was in December 1992. Our common
stock trades on the New York Stock Exchange under the ticker symbol “SM.”
Our principal office is located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Strategy
At SM Energy, our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and
prosperity, and having a positive impact in the communities where we live and work. Our long-term vision for the Company is to sustainably grow value for all of
our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top tier assets. Our current energy project development
portfolio is focused on oil and gas producing properties in the state of Texas.
Significant Developments in 2019
Strategic Transformation. During 2019, we completed our strategic transformation, which commenced in 2016 through a series of asset acquisitions
and divestitures. For the fourth quarter of 2019, we passed an important milestone by achieving a positive difference between our net cash provided by
operating activities and our net cash used in investing activities. Our operational execution in 2019 was outstanding, achieving our objectives in important
industry metrics, including key top-quartile benchmarks for environmental, health, and safety performance. We were also successful in proving up additional
investment opportunities on our existing acreage positions.
Production. Our average daily production in 2019 consisted of 59.9 MBbl of oil, 300.8 MMcf of gas, and 22.2 MBbl of NGLs, for an average net daily
equivalent production rate of 132.3 MBOE, which represented a 10 percent increase compared with 2018. This increase was primarily driven by a 25 percent
increase in production volumes from our Midland Basin assets as a result of strong well performance, increased drilling and completion efficiencies, improved
completion designs, and longer laterals. We completed more lateral feet in 2019 compared with 2018, driving continued increases in volumes at a lower average
drilling and completion cost. On a retained asset basis, our production volumes increased 13 percent in 2019. As a result of the above, oil production revenue
was approximately 75 percent of total production revenue for the year ended December 31, 2019, compared with 65 percent and 52 percent for the years ended
December 31, 2018 and 2017, respectively. Please refer to Areas of Operation below for additional discussion.
Reserves and Capital Investment. Our estimated proved reserves decreased eight percent to 462.0 MMBOE at December 31, 2019, from 503.4
MMBOE at December 31, 2018. Reserve additions from discoveries, extensions, and infills totaled 98.4 MMBOE and were a result of our successful
development programs, completion optimizations that resulted in improved well performance, and development plan improvements that we believe will enhance
inventory value. The 2019 reserve additions were offset by 2019 production volumes of 48.3 MMBOE and by downward revisions of 94.7 MMBOE, which
resulted primarily from the impact of lower commodity prices. Our proved reserve life index decreased to 9.6 years as of December 31, 2019, compared with
11.5 years as of December 31, 2018. Costs incurred for development and exploration activities, excluding acquisitions, decreased 23 percent from the prior year
to $1.0 billion in 2019. Please refer to Areas of Operation and Reserves below, and to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this
report for additional discussion.
Net Cash Provided by Operating Activities. Net cash provided by operating activities was $823.6 million for the year ended December 31, 2019,
compared with $720.6 million for the year ended December 31, 2018, which was an increase of 14 percent year-over-year. Oil, gas, and NGL production
revenues decreased for the year ended December 31, 2019, compared with 2018, as the impact from higher production volumes was offset by lower commodity
prices. However, the impact of lower commodity prices in 2019 was offset by a net derivative cash settlement gain of $39.2 million for the year ended
December 31, 2019, compared to a net derivative cash settlement loss of $135.8 million for 2018. Please refer to Analysis of Cash Flow Changes Between 2019
and 2018 and Between
7
2018 and 2017 in Overview of Liquidity and Capital Resources in Part II, Item 7, and to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report
for additional discussion.
Outlook
Our business outlook for the next several years is a continuation of our trajectory of improving operating margins and cash flows while strengthening
our balance sheet through absolute debt reduction and improved leverage metrics. Our total capital program in 2020, is budgeted to be between $825.0 million
and $850.0 million, and is expected to be approximately 20% lower compared with 2019, in large part due to significant cost reductions and efficiencies that
were achieved in 2019. Our 2020 program will be focused on highly economic oil development projects in both our Midland Basin and South Texas assets. We
expect total production volumes in 2020 to decrease slightly compared with 2019 as expected continued growth in our oil production volumes will not completely
offset expected decreases in gas and NGL production volumes.
Sustainability is a key focus of our plans, in terms of positioning ourselves financially to participate in future energy investment opportunities, and
executing our strategy of being a premier operator with high standards for corporate responsibility. We are committed to exceptional safety, health, and
environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference in the
communities where we live and work; and transparency in reporting on our progress in these areas.
Please refer to Overview of Liquidity and Capital Resources in Part II, Item 7 of this report for discussion of how we expect to fund our 2020 capital
program.
Areas of Operation
Our 2019 operations were concentrated in the Midland Basin and South Texas, as further described below. The following table summarizes estimated
proved reserves, production, and costs incurred in oil and gas producing activities (“costs incurred”) for the year ended December 31, 2019, for these areas:
Proved reserves
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Relative percentage
Proved developed %
Production
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Avg. daily equivalents (MBOE/d) (1)
Midland Basin
South Texas
Total (1)
167.5
398.8
0.1
234.1
51%
49%
20.5
34.4
—
26.3
72.0
16.6
824.4
73.9
227.8
49%
58%
1.3
75.4
8.1
22.0
60.3
184.1
1,223.2
74.0
462.0
100%
53%
21.9
109.8
8.1
48.3
132.3
Relative percentage
54%
46%
100%
Costs incurred (in millions) (2) (3)
____________________________________________
(1) Amounts may not calculate due to rounding.
(2) Regional costs incurred do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activities that are excluded
from this regional table. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II,
Item 8 of this report.
1,040.2
160.9
859.6
$
$
$
(3) Costs incurred for 2019 included $11.3 million related to acquisitions of primarily unproved oil and gas properties in the Midland Basin. Please refer to Costs
Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
Excluding acquisition activity, costs incurred decreased in 2019 by 23 percent compared with 2018 primarily due to increased operational efficiencies
and decreased drilling, completion crew, and sand costs incurred in developing our Midland Basin assets. Total estimated proved reserves at year end 2019
decreased eight percent from 2018. Production increased 10 percent on an equivalent basis for the year ended December 31, 2019, compared with 2018, and
increased 13 percent on a retained assets basis.
8
Midland Basin. Our Midland Basin assets are located within the Permian Basin in Western Texas and are comprised of approximately 80,000 net acres
(“Midland Basin”). In 2019, we focused on continuing to delineate, develop, and expand our Midland Basin position. Our current Midland Basin position provides
substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
In 2019, we incurred $859.6 million of costs and averaged six drilling rigs and three completion crews. The majority of our Midland Basin capital was
deployed on projects targeting the Lower Spraberry and Wolfcamp A and B intervals on our RockStar assets in Howard and Martin Counties, Texas and Sweetie
Peck assets in Upton and Midland Counties, Texas. We completed 123 gross (111 net) wells and full-year production increased 25 percent year-over-year to
26.3 MMBOE for 2019. As of December 31, 2019, there were 51 gross (48 net) wells that had been drilled but not completed in our Midland Basin program.
Estimated proved reserves increased nine percent to 234.1 MMBOE at year end 2019, from 214.3 MMBOE at year end 2018. This increase was driven by
additions of 58.9 MMBOE from discoveries, extensions and infill, and acquisitions, partially offset by 12.6 MMBOE of downward revisions from price,
performance, and aged proved undeveloped reserves.
South Texas. Our South Texas assets are comprised of approximately 158,900 net acres located in Dimmit and Webb Counties, Texas (“South
Texas”). Our current operations in South Texas are focused on developing the Eagle Ford shale formation and delineating the Austin Chalk formation. Our
overlapping acreage position in the Eagle Ford shale and Austin Chalk formations covers a significant portion of the western Eagle Ford shale and Maverick
Basin Austin Chalk (“Eagle Ford shale”) and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to
processing for NGL extraction.
In 2019, we incurred $160.9 million of costs and averaged one drilling rig and one completion crew. We completed 31 gross (20 net) wells during 2019,
and full-year regional production increased one percent year-over-year to 22.0 MMBOE for 2019. As of December 31, 2019, there were 21 gross (21 net) wells
that had been drilled but not completed in our South Texas program.
Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to
our joint development agreement. The agreement provided that the third party carried substantially all drilling and completion costs and receives a majority of
the working and revenue interest in these wells until certain payout thresholds are reached. This arrangement allowed us to leverage third-party capital to prove
up the value of our Eagle Ford North area, while also allowing us to test cutting edge technology, capture additional technical data, satisfy certain lease
obligations, and potentially expand economic drilling inventory in the future. All wells subject to this agreement were drilled and completed as of December 31,
2019.
During 2019, we added 43.0 MMBOE of estimated proved reserves, offset by downward revisions of 82.1 MMBOE, of which 68.5 MMBOE resulted
from decreased commodity pricing and 10.3 MMBOE resulted from performance revisions. As a result, estimated proved reserves decreased 21 percent to
227.8 MMBOE at year end 2019, from 289.1 MMBOE at year end 2018.
Reserves
Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates
for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The following table presents the
standardized measure of discounted future net cash flows and pre-tax PV-10 (“PV-10”). PV-10 is a non-GAAP financial measure, and generally differs from the
standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of
income taxes on future net revenues. Neither the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil
and gas properties. We and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held without
regard to the specific tax characteristics of such entities. Please refer to the Glossary of Oil and Gas Terms section of this report for additional information
regarding these measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual
quantities and present value of our estimated proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been
filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The following table should be
read along with the section entitled Risk Factors – Risks Related to Our Business below.
Our ability to replace production with new oil and gas reserves is critical to the future success of our business. Please refer to the reserve life index
term in the Glossary of Oil and Gas Terms section of this report for information describing how this metric is calculated.
9
The following table summarizes estimated proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP),
the prices used in the calculation of proved reserves estimates, and reserve life index as of December 31, 2019, 2018, and 2017:
Reserve data:
Proved developed
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Proved undeveloped
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Total proved (1)
Oil (MMBbl)
Gas (Bcf) (2)
NGLs (MMBbl)
MMBOE
Proved developed reserves %
Proved undeveloped reserves %
Reserve data (in millions):
Standardized measure of discounted future net cash flows (GAAP)
PV-10 (non-GAAP):
Proved developed PV-10
Proved undeveloped PV-10
Total proved PV-10 (non-GAAP)
12-month trailing average prices (3)
Oil (per Bbl)
Gas (per MMBtu)
NGLs (per Bbl)
As of December 31,
2019
2018
2017
85.0
712.1
43.4
247.0
99.1
511.1
30.6
214.9
184.1
1,223.2
74.0
462.0
68.2
699.1
60.1
244.8
107.6
622.7
47.2
258.6
175.7
1,321.8
107.4
503.4
53%
47%
49%
51%
58.6
642.9
49.0
214.7
99.6
637.2
47.6
253.4
158.2
1,280.1
96.5
468.1
46%
54%
$
$
$
$
$
$
4,104.0
$
4,654.4
$
3,024.1
2,830.4
$
3,084.2
$
1,532.4
2,020.1
4,362.8
$
5,104.3
$
1,984.2
1,072.3
3,056.5
55.69
2.58
22.68
$
$
$
65.56
3.10
33.45
$
$
$
51.34
3.00
27.69
Reserve life index (years)
9.6
11.5
10.5
____________________________________________
(1) Amounts may not calculate due to rounding.
(2) For the years ended December 31, 2019, 2018, and 2017, proved gas reserves contained 44.9 Bcf, 59.1 Bcf, and 48.1 Bcf of gas, respectively, that we
expect to produce and use as a field equipment fuel source (primarily to power compressors).
(3) The prices used in the calculation of proved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with SEC
rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves.
10
The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated
proved reserves. Please refer to the Glossary of Oil and Gas Terms section of this report for the definitions of standardized measure of discounted future net
cash flows and PV-10.
As of December 31,
2019
2018
2017
(in millions)
Standardized measure of discounted future net cash flows (GAAP)
$
4,104.0 $
4,654.4 $
Add: 10 percent annual discount, net of income taxes
Add: future undiscounted income taxes
Pre-tax undiscounted future net cash flows
Less: 10 percent annual discount without tax effect
2,955.3
579.8
7,639.1
(3,276.3)
3,847.1
1,012.2
9,513.7
(4,409.4)
PV-10 (non-GAAP)
$
4,362.8 $
5,104.3 $
3,024.1
2,573.2
205.7
5,803.0
(2,746.5)
3,056.5
Proved Undeveloped Reserves
Proved undeveloped reserves include those reserves that are expected to be recovered from future wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly
offsetting development areas that are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic
producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2019, we did not have any proved undeveloped
reserves that had been on our books in excess of five years, and none of our proved undeveloped reserves were on acreage expected to expire or on acreage
that was not expected to be held through renewal before the targeted completion date.
For proved undeveloped locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic
and engineering technology when booking estimated proved undeveloped reserves. Of the 214.9 MMBOE of total proved undeveloped reserves as of
December 31, 2019, approximately 60.1 MMBOE of proved undeveloped reserves in the Midland Basin and 68.7 MMBOE of proved undeveloped reserves in
our South Texas position were offset by more than one development spacing area from the nearest developed producing location. We incorporated public and
proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and
interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud
logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as statistical
performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where
both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas,
we restricted proved undeveloped locations to development spacing areas that are immediately adjacent to developed spacing areas.
As of December 31, 2019, estimated proved undeveloped reserves decreased 43.7 MMBOE, or 17 percent compared with December 31, 2018. The
following table provides a reconciliation of our proved undeveloped reserves for the year ended December 31, 2019:
Total proved undeveloped reserves:
Beginning of year
Revisions of previous estimates
Additions from discoveries, extensions, and infill
Purchases of minerals in place
Removed for five-year rule
Conversions to proved developed
End of year
Total
(MMBOE)
258.6
(47.6)
78.5
1.9
(9.8)
(66.7)
214.9
Revisions of previous estimates. Revisions of previous estimates includes a downward pricing revision of 42.3 MMBOE from our South Texas program
as a result of decreased gas and NGL prices. In addition, we had downward performance revisions of 6.0 MMBOE in our Midland Basin program as we updated
certain assumptions based on future well spacing.
11
Additions from discoveries, extensions, and infill. We added 40.8 MMBOE and 30.4 MMBOE of infill estimated proved undeveloped reserves in our
Midland Basin and South Texas assets, respectively, in 2019. We added an additional 3.1 MMBOE and 4.1 MMBOE of estimated proved undeveloped reserves
in the Midland Basin and South Texas, respectively, through various extensions and discoveries. The majority of additions in our Midland Basin and South
Texas programs resulted from future development projects identified by our on-going development and portfolio optimization activities.
Removed for five-year rule. As a result of our testing and delineation efforts in 2019, we revised certain aspects of our future development plans to
focus on maximizing returns and the value of our assets. As a result, we removed 9.8 MMBOE of estimated proved undeveloped reserves and reclassified these
locations to unproved reserve categories. The reclassified locations were generally replaced by locations with higher quality proved undeveloped reserves,
which are reflected as additions from discoveries, extensions, and infill.
Conversions to proved developed. Our 2019 conversion rate was 26 percent. During 2019, we incurred $686.3 million on projects with reserves booked
as proved undeveloped at the end of 2018, of which $611.1 million was spent on converting proved undeveloped reserves to proved developed reserves by
December 31, 2019. At December 31, 2019, drilled but not completed wells represented 26.8 MMBOE of total estimated proved undeveloped reserves. We
expect to incur $182.0 million of capital expenditures in completing these drilled but not completed wells, and we expect all estimated proved undeveloped
reserves to be converted to proved developed reserves within five years from their initial booking as proved undeveloped reserves.
As of December 31, 2019, estimated future development costs relating to our proved undeveloped reserves were $591.5 million, $615.6 million, and
$458.1 million in 2020, 2021, and 2022, respectively.
Internal Controls Over Proved Reserves Estimates
Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in
compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our corporate reserves group and is
coordinated by our Corporate Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors, as
discussed below. Our Corporate Engineering Manager has approximately 12 years of experience in the energy industry and has been employed by the
Company for 10 years. He holds a Bachelor of Science Degree in Petroleum Engineering from Montana Tech of the University of Montana and is a Registered
Professional Petroleum Engineer in the states of Texas, Wyoming and Montana. He is also a member of the Society of Petroleum Engineers. Technical,
geological, and engineering reviews of our assets are performed throughout the year by our regional staff. Data, obtained from these reviews, in conjunction with
economic data and our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineering technical staff
do not report directly to our Corporate Engineering Manager; they report to either their respective regional technical managers or directly to the regional
manager. This design is intended to promote objective and independent analysis within our regions in the proved reserves estimation process.
Third-party Reserves Audit
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the
world for over 70 years. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we
provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited
properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total Company, as well as for
each respective region. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is an Advising Senior Vice President who
received a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science degree in Chemical Engineering from
the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers
and the Society of Petroleum Evaluation Engineers. The 2019 Ryder Scott report concerning our reserves is included as Exhibit 99.1.
In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee of our Board of Directors. Our management,
which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Executive Vice President and Chief
Operating Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee
reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives, apart from our
management, from time to time to discuss processes and findings.
12
Production
The following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties in which we held an interest
during the periods presented. Realized prices presented below exclude the effects of derivative contract settlements. Also presented is a summary of related
production expense on a per BOE basis.
Net production volumes
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE) (1)
Midland Basin net production volumes (2)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE) (1)
Eagle Ford shale net production volumes (2)(3)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE) (1)
Realized price, before the effect of derivative settlements
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Per BOE
Production expense per BOE
Lease operating expense
Transportation costs
Production taxes
For the Years Ended December 31,
2019
2018
2017
21.9
109.8
8.1
48.3
20.5
34.4
—
26.3
1.3
75.4
8.1
21.9
54.10 $
2.39 $
17.26 $
32.84 $
4.67 $
3.88 $
1.35 $
18.8
103.2
7.9
43.9
16.6
25.8
—
20.9
1.2
76.1
7.9
21.8
56.80 $
3.43 $
27.22 $
37.27 $
4.74 $
4.36 $
1.52 $
13.7
123.0
10.3
44.5
8.5
14.7
—
11.0
1.9
104.0
10.1
29.3
47.88
3.00
22.35
28.20
4.43
5.48
1.18
$
$
$
$
$
$
$
Ad valorem tax expense
____________________________________________
(1) Amounts may not calculate due to rounding.
(2) For each of the years ended December 31, 2019, 2018, and 2017, total estimated proved reserves attributed to our Midland Basin assets and our Eagle
0.34
$
0.48 $
0.48 $
Ford shale assets exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis.
(3) During the first quarter of 2017, we completed the divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5
MMBOE of net production on an equivalent basis for the year ended December 31, 2017.
Productive Wells
As of December 31, 2019, we had working interests in 807 gross (758 net) productive oil wells and 519 gross (487 net) productive gas wells.
Productive wells are exploratory, development, or extension wells that are producing, or are capable of commercial production of oil, gas, and/or NGLs.
Productive wells may be temporarily shut-in. Multiple completions in the same wellbore are counted as one well. As of December 31, 2019, two of these wells
had multiple completions. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first
commenced production, but such designation may not be indicative of current or future production composition.
13
Drilling and Completion Activity
All of our drilling and completion activities are conducted by independent contractors. We do not own any drilling or completion equipment. The
following table summarizes the number of operated and outside-operated wells drilled and completed or recompleted on our properties in 2019, 2018, and 2017,
excluding non-consented projects, active injector wells, salt water disposal wells, or wells in which we own only a royalty interest:
Development wells
Oil
Gas
Non-productive
Exploratory wells
Oil
Gas
Non-productive
For the Years Ended December 31,
2019
2018
2017
Gross
Net
Gross
Net
Gross
Net
119
27
1
147
4
4
1
9
107
16
1
124
4
4
1
9
103
39
—
142
18
1
—
19
92
24
—
116
14
1
—
15
56
38
4
98
32
—
1
33
46
35
3
84
29
—
—
29
Total
156
133
161
131
131
113
A productive well is an exploratory, development, or extension well that is producing or is capable of commercial production of oil, gas, and/or NGLs. A
non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development, or extension well that proves to be incapable of
producing oil, gas, and/or NGLs in sufficient commercial quantities to justify completion, or upon completion, the economic operation of a well.
As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil
or gas in another reservoir. A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to
be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was
initiated. Completion refers to the installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry hole, the reporting to the appropriate
authority that the well has been abandoned.
In addition to the wells drilled and completed in 2019 (included in the table above), we were actively participating in the drilling of 22 gross (20 net) wells
and had 66 gross (63 net) drilled but not completed wells as of January 31, 2020. These drilled but not completed wells represent wells that were being
completed or were waiting on completion as of January 31, 2020.
14
Acreage
The following table sets forth the number of gross and net surface acres of developed and undeveloped oil and gas leasehold, fee properties, and
mineral servitudes that we held as of December 31, 2019. Undeveloped acreage includes leasehold interests containing proved undeveloped reserves.
Midland Basin:
RockStar
Sweetie Peck
Midland Basin Total (4)
Eagle Ford shale
Other (5)
Total
Developed Acres (1)
Undeveloped Acres (2)(3)
Total
Gross
Net
Gross
Net
Gross
Net
67,113
17,007
84,120
74,247
16,259
59,589
15,782
75,371
71,296
11,363
4,966
2,835
7,801
88,058
90,415
4,217
251
4,468
87,631
25,599
174,626
158,030
186,274
117,698
72,079
19,842
91,921
162,305
106,674
360,900
63,806
16,033
79,839
158,927
36,962
275,728
____________________________________________
(1) Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that
includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as
developed acreage in the table above.
(2) Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of
oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.
(3) As of February 6, 2020, approximately 1,354, 184, and 155 net acres of undeveloped acreage are scheduled to expire by December 31, 2020, 2021, and
2022, respectively, if production is not established or we take no other action to extend the terms of the applicable leases. Certain of our Eagle Ford shale
acreage is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet
these obligations results in termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous
development obligations required by individual leases are not met.
(4) As of December 31, 2019, total Midland Basin acreage excludes approximately 1,940 net acres associated with drill-to-earn opportunities that we intend to
pursue.
Includes other non-core acreage located in Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming.
(5)
Delivery Commitments
As of December 31, 2019, we had gathering, processing, transportation throughput, and delivery commitments with various third-parties that require
delivery of a minimum quantity of 24 MMBbl of oil and 424 Bcf of gas through 2023, and 18 MMBbl of produced water through 2027. We are required to make
periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. We expect to fulfill our delivery
commitments from a combination of production from our existing productive wells, future development of our proved undeveloped reserves, and future
development of resources not yet characterized as proved reserves. Under certain of our commitments, if we are unable to deliver the minimum quantity from
our production, we may deliver production acquired from third-parties to satisfy our minimum volume commitments.
As of December 31, 2019, in the event that no additional volumes are delivered in accordance with these agreements, the aggregate undiscounted
future deficiency payments would total $218.5 million. This amount does not include deficiency payment estimates associated with approximately 16.5 MMBbl of
future oil delivery commitments where we cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the
price of oil in effect at the time of settlement.
As of the filing of this report, we do not expect to incur any material shortfalls with regard to these commitments.
Major Customers
We do not believe the loss of any single purchaser of our production would materially impact our operating results, as oil, gas, and NGLs are products
with well-established markets and other viable purchaser options are available in our operating regions.
15
The following major customers and entities under common control accounted for 10 percent or more of our total oil, gas, and NGL production revenue
for at least one of the periods presented:
Major customer #1 (1)
Major customer #2 (1)
Major customer #3 (1)
Major customer #4 (1)
Group #1 of entities under common control (2)
For the Years Ended December 31,
2019
2018
2017
18%
14%
13%
9%
13%
18%
5%
7%
10%
18%
6%
1%
—%
10%
17%
Group #2 of entities under common control (2)
____________________________________________
(1) These major customers are purchasers of a portion of our production from our Midland Basin assets.
(2)
8%
12%
11%
In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production
revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of our total
oil, gas, and NGL production revenue.
Employees and Office Space
As of February 6, 2020, we had 530 full-time employees. This is a 13 percent decrease from the 611 full-time employees that we reported as of
February 7, 2019. None of our employees are subject to a collective bargaining agreement.
The following table summarizes the approximate square footage of office space leased by us, as of December 31, 2019, including our corporate
headquarters and regional offices:
Corporate
Midland Basin
South Texas
Total
Approximate Square
Footage Leased
107,000
59,000
62,000
228,000
In addition to the leased office space summarized in the table above, as of December 31, 2019, we owned approximately 12,000 square feet of office
space in South Texas.
Title to Properties
Substantially all of our oil and gas producing assets are held pursuant to oil and gas leases from third-party mineral owners. We obtain title opinions
prior to commencing initial drilling operations on the properties we operate. We have obtained title opinions or have conducted other title review on substantially
all of our producing properties and believe we have satisfactory title to such properties. Most of our producing properties are subject to mortgages securing
indebtedness under our Credit Agreement, royalty and overriding royalty interests, liens for current taxes, and other ordinary course burdens that we believe do
not materially interfere with the development of such properties. We typically perform title investigation in accordance with standards generally accepted in the
oil and gas industry before acquiring developed and undeveloped leasehold acreage.
Seasonality
The price of crude oil is primarily driven by global socioeconomic factors and is less affected by seasonal fluctuations; however, demand for energy is
generally higher in the winter and the summer driving season. The demand and price for gas frequently increases during winter months and decreases during
summer months. To lessen the impact of seasonal gas demand and price fluctuations, pipelines, utilities, local distribution companies, and industrial users
regularly utilize gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime
demand for electricity can divert gas that is traditionally placed into storage which, in turn, may increase the typical winter seasonal price. Seasonal anomalies,
such as mild winters, sometimes lessen these fluctuations.
Certain of our drilling, completion, and other operations are also subject to seasonal limitations. Seasonal weather conditions, government regulations,
and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. Please refer to Risk Factors - Risks
Related to Our Business below for additional discussion.
16
Competition
The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and gas properties. We believe our acreage
positions provide a foundation for development activities that we expect to fuel our future growth. Our competitive position also depends on our geological,
geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and
production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams
enable us to compete in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and gas
companies, which in some cases have larger technical teams and greater financial and operational resources than we do. Many of these companies not only
engage in the acquisition, exploration, development, and production of oil and gas reserves, but also have gathering, processing or refining operations, market
refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or production equipment, or generate electricity.
We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and
maintenance of wells, as well as for the gathering, transporting, and processing of oil, gas, NGLs and water. Consequently, we may face shortages, delays, or
increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including renewable
energy sources such as solar and wind-generated energy, and other fossil fuels such as coal. Competitive conditions may be affected by future energy, climate-
related, financial, or other policies, legislation, and regulations.
In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals. Throughout the oil and gas
industry, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to
the evolving demographics of our industry. We are not insulated from competition for quality people, and we must compete effectively in order to be successful.
Government Regulations
Nearly every aspect of our business is subject to expansive federal, state, and local laws and governmental regulations. These laws and regulations
frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and
regulations have the potential to increase our cost of doing business and consequently could affect our profitability. However, we do not believe that we are
affected to a materially greater or lesser extent than others in our industry.
Energy Regulations
Texas, the state where we conduct operations and own nearly all of our oil and gas assets, has adopted laws and regulations governing the exploration
for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bond requirements in order to drill or
operate wells, governing the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to Texas conservation laws and regulations, including
regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the
unitization or pooling of oil and gas properties. In addition, Texas conservation laws establish maximum rates of production from oil and gas wells, generally limit
or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and
individual wells.
Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”)
has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC’s current regulatory framework generally provides for a
competitive and open access market for sales and transportation of gas. However, FERC regulations continue to affect the midstream and transportation
segments of the industry, and thus can indirectly affect the sales prices we receive for gas production.
Environmental, Health and Safety Matters
General. Our operations are subject to stringent and complex federal, state, and local laws and regulations governing protection of the environment and
worker health and safety as well as the discharge of materials into the environment. These laws and regulations may, among other things:
•
•
•
require the acquisition of various permits before drilling commences;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas
drilling and production and saltwater disposal activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain
wildlife or threatened and endangered plant and animal species; and
17
•
require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.
These laws, rules, and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory
burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws
and regulations are revised frequently, and any changes may result in more stringent, or different permitting, waste handling, disposal, and cleanup
requirements for the oil and gas industry and could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules, and regulations to which our business is subject.
Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation,
treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency
(“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids,
produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas are currently regulated under RCRA’s
non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a
material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation, and Liability Act. The Comprehensive Environmental Response, Compensation, and Liability
Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who
are considered to be responsible for the release or threatened release of a hazardous substance into the environment. These persons include the owner or
operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under
CERCLA, such persons may be subject to joint and several 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. In addition, it is not uncommon for third-parties to file claims for
personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently own, lease, or operate numerous properties that have been used for oil and gas exploration and production for many years. Although we
believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons
may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances
have been taken for disposal. In addition, some of our properties have been operated by third-parties or by previous owners or operators whose treatment and
disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them
may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes,
pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination.
Water discharges. The federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with
respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of
pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or analogous state agencies. The Clean Water
Act also prohibits discharge of dredged or fill material into waters of the United States, including wetlands, except in accordance with the terms of a permit
issued by the United States Army Corps of Engineers, or a state if the state has assumed authority to issue such permits. 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.
The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels,
offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages
and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in
governmental penalties and civil liability.
Air emissions. The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions
permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing
emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-
compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other “greenhouse gases” (“GHG”) present
an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s
atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing a comprehensive suite of regulations to restrict
emissions of GHGs under existing provisions of the CAA. The Trump administration has taken steps to rescind or review many of these regulations. Legislative
and regulatory initiatives related to climate
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change could have an adverse effect on our operations and the demand for oil and gas. Please refer to Risk Factors - Risks Related to Our Business -
Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas,
and NGLs. In addition to the effects of regulation, the meteorological effects of global climate change could pose additional risks to our operations, including
physical damage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for our products.
Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on
threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be
obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in
certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on these species. It is
also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious
adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair
our ability to timely complete well drilling and development and could adversely affect our future production from those areas.
National Environmental Policy Act. Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy
Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact
the environment. In the course of such evaluations, an agency will prepare an environmental assessment to determine 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. The Trump administration has taken steps to modify NEPA’s implementing regulations intended to streamline the NEPA process. No new
regulations have yet been finalized. Judicial and regulatory challenges are expected, and we cannot predict the outcome of any such challenges. All of our
current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits subject to
the requirements of NEPA. This process has the potential to delay development of some of our oil and gas projects.
OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable
state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes
require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational
Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and
safety. We believe we are in substantial compliance with the applicable requirements of OSHA and comparable laws.
Hydraulic fracturing. Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons from tight formations. We
routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand, and chemicals
under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions.
However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground
Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation’s public drinking water through the adoption of drinking water
standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water
sources.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas activities using hydraulic
fracturing techniques, which could potentially cause a decrease in the completion of new oil and gas wells, an increase in compliance costs, and delays, all of
which could adversely affect our financial position, results of operations and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing
are adopted at the state and local levels, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations.
In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal
agencies, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential
increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.
We believe it is reasonably likely that the trend in local and state environmental legislation and regulation will continue toward stricter standards, while
the trend in federal environmental legislation and regulation faces an uncertain future under the Trump administration. While we believe we are in substantial
compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements
will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected
in the future.
Environmental, Health and Safety Initiatives. We are committed to exceptional safety, health, and environmental stewardship; making a positive
difference in the communities where we live and work; and transparency in reporting on our progress in these areas. We set annual goals for our
environmental, health and safety program focused on reducing the number of safety related incidents and the number and impact of spills of produced fluids. In
addition, we set annual goals for GHG emissions intensity and methane emissions as a percentage of total methane produced. We also periodically conduct
audits of our operations to ensure regulatory compliance and we strive to provide appropriate training for our employees. Reducing air emissions as a result of
leaks, venting, or
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flaring of gas during operations has become a major focus area for regulatory efforts and for our compliance efforts. While flaring is sometimes necessary,
reducing these volumes is a priority for us. To avoid flaring when possible, we restrict testing periods and connect our production to gas pipeline infrastructure as
quickly as possible after well completions. We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance.
Such expenditures are included within our overall capital budget and are not separately itemized.
Available Information
Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website’s
investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and
amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably
practical after we electronically file such materials with or furnish such materials to the SEC, and can be located at www.sec.gov. We also make available
through our website our Corporate Governance Guidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics, and the Charters
of the Audit, Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors. Information on our website is not
incorporated by reference into this report and should not be considered part of this document.
ITEM 1A. RISK FACTORS
In addition to the other information included in this report, the following risk factors should be carefully considered when evaluating an investment in us.
Risks Related to Our Business
Oil, gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.
Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and gas properties depend heavily on the prices we
receive for oil, gas, and NGL sales. Oil, gas, and NGL prices also affect our cash flows available for capital expenditures and other items, our borrowing
capacity, and the volume and value of our oil, gas, and NGL reserves. For example, the amount of our borrowing base under our Credit Agreement is subject to
periodic redetermination based on oil, gas, and NGL prices specified by our bank group at the time of redetermination. In addition, we may have oil and gas
property impairments or downward revisions of estimates of proved reserves if prices fall significantly. Please refer to Significant Developments in 2019 and
Reserves in Part I, Items 1 and 2 Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 in Part II, Item 7, and Note
1 – Summary of Significant Accounting Policies, Note 11 – Fair Value Measurements, and Supplemental Oil and Gas Information (unaudited) in Part II, Item 8
for specific discussion.
Historically, the markets for oil, gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, gas, and NGL
prices may result from relatively minor changes in the supply of and demand for oil, gas, and NGLs, market uncertainty, and other factors that are beyond our
control, including:
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global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;
the level of consumer demand for oil, gas, and NGLs;
overall global and domestic economic conditions;
weather conditions;
the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas;
liquefied natural gas deliveries to and from the United States;
the price and availability of alternative fuels;
technological advances and regulations affecting energy consumption and conservation;
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and
production controls;
political instability or armed conflict in oil or gas producing regions;
actual or perceived epidemic risks, such as the Coronavirus outbreak in early 2020;
strengthening and weakening of the United States dollar relative to other currencies;
stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas,
and NGLs and related infrastructure; and
governmental regulations and taxes.
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Declines in oil, gas, and NGL prices would reduce our revenues and could also reduce the amount of oil, gas, and NGLs that we can produce
economically, which could have a materially adverse effect on us.
Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.
In the last decade, the United States and global economies and financial systems have experienced turmoil and upheaval characterized by extreme
volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure,
collapse, or sale of financial institutions, and an unprecedented level of intervention by the United States federal government and other governments. Weakness
or uncertainty in the United States economy or other large economies could materially adversely affect our business and financial condition. For example:
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the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;
the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;
our ability or the ability of our suppliers or contractors to access the capital markets may be restricted or non-existent at a time when we or they
would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;
our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek
bankruptcy protection; and
variable interest rate spread levels, including for LIBOR (or any applicable replacement rate) and the prime rate, could increase significantly,
resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement.
If we are unable to replace reserves, we will not be able to sustain production.
Our future operations depend on our ability to find, develop, and acquire oil, gas, and NGL reserves that are economically producible. Our properties
produce oil, gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate, develop and acquire new oil, gas, and
NGL reserves to replace those being depleted by production. Competition for oil and gas properties is intense, and many of our competitors have financial,
technical, human, and other resources necessary to evaluate and integrate acquisitions that are substantially greater than those available to us.
For our prior acquisitions, as well as any future acquisitions we may complete, a successful outcome for our business will depend on a number of
factors, many of which are beyond our control. These factors include the purchase price and transaction costs for the acquisition, future oil, gas, and NGL
prices, the ability to reasonably estimate the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future
operating and capital costs, results of future exploration, exploitation, and development activities on the acquired properties, and future abandonment and
possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future
production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those
assumed in the estimates. Our customary review in connection with acquisitions will not necessarily reveal, or allow us to fully assess, all existing or potential
problems and deficiencies with such properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, or
environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities.
We often acquire interests in properties on an “as-is” basis with limited remedies for breaches of representations and warranties.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if
they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that
acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions
may be limited.
Integrating acquired businesses and properties involves a number of unique risks. These risks include the possibility that management may be
distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations
and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on
our operating results and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.
Substantial capital is required to develop and replace our reserves.
We must make substantial capital expenditures to find, acquire, develop, and produce oil, gas, and NGL reserves. Future cash flows and the availability
of financing are subject to a number of factors, such as the level of production from existing wells, prices received for oil, gas, and NGL sales, our success in
locating, developing and acquiring new reserves, and the orderly functioning of
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credit and capital markets. If our cash flows from operations are less than expected, we may reduce our planned capital expenditures unless we can raise
additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may not always be available to us in sufficient amounts or
on acceptable terms, and the proceeds offered to us for potential divestitures may not always be acceptable to us. Any downgrades to our credit ratings may
make it more difficult or expensive for us to borrow additional funds.
If our revenues decrease in the future due to lower oil, gas, or NGL prices, decreased production, or other reasons, and if we cannot access sufficient
liquidity under our Credit Agreement, other acceptable debt or equity financing arrangements, or through the sale of assets, our ability to execute development
plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.
Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems,
processing facilities, pipelines, and other transportation systems owned or operated by third-parties or by other interruptions beyond our control, which could
obstruct, limit, or eliminate our access to oil, gas, and NGL markets.
The marketability of our oil, gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing
facilities, pipelines, and other transportation systems, which are generally owned or operated by third-parties. Any significant interruption in service from,
damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay, or discontinuance of
development plans for our properties, or lower price realizations. Although we have some influence over the processing and transportation of our operated
production, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil, gas, and NGL production
and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities,
infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process, transport, or market oil,
gas, and NGLs.
In particular, if production from the Midland Basin continues to grow, the amount of oil, gas, and NGLs being produced by us and others could exceed
the capacity of, and result in constraints on, available gathering and transportation systems, pipelines, processing facilities, and other infrastructure. In such
circumstances, it will be necessary for pipelines, gathering and transportation systems, processing facilities, and additional infrastructure to be expanded, built,
or developed to accommodate anticipated production. Certain processing, pipeline, and other gathering, transportation, and infrastructure projects that might be,
or are being, considered for these areas may not be developed timely or at all due to lack of financing or other constraints, including regulatory constraints.
Capital and other constraints could also limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production
to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait
for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect our results of
operations and cash flows. In addition, the operations of the third-parties on whom we rely for gathering, processing, and transportation services are subject to
complex and stringent laws and regulations, which require obtaining and maintaining numerous permits, approvals, and certifications from various federal, state,
and local government authorities. These third-parties may incur substantial costs in order to comply with existing and future laws and regulations. If existing laws
and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these
changes may affect the availability and costs of such services. Similarly, a failure to comply with such laws and regulations by the third-parties on whom we rely
could have a material adverse effect on our business, financial condition, and results of operations.
A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather
conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily
curtail production in response to market or other conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our
cash flows and results of operations.
Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and materially adversely affect our business and financial
condition.
Our debt rating levels could have materially adverse consequences on our business and future prospects and could:
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limit our ability to access debt markets, including for the purpose of refinancing our existing debt;
cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any
dividend distributions or repurchase shares;
negatively impact current and prospective customers’ willingness to transact business with us;
impose additional insurance, guarantee and collateral requirements;
limit our access to bank and third-party guarantees, surety bonds and letters of credit; and
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cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when
dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding
indebtedness.
We cannot provide assurance that any of our current Debt Ratings will remain in effect for any given period of time or that a Debt Rating will not be
further lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.
Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.
We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies, and institutional and
individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise, labor, and materials required to operate oil and
gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many oil and gas properties are sold
in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and productive
properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. We
may not be successful in acquiring and developing profitable properties in the face of this competition. In addition, other companies may have a greater ability to
continue drilling activities during periods of low oil or gas prices and to absorb the burden of current and future governmental regulations and taxation. In
addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as
needed. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on our business activities,
financial condition, and results of operations.
The loss of key personnel could adversely affect our business.
We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of their
services could adversely affect our business. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability
to attract and retain experienced geologists, engineers, landmen, and other professionals. Competition for many of these professionals can be intense. If we
cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.
The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated.
This report and certain of our other SEC filings contain estimates of our proved oil, gas, and NGL reserves and the estimated future net revenues from
those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to oil, gas, and NGL prices, drilling and
completion costs, gathering and transportation costs, operating expenses, capital expenditures, effects of governmental regulation, taxes, timing of operations,
and availability of funds. The process of estimating oil, gas, and NGL reserves is complex and involves significant decisions and assumptions in the evaluation
of available geological, geophysical, engineering, and economic data for each reservoir. These estimates depend on many variables, and changes often occur
as our knowledge of these variables evolves. Therefore, these estimates are inherently imprecise. In addition, our reserve estimates for properties that do not
have a significant production history may be less reliable than estimates for properties with lengthy production histories. A lack of production history may
contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing and/or amount of development expenditures.
Actual future production; prices for oil, gas, and NGLs; revenues; production taxes; development expenditures; operating expenses; and quantities of
producible oil, gas, and NGL reserves will most likely vary from those estimated. Any significant variance of any nature could materially affect the estimated
quantities of and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than what we
have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of operations, results of exploration and
development activity, prevailing oil, gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our
properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may not control.
As of December 31, 2019, 47 percent, or 214.9 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our proved
undeveloped reserves, as of December 31, 2019, we estimate approximately $2.0 billion of capital expenditures would be required. Although we have estimated
our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate,
development may not occur as scheduled, and actual results may not occur as estimated.
You should not assume that the standardized measure of discounted future net cash flows or PV-10 included in this report represent the current market
value of our estimated proved oil, gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on
price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, the present value of
our proved reserves as of December 31, 2019, was estimated using 12-month average sales prices of $55.69 per Bbl of oil (NYMEX WTI spot price), $2.58 per
MMBtu of gas (NYMEX Henry Hub spot price), and $22.68 per Bbl of NGL (OPIS spot price). We then adjust these prices to reflect appropriate quality and
location differentials over the period in estimating our proved reserves. During 2019, our monthly average realized oil prices before the
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effect of derivative settlements were as high as $61.66 per Bbl and as low as $42.28 per Bbl for oil, were as high as $3.33 per Mcf and as low as $2.05 per Mcf
for gas, and were as high as $20.06 per Bbl and as low as $13.84 per Bbl for NGLs. Many other factors will affect actual future net cash flows, including:
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amount and timing of actual production;
supply and demand for oil, gas, and NGLs;
curtailments or increases in consumption by oil purchasers and gas pipelines;
changes in government regulations or taxes, including severance and excise taxes; and
escalations or reductions in service provider and equipment costs resulting from changes in supply and demand.
The timing of production from oil and gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves,
and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10. In
addition, the 10 percent discount factor required by the SEC to be used to calculate PV-10 for reporting purposes is not necessarily the most appropriate
discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and gas industry in general are subject.
Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.
We regularly sell non-core assets in order to increase capital resources available for core assets and other purposes and to create organizational and
operational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in other
core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third-parties, the
availability of purchasers willing to acquire the assets on terms we deem acceptable, or other matters or uncertainties that could impact such dispositions,
including whether transactions could be consummated or completed in the form or timing and for the value that we anticipate. We at times may be required to
retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liabilities or of the
indemnification obligations may be difficult to quantify at the time of the transaction and ultimately could be material.
We have limited control over the activities on properties we do not operate.
Some of our properties are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence
or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill and
expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of
suitable technology, or the amount of expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other
working interest owners of such projects to fund their contractual share of the expenditures of such properties. These limitations and our dependence on the
operator and other working interest owners in these projects could cause us to incur unexpected future costs and materially and adversely affect our financial
condition and results of operations.
We rely on third-party service providers to conduct drilling and completion and other related operations on properties we operate.
Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion and other related
operations. The ability of third-party service providers to perform such operations will depend on those service providers’ ability to compete for and retain
qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, gas, and
NGLs, prevailing economic conditions and financial, business, and other factors. In addition, sustained low commodity prices could cause third-party service
providers to consolidate or declare bankruptcy, which could limit our options for engaging such providers. The failure of a third-party service provider to
adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results
of operations.
Title to the properties in which we have an interest may be impaired by title defects.
We generally rely on title reports in acquiring oil and gas leasehold interests. We obtain title opinions prior to commencing initial drilling operations on
the properties we operate. Undeveloped acreage has greater risk of title defects than developed acreage and title insurance is not generally available for oil and
gas properties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in
the appropriate governmental offices and title abstract facilities before acquiring a specific mineral interest and/or undertaking drilling activities. We, in some
cases, perform curative work to correct deficiencies in the marketability of the title. Generally, under the terms of the operating agreements affecting our
properties, any monetary loss attributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. A
material title defect can reduce the value of a property or render it worthless, thus adversely affecting our financial condition, results of operations, and operating
cash flow if such property is of sufficient value.
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Exploration and development drilling may not result in commercially producible reserves.
Oil and gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible oil, gas, or
NGLs will be found. The cost of drilling and completing wells is often uncertain, and oil, gas, or NGLs drilling and production activities may be shortened,
delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors may include, but are not limited to:
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unexpected adverse drilling or completion conditions;
title problems;
disputes with owners or holders of surface interests on or near areas where we operate;
pressure or geologic irregularities in formations;
engineering and construction delays;
equipment failures or accidents;
hurricanes, tornadoes, flooding, or other adverse weather conditions;
governmental permitting delays;
compliance with environmental and other governmental requirements; and
shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe,
chemicals, water, sand, and other supplies.
The prevailing prices for oil, gas, and NGLs affect the cost of and the demand for drilling rigs, completion and production equipment, and other related
services. However, changes in costs may not occur simultaneously with corresponding changes in commodity prices. The availability of drilling rigs can vary
significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of
demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the available rigs in that region.
Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in
obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the
applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially
adverse effect on our ability to explore or develop our properties.
The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other
technologies we use do not allow us to know conclusively prior to drilling a well if oil, gas, or NGLs are present, or whether they can be produced economically.
Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling
and completion costs. Even if sufficient amounts of oil, gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or
experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to
repair the well, and/or the loss and abandonment of the well.
Results in newer resource plays may be more uncertain than results in resource plays that are more developed and have longer established production
histories. We and the industry generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in newer
resource plays than other areas with longer histories of development and production. Drilling and completion techniques that have proven to be successful in
other resource plays are being used in the early development of new plays; however, we can provide no assurance of the ultimate success of these drilling and
completion techniques.
In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drilling inventories can be more
susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling. Because of these uncertainties, we do not know if the
potential drilling locations we have identified will ever be drilled, although we have the present intent to do so for locations booked as proved undeveloped
locations, or if we will be able to produce oil, gas, or NGLs from these potential drilling locations.
We may not be able to obtain any options or lease rights in potential drilling locations that we identify. Unless production is established within the
spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire and we will lose our right to
develop the related properties. Our total net acreage as of February 6, 2020, that is scheduled to expire over the next three years, represents approximately one
percent of our total net undeveloped acreage as of December 31, 2019. Although we have identified numerous potential drilling locations, we may not be able to
economically drill for and produce oil, gas, or NGLs from all of them, and our actual drilling activities may materially differ from those presently identified, which
could adversely affect our financial condition, results of operations and operating cash flow.
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Part of our strategy involves drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques. The
results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and 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.
Many of our operations involve utilizing the latest drilling and completion techniques as developed by us, other operators and our service providers in
order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while drilling include, but are not limited
to, landing our well bore outside the desired drilling zone, deviating from the desired drilling zone while drilling horizontally through the formation, the inability to
run our casing the entire length of the well bore, and the inability to run tools and recover equipment consistently through the horizontal well bore. Risks we face
while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other
equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to
successfully clean out the well bore after completion of the final 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, limited access to gathering systems and takeaway capacity, and/or prices for oil, gas, and NGLs decline, then the return on our
investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of
our undeveloped acreage could decline in the future.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by
actions other operators may take when drilling, completing, or operating wells that they own.
Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests
adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well
is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially
away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit
our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause
production from our wells to be shut in for indefinite periods of time, result in increased lease operating expenses and adversely affect the production and
reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales.
To mitigate a portion of the exposure to potentially adverse market changes in oil, gas, and NGL prices and the associated impact on cash flows, we
have entered into various derivative contracts. Our derivative contracts in place include swap and collar arrangements for oil, and swap arrangements for gas
and NGLs. We have also entered into basis swap arrangements for a portion of our expected Midland Basin oil production to reduce volatility associated with
location differentials between where these volumes are sold and NYMEX WTI. As of December 31, 2019, we were in a net accrued asset position of $21.5
million with respect to our oil, gas, and NGL derivative activities. These activities may expose us to the risk of financial loss in certain circumstances, including
instances in which:
•
•
•
our production is less than expected;
one or more counterparties to our commodity derivative contracts default on their contractual obligations; or
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative
contract arrangement.
In addition, commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially
over the price established by the commodity derivative contract.
The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil, gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we
operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various
economic and other market conditions, including declines in oil, gas, and NGL prices. The loss of one or more of these customers could reduce competition for
our products and negatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact our operating
results, as we have numerous options for purchasers in each of our operating areas for our oil, gas, and NGL production. Please refer to Concentration of Credit
Risk and Major Customers in Note 1 – Summary of Significant Accounting Policies, in Part II, Item 8 of this report for further discussion of our concentration of
credit risk and major customers. Additionally, the inability of our co-owners to pay joint interest billings could negatively impact our cash flows and financial ability
to drill and complete current and future wells.
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We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of quantities actually shipped,
processed, or gathered. If we are unable to deliver the necessary quantities of oil, gas, NGL, or produced water to our counterparties, our results of operations,
financial position, and liquidity could be adversely affected.
As of December 31, 2019, we were contractually committed to deliver 24 MMBbl of oil and 424 Bcf of gas through 2023, and 18 MMBbl of produced
water through 2027. We may enter into additional firm transportation agreements as we expand the development of our resource plays. At the current time, we
do not have enough proved developed reserves to offset these contractual liabilities, but we expect to develop reserves that will meet or exceed the
commitments and therefore do not expect any material shortfalls. In the event we encounter delays in drilling and completing our wells or otherwise due to
construction, interruptions of operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, or if we further
limit our capital expenditures due to future commodity price declines or for other reasons, the requirements to pay for quantities not delivered could have a
material impact on our results of operations, financial position, and liquidity.
Future oil, gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.
We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of exploratory and
development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If commercial quantities of
hydrocarbons are not discovered with an exploratory well, the costs of drilling the well are expensed.
The capitalized costs of our oil and gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that
depletion pool. If net capitalized costs exceed undiscounted future net cash flows, we generally must write down the costs of each depletion pool to the
estimated discounted future net cash flows of that depletion pool. Write downs for unproved properties are also evaluated for carrying costs in excess of fair
value. This evaluation considers the potential for abandonment due to lease expirations, losses on acreage due to title defects, changes in development plans,
and other inherent acreage risks. For the years ended December 31, 2019, 2018, and 2017, we incurred impairment of oil and gas properties expense totaling
$33.8 million, $49.9 million, and $16.1 million, respectively. If the prices of oil, gas, or NGLs decline, or we have unsuccessful exploration efforts, it could cause
additional proved and/or unproved property impairments in the future.
We review the carrying values of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter.
Once incurred, a write-down of oil and gas properties held for use cannot be reversed at a later date, even if oil, gas, or NGL prices increase.
Lower oil, gas, or NGL prices could limit our ability to borrow under our Credit Agreement.
Our Credit Agreement has a current commitment amount of $1.2 billion, subject to a borrowing base that the lenders redetermine semi-annually based
on the bank group’s assessment of the value of our proved reserves, which in turn is impacted by oil, gas, and NGL prices. The borrowing base under our Credit
Agreement is $1.6 billion, up from $1.5 billion at December 31, 2018. The next semi-annual redetermination date is scheduled for April 1, 2020. Divestitures of
additional properties, incurrence of additional debt, or declines in commodity prices could limit our borrowing base and reduce the amount we can borrow under
our Credit Agreement.
The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more
difficult for us to make payments on our debt.
As of December 31, 2019, we had the following outstanding long-term debt:
•
•
•
•
•
•
$476.8 million of long-term senior unsecured debt relating to our 6.125% Senior Notes due 2022 (“2022 Senior Notes”) that we issued on
November 17, 2014;
$500.0 million of long-term senior unsecured debt relating to our 5.0% Senior Notes due 2024 (“2024 Senior Notes”) that we issued on May 20,
2013;
$500.0 million of long-term senior unsecured debt relating to our 5.625% Senior Notes due 2025 (“2025 Senior Notes”) that we issued on May 21,
2015;
$500.0 million of long-term senior unsecured debt relating to our 6.75% Senior Notes due 2026 (“2026 Senior Notes”) that we issued on
September 12, 2016;
$500.0 million of long-term senior unsecured debt relating to our 6.625% Senior Notes due 2027 (“2027 Senior Notes”, and all senior notes
collectively referred to as the “Senior Notes”) that we issued on August 20, 2018; and,
$172.5 million in aggregate principal amount of long-term senior unsecured convertible debt relating to our 1.50% Senior Convertible Notes due
July 1, 2021 (“Senior Convertible Notes”) that we issued on August 12, 2016.
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Additionally, we had $122.5 million of outstanding borrowings under our Credit Agreement as of December 31, 2019, resulting in $1.1 billion of
available borrowing capacity under our secured credit facility. Our long-term debt represented 50 percent of our total book capitalization as of December 31,
2019.
Our indebtedness could have important consequences for our operations, including:
• making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements,
capital expenditures, debt service, or other general corporate requirements;
•
•
•
requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs
associated with our debt, rather than to productive investments;
limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making
acquisitions, and paying dividends;
placing us at a competitive disadvantage compared to our competitors with less debt; and
• making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.
If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our Credit Agreement
or from other sources, we might not be able to service our debt, issue additional debt, or fund our planned capital expenditures and other liquidity needs. If we
are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity
securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sell our assets, or restructure or refinance our debt on
a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our Credit Agreement and any future
credit agreements, may prohibit us from pursuing any of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost,
terms, conditions, and availability of future financing.
Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes and our Senior Convertible Notes, permit us to
incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition, entities we may acquire in the future
could have significant amounts of debt outstanding that we could be required to assume, and in some cases accelerate repayment thereof, in connection with
the acquisition, or we may incur our own significant indebtedness to consummate an acquisition.
As discussed above, our Credit Agreement is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank
borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we
do not have sufficient funds and are otherwise unable to negotiate adjustments to our borrowing base or arrange new financing, we may be forced to sell
significant assets.
The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from
engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.
Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes and our Senior Convertible Notes, contain
restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our Credit Agreement is
subject to compliance with certain financial covenants. Financial covenants under the Credit Agreement require that our (a) total funded debt, as defined in the
Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which will use
annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal
quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot
be less than 1.0 to 1.0 as of the last day of any fiscal quarter. Our Credit Agreement also requires us to comply with certain additional financial covenants,
including a requirement that we limit our annual cash dividends to no more than $50.0 million. These restrictions on our ability to operate our business could
seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate
opportunities. We were in compliance with all financial and non-financial covenants as of December 31, 2019, and through the filing of this report. Please refer to
Non-GAAP Financial Measures in Part II, Item 7 of this report for our definition of adjusted EBITDAX.
The respective indentures governing the Senior Notes and Senior Convertible Notes also contain covenants that, among other things, limit our ability
and the ability of our subsidiaries to:
•
incur additional debt;
• make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire common stock;
•
•
sell assets, including common stock of our subsidiaries;
restrict dividends or other payments of our subsidiaries;
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•
•
create liens that secure debt;
enter into transactions with affiliates; and
• merge or consolidate with, or transfer or lease all or substantially all of our assets to another company.
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a
portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion
of our outstanding indebtedness.
Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational
disruptions or financial loss.
We are subject to cybersecurity risks. The oil and gas industry is increasingly dependent on digital technology in all aspects of our business. We use
digital technology to conduct certain of our drilling development, production and gathering activities, manage drilling rigs and completion equipment, gather and
interpret seismic data, conduct reservoir modeling, record financial and operating data, and maintain employee and other databases. Our service providers,
including those who gather, process and market our oil, gas and NGLs, are also increasingly reliant on digital technology. Our and their reliance on this
technology increasingly puts us at risk for technology system failures, data or network disruptions, cyberattacks and other breaches in cybersecurity. Power
failures, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire,
flood, human error or other means could significantly impair our ability to conduct our business.
Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data,
and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information,
and corruption of data. Deliberate attacks on, or security breaches in our systems, infrastructure, the systems and infrastructure of third-parties, or cloud-based
applications could lead to disclosure of confidential information, a corruption or loss of our proprietary data, delays in production or exploration activities, difficulty
in completing or settling transactions, challenges in maintaining our books and records, environmental damage, communication or other operational disruptions,
and liability to third parties. Any insurance we might obtain in the future may not provide adequate protection from these risks. Any such events could damage
our reputation and lead to financial losses from remedial actions, loss of business or potential liability. As these cyber risks continue to evolve and our
dependence on digital technologies grows, we may be required to expend significant additional resources to continue to modify or enhance our protective
measures and remediate cyber vulnerabilities.
Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.
As an oil, gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information
or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third-party facilities and
infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these
threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats
from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel, or capabilities
essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
The threat of terrorism and the impact of military and other actions have caused instability in world financial markets and could lead to increased
volatility in prices for oil, gas, and NGLs, all of which could adversely affect the markets for our production. Energy assets might be specific targets of terrorist
attacks. While we currently maintain some insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and
difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms we consider reasonable, or at all. In addition, this
insurance may not cover all of our losses for a terrorist attack. These developments have subjected our operations to increased risk and, depending on their
occurrence and ultimate magnitude, could have a material adverse effect on our business, financial condition, or results of operations.
Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business,
operations and our ability to attract capital.
Certain segments of the public as a whole, and the investment community in particular, have developed negative sentiment towards our industry.
Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition,
some investors, including investment management firms, sovereign wealth and pension funds, university endowments and other investment advisors, have
adopted policies to discontinue or reduce their investments in the oil and gas sector based on social and environmental considerations. Furthermore, other
influential stakeholders have pressured commercial and investment banks to reduce or cease financing of oil and gas companies and related infrastructure
projects.
Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in
downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for
potential development projects, impacting our future financial results.
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We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.
Oil and gas operations are subject to many risks, including human error and accidents, that could cause personal injury, death, property damage, well
blowouts, craterings, explosions, uncontrollable flows of oil, gas and NGLs, or well fluids, releases or spills of completion fluids, spills or releases from facilities
and equipment used to deliver or store these materials, spills or releases of brine or other produced or flowback water, subsurface conditions that prevent us
from stimulating the planned number of completion stages, accessing the entirety of the wellbore with our tools during completion, or removing materials from
the wellbore to allow production to begin, fires, adverse weather such as hurricanes or tornadoes, freezing conditions, floods, droughts, formations with
abnormal pressures, pipeline ruptures or spills, pollution, seismic events, releases of toxic gas such as hydrogen sulfide, and other environmental risks and
hazards. If any of these types of events occurs, we could sustain substantial losses.
Furthermore, if we experience any of the problems with well stimulation and completion activities referenced above, our ability to explore for and
produce oil, gas, or NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of
the need to shut down, abandon, or relocate drilling operations, the need to modify drill sites to lessen the risk of spills or releases, the need to investigate
and/or remediate any spills, releases or ground water contamination that might have occurred, and the need to suspend our operations.
There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling, and
disposal of materials, including produced water, solid and hazardous wastes, and petroleum hydrocarbons. We may incur joint and several, and/or strict liability
under applicable United States federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at,
on, under or from our leased or owned properties, some of which have been used for oil and gas exploration and production activities for a number of years,
often by third-parties not under our control. For our outside-operated properties, we are dependent on the operator for operational and regulatory compliance
and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or therefrom could be subject to stringent
and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original
conduct, including CERCLA or the Superfund law, RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under various implementing
regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or
closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal
injury or property damage, including induced seismicity damage, allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into
the environment. As a result, we may incur substantial liabilities to third-parties or governmental entities, which could reduce or eliminate funds available for
exploration, development, or acquisitions, or cause us to incur losses.
We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental
damage. We do not believe that insurance coverage for the full potential liability that could be caused by environmental damage that occurs gradually over time
is appropriate for us at this time given the nature of our operations and the nature and cost of such coverage. Further, we may elect not to obtain insurance
coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we
may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is
not fully covered by insurance, we could suffer a material loss.
Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks.
Federal, state, and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant
review for amendment or expansion, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the
pricing, or marketing of oil, gas, and NGL production. Non-compliance with statutes and regulations and more vigorous enforcement of such statutes and
regulations by regulatory agencies may lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages,
the imposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations. The overall regulatory
burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases
profitability.
Governmental authorities regulate various aspects of drilling for and the production of oil, gas, and NGLs, including the permit and bonding
requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in oil and gas properties, rights-of-way and easements, disposal of
produced water, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, restoration
standards, and oil and gas operations. Public interest in environmental protection has increased in recent years, and environmental organizations have
opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose
conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain
properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed, suspended, or terminated. Any such
delay, suspension, or termination could have a materially adverse effect on our operations.
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Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, and local
governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current
requirements, including the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate in, could result in
material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory
interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur
significant liability, including joint and several, strict liability under federal, state, and local environmental laws for emissions and for discharges of oil, gas, and
NGLs or other pollutants into the air, soil, surface water, or groundwater. We could be required to spend substantial amounts on investigations, litigation, and
remediation for these emissions and discharges and other compliance issues. Any unpermitted release of petroleum or other pollutants from our operations
could result not only in cleanup costs, but also natural resources, real or personal property and other damages and civil and criminal liabilities. The listing of
additional wildlife or plant species as federally endangered or threatened could result in limitations on exploration and production activities in certain locations.
Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a
materially adverse effect on us.
The impact of extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Our operations on our Midland Basin and South Texas assets are adversely affected by the impact of extreme weather conditions and lease
stipulations designed to protect various wildlife or plant species. In certain areas, drilling and other oil and gas activities can only be conducted during limited
times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs and completion equipment, oil
field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal
leases or across federal lands. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and
capital costs.
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing, air quality, and greenhouse gas emissions could result in
increased costs and additional operating restrictions or delays.
Hydraulic fracturing is a common practice in the oil and gas industry used to stimulate the production of oil, gas, and NGLs from dense subsurface rock
formations. We routinely apply hydraulic fracturing techniques to many of our oil and gas properties, including our unconventional resource plays within our
Midland Basin and South Texas assets. Hydraulic fracturing involves injecting water, sand, and certain chemicals under pressure to fracture the hydrocarbon-
bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and gas commissions. However, the
EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulic fracturing activities, as outlined below.
The EPA has authority to regulate underground injections that contain diesel in the fluid system under the Safe Drinking Water Act. The EPA has
published an interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatory authority. In June 2016, the EPA
issued regulations under the Federal Clean Water Act establishing federal pre-treatment standards for wastewater generated by unconventional oil and gas
operations during the hydraulic fracturing process. Under a recent settlement, the EPA had until March 2019 to decide whether to initiate rulemaking governing
the disposal of wastewater from oil and gas development under RCRA Subtitle D. In April 2019, the EPA released its review, concluding that no new regulations
were needed for managing wastewater based on the EPA’s conclusion that existing state regulations and best management practices are sufficiently protective
of human health and the environment. If the EPA implements further regulations of hydraulic fracturing, we may incur additional costs to comply with such
requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could
even be prohibited from drilling and/or completing certain wells.
Certain states, including Texas, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting,
public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.
In addition to state laws, local land use restrictions, such as city ordinances, may restrict, or prohibit the performance of drilling in general and/or hydraulic
fracturing in particular. Recently, municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city
boundaries, setting the stage for challenges by state regulators and third-parties. Similar events and processes are playing out in several cities, counties, and
townships across the United States. In the event that state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in
the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or
curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.
In the recent past, several federal governmental agencies were actively involved in studies or reviews that focus on environmental aspects and impacts
of hydraulic fracturing practices. For example, in December 2016, the EPA issued a final assessment of potential impacts to drinking water resources from
hydraulic fracturing. On March 28, 2017, President Trump issued Executive Order 13783 entitled “Promoting Energy Independence and Economic Growth”
(“Executive Order 13783”). Executive Order 13783 directed executive departments and agencies to review regulations that potentially burden the development
or use of
31
domestically produced energy resources and, as appropriate, suspend, revise, or rescind those that unduly burden domestic energy resources development.
We will continue to be subject to uncertainty associated with new regulatory suspensions, revisions or rescissions and inconsistent state and federal
regulatory mandates that could adversely affect our production.
Further, as to air quality and GHG regulation of oil and gas sources, the overall trend has been toward increased regulation and requirements for
reduced emissions. The Trump administration has taken steps toward rescinding or reviewing many of those regulations, but any deregulation will likely face
immediate judicial challenges. The Obama administration took several actions to regulate air quality and GHGs, many of which remain in effect. For example, on
August 16, 2012, the EPA issued final rules subjecting all new and modified oil and gas operations (production, processing, transmission, storage, and
distribution) to regulation under the New Source Performance Standards (“NSPS”) and all existing and new operations to the National Emission Standards for
Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules also include NSPS standards for completions of hydraulically fractured gas wells. These
standards require the use of reduced emission completion (“REC”) techniques developed in the EPA’s Natural Gas STAR program along with the pit flaring of
gas not sent to the gathering line beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as existing wells that are
refractured. Further, the regulations under NESHAP include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and
certain storage vessels at major sources of hazardous air pollutants not previously subject to MACT standards. These rules require additional control equipment,
changes to procedure, and extensive monitoring and reporting. In September 2013 and December 2014, the EPA published technical fixes to the 2012 NSPS,
including standards for storage tanks subject to the NSPS. The amendments clarified stages for flowback and the point at which green completion equipment is
required and updated requirements for storage tanks and leak detection requirements for processing plants. As part of the EPA’s strategy during the Obama
administration to reduce methane and ozone-forming volatile organic compound (“VOC”) emissions from the oil and gas industry, on May 12, 2016, the EPA
issued final regulations that amend and expand the 2012 regulations. The 2016 NSPS requires reduction of GHGs in the form of methane and VOCs from
certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September
18, 2015. The final regulation requires, among other things, GHG and VOC standards for certain equipment, such as centrifugal compressors and reciprocating
compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and natural gas transmission
compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well
completions. Both the 2012 and 2016 rules are the subjects of Petitions for Review before the U.S. Circuit Court of Appeals for the District of Columbia, though
the litigation of both rules has been stayed. In June 2017, the EPA proposed a 2-year stay of the compliance requirements in the 2016 NSPS. In a related action
in March 2017, the EPA withdrew the final information request it had issued in 2016 as part of an effort to develop standards under the CAA NSPS provisions for
methane and other emissions from existing sources in the oil and natural gas industry. In September 2018, the EPA proposed changes to the 2016 NSPS
amending specific provisions related to, among other things, fugitive emissions requirements. On August 29, 2019, the EPA proposed amendments to the 2012
and 2016 NSPS that would remove transmission and storage infrastructure from regulation of methane emissions and other VOCs. The amendments would also
rescind methane requirements for oil and gas production and processing equipment. As an alternative, the EPA proposed to rescind the methane requirements
for oil and gas altogether and sought comment on alternative interpretations of its authority to regulate pollutants under Section 111 of the Clean Air Act.
In October 2015, the EPA revised and lowered the ambient air quality standard for ozone in the U.S. under the CAA, from 75 parts per billion to 70
parts per billion, which is likely to result in more, and expanded, ozone non-attainment areas, which in turn will require states to adopt implementation plans to
reduce emissions of ozone-forming pollutants, like VOCs and nitrogen oxides, that are emitted from, among others, the oil and gas industry. Opponents to the
new ozone standards challenged the agency’s action in federal court. In August 2019, the D.C. Court of Appeals upheld the health-based ozone standards, but
remanded to the EPA the secondary, public welfare standards designed to protect environmental values. The 2015 ozone standard is being implemented
pursuant to the EPA’s December 2018 final implementation rule. In October 2016, the EPA finalized Control Techniques Guidelines for VOC emissions from
existing oil and natural gas equipment and processes in moderate ozone non-attainment areas. These Control Techniques Guidelines provide recommendations
for states and local air agencies to consider when determining what emissions requirements apply to sources in the non-attainment areas. The EPA has
proposed to completely withdraw the rules. On May 12, 2016, the EPA also issued a final rule named the “Source Determination Rule” that was issued to clarify
when multiple pieces of oil and gas equipment and activities must be aggregated as a single source for determining whether major source permitting programs
apply. This action can expand the permitting and related control requirements to sources that were not previously subject to permitting requirements. However,
more recently, the EPA has issued several guidance documents and memorandums related to aggregation of facilities that may narrow the effect of the Source
Determination Rule.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas
production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third-parties
opposing such activities to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing
process could adversely affect human health or the environment, including groundwater. In 2013, a court in California held that the Bureau of Land Management
(“BLM”) did not comply with NEPA because it did not adequately consider the impact of hydraulic fracturing and horizontal drilling before issuing leases. Courts
in New York and Colorado reduced the level of evidence required before a court will agree to consider alleged damage claims from hydraulic fracturing by
property owners. Litigation resulting in financial compensation for damages linked to hydraulic fracturing,
32
including damages from induced seismicity, could spur future litigation and bring increased attention to the practice of hydraulic fracturing. Judicial decisions
could also lead to increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to
operational delays or restrictions or increased costs in the exploration for, and production of, oil, gas, and NGLs, including from the development of shale plays,
or could make it more difficult to perform hydraulic fracturing. The adoption of additional state or local laws, or the implementation of new regulations regarding
hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could
adversely affect our financial position, results of operations, and cash flows.
Requirements to reduce gas flaring could have an adverse effect on our operations.
Wells in the Midland Basin in Texas, where we have significant operations, produce natural gas, as well as oil and NGLs. Constraints in the gas
gathering and processing network in certain areas of the Midland Basin have resulted in significant quantities of that gas being flared instead of gathered,
processed, and sold. Further, we are subject to laws established by state and other regulatory agencies that restrict the duration and amount of natural gas that
can be legally flared. These laws and regulations, including potential future regulations that may impose further restrictions on flaring, could limit the amount of
oil and gas we can produce from our wells or may limit the number of wells or the locations that we can drill. Any future laws and regulations may increase our
operational costs, or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.
Our ability to produce oil, gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for
our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable
environmental rules.
The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of oil, gas,
and NGLs requires the use and disposal of significant quantities of water.
Our inability to secure sufficient amounts of water, or to dispose of or recycle the water produced from our wells, could adversely impact our operations.
Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic
fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or
production of oil, gas, and NGLs.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surface water or groundwater
necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which
cannot be predicted, all of which could have an adverse effect on our operations and financial condition.
Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas,
and NGLs.
In December 2009, the EPA made a finding that emissions of carbon dioxide, methane, and other GHGs endanger public health and the environment
because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on this finding, the EPA adopted and
implemented a comprehensive suite of regulations to restrict and otherwise regulate emissions of GHGs under existing provisions of the CAA. In particular, the
EPA adopted two sets of rules regulating GHG emissions under the CAA. One rule requires a reduction in GHG emissions from motor vehicles, and the other
regulates permitting and GHG emissions from certain large stationary sources. These EPA regulatory actions have been challenged by various industry groups,
initially in the D.C. Circuit, which in 2012 ruled in favor of the EPA in all respects. However, in June 2014, the United States Supreme Court reversed the D.C.
Circuit and struck down the EPA’s GHG permitting rules to the extent they impose a requirement to obtain a permit based solely on emissions of GHGs. The
EPA proposed a rule in 2016 to comply with the U.S. Supreme Court’s ruling by limiting the requirement to obtain permits addressing emissions of GHGs to
large sources of other air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2 (or
modifications of these sources that result in an emissions increase of 75,000 tons per year or more of CO2e). If finalized, large sources of air pollutants other
than GHGs will be required to implement the best available capture technology for GHGs. However, the EPA has not taken action on the proposed rule and is
unlikely to do so under the Trump administration. The EPA has also adopted reporting rules for GHG emissions from specified GHG emission sources in the
United States, including petroleum refineries as well as certain onshore oil and gas extraction and production facilities.
Several other cases regarding GHGs have been heard by the courts in recent years. While courts have generally declined to assign direct liability for
climate change to large sources of GHG emissions, some have required increased scrutiny of such emissions by federal agencies and permitting authorities.
There is a continuing risk of claims being filed against companies that have significant GHG emissions, and new claims for damages and increased government
scrutiny, especially from state and local governments, will likely continue. Such cases often seek to challenge air emissions permits that GHG emitters apply for,
seek to force emitters to reduce their emissions, or seek damages for alleged climate change impacts to the environment, people, and property. Any court
rulings, laws, or regulations that restrict or require reduced emissions of GHGs could lead to increased operating and compliance costs and could have an
adverse effect on demand for the oil and gas that we produce.
33
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states
have already taken measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG “cap
and trade” programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of
fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced
each year in an effort to achieve the overall GHG emission reduction goal. In 2013, the Congressional Budget Office provided Congress with a study on the
potential effects on the United States economy of a tax on GHG emissions and recently summarized the impact of imposition of a tax on GHG emissions for
reducing the deficit. While “carbon tax” legislation has been introduced in Congress, the prospects for passage of such legislation are uncertain at this time.
On June 25, 2013, President Obama issued a Climate Action Plan to address climate change through a variety of executive actions, including reduction
of methane emissions from oil and gas production and processing operations as well as pipelines and coal mines (the “Climate Action Plan”). Please refer to
Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing, air quality, and greenhouse gas emissions could result in
increased costs and additional operating restrictions or delays for more information on EPA actions to implement the Climate Action Plan. The focus on
legislating and/or regulating methane could eventually result in:
•
•
•
•
requirements for methane emission reductions from existing oil and gas equipment;
increased scrutiny for sources emitting high levels of methane, including during permitting processes;
analysis, regulation and reduction of methane emissions as a requirement for project approval; and
actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors.
In relation to the Climate Action Plan, both assumed global warming potential (“GWP”) and assumed social costs associated with methane and other
GHG emissions have been finalized, including a 20% increase in the GWP of methane. Changes to these measurement tools could adversely impact permitting
requirements, application of agencies’ existing regulations for source categories with high methane emissions, and determinations of whether a source qualifies
for regulation under the CAA. However, in Executive Order 13783, President Trump ordered a review of the use of social cost of carbon for regulatory impact
analysis. Therefore, the continued use of the social cost of carbon under the Trump administration is uncertain.
Finally, it should be noted that scientists have predicted 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, droughts, and floods and other climatic events. If such
effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our production activities, including, for
example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially
increased costs for insurance coverage in the aftermath of such events. Significant physical effects of climate change could also have an indirect effect on our
financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies, or suppliers with
whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from
potential physical effects of climate change. Federal regulations or policy changes regarding climate change preparation requirements could also impact our
costs and planning requirements.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services that use
new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us
to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to
enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies we currently
use or implement in the future may become obsolete. We cannot be certain we will be able to implement technologies on a timely basis or at a cost that is
acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations, and financial condition may be
adversely affected.
Risks Related to Our Common Stock
The price of our common stock may fluctuate significantly, which may result in losses for investors.
From January 1, 2019, to February 6, 2020, the intraday trading prices per share of our common stock as reported by the New York Stock Exchange
ranged from a low of $6.85 per share in October 2019 to a high of $21.19 per share in January 2019. We expect our stock to continue to be subject to
fluctuations as a result of a variety of factors, including factors beyond our control. These factors include, in addition to the other risk factors set forth herein, the
following:
•
changes in oil, gas, or NGL prices;
34
•
•
•
•
•
•
•
•
•
changes in the outlook for regional, national, or global commodity supply and demand;
variations in drilling, recompletion, and operating activity;
changes in financial estimates by securities analysts;
changes in market valuations of comparable companies;
additions or departures of key personnel;
increased volatility due to the impacts of algorithmic trading practices;
future sales of our common stock;
changes in the national and global economic outlook, including potential impacts from trade agreements; and
international trade relationships, potentially including the effects of trade restrictions or tariffs affecting the raw materials we utilize and the
commodities we produce in our business.
We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a
result.
Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover
premium on their investment, which could adversely affect the price of our common stock.
Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change
of control of us or our management. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of
Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at
stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control,
including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result,
these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price investors
are willing to pay in the future for shares of our common stock.
In addition, stockholder activism in our industry has been increasing, and if investors seek to exert influence or affect changes to our business that we
do not believe are in the long-term best interests of our stockholders, such actions could adversely impact our business by, among other things, distracting our
Board of Directors and management team, causing us to incur unexpected advisory fees and other related costs, impacting execution of our strategic objectives,
and creating unnecessary market uncertainty.
We may not always pay dividends on our common stock.
Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings, capital requirements,
financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our Credit Agreement limiting our annual cash dividends to
no more than $50.0 million, and to covenants in the indentures for our Senior Notes and Senior Convertible Notes that limit our ability to pay dividends beyond a
certain amount. Our Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share or discontinue the
payment of dividends altogether.
35
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of
the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely to have a materially adverse effect upon
our financial condition, results of operations or cash flows.
Chieftain Royalty Company v. SM Energy Company, Case No. CIV-11-D, In the United States District Court, Western District of Oklahoma. On January
27, 2011, Chieftain Royalty Company (“Plaintiff”) commenced a putative class action lawsuit against the Company by filing a Petition in the District Court of
Beaver County, Oklahoma, in the matter originally styled Chieftain Royalty Company v. SM Energy Company (including predecessors, successors and
affiliates), Case No. CJ-201104, alleging that the Company had improperly deducted post-production costs from royalty payments due on production from wells
located throughout Oklahoma, and asserting claims against the Company for breach of contract, tortious breach of contract, breach of fiduciary or quasi-
fiduciary duty, fraud (actual and constructive), deceit, conversion and conspiracy. The Company removed the case to the United States District Court for the
Western District of Oklahoma.
On August 2, 2018, the Court required that Plaintiff file any motion to certify a class by February 8, 2019. Plaintiff filed such motion but limited to royalty
owners in wells related to the Coal County, Oklahoma pipeline system, which was owned by the Company’s affiliate, Four Winds Marketing, LLC, until 2015,
when the subject wells and pipeline system were sold to a third party. The Company opposed the Motion and it remains at issue and pending.
This case involves complex legal and factual issues and uncertainties as to Oklahoma law and federal law concerning class certification under the
circumstances of this case, and has resulted in a significant amount of discovery. The Company believes that it has properly paid royalties under Oklahoma law
and that the class as proposed by Plaintiff should not be certified. The Company has and will continue to vigorously defend this case.
SPM NAM LLC. et al., v. SM Energy Company, Case No. 2018-07160, in the 189th Judicial District of Harris County, Texas (the “Lawsuit”). Plaintiff
SPM NAM LLC (“SPM”) filed the Lawsuit against the Company on February 1, 2018. The Lawsuit concerns the Acquisition and Development Funding
Agreement dated August 2, 2016 (together with its amendments, the “ADFA”). The parties to the ADFA (and its amendments) are the Company; SPM; and
certain affiliates of SPM-(1) Schlumberger Technology Corporation; (2) Smith International, Inc.; (3) M-I, L.L.C.; and (4) Cameron International Corporation (the
“Schlumberger Service Providers”). In the Lawsuit, SPM and the Schlumberger Service Providers are the plaintiffs, and the Company is the defendant.
In the Lawsuit, SPM alleges that the Company breached the ADFA in connection with the Company’s agreement to sell its interests in the Powder
River Basin (collectively, the “Company Interests”) to a third party (“Buyer”). SPM alleges that pursuant to the ADFA, SPM was entitled to sell its related wellbore
interests to Buyer on the same terms and conditions that the Company Interests were to be sold, through a “tag-along” process. SPM alleges that the Company
failed to honor the tag-along provisions of the ADFA. The Lawsuit further alleges that the Company fraudulently induced SPM to enter an amendment to the
ADFA in connection with its sale. SPM brings claims for rescission, fraud, breach of contract, unjust enrichment, breach of good faith and fair dealing, and
declaratory judgment. SPM has not specified the damages it seeks in its pleadings, except to state that they are more than $1,000,000.
The Company has asserted affirmative defenses and counterclaims, that in part allege that: (1) SPM has breached the ADFA by filing an action for
rescission, when any rescission remedy is expressly barred by the ADFA; and (2) the Company is entitled to a declaration that the Company has complied with
the ADFA; and (3) SPM’s tag-along rights under the ADFA expired.
The case is in discovery, and trial is scheduled for June 22, 2020. The Company believes it has complied with the terms of the ADFA, intends to
vigorously defend against SPM’s claims, and intends to vigorously prosecute its own claims.
ITEM 4. MINE SAFETY DISCLOSURES
These disclosures are not applicable to us.
36
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Market Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM.”
PART II
PERFORMANCE GRAPH
The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2014, and ending
December 31, 2019, with the cumulative total returns of the Dow Jones Exploration and Production Index (“DJUSOS”), and the Standard & Poor’s 500 Stock
Index (“SPX”).
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS
The preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the SEC.
Holders. As of February 6, 2020, the number of record holders of our common stock was 75. Based upon inquiry, management believes that the
number of beneficial owners of our common stock is approximately 17,350.
Purchases of Equity Securities by Issuer and Affiliated Purchasers. The following table provides information about purchases made by us and any
affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and year ended December 31, 2019, of shares of our
common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act.
37
PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
Total Number of Shares
Purchased (1)
Weighted Average Price
Paid per Share
Total Number of Shares
Purchased as Part of
Publicly Announced
Program
Maximum Number of
Shares that May Yet be
Purchased Under the
Program (2)
990 $
154 $
130,992 $
— $
132,136 $
17.82
14.91
12.52
—
12.56
—
—
—
—
—
3,072,184
3,072,184
3,072,184
3,072,184
3,072,184
Period
01/01/2019 -
03/31/2019
04/01/2019 -
06/30/2019
07/01/2019 -
09/30/2019
10/01/2019 -
12/31/2019
Total
(2)
____________________________________________
(1) All shares purchased by us in 2019 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying Restricted
Stock Units (“RSUs”) issued under the terms of award agreements granted under the SM Energy Equity Incentive Compensation Plan, as amended and
restated effective as of May 22, 2018 (the “Equity Plan”).
In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to
6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may
repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions
or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures
governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash
balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time.
38
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected supplemental financial and operating data as of the dates or for the years indicated. The financial data for each
of the five years presented was derived from our consolidated financial statements. The following data should be read in conjunction with Management’s
Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report, which includes a discussion of factors materially
affecting the comparability of the information presented, and in conjunction with our consolidated financial statements included in this report.
Statement of operations data:
Total operating revenues and other
income
Net income (loss)
Net income (loss) per share:
Basic
Diluted
Cash dividends declared and paid per
common share
Balance sheet data:
Total assets
Long-term debt:
Revolving credit facility
Senior Notes, net of unamortized
deferred financing costs
Senior Convertible Notes, net of
unamortized discount and
deferred financing costs
$
$
$
$
$
$
$
$
$
As of or for the Years Ended December 31,
2019
2018
2017
2016
2015
(in millions, except per share data)
1,590.1 $
2,067.1 $
1,129.4 $
1,217.5 $
1,557.0
(187.0) $
508.4 $
(160.8) $
(757.7) $
(447.7)
(1.66) $
(1.66) $
4.54 $
4.48 $
(1.44) $
(1.44) $
(9.90) $
(9.90) $
(6.61)
(6.61)
0.10 $
0.10 $
0.10 $
0.10 $
0.10
6,292.2 $
6,352.9 $
6,176.8 $
6,393.5 $
5,621.6
122.5 $
— $
— $
— $
202.0
2,453.0 $
2,448.4 $
2,769.7 $
2,766.7 $
2,316.0
157.3 $
147.9 $
139.1 $
130.9 $
—
39
Supplemental Selected Financial and Operations Data
As of or for the Years Ended December 31,
2019
2018
2017
2016
2015
Balance sheet data (in millions):
Total working capital (deficit)
Total stockholders’ equity
$
$
(219.4) $
(36.8) $
(10.1) $
(190.5) $
216.5
2,749.0 $
2,920.3 $
2,394.6 $
2,497.1 $
1,852.4
Weighted-average common shares outstanding (in thousands):
Basic
Diluted
Reserves:
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Production and operations (in millions):
Oil, gas, and NGL production revenue
Oil, gas, and NGL production expense
$
$
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion $
General and administrative (2)
$
Production volumes:
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
MMBOE (1)
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Per BOE
Expense per BOE:
Lease operating expense
Transportation costs
Production taxes
Ad valorem tax expense
$
$
$
$
$
$
$
$
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion $
General and administrative (2)
Statement of cash flows data (in millions):
Provided by operating activities (2)
Used in investing activities (2)
Provided by (used in) financing activities (2)
$
$
$
$
112,544
111,912
111,428
112,544
113,502
111,428
76,568
76,568
67,723
67,723
184.1
175.7
158.2
104.9
145.3
1,223.2
1,321.8
1,280.1
1,111.1
1,264.0
74.0
462.0
107.4
503.4
96.5
468.1
105.7
395.8
115.4
471.3
1,585.8 $
1,636.4 $
1,253.8 $
1,178.4 $
1,499.9
500.7 $
487.4 $
507.9 $
597.6 $
723.6
823.8 $
132.8 $
665.3 $
116.5 $
557.0 $
117.3 $
790.7 $
124.8 $
21.9
109.8
8.1
48.3
18.8
103.2
7.9
43.9
13.7
123.0
10.3
44.5
16.6
146.9
14.2
55.3
54.10 $
56.80 $
47.88 $
36.85 $
2.39 $
17.26 $
32.84 $
3.43 $
27.22 $
37.27 $
3.00 $
22.35 $
28.20 $
2.30 $
16.16 $
21.32 $
4.67 $
3.88 $
1.35 $
0.48 $
4.74 $
4.36 $
1.52 $
0.48 $
4.43 $
5.48 $
1.18 $
0.34 $
3.51 $
6.16 $
0.94 $
0.21 $
17.06 $
15.15 $
12.53 $
14.30 $
2.75 $
2.65 $
2.64 $
2.26 $
921.0
156.1
19.2
173.6
16.1
64.2
41.49
2.57
15.92
23.36
3.73
6.02
1.13
0.39
14.34
2.43
823.6 $
720.6 $
515.4 $
552.8 $
990.8
(1,013.3) $
(587.9) $
(201.5) $
(1,867.6) $
(1,144.6)
111.8 $
(368.7) $
(12.3) $
1,327.2 $
153.7
Realized price, before the effect of derivative settlements:
____________________________________________
(1) Amounts may not calculate due to rounding.
(2) As a result of adopting new accounting standards in prior periods, certain prior period amounts have been reclassified to conform to the current period
presentation on the consolidated financial statements.
40
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of
this report for important information about these types of statements.
Overview of the Company
General Overview
Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to energy security and prosperity, and having a
positive impact in the communities where we live and work. Our long-term vision for the Company is to sustainably grow value for all of our stakeholders. We
believe that in order to accomplish this vision, we must be a premier operator of top tier assets. At present, our investment portfolio is focused on high quality oil
and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in South Texas.
2019 Financial and Operational Highlights
We remain focused on maximizing returns and increasing the value of our top tier Midland Basin and South Texas assets. We expect to do this through
continued development optimization and delineation. We believe our assets provide significant production growth potential and strong returns that are capable of
increasing internally generated cash flows and support our priorities of improving credit metrics and maintaining strong financial flexibility.
Financial and Operational Results. Average net daily production for the year ended December 31, 2019, was 132.3 MBOE, compared with 120.3
MBOE for the same period in 2018. This increase was primarily driven by a 25 percent increase in production volumes from our Midland Basin assets. Realized
prices before the effects of derivative settlements for oil, gas, and NGLs decreased five percent, 30 percent, and 37 percent, respectively, for the year ended
December 31, 2019, compared with the year ended December 31, 2018. As a result of decreased realized prices, oil, gas, and NGL production revenue
decreased three percent to $1.59 billion for the year ended December 31, 2019, compared with $1.64 billion for 2018. The decrease in oil, gas, and NGL
production revenue due to pricing was largely offset by increased production. We recorded a net derivative loss of $97.5 million for the year ended
December 31, 2019, compared to a net derivative gain of $161.8 million for the same period in 2018. Included within these derivative amounts is a gain of $39.2
million on derivative contracts that settled during the year ended December 31, 2019, and a loss of $135.8 million for the same period in 2018. Overall financial
and operational activities during the year ended December 31, 2019, resulted in the following:
•
•
•
net loss of $187.0 million, or $1.66 per diluted share, for the year ended December 31, 2019, compared with net income of $508.4 million, or $4.48
per diluted share, for the year ended December 31, 2018. Please refer to Comparison of Financial Results and Trends Between 2019 and 2018
and Between 2018 and 2017 below for additional discussion regarding the components of net income (loss) for each period presented;
net cash provided by operating activities was $823.6 million for the year ended December 31, 2019, compared with $720.6 million in 2018, which
was an increase of 14 percent year-over-year. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between 2018 and
2017 below for additional discussion; and
adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2019, was $993.4 million, compared with $900.4 million for
the same period in 2018. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted
EBITDAX and reconciliations to our net income (loss) and net cash provided by operating activities.
Total estimated proved reserves as of December 31, 2019 decreased eight percent from December 31, 2018 to 462.0 MMBOE, of which, 56 percent
were liquids (oil and NGLs) and 53 percent were characterized as proved developed. During 2019, we added 98.4 MMBOE through our Midland Basin and
South Texas development activities. The 2019 results were partially offset by downward revisions of 94.7 MMBOE primarily resulting from lower commodity
prices. Lower commodity prices were also the primary factor in our decreased estimated proved reserve life index, which was 9.6 years at December 31, 2019,
compared to 11.5 years at December 31, 2018. Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized
measure of discounted future net cash flows was $4.1 billion as of December 31, 2019, compared with $4.7 billion as of December 31, 2018, which was a
decrease of 12 percent year-over-year. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional
discussion.
Operational Activities. The performance of the RockStar area of our Midland Basin position continues to exceed our pre-acquisition expectations and
was key to driving significant growth in our operating margin and cash flows from operations in 2019 due to the high percentage of oil that these wells produce.
Our operational execution and development strategy in this region have resulted in strong well performance due to enhanced completion designs and our ability
to drill longer laterals given the increasingly contiguous nature of our acreage position as a result of successful infill leasing and acreage trades. Efficiency in
completions and operations
41
continued in 2019, as a large portion of our water transportation and disposal needs continue to be satisfied by the water facilities we operate in a core area of
our RockStar acreage. We also continued to increase our use of locally sourced sand in our well completions, which has resulted in further cost savings and
improved returns for our program.
Our Midland Basin program averaged six drilling rigs and three completion crews during 2019. We completed 123 gross (111 net) operated wells during
2019 and increased production volumes year-over-year by 25 percent to 26.3 MMBOE, 78 percent of which was oil. 82 percent of our total 2019 costs incurred
in our oil and gas producing activities was incurred in our Midland Basin program. Drilling and completion activities within our RockStar and Sweetie Peck
positions in the Midland Basin continue to focus primarily on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals.
Our South Texas program averaged one drilling rig and one completion crew during 2019. We completed 31 gross (20 net) wells during 2019. Total
production for 2019 was 22.0 MMBOE, a one percent increase from 2018. 16 percent of our total 2019 costs incurred in our oil and gas producing activities was
incurred in our South Texas program. Drilling and completion activities in South Texas continue to focus on developing the Eagle Ford shale formation and
delineating the Austin Chalk formation.
Certain drilling and completion activities in the northern portion of our South Texas acreage position were primarily funded by a third party pursuant to
our joint development agreement. The agreement provided that the third party would carry substantially all drilling and completion costs and receive a majority of
the working and revenue interest in these wells until certain payout thresholds are reached. This arrangement allowed us to leverage third-party capital to prove
up the value of our Eagle Ford North area, while also allowing us to test cutting edge technology, capture additional technical data, and satisfy certain lease
obligations. All wells subject to this agreement were drilled and completed as of December 31, 2019.
The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our
operated programs for the year ended December 31, 2019:
Wells drilled but not completed at December 31, 2018
Wells drilled
Wells completed
Other (1)
Wells drilled but not completed at December 31, 2019
_____________________________________
Midland Basin
South Texas
Total
Gross Net
Gross Net
Gross Net
61
113
55
104
(123)
(111)
—
51
—
48
29
25
(31)
(2)
21
23
20
90
138
78
124
(20)
(154)
(131)
(2)
21
(2)
72
(2)
69
(1)
Includes adjustments related to previously drilled wells that we no longer intend to complete.
Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether
capitalized or expensed, are summarized as follows:
Development costs
Exploration costs
Acquisitions
Proved properties
Unproved properties
For the Year Ended
December 31, 2019
(in millions)
$
914.0
115.0
(0.3)
11.6
Total, including asset retirement obligations (1) $
____________________________________________
Note: Total may not calculate due to rounding.
(1) Please refer to the caption Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this
1,040.2
report.
All of our development and exploration costs were incurred in our Midland Basin and South Texas programs for the year ended December 31, 2019. Of
these costs, $848.6 million was directed to the development of our Midland Basin assets, which resulted in 104 net wells drilled and 111 net wells completed.
Comparatively, for the year ended December 31, 2018, $1.1 billion was directed to the development of our Midland Basin assets, which resulted in 117 net wells
drilled and 104 net wells completed. Costs incurred for acquisitions during the year related to transactions in the Midland Basin, as well as payments made to
extend certain lease terms and to acquire new leases. Please refer to Operational Activities above and Acquisition Activity below for additional information on
our regional activities.
42
Production Results. The table below presents the disaggregation of our production by product type for each of our operating regions for the year ended
December 31, 2019:
Production:
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE)
Avg. daily equivalents (MBOE/d)
Relative percentage
____________________________________________
Note: Amounts may not calculate due to rounding.
Midland Basin South Texas
Total
20.5
34.4
—
26.3
72.0
1.3
75.4
8.1
22.0
60.3
21.9
109.8
8.1
48.3
132.3
54%
46%
100%
Production increased 10 percent for the year ended December 31, 2019, compared with 2018. The increase in overall production volumes was
primarily attributable to our Midland Basin assets, which had an increase in production volumes of 25 percent for the year ended December 31, 2019, compared
with 2018. Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results
and Trends Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion on production.
Acquisition Activity. During 2019, while no significant acquisition activity occurred, we completed several non-monetary acreage trades of undeveloped
properties located in Howard, Martin, and Midland Counties, Texas, to continue maximizing our operational efficiencies in our Midland Basin program. Please
refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional discussion.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which
can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period,
before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis
for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products.
The following table summarizes commodity price data, as well as the effects of derivative settlements, for the years ended December 31, 2019, 2018,
and 2017:
Oil (per Bbl):
Average NYMEX contract monthly price
Realized price, before the effect of derivative settlements
Effect of oil derivative settlements
Gas:
Average NYMEX monthly settle price (per MMBtu)
Realized price, before the effect of derivative settlements (per Mcf)
Effect of gas derivative settlements (per Mcf)
NGLs (per Bbl):
Average OPIS price (1)
Realized price, before the effect of derivative settlements
Effect of NGL derivative settlements
For the Years Ended December 31,
2019
2018
2017
$
$
$
$
$
$
$
$
$
57.03 $
54.10 $
(0.90) $
64.77 $
56.80 $
(3.67) $
2.63 $
2.39 $
0.21 $
3.09 $
3.43 $
(0.12) $
22.34 $
17.26 $
4.43 $
32.96 $
27.22 $
(6.78) $
50.95
47.88
(2.28)
3.11
3.00
0.72
27.63
22.35
(3.44)
____________________________________________
(1) Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane,
and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent
our product mix for NGL production. Realized prices reflect our actual product mix.
43
We expect future benchmark prices for oil, gas, and NGLs to continue to be volatile due to uncertainty in global supply and demand. In addition to
supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well
as the relative strength of the United States dollar compared to other currencies. Increased demand for liquefied natural gas and gas exports to Mexico are
expected to help balance natural gas supply. NGL prices may continue to benefit from increased demand from export and petrochemical markets while being
offset by increased drilling activity. Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and
beyond.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed
under the table above) as of February 6, 2020, and December 31, 2019:
NYMEX WTI oil (per Bbl)
NYMEX Henry Hub gas (per MMBtu)
OPIS NGLs (per Bbl)
$
$
$
51.46 $
2.15 $
18.09 $
59.01
2.28
20.00
As of February 6, 2020
As of December 31, 2019
We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our
use of derivatives, and decisions regarding entering into derivative commodity contracts are overseen by a financial risk management committee consisting of
senior executive officers and finance personnel. The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet, the
level of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity contracts. With our current
derivative commodity contracts, we believe we have partially reduced our exposure to volatility in commodity prices and location differentials in the near term.
Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a
price floor for a portion of our oil and gas production.
Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report and to Commodity Price Risk in Overview of Liquidity and
Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
Outlook
Please refer to Outlook in Part I, Item 1 of this report for discussion of our financing and capital plans for 2020, and refer to Overview of Liquidity and
Capital Resources below for discussion of how we expect to fund our 2020 capital program.
44
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended December 31, 2019, and the
preceding three quarters.
For the Three Months Ended
December 31,
September 30,
June 30,
March 31,
2019
2019
2019
2019
12.8
449.0 $
127.3 $
228.7 $
17.7 $
37.2 $
(102.1) $
$
$
$
$
$
$
(in millions)
12.4
389.4 $
129.0 $
12.4
406.9 $
123.1 $
211.1 $
206.3 $
11.6 $
32.6 $
42.2 $
10.9 $
30.9 $
50.4 $
10.7
340.5
121.3
177.7
11.3
32.1
(177.6)
Production (MMBOE)
Oil, gas, and NGL production revenue
Oil, gas, and NGL production expense
Depletion, depreciation, amortization, and asset
retirement obligation liability accretion
Exploration
General and administrative
Net income (loss)
__________________________________________
Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
For the Three Months Ended
December 31,
September 30,
June 30,
March 31,
2019
2019
2019
2019
Average net daily production equivalent (MBOE per
day)
Lease operating expense (per BOE)
Transportation costs (per BOE)
Production taxes as a percent of oil, gas, and NGL
production revenue
Ad valorem tax expense (per BOE)
Depletion, depreciation, amortization, and asset
retirement obligation liability accretion (per BOE)
General and administrative (per BOE)
$
$
$
$
$
138.8
4.67
3.46
$
$
4.2%
0.37
$
134.9
4.73
4.00
$
$
4.1%
0.39
$
136.5
4.16
4.00
$
$
4.0%
0.44
$
17.91
2.92
$
$
17.02
2.63
$
$
16.61
2.49
$
$
118.7
5.20
4.08
4.1%
0.76
16.63
3.00
45
A Year-to-Year Overview of Selected Production and Financial Information, Including Trends
For the Years Ended
December 31,
Amount Change Between Percent Change Between
2019
2018
2017
2019/2018 2018/2017 2019/2018 2018/2017
Net production volumes: (1)
Oil (MMBbl)
Gas (Bcf)
NGLs (MMBbl)
Equivalent (MMBOE)
Average net daily production: (1)
Oil (MBbl per day)
Gas (MMcf per day)
NGLs (MBbl per day)
Equivalent (MBOE per day)
21.9
109.8
8.1
48.3
59.9
300.8
22.2
132.3
18.8
103.2
7.9
43.9
51.4
282.7
21.8
120.3
13.7
123.0
10.3
44.5
37.4
337.0
28.2
121.8
3.1
6.6
0.2
4.4
8.5
18.1
0.5
12.0
5.1
(19.8)
(2.4)
(0.6)
14.0
(54.3)
(6.4)
(1.5)
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue
Gas production revenue
NGL production revenue
$ 1,183.2 $ 1,065.7 $
262.5
140.0
354.5
216.2
654.3 $
369.4
230.1
117.5 $
(91.9)
(76.2)
411.4
(15.0)
(13.9)
Total oil, gas, and NGL production
revenue
$ 1,585.8 $ 1,636.4 $ 1,253.8 $
(50.6) $
382.6
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense
$
Transportation costs
Production taxes
Ad valorem tax expense
225.5 $
187.1
65.0
23.1
208.1 $
191.5
66.9
20.9
196.9 $
243.6
52.4
15.0
17.4 $
(4.4)
(1.9)
2.2
11.2
(52.1)
14.5
5.9
Total oil, gas, and NGL production
expense
$
500.7 $
487.4 $
507.9 $
13.3 $
(20.5)
Realized price, before the effect of derivative settlements:
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Per BOE
Per BOE data:
Production costs:
Lease operating expense
Transportation costs
Production taxes
Ad valorem tax expense
Total production costs (1)
Depletion, depreciation, amortization,
and asset retirement obligation liability
accretion
General and administrative
Derivative settlement gain (loss) (2)
Earnings per share information:
Basic weighted-average common shares
outstanding (in thousands)
Diluted weighted-average common
shares outstanding (in thousands)
Basic net income (loss) per common
share
Diluted net income (loss) per common
share
$
$
$
$
$
$
$
$
$
$
$
$
$
$
54.10 $
2.39 $
17.26 $
32.84 $
56.80 $
3.43 $
27.22 $
37.27 $
47.88 $
3.00 $
22.35 $
28.20 $
(2.70) $
(1.04) $
(9.96) $
(4.43) $
4.67 $
3.88 $
1.35 $
0.48 $
10.38 $
4.74 $
4.36 $
1.52 $
0.48 $
11.10 $
4.43 $
5.48 $
1.18 $
0.34 $
11.43 $
17.06 $
2.75 $
0.81 $
15.15 $
2.65 $
(3.09) $
12.53 $
2.64 $
0.48 $
(0.07) $
(0.48) $
(0.17) $
— $
(0.72) $
1.91 $
0.10 $
3.90 $
8.92
0.43
4.87
9.07
0.31
(1.12)
0.34
0.14
(0.33)
2.62
0.01
(3.57)
112,544
111,912
111,428
112,544
113,502
111,428
632
(958)
484
2,074
17 %
6 %
2 %
10 %
17 %
6 %
2 %
10 %
11 %
(26)%
(35)%
(3)%
8 %
(2)%
(3)%
10 %
3 %
(5)%
(30)%
(37)%
(12)%
(1)%
(11)%
(11)%
— %
(6)%
13 %
4 %
126 %
1 %
(1)%
37 %
(16)%
(23)%
(1)%
37 %
(16)%
(23)%
(1)%
63 %
(4)%
(6)%
31 %
6 %
(21)%
28 %
39 %
(4)%
19 %
14 %
22 %
32 %
7 %
(20)%
29 %
41 %
(3)%
21 %
— %
(744)%
— %
2 %
415 %
411 %
(1.66) $
4.54 $
(1.44) $
(6.20) $
5.98
(137)%
(1.66) $
4.48 $
(1.44) $
(6.14) $
5.92
(137)%
____________________________________________
(1) Amounts and percentage changes may not calculate due to rounding.
(2) Derivative settlements for the years ended December 31, 2019, 2018, and 2017, are included within the net derivative (gain) loss line item in the accompanying
consolidated statements of operations (“accompanying statements of operations”).
46
Average net equivalent daily production for the year ended December 31, 2019, increased 10 percent compared with 2018. This increase was primarily
driven by a 25 percent increase in production volumes from our Midland Basin assets for the year ended December 31, 2019, compared with 2018. Production
volumes from our South Texas assets for the year ended December 31, 2019, were relatively flat compared with 2018. We divested our remaining producing
assets in the Rocky Mountain region in the first half of 2018. We expect total production volumes in 2020 to decline slightly compared with 2019; however, we
expect total oil volumes to increase. As a result, we expect oil volumes to be approximately 50 percent of our total production mix in 2020. Please refer to
Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion.
We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we
believe may require additional analysis and discussion.
Our realized price before the effect of derivative settlements on a per BOE basis decreased 12 percent for the year ended December 31, 2019,
compared with 2018. This decrease was primarily driven by lower benchmark commodity prices for oil, gas, and NGLs, as well as increased regional differentials
in the Midland Basin for natural gas caused by tight takeaway capacity. In the first half of 2019, certain third-party midstream force majeure events negatively
affected the price we received for our Midland Basin gas production. Regional differentials for gas in the Midland Basin are expected to continue to negatively
affect our realized prices in 2020. Additional expected take-away capacity is anticipated to come online in early 2021. For the year ended December 31, 2019,
we recognized a gain of $0.81 per BOE on the settlement of our derivative contracts, compared to a recognized loss of $3.09 per BOE in 2018.
Lease operating expense (“LOE”) on a per BOE basis was relatively flat for the year ended December 31, 2019, compared with 2018, despite the
increase in oil production as a percentage of our total production. The increase in absolute LOE was primarily driven by increased production. We expect LOE
on a per BOE basis to be higher in 2020 compared with 2019 as our product mix continues to shift towards more oil production. We anticipate volatility in LOE
on a per BOE basis as a result of changes in total production, our overall production mix, timing of workover projects, and industry activity, all of which impacts
service provider costs.
Transportation costs on a per BOE basis decreased 11 percent for the year ended December 31, 2019, compared with 2018. The decrease was driven
primarily by an increase in the percentage of production generated from our Midland Basin assets, as production from these assets is typically sold at or near
the wellhead and incurs minimal transportation costs. We expect total transportation costs to fluctuate relative to changes in production from our South Texas
assets, which incur the majority of our transportation costs. On a per BOE basis, we expect transportation costs to decrease in 2020, compared with 2019, as
production from our Midland Basin assets continues to become a larger portion of our total production.
Production taxes on a per BOE basis for the year ended December 31, 2019, decreased 11 percent compared with 2018, primarily due to a 12 percent
decrease in our realized price on a per BOE basis before the effect of derivative settlements for the year ended December 31, 2019, compared with 2018. Our
overall production tax rate for each of the years ended December 31, 2019, and 2018 was 4.1 percent. We expect our overall production tax rate to remain
consistent in 2020, compared with 2019. We generally expect production tax expense to trend with oil, gas, and NGL production revenue on an absolute and per
BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax we
recognize.
Ad valorem tax expense on a per BOE basis for the year ended December 31, 2019, was flat compared with 2018, as the increases on an absolute
basis, resulting from changes in our asset and production base, were consistent with higher production volumes. We anticipate volatility in ad valorem tax
expense on a per BOE and absolute basis as a result of continuing changes in the valuation of our producing properties.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased 13 percent for
the year ended December 31, 2019, compared with 2018. The increase was driven by our focus on developing oil producing assets in the Midland Basin, which
have higher depletion rates than our primarily gas and NGL producing assets in South Texas. Our DD&A rate fluctuates as a result of impairments, divestiture
activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve
volumes. In general, we expect DD&A expense on a per BOE basis in 2020 to increase compared with 2019 as production from our Midland Basin assets
continues to become a larger portion of our total production.
General and administrative (“G&A”) expense on a per BOE basis for the year ended December 31, 2019, increased four percent compared with 2018.
The increase was primarily due to a reduction in the amount of employee compensation that was reclassified to exploration expense as compared with the prior
year, as more employee time was allocated to development activities in 2019. During the fourth quarter of 2019, we announced the reorganization of certain
functions to eliminate duplicative regional operational functions and reduce overhead costs, which we expect will result in reduced G&A expense in future years.
As a result, we expect to incur total charges related to this reorganization ranging from $8.0 million to $8.5 million, including $4.2 million incurred in the fourth
quarter of 2019. We expect G&A expense to decrease in total and on a per BOE basis in 2020 compared with 2019.
Please refer to Note 9 - Earnings Per Share in Part II, Item 8 of this report for additional discussion on the types of shares included in our basic and
diluted net income (loss) per common share calculations. We recorded a net loss for each of the years ended
47
December 31, 2019, and 2017. Consequently, all potentially dilutive shares were anti-dilutive and were excluded from the calculation of diluted net loss per
common share for the years ended December 31, 2019, and 2017. For the year ended December 31, 2018, we recorded net income and thus considered
dilutive shares in the calculation of diluted net income per common share as of December 31, 2018.
Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017
Please refer to Comparison of Financial Results and Trends Between 2018 and 2017 and Between 2017 and 2016 in Management’s Discussion and
Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2018 Annual Report on Form 10-K, filed with the SEC on February 21, 2019,
for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2018, compared with the year ended
December 31, 2017.
Net equivalent production, production revenue, and production expense
The following table presents the regional changes in our net equivalent production, production revenue, and production expense between the years
ended December 31, 2019, and 2018:
Net Equivalent Production
Increase (Decrease)
Production Revenue
Increase (Decrease)
Production Expense
Increase (Decrease)
(MBOE per day)
(in millions)
(in millions)
14.6 $
0.4
(3.1)
12.0 $
131.1 $
(124.5)
(57.2)
(50.6) $
31.5
5.2
(23.3)
13.3
Midland Basin
South Texas
Rocky Mountain (1)
Total
__________________________________________
Note: Amounts may not calculate due to rounding.
(1) We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from
this region after the second quarter of 2018.
We experienced a 10 percent increase in net equivalent production in 2019 compared with 2018, primarily as a result of increased production from our
Midland Basin assets. As a result of increased Midland Basin production, oil production as a percentage of our overall product mix increased from 43 percent in
2018, to 45 percent in 2019. Oil, gas, and NGL production revenues decreased three percent for the year ended December 31, 2019, compared with 2018, as a
result of lower commodity pricing and the divestiture in the first half of 2018 of our remaining producing assets in the Rocky Mountain region. Total production
expense for the year ended December 31, 2019, increased three percent compared with 2018, due to increased LOE and ad valorem tax expense, partially
offset by decreased production taxes and transportation costs. Production expense on a per BOE basis decreased six percent for the year ended December 31,
2019, compared with 2018, primarily due to increased production volumes, decreased transportation costs, and decreased production taxes resulting from lower
oil, gas, and NGL production revenues.
The following table presents the regional changes in our net equivalent production, production revenue, and production expense between the years
ended December 31, 2018 and 2017:
Net Equivalent Production
Increase (Decrease)
Production Revenue
Increase (Decrease)
Production Expense
Increase (Decrease)
(MBOE per day)
(in millions)
(in millions)
27.4 $
(20.8)
(8.1)
(1.5) $
582.5 $
(95.9)
(104.0)
382.6 $
89.5
(64.5)
(45.5)
(20.5)
Midland Basin
South Texas
Rocky Mountain (1)
Total
__________________________________________
Note: Amounts may not calculate due to rounding.
(1) We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from
this region after the second quarter of 2018.
We experienced a one percent decrease in net equivalent production in 2018 compared with 2017. The decrease in overall production volumes was a
result of decreased production from our operated Eagle Ford shale assets as a result of reduced capital investment, the divestiture of our outside-operated
Eagle Ford shale assets which occurred in the first quarter of 2017, and the divestiture of our remaining producing assets in the Rocky Mountain region in the
first half of 2018. Production decreases in the South Texas and Rocky Mountain regions were predominately offset by the 91 percent production volume
increase in our Midland Basin assets for the year ended December 31, 2018, compared with 2017. Increased production in the Midland Basin also drove oil
48
production as a percentage of our overall product mix to increase from 31 percent in 2017, to 43 percent in 2018. The increase in higher margin oil production
also increased realized prices, before the effects of derivative settlements, on a per BOE basis by 32 percent in 2018, resulting in a 31 percent increase in oil,
gas, and NGL production revenue for the year ended 2018 compared with 2017. Production expense in 2018, compared with 2017, decreased four percent, and
was primarily driven by the divestiture of the remaining assets in our Rocky Mountain region in the first half of 2018, which had the highest average production
costs in our portfolio.
Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends above for discussion of trends on a per
BOE basis for the years ended December 31, 2019, 2018, and 2017.
Net gain (loss) on divestiture activity
For the Years Ended December 31,
2019
2018
2017
(in millions)
Net gain (loss) on divestiture activity
$
0.9 $
426.9 $
(131.0)
No material divestitures occurred during 2019. The $426.9 million net gain on divestiture activity recorded for the year ended December 31, 2018, was
the result of a total net gain of $410.6 million recorded for the divestiture of our Powder River Basin assets (the “PRB Divestiture”), which closed in the first
quarter of 2018, and a combined total net gain of $15.4 million recorded for the completed divestitures of our remaining assets in the Williston Basin located in
Divide County, North Dakota (the “Divide County Divestiture”) and our Halff East assets in the Midland Basin (the “Halff East Divestiture”), which closed in the
second quarter of 2018.
The net loss on divestiture activity recorded for the year ended December 31, 2017, was primarily the result of $526.5 million of write-downs recorded
on certain retained North Dakota assets. These assets were divested in the second quarter of 2018, as discussed above. Partially offsetting these write-downs
recorded during 2017, was a $396.8 million total net gain recorded on the sale of our outside-operated Eagle Ford shale assets.
Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional discussion.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
For the Years Ended December 31,
2019
2018
2017
(in millions)
Depletion, depreciation, amortization, and asset retirement
obligation liability accretion
$
823.8 $
665.3 $
557.0
DD&A expense for the year ended December 31, 2019, increased 24 percent compared with 2018. DD&A expense for the year ended December 31,
2018, increased 19 percent compared with 2017. These increases are directly related to the 25 percent and 91 percent increases for the years ended
December 31, 2019, and 2018, respectively, in production volumes from our Midland Basin assets as these assets have higher depletion rates than our assets
in South Texas.
Please refer to A Year-to-Year Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on
a per BOE basis.
Exploration
Geological and geophysical expenses
Exploratory dry hole
Overhead and other expenses
Total
For the Years Ended December 31,
2019
2018
2017
(in millions)
$
$
2.9 $
4.8
43.8
51.5 $
5.6 $
—
49.6
55.2 $
4.0
2.4
48.3
54.7
Exploration expense decreased seven percent for the year ended December 31, 2019, compared with 2018. The decrease was primarily driven by a
reduction in the amount of employee compensation reclassified to exploration expense as more employee time is being allocated to development activities,
which is recognized as G&A expense. Exploration expense is impacted by actual geological and geophysical studies we perform and the potential for
exploratory dry hole expense.
49
Impairment of oil and gas properties
Impairment of proved properties
Abandonment and impairment of unproved properties
Total
For the Years Ended December 31,
2019
2018
2017
$
$
(in millions)
— $
33.8
33.8 $
— $
49.9
49.9 $
3.8
12.3
16.1
There was no impairment of proved properties expense recognized for the years ended December 31, 2019, and 2018. Unproved property
abandonments and impairments recorded for the years ended December 31, 2019, and 2018 related to actual and anticipated lease expirations, as well as
actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks.
We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of
unproved property abandonments and impairments will fluctuate with the timing of lease expirations or defects, and changing economics associated with
decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in
proved and unproved property impairments. Future impairments of proved and unproved properties are difficult to predict; however, based on our updated
commodity price assumptions as of February 6, 2020, we do not expect any material impairments in the first quarter of 2020 resulting from commodity price
impacts. Please refer to Critical Accounting Policies and Estimates below for additional discussion.
General and administrative
For the Years Ended December 31,
2019
2018
2017
(in millions)
General and administrative
$
132.8 $
116.5 $
117.3
G&A expense increased 14 percent for the year ended December 31, 2019, compared with 2018. Please refer to A Year-to-Year Overview of Selected
Production and Financial Information, Including Trends above for discussion of G&A expense.
Net derivative (gain) loss
For the Years Ended December 31,
2019
2018
2017
(in millions)
Net derivative (gain) loss
$
97.5 $
(161.8) $
26.4
We recognized a net derivative loss of $97.5 million for the year ended December 31, 2019. For contracts that settled during 2019, the fair value was a
net asset of $112.2 million at December 31, 2018, and net cash settlements received totaled $39.2 million, resulting in a $73.0 million net loss. Additionally, we
recorded a $24.5 million mark-to-market loss on remaining contracts as of December 31, 2019, resulting from an increase in commodity strip prices toward the
end of 2019.
We recognized a net derivative gain of $161.8 million for the year ended December 31, 2018. For contracts that settled during 2018, the fair value was
a net liability of $108.3 million at December 31, 2017, and net cash settlements paid totaled $135.8 million, resulting in a $27.5 million loss. Offsetting this loss
was a $189.3 million mark-to-market gain on remaining contracts as of December 31, 2018, resulting from a decrease in commodity strip prices toward the end
of 2018.
We recognized a net derivative loss of $26.4 million for the year ended December 31, 2017. For contracts that settled during 2017, the fair value was a
net liability of $60.9 million at December 31, 2016, and net cash settlements received totaled $21.2 million, resulting in an $82.1 million gain. Offsetting this gain
was a $108.5 million mark-to-market loss on remaining contracts as of December 31, 2017, resulting from an increase in commodity strip prices.
Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
50
Interest expense
For the Years Ended December 31,
2019
2018
2017
(in millions)
Interest expense
$
(159.1) $
(160.9) $
(179.3)
Interest expense for the year ended December 31, 2019, was relatively flat compared with 2018. We expect interest expense related to our Senior
Notes to be relatively flat in 2020 compared with 2019; however, total interest expense can vary based on the timing and amount of any borrowings against our
credit facility.
The $18.4 million, or 10 percent, decrease in interest expense for the year ended December 31, 2018, compared with 2017, was driven in part by the
redemption of our 6.50% Senior Notes due 2021 (“2021 Senior Notes”), which reduced interest expense related to debt in 2018 by $9.4 million compared with
2017. In addition to the overall reduction in debt, interest expense was also reduced as the amount of interest we capitalized increased given our higher level of
development activity in 2018 compared with 2017.
Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report and Overview of Liquidity and Capital Resources below for additional
discussion.
Loss on extinguishment of debt
For the Years Ended December 31,
2019
2018
2017
(in millions)
Loss on extinguishment of debt
$
— $
(26.7) $
—
For the year ended December 31, 2018, we recorded a $26.7 million net loss on the early extinguishment of our 2021 Senior Notes, 6.50% Senior
Notes due 2023 (“2023 Senior Notes”), and a portion of our 6.125% Senior Notes due 2022 (“2022 Senior Notes”). The net loss on extinguishment of debt
included $20.4 million associated with the premiums paid upon redemption and repurchase, and $6.3 million related to the acceleration of unamortized deferred
financing costs.
Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Income tax (expense) benefit
Income tax (expense) benefit
Effective tax rate
For the Years Ended December 31,
2019
2018
2017
(in millions, except tax rate)
$
44.0
$
(143.4)
$
19.1%
22.0%
183.0
53.2%
The decrease in the effective tax rate for the year ended December 31, 2019, compared with 2018, was primarily due to the differing effects of
permanent items on the loss before income taxes for the year ended December 31, 2019, compared to the impact of these items on income before income
taxes for 2018. Excess tax deficiencies from stock-based compensation awards, limits on expensing of certain covered individual’s compensation, and other
permanent expense items reduced the tax benefit rate for the year ended December 31, 2019. These same items increased the tax expense rate for the year
ended December 31, 2018. The reduction in the tax expense rate also reflects a cumulative effect in 2018 from divestitures, and the impact of a correlative
change to our state apportionment rate.
The decrease in the effective tax rate for the year ended December 31, 2018, compared with 2017 was primarily due to the impacts of the Tax Cuts
and Jobs Act (the “2017 Tax Act”). The 18.5 percent increase in 2017 from a nonrecurring deferred tax adjustment was caused by the 14 percent decrease in
the highest marginal corporate rate from 35 percent to 21 percent beginning in 2018. The effect for 2017 was cumulatively added to a tax benefit calculated for
that year. The 14 percent decrease is reflected in the 2018 income tax expense rate. In addition, the year-over-year tax rate decreased due to effects related to
an excess tax deficiency from stock-based compensation awards, which had the effect of increasing the 2018 tax rate and partially offsetting the year-over-year
decrease. Other nominal 2018 tax rate decreases included effects from property sales, net apportionment changes, research credits, and percentage depletion
offset by the effects from limits to certain covered individual’s compensation.
Please refer to Overview of Liquidity and Capital Resources and Critical Accounting Policies and Estimates below as well as Note 4 – Income Taxes in
Part II, Item 8 of this report for further discussion.
51
Overview of Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the
foreseeable future. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to
our activity level and capital expenditures.
Sources of Cash
We currently expect our 2020 capital program to be funded by cash flows from operations with any remaining cash needs being funded by borrowings
under our credit facility. During the year ended December 31, 2019, we generated $823.6 million of cash flows from operating activities. As of December 31,
2019, the remaining available borrowing capacity under our Credit Agreement provided $1.1 billion in liquidity; however, our borrowing base can be adjusted as
a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities.
Although we expect cash flows from these sources to be sufficient to fund our expected 2020 capital program, we may also elect to raise funds through
new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the
percentage ownership of our current stockholders could be diluted, and these newly-issued securities may have rights, preferences, or privileges senior to those
of existing stockholders. Future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. Additionally, we may
enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. All of our sources of liquidity can be
affected by the general conditions of the broader economy, force majeure events, and fluctuations in commodity prices, operating costs, and volumes produced,
all of which affect us and our industry.
We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil,
gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Please refer to Note 10 – Derivative
Financial Instruments in Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of
settlement of those contracts.
The enactment of the 2017 Tax Act reduced our highest marginal corporate tax rate for 2018 and future years from 35 percent to 21 percent, however
future deductibility of interest expense may be limited. In general, the enactment of the 2017 Tax Act has had a positive impact on operating cash flows, and we
believe it will positively impact future operating cash flows.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion and is scheduled to mature on
September 28, 2023. The maturity date could, however, occur earlier on August 16, 2022, if we have not completed certain repurchase, redemption, or
refinancing activities associated with our 2022 Senior Notes, as outlined in the Credit Agreement. No individual bank participating in our Credit Agreement
represents more than 10 percent of the lender commitments under the Credit Agreement. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this
report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under
our Credit Agreement as of February 6, 2020, December 31, 2019, and December 31, 2018.
The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil
and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each
as determined by our lender group. The next scheduled borrowing base redetermination date is April 1, 2020.
We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend
payments and requiring that we maintain certain financial ratios, as defined by the Credit Agreement. Please refer to Note 5 – Long-Term Debt in Part II, Item 8
of this report for additional detail regarding our financial covenants. We were in compliance with all financial and non-financial covenants as of December 31,
2019, and through the filing of this report.
Our daily weighted-average credit facility debt balance was approximately $115.2 million and $13.1 million for the years ended December 31, 2019,
and 2017, respectively. We had no credit facility borrowing activity during 2018 as a result of cash on hand and cash proceeds received during 2018 from
divestitures. Cash flows provided by our operating activities, divestiture proceeds, capital markets activities, and the amount of our capital expenditures,
including acquisitions, all impact the amount we borrow under our credit facility.
Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on the London Interbank Offered Rate (“LIBOR”). The
use of LIBOR as a global reference rate is expected to be discontinued after 2021. Our Credit Agreement specifies that in the event that LIBOR is no longer a
widely used benchmark rate, or that it shall no longer be used for determining interest rates for loans in the United States, a replacement interest rate that fairly
reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. We
52
currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to
otherwise have a material adverse impact on our business.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the
Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and the non-cash amortization of the discount related to the Senior
Convertible Notes. Our weighted-average borrowing rate includes paid and accrued interest only.
The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2019,
2018, and 2017.
Weighted-average interest rate
Weighted-average borrowing rate
For the Years Ended December 31,
2019
2018
2017
6.4%
5.7%
6.4%
5.8%
6.4%
5.8%
Our weighted-average interest rates and weighted average borrowing rates for the years ended December 31, 2019, 2018, and 2017, were impacted
by the timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-
average interest rates were impacted by the fees paid on the unused portion of our aggregate lender commitments. There was no material change in our
weighted-average interest rates or weighted-average borrowing rates for the years ended December 31, 2019, 2018, and 2017. The rates disclosed in the
above table do not reflect amounts associated with the repurchase of Senior Notes, such as the discount realized or premium paid upon repurchase, or the
acceleration of unamortized deferred financing costs expensed upon repurchase. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for
additional discussion.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and
administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the development, exploration, and acquisition of oil and
gas properties are the primary use of our capital resources. During 2019, we spent approximately $1.0 billion on capital expenditures. This amount slightly differs
from the costs incurred amount as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical
expenses, acquisitions of oil and gas properties, and exploration overhead amounts. Please refer to Costs Incurred in Oil and Gas Producing Activities in
Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including the number and size of acquisitions, our
cash flows from operating, investing, and financing activities, and our ability to execute our development program. In addition, the impact of oil, gas, and NGL
prices on investment opportunities, the availability of capital, and the timing and results of our exploration and development activities may lead to changes in
funding requirements for future development. We periodically review our capital expenditure budget to assess changes in current and projected cash flows,
acquisition and divestiture activities, debt requirements, and other factors.
We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a
combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, or otherwise. Any such
repurchases or redemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and
other factors. The amounts involved in any such transaction may be material. Repurchases or redemptions are reviewed as part of the allocation of our capital.
During the third quarter of 2018, we redeemed our 2021 Senior Notes, repurchased or redeemed all of our 2023 Senior Notes, repurchased a portion of our
2022 Senior Notes, and issued our 2027 Senior Notes. We did not conduct similar debt transactions during 2019, or through the filing of this report. Please refer
to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion. As part of our strategy for 2020, we will continue to focus on improving our
debt metrics, which could include reducing the amount of our outstanding debt.
As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the
approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market
conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes, the indenture governing our
Senior Convertible Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically
reviews this program as part of the allocation of our capital. During 2019, we did not repurchase any shares of our common stock, and we currently do not plan
to repurchase any outstanding shares of our common stock during 2020.
53
During the years ended December 31, 2019, 2018, and 2017, we paid $11.3 million, $11.2 million, and $11.1 million, respectively, in dividends to our
stockholders, reflecting a dividend of $0.10 per share each year. Our current intention is to continue to make dividend payments for the foreseeable future,
subject to our future earnings, our financial condition, Credit Agreement, indentures governing our Senior Notes and Senior Convertible Notes, other covenants,
and other factors which could arise. The payment and amount of future dividends remains at the discretion of our Board of Directors.
Analysis of Cash Flow Changes Between 2019 and 2018 and Between 2018 and 2017
The following tables present changes in cash flows between the years ended December 31, 2019, 2018, and 2017, for our operating, investing, and
financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows
(“accompanying statements of cash flows”) in Part II, Item 8 of this report.
Operating Activities
For the Years Ended December 31,
Amount Change Between
2019
2018
2017
2019/2018 2018/2017
(in millions)
Net cash provided by operating activities
$
823.6 $
720.6 $
515.4 $
103.0 $
205.2
Derivative settlements increased $202.9 million for the year ended December 31, 2019, compared with 2018. This increase was partially offset by
decreased cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes of $73.4 million, and increased cash paid
for LOE and ad valorem taxes of $22.0 million for the year ended December 31, 2019, compared with 2018. Cash paid for interest decreased $8.8 million for the
year ended December 31, 2019, compared with 2018, due to the redemption and repurchase of certain senior notes in the third quarter of 2018, partially offset
by increased interest paid on the 2027 Senior Notes and interest paid on credit facility borrowings during the year ended December 31, 2019. Net cash provided
by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, including derivative cash settlements,
increased $196.0 million for the year ended December 31, 2018, compared with 2017, primarily as a result of an increase in our realized price, after the effect of
derivative settlements. Interest paid decreased $13.4 million for the year ended December 31, 2018, compared with 2017, due to the redemption and
repurchase of certain of our senior notes in the third quarter of 2018. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional
discussion.
Investing Activities
For the Years Ended December 31,
Amount Change Between
2019
2018
2017
2019/2018 2018/2017
(in millions)
Net cash used in investing activities
$
(1,013.3) $
(587.9) $
(201.5) $
(425.4) $
(386.4)
Net cash used in investing activities increased for the year ended December 31, 2019, compared with 2018. Proceeds received from the sale of oil and
gas properties were $735.5 million lower in 2019 than in 2018 as no material divestitures occurred during 2019. This was partially offset by lower capital
expenditures and less cash paid to acquire proved and unproved oil and gas properties of $279.4 million and $30.7 million, respectively.
Net cash used in investing activities increased for the year ended December 31, 2018, compared with 2017. Capital expenditures in 2018 increased
$414.8 million compared with 2017, from $888.4 million to $1.3 billion as a result of increased drilling and completion activities. During 2018, cash paid to
acquire proved and unproved properties decreased $56.6 million compared with 2017. Further, net proceeds from the sale of oil and gas properties decreased
$28.2 million in 2018, compared with 2017. During 2018, net proceeds were primarily from the PRB Divestiture, Divide County Divestiture, and Halff East
Divestiture. During 2017, net proceeds were primarily from the sale of our outside-operated Eagle Ford shale assets.
54
Financing Activities
Net cash provided by (used in) financing
activities
$
111.8 $
(368.7) $
(12.3) $
480.5 $
(356.4)
For the Years Ended December 31,
Amount Change Between
2019
2018
2017
2019/2018 2018/2017
(in millions)
Net cash provided by (used in) financing activities increased $480.5 million for year ended December 31, 2019, compared with 2018. During the year
ended December 31, 2019, net borrowings under our credit facility increased $122.5 million. We had a zero balance on our credit facility throughout 2018 due to
our cash balance resulting from the proceeds received from divestitures in the first half of 2018. During the year ended December 31, 2018, we redeemed or
repurchased $824.6 million principal outstanding of certain of our senior notes, and paid premiums totaling $20.4 million in connection with these redemptions
and repurchases. Additionally, we issued our 2027 Senior Notes for net proceeds of $492.1 million. There were no such debt transactions during 2019. Please
refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Interest Rate Risk
We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of
December 31, 2019, we had a $122.5 million balance on our credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the
principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the credit
facility’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest
rate changes will not affect the fair value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of
interest we pay on our fixed-rate Senior Notes or fixed-rate Senior Convertible Notes but can impact their fair values. As of December 31, 2019, our outstanding
principal amount of fixed-rate debt totaled $2.6 billion and our floating-rate debt outstanding totaled $122.5 million. Please refer to Note 11 – Fair Value
Measurements in Part II, Item 8 of this report for additional discussion on the fair values of our Senior Notes and Senior Convertible Notes.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, and future rate of growth. Oil,
gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand, all of which are
typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several years, and these markets will likely continue
to be volatile in the future. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on
our 2019 production, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced
our oil, gas, and NGL production revenues by approximately $118.3 million, $26.3 million, and $14.0 million, respectively. If commodity prices had been 10
percent lower, our net derivative settlements for the year ended December 31, 2019 would have offset the declines in oil, gas, and NGL production revenue by
approximately $75.9 million.
We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative
contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2019, a 10 percent increase or decrease in
the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products
by approximately $113.4 million, $6.4 million, and $3.6 million, respectively.
Schedule of Contractual Obligations
The following table summarizes our contractual obligations at December 31, 2019, for the periods specified (in millions):
Contractual Obligations
Total
Less than 1
year
1-3 years
3-5 years
More than 5
years
Long-term debt (1)
Interest payments (2)
Delivery commitments (3)
Operating leases and contracts (3)
Asset retirement obligations (4)
Derivative liabilities (5)
Other (6)
Total
$
2,771.8 $
— $
649.3 $
622.5 $
1,500.0
832.7
218.5
131.1
114.4
54.6
35.6
160.4
46.3
56.3
3.1
51.1
5.6
313.2
133.7
34.6
6.2
3.5
14.9
222.4
136.7
32.5
21.5
36.0
—
15.1
6.0
18.7
69.1
—
—
$
4,158.7 $
322.8 $
1,155.4 $
950.0 $
1,730.5
55
____________________________________________
(1) Long-term debt consists of the $122.5 million balance on our revolving credit facility, our Senior Notes, and our Senior Convertible Notes and assumes no
(2)
principal repayment until the maturity dates of these instruments. The actual payment dates may vary significantly.
Interest payments on our Senior Notes and Senior Convertible Notes are estimated assuming no principal repayment until the maturity dates of these
instruments. Interest payments on our credit facility have been estimated using the rate applicable to the outstanding balance on our credit facility as of
December 31, 2019, and assume no future borrowings or repayments until the September 28, 2023 maturity date of the Credit Agreement. The actual
interest payments on our Senior Notes, Senior Convertible Notes, and our credit facility may vary significantly.
(3) Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating leases, contracts,
and gathering, processing, transportation throughput, and delivery commitments. The amount relating to our gathering, processing, transportation
throughput, and delivery commitments reflects the aggregate undiscounted deficiency payments assuming we delivered no product. This amount does not
include any costs that may be incurred for certain contracts where we cannot predict with accuracy the amount and timing of any payments that may be
incurred for not meeting certain minimum commitments, as such payments are dependent upon the price of oil in effect at the time of settlement.
(4) Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our
accompanying consolidated balance sheets (“accompanying balance sheets”) as of December 31, 2019. The timing and amount of the ultimate settlement
of these obligations is unknown and can be impacted by economic factors, a change in development plans, and federal and state regulations. Please refer
to Note 14 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion.
(5) Amounts shown represent only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices as of
December 31, 2019, and exclude estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on the
accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for us
and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, as they are subject to continuing market risk and
commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
(6) The majority of this amount is related to the unfunded portion of our estimated pension liability of $35.2 million, for which we have estimated the timing of
future payments based on historical annual contribution amounts.
Off-Balance Sheet Arrangements
As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial
partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of
facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest
entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during 2019 or
2018, or through the filing of this report.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The
preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to
make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets
and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other
sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in circumstances,
global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant
Accounting Policies in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and
results of operations and that require the application of significant management judgment.
Successful Efforts Method of Accounting. GAAP provides for two alternative methods for the oil and gas industry to use in accounting for oil and gas
producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely
used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a
given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note
1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report.
Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our
business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including
the calculations of depletion and impairment of proved and unproved oil
56
and gas properties. Please refer to Oil and Gas Producing Activities in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report for
additional discussion on our accounting policies impacted by estimated reserve quantities.
Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality
differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that
period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future
net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise, and estimates of new
discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in
estimating our reserves. We engage Ryder Scott, an independent reservoir evaluation consulting firm, to audit at least 80 percent of our total calculated proved
reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital
costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net
cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2019, is the current market value of our estimated proved reserves. In accordance with SEC
requirements, we based these measures on a 12-month average of the first-day-of-the-month prices for the year ended December 31, 2019. Actual future prices
and costs may be materially higher or lower than the prices and costs utilized in the estimates. Please refer to Risk Factors - Risks Related to Our Business in
Part I, Item 1A of this report.
If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, which would reduce future net income.
Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact
the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.
The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from
changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital
expenditures we incurred to develop other estimated proved reserves.
For the Years Ended December 31,
2019
2018
2017
MMBOE Change MMBOE Change MMBOE Change
Revisions resulting from performance
Removal of proved undeveloped reserves no longer
in our five-year development plan
Revisions resulting from price changes
Total
(14.9)
(9.8)
(70.0)
(94.7)
(59.7)
(22.6)
13.5
(68.8)
7.4
(13.9)
23.1
16.6
As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue
experiencing these types of changes.
We cannot reasonably predict future commodity prices, although we believe that together, the below analyses provide reasonable information regarding
the impact of changes in pricing and trends on total estimated proved reserves. The following table reflects the estimated MMBOE change and percentage
change to our total reported estimated proved reserve volumes from the described hypothetical changes:
10 percent decrease in SEC pricing (1)
Average NYMEX strip pricing as of fiscal year end (2)
(7.2)
(5.2)
(2)%
(1)%
For the year ended December 31, 2019
MMBOE Change
Percentage Change
10 percent decrease in proved undeveloped reserves (3)
___________________________________________
(1) The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated proved reserve volumes as of December 31,
2019, and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future
service or equipment costs.
(5)%
(21.5)
(2) The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2019. SEC pricing of
$55.69 per Bbl for oil, $2.58 per MMBtu for gas, and $22.68 per Bbl for NGLs as of December 31, 2019, compared to the five-year average NYMEX strip
pricing of $53.65 per Bbl for oil, $2.42 per MMBtu for gas, and $19.67 per Bbl for NGLs as of December 31, 2019, would result in a one percent decrease to
our total reported estimated proved reserve volumes.
(3) The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2019, and does not include any additional impacts to
our estimated proved reserves.
57
Additional reserve information can be found in Reserves in Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information (unaudited)
in Part II, Item 8 of this report.
Impairment of Oil and Gas Properties. Proved properties are evaluated periodically for impairment on a pool-by-pool basis when events or changes in
circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and
gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount
exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value (or discounted future
cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which
are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs,
development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows.
Unproved oil and gas properties are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be
recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive
prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other
information, including current drilling plans and our intent to renew leases. We estimate the fair value of unproved properties using a market approach, which
takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated
reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by us or other market participants.
We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any
amount of future impairment being difficult to predict, based on our commodity price assumptions as of February 6, 2020, we do not expect any material
property impairments in the first quarter of 2020 resulting from commodity price impacts.
Please refer to Note 1 – Summary of Significant Accounting Policies and Note 11 – Fair Value Measurements in Part II, Item 8 of this report for
discussion of impairments of oil and gas properties recorded for the years ended December 31, 2019, 2018, and 2017.
Asset Retirement Obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas
properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells and our current understanding of federal and state
regulatory requirements. Our present value calculations require us to estimate the cost, the economic lives and timing of abandonment of our properties, future
inflation rates, and the appropriate credit-adjusted risk-free discount rate to use. The impact to the accompanying statements of operations from these estimates
is reflected in our depletion, depreciation, and amortization calculations and occurs over the remaining life of our respective oil and gas properties. Please refer
to Note 14 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion.
Revenue Recognition. Effective January 1, 2018, our revenue recognition policy was updated to reflect the adoption of new accounting guidance. Our
revenue recognition policy is a critical accounting policy because revenue is a key component of our results of operations and our forward-looking statements
contained in our analysis of liquidity and capital resources. Our primary source of revenue is derived by the sale of produced oil, gas, and NGLs. Revenue is
recognized at the point in time when custody and title (“control”) of the product, as defined by contractual terms, transfers to the purchaser. Payment for these
sales is typically received between 30 and 90 days after the date of production. At the end of each month, we make estimates of the amount of production
delivered to the purchaser and the price we will receive. We use our knowledge of our properties, contractual arrangements, historical performance, NYMEX,
local spot market, and OPIS prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are
recorded in the month payment is received. A 10 percent change in our revenue accrual at year end 2019 would have impacted total operating revenues by
approximately $14.6 million in 2019. Please refer to Note 2 - Revenue from Contracts with Customers in Part II, Item 8 of this report for additional discussion.
Derivative Financial Instruments. We periodically enter into commodity derivative contracts to manage our exposure to oil, gas, and NGL price volatility
and location differentials. We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any
such amounts in accumulated other comprehensive income (loss). The estimated fair value of our derivative instruments requires substantial judgment. These
values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values we report in our
consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which
are beyond our control. Please refer to Note 1 – Summary of Significant Accounting Policies and Note 10 – Derivative Financial Instruments in Part II, Item 8 of
this report for additional discussion.
Income Taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our
consolidated financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is
recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely
than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we
estimate the tax basis of our assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital
loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are
58
recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could
have an impact on our results of operations. A one percent change in our effective tax rate would have changed our calculated income tax expense by
approximately $2.3 million for the year ended December 31, 2019. Please refer to Note 1 – Summary of Significant Accounting Policies and Note 4 – Income
Taxes in Part II, Item 8 of this report for additional discussion.
Accounting Matters
Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for
information on new authoritative accounting guidance.
Environmental
We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures
will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to
predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital
expenditures, liquidity, and results of operations.
Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight
formations. For additional information about hydraulic fracturing and related environmental matters, please refer to Risk Factors – Risks Related to Our Business
– Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing, air quality, and greenhouse gas emissions could result in
increased costs and additional operating restrictions or delays.
Climate Change. In June 2013, President Obama announced a Climate Action Plan designed to further reduce GHG emissions and prepare the nation
for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas sector as part of
a comprehensive interagency methane strategy. As part of the Climate Action Plan, on May 12, 2016, the EPA issued final regulations that amend and expand
2012 regulations for the oil and gas sector by setting emission limits for VOCs and methane, a GHG, and added requirements for previously unregulated
sources. The 2016 NSPS requires reduction of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and
applies to facilities constructed, modified, or reconstructed after September 18, 2015. The regulation requires, among other things, GHG and VOC emission
limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly
boosting and garnering compressor stations and gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and
additional requirements for control of GHGs and VOCs from well completions. Both the 2012 and 2016 rules are the subject of Petitions for Review before the
U.S. Circuit Court of Appeals for the District of Columbia, although the litigation of both rules has been stayed. In October 2018, the EPA proposed scaling back
provisions of the 2016 NSPS directed toward cutting leaks of methane, including proposing allowing only annual inspections for many sites. The rule does not
extend to existing sources and the Trump EPA has rescinded the Information Collection Request that was intended to gather information to develop existing
source standards. On August 29, 2019, the EPA proposed amendments to the 2012 and 2016 NSPS that would remove transmission and storage infrastructure
from regulation of methane emissions and other VOCs. The amendments would also rescind methane requirements for oil and gas production and processing
equipment. As an alternative, the EPA proposed to rescind the methane requirements for oil and gas altogether and sought comment on alternative
interpretations of its authority to regulate pollutants under Section 111 of the Clean Air Act. On November 16, 2016, the BLM finalized regulations to address
methane emissions from oil and gas operations on federal and tribal lands, as part of President Obama’s Climate Action Plan. The regulations were intended to
reduce the waste of gas from flaring, venting, and leaks by oil and gas production. The rule included requirements that prohibits venting of gas except in limited
circumstances and limits flaring of gas and includes requirements for leak detection and repair. The rule also increased royalty payments for “waste” gas that is
released in contravention of the rule requirements. After continuous court challenges, the BLM issued a final rule in September 2018 that rescinded most of the
2016 rule, including most of the methane control requirements. Any future regulations requiring similar capture standards may increase our operational costs, or
restrict our production, which could materially and adversely affect our financial condition, results of operations, and cash flows.
In August of 2015, the EPA finalized existing source performance standards as stringent state emission “goals” for utilities to reduce GHG emissions.
The proposed standards focus on re-dispatching electricity from coal-fired units to gas combined cycle plants and renewables. In February 2016, however, the
Supreme Court stayed these rules pending judicial review. The EPA has proposed a repeal of the rule based on a new legal interpretation of the EPA’s
authority. The EPA proposed a replacement rule, the Affordable Clean Energy Rule, in August 2018 and finalized the rule in June 2019.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have
already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap
and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of
fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced
each year in an effort to achieve the overall GHG emission reduction goal. In addition, there have been international conventions and efforts to establish
standards for the reduction of GHGs globally, including the Paris accords in December 2015. The conditions for entry into force of the
59
Paris accords were met on October 5, 2016 and the Agreement went into force 30 days later on November 4, 2016. However, in August 2017, the U.S. notified
the United Nations Secretary-General that it intends to withdraw from the agreement as soon as it is able to do so, or November 2019. On November 4, 2019,
President Trump formally notified the United Nations that the United States would withdraw from the Paris Agreement. The November 4, 2019 formal notice
triggered the start of a year-long withdrawal process.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to
purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such
legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently,
legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations.
Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or
rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory
compliance. Finally, scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere produce climate changes that likely have
significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an adverse
effect on our financial condition and results of operations.
In terms of opportunities, the regulation of GHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon
sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation
could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces lower
levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become more
prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards,
gas may become a more attractive transportation fuel. Approximately 38 percent and 39 percent of our production on a BOE basis in 2019 and 2018,
respectively, was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs,
could also benefit us through the potential to obtain GHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and
asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based
compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and
certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are
generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe
provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for
development, exploration, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX
ratios as further described in the Credit Agreement section in Overview of Liquidity and Capital Resources above. In addition, adjusted EBITDAX is widely used
by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and
production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not
be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or
liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among
companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our credit facility provides a material
source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total
funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our credit
facility and would therefore materially limit our sources of liquidity. In addition, if we are in default under our credit facility and are unable to obtain a waiver of
that default from our lenders, lenders under the credit facility and under the indentures governing our outstanding Senior Notes and Senior Convertible Notes
would be entitled to exercise all of their remedies for default.
60
The following table provides reconciliations of our net income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX
(non-GAAP) for the periods presented:
Net income (loss) (GAAP)
Interest expense
Income tax expense (benefit)
For the Years Ended December 31,
2019
2018
2017
(in thousands)
$
(187,001) $
508,407 $
(160,843)
159,102
(44,043)
160,906
143,370
179,257
(182,970)
Depletion, depreciation, amortization, and asset retirement obligation
liability accretion
823,798
665,313
557,036
Exploration (1)
Impairment of oil and gas properties
Stock-based compensation expense
Net derivative (gain) loss
Derivative settlement gain (loss)
Net (gain) loss on divestiture activity
Loss on extinguishment of debt
Other, net
Adjusted EBITDAX (non-GAAP)
Interest expense
Income tax (expense) benefit
Exploration (1)
Amortization of debt discount and deferred financing costs
Deferred income taxes
Other, net
Changes in current assets and liabilities
46,995
33,842
24,318
97,539
39,222
(862)
—
481
49,627
49,889
23,908
(161,832)
(135,803)
(426,917)
26,740
(3,214)
48,413
16,078
22,700
26,414
21,234
131,028
35
4,852
993,391
900,394
663,234
(159,102)
(160,906)
(179,257)
44,043
(143,370)
(46,995)
15,474
(41,835)
1,739
16,852
(49,627)
15,258
141,708
3,501
13,671
182,970
(48,413)
16,276
(192,066)
3,033
69,613
Net cash provided by operating activities (GAAP)
$
823,567 $
720,629 $
515,390
____________________________________________
(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying
statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying
statements of operations for the component of stock-based compensation expense recorded to exploration expense.
61
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk in Item 7 above, as well as under the
section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place in Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report and is
incorporated herein by reference.
62
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of SM Energy Company and subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the Company) as of December 31, 2019 and 2018,
the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period
ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial
statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal
control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 20, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial
statements based on our audits. We are a public accounting firm registered with the 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 audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to
assess the risks of material misstatement of the 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 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 financial statements. We
believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to
be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our
especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the
consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the
critical audit matter or on the accounts or disclosures to which it relates.
63
Depletion, depreciation and amortization (‘DD&A’) of proved oil and gas properties
Description of the
Matter
At December 31, 2019, the net book value of the Company’s proved oil and gas properties was $4.8 billion, and depletion, depreciation
and amortization (DD&A) expense was $823.8 million for the year then ended. As described in Note 1 to the consolidated financial
statements, under the successful efforts method of accounting, the costs of development wells are capitalized whether those wells are
successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs,
and operational support facilities in the field are depleted as a group of assets using the units-of-production method based on proved
developed oil and gas reserves, as estimated by the Company’s engineering technical team. Similarly, proved leasehold costs are
depleted on the same group asset basis; however, the units-of-production method is based on total proved oil and gas reserves, as
estimated by the Company’s engineering technical team. Significant judgment is required by the Company’s engineering technical team in
evaluating geoscience and engineering data when estimating proved oil and gas reserves. Estimating reserves also requires the use of
inputs, including oil and gas prices and operating and capital costs assumptions, among others. Because of the complexity involved in
estimating oil and gas reserves, management used an independent petroleum engineering consulting firm to audit the estimates prepared
by the Company’s engineering technical team for at least 80% of the Company’s total calculated proved reserve PV-10 as of December
31, 2019.
Auditing the Company’s DD&A calculation is especially complex and judgmental because of our use of the work of the Company’s
engineering technical team and independent petroleum engineering consulting firm and the evaluation of management’s determination of
the inputs described above used by the engineering technical team and independent petroleum engineering consulting firm in estimating
proved oil and gas reserves.
How We Addressed
the Matter in Our
Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s process to
calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the Company’s
engineering technical team and independent petroleum engineering consulting firm for use in estimating the proved oil and gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the engineering technical team
primarily responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineering consulting firm
used to audit the estimates. In addition, in assessing whether we can use the work of the Company’s engineering technical team and
independent petroleum engineering consulting firm we evaluated the completeness and accuracy of the financial data and inputs
described above used by the engineering technical team and independent petroleum engineering consulting firm in estimating proved oil
and gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We
also tested the mathematical accuracy of the DD&A calculations, including comparing the proved oil and gas reserve amounts used to the
Company’s reserve report.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2012.
Denver, Colorado
February 20, 2020
64
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Derivative assets
Prepaid expenses and other
Total current assets
Property and equipment (successful efforts method):
Proved oil and gas properties
Accumulated depletion, depreciation, and amortization
Unproved oil and gas properties
Wells in progress
Other property and equipment, net of accumulated depreciation of $64,032 and $57,102, respectively
Total property and equipment, net
Noncurrent assets:
Derivative assets
Other noncurrent assets
Total noncurrent assets
Total assets
Current liabilities:
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued expenses
Derivative liabilities
Other current liabilities
Total current liabilities
Noncurrent liabilities:
Revolving credit facility
Senior Notes, net of unamortized deferred financing costs
Senior Convertible Notes, net of unamortized discount and deferred financing costs
Asset retirement obligations
Deferred income taxes
Derivative liabilities
Other noncurrent liabilities
Total noncurrent liabilities
Commitments and contingencies (note 6)
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,987,952 and
112,241,966 shares, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss
Total stockholders’ equity
Total liabilities and stockholders’ equity
December 31,
2019
2018
$
10 $
184,732
55,184
12,708
252,634
8,934,020
(4,177,876)
1,005,887
118,769
72,848
77,965
167,536
175,130
8,632
429,263
7,278,362
(3,417,953)
1,581,401
295,529
93,826
$
$
5,953,648
5,831,165
20,624
65,326
85,950
58,499
33,935
92,434
6,292,232 $
6,352,862
402,008 $
50,846
19,189
472,043
122,500
2,453,035
157,263
84,134
189,386
3,444
61,433
403,199
62,853
—
466,052
—
2,448,439
147,894
91,859
223,278
12,496
42,522
3,071,195
2,966,488
1,130
1,791,596
967,587
(11,319)
2,748,994
$
6,292,232 $
1,122
1,765,738
1,165,842
(12,380)
2,920,322
6,352,862
The accompanying notes are an integral part of these consolidated financial statements.
65
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
For the Years Ended
December 31,
2019
2018
2017
Operating revenues and other income:
Oil, gas, and NGL production revenue
Net gain (loss) on divestiture activity
Other operating revenues
Total operating revenues and other income
Operating expenses:
Oil, gas, and NGL production expense
Depletion, depreciation, amortization, and asset retirement obligation liability
accretion
Exploration
Impairment of oil and gas properties
General and administrative
Net derivative (gain) loss
Other operating expenses, net
Total operating expenses
Income (loss) from operations
Interest expense
Loss on extinguishment of debt
Other non-operating income (expense), net
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Basic weighted-average common shares outstanding
Diluted weighted-average common shares outstanding
Basic net income (loss) per common share
Diluted net income (loss) per common share
$
1,585,750 $
1,636,357 $
862
3,493
1,590,105
426,917
3,798
2,067,072
500,709
487,367
823,798
51,500
33,842
132,797
97,539
19,888
1,660,073
(69,968)
(159,102)
—
(1,974)
(231,044)
44,043
665,313
55,166
49,889
116,504
(161,832)
18,328
1,230,735
836,337
(160,906)
(26,740)
3,086
651,777
(143,370)
$
$
$
(187,001) $
508,407 $
112,544
112,544
(1.66) $
(1.66) $
111,912
113,502
4.54 $
4.48 $
1,253,783
(131,028)
6,621
1,129,376
507,906
557,036
54,713
16,078
117,283
26,414
13,667
1,293,097
(163,721)
(179,257)
(35)
(800)
(343,813)
182,970
(160,843)
111,428
111,428
(1.44)
(1.44)
The accompanying notes are an integral part of these consolidated financial statements.
66
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Net income (loss)
Other comprehensive income, net of tax:
Pension liability adjustment (1)
Total other comprehensive income, net of tax
Total comprehensive income (loss)
For the Years Ended
December 31,
2019
2018
2017
(187,001) $
508,407 $
(160,843)
1,061
1,061
4,378
4,378
767
767
(185,940) $
512,785 $
(160,076)
$
$
____________________________________________
(1) Please refer to Note 8 – Pension Benefits for additional discussion on the pension liability adjustment.
The accompanying notes are an integral part of these consolidated financial statements.
67
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands, except share data and dividends per share)
Common Stock
Shares
Amount
Additional
Paid-in Capital
Retained
Earnings
Accumulated Other
Comprehensive Loss
Total
Stockholders’
Equity
Balances, January 1, 2017
Net loss
Other comprehensive income
Cash dividends, $ 0.10 per share
Issuance of common stock under Employee Stock
Purchase Plan
Issuance of common stock upon vesting of RSUs,
net of shares used for tax withholdings
Stock-based compensation expense
Cumulative effect of accounting change (1)
Other
Balances, December 31, 2017
Net income
Other comprehensive income
Cash dividends, $0.10 per share
Issuance of common stock under Employee Stock
Purchase Plan
Issuance of common stock upon vesting of RSUs,
net of shares used for tax withholdings
Stock-based compensation expense
Cumulative effect of accounting change (1)
111,257,500 $
—
—
—
186,665
171,278
71,573
—
—
111,687,016 $
—
—
—
199,464
291,745
63,741
—
Balances, December 31, 2018
112,241,966 $
Net loss
Other comprehensive income
Cash dividends declared, $0.10 per share
Issuance of common stock under Employee Stock
Purchase Plan
Issuance of common stock upon vesting of RSUs,
net of shares used for tax withholdings
Stock-based compensation expense
—
—
—
314,868
334,399
96,719
1,113 $
—
—
—
2
1
1
—
—
1,117 $
—
—
—
2
3
—
—
1,122 $
—
—
—
1,716,556 $
—
—
—
2,621
(1,241)
22,699
1,108
(120)
1,741,623 $
—
—
—
3,185
(2,978)
23,908
—
1,765,738 $
—
—
—
3
3,206
4
1
1,130 $
(1,665)
24,317
1,791,596 $
794,020 $
(160,843)
—
(11,144)
—
—
—
43,624
—
665,657 $
508,407
—
(11,191)
—
—
—
2,969
1,165,842 $
(187,001)
—
(11,254)
—
—
—
967,587 $
Balances, December 31, 2019
____________________________________________
(1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.
112,987,952 $
The accompanying notes are an integral part of these consolidated financial statements.
68
(14,556)
$
—
767
—
—
—
—
—
—
2,497,133
(160,843)
767
(11,144)
2,623
(1,240)
22,700
44,732
(120)
(13,789)
$
2,394,608
—
4,378
—
—
—
—
(2,969)
(12,380)
$
—
1,061
—
—
—
—
508,407
4,378
(11,191)
3,187
(2,975)
23,908
—
2,920,322
(187,001)
1,061
(11,254)
3,209
(1,661)
24,318
(11,319)
$
2,748,994
SM ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (gain) loss on divestiture activity
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
Impairment of oil and gas properties
Stock-based compensation expense
Net derivative (gain) loss
Derivative settlement gain (loss)
Amortization of debt discount and deferred financing costs
Loss on extinguishment of debt
Deferred income taxes
Other, net
Changes in current assets and liabilities:
Accounts receivable
Prepaid expenses and other
Accounts payable and accrued expenses
Net cash provided by operating activities
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties
Capital expenditures
Acquisition of proved and unproved oil and gas properties
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from credit facility
Repayment of credit facility
Net proceeds from Senior Notes
Cash paid to repurchase Senior Notes, including premium
Net proceeds from sale of common stock
Dividends paid
Other, net
Net cash provided by (used in) financing activities
Net change in cash, cash equivalents, and restricted cash
Cash, cash equivalents, and restricted cash at beginning of period
Cash, cash equivalents, and restricted cash at end of period
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest
Net cash (paid) refunded for income taxes
Investing activities:
Changes in capital expenditure accruals and other
Supplemental non-cash investing activities:
Carrying value of properties exchanged
Supplemental non-cash financing activities:
Non-cash loss on extinguishment of debt, net
For the Years Ended
December 31,
2019
2018
2017
$
(187,001) $
508,407 $
(160,843)
(862)
823,798
33,842
24,318
97,539
39,222
15,474
—
(41,835)
2,220
(39,556)
6,130
50,278
823,567
13,059
(1,023,769)
(2,581)
(1,013,291)
1,589,000
(1,466,500)
—
—
3,209
(11,254)
(2,686)
111,769
(77,955)
77,965
10 $
(426,917)
665,313
49,889
23,908
(161,832)
(135,803)
15,258
26,740
141,708
287
(20,775)
(729)
35,175
720,629
748,509
(1,303,188)
(33,255)
(587,934)
—
—
492,079
(845,002)
3,187
(11,191)
(7,746)
(368,673)
(235,978)
313,943
77,965 $
131,028
557,036
16,078
22,700
26,414
21,234
16,276
35
(192,066)
7,885
20,410
(1,953)
51,156
515,390
776,719
(888,353)
(89,896)
(201,530)
406,000
(406,000)
—
(2,357)
2,623
(11,144)
(1,411)
(12,289)
301,571
12,372
313,943
(141,902) $
6,109 $
(150,727) $
(2,995) $
(164,097)
(5,986)
(24,289) $
(2,774) $
7,309
73,442 $
95,121 $
293,963
— $
6,334 $
22
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
69
SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Summary of Significant Accounting Policies
Description of Operations
SM Energy Company, together with its consolidated subsidiaries, is an independent energy company engaged in the acquisition, exploration,
development, and production of oil, gas, and NGLs in the state of Texas.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the
instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the
consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2019, through the filing of this report.
Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the consolidated financial statements.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported
amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas
reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset
retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of
cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Accounts Receivable
The Company’s accounts receivable consists mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the
Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover
non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had
minimal bad debts.
Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by
the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 13 – Accounts Receivable and Accounts Payable and
Accrued Expenses for additional disclosure.
Concentration of Credit Risk and Major Customers
The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related
industries. The creditworthiness of customers and other counterparties is subject to regular review.
70
The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as oil, gas, and NGLs are
products with well-established markets and numerous purchasers in the Company’s operating regions. The following major customers and entities under
common control accounted for 10 percent or more of its total oil, gas, and NGL production revenue for at least one of the periods presented:
Major customer #1 (1)
Major customer #2 (1)
Major customer #3 (1)
Major customer #4 (1)
Group #1 of entities under common control (2)
For the Years Ended December 31,
2019
2018
2017
18%
14%
13%
9%
13%
18%
5%
7%
10%
18%
6%
1%
—%
10%
17%
Group #2 of entities under common control (2)
____________________________________________
(1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets.
(2)
8%
11%
12%
In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production
revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of the
Company’s total oil, gas, and NGL production revenue.
The Company generally contracts with the affiliates of the lenders under its Credit Agreement as its derivative counterparties, and the Company’s policy
is that each counterparty must have investment grade senior unsecured debt ratings.
The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. The
Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the
amount of credit exposure to any single institution or investment. The Company maintains investments in highly rated, highly liquid investment products with
numerous banks that are party to its revolving credit facility.
Oil and Gas Producing Activities
Proved properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, the costs of
development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well
equipment, intangible development costs, and operational support facilities in the field, are depleted on a group basis (properties aggregated based on
geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved
leasehold costs are depleted on the same group asset basis; however, the units-of-production method is based on estimated total proved oil and gas reserves.
The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging
equipment.
Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may
not be recoverable. The Company uses an income valuation technique, which converts future cash flow to a single present value amount, to measure the fair
value of proved properties through an application of discount rates and price forecasts, as selected by the Company’s management. The Company uses
discount rates that are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of
possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The discount rates typically range from 10 percent to
15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows. The prices for oil and gas are forecasted based on
NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for
NGLs are forecasted using OPIS pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also
adjusted as deemed appropriate for these estimates.
The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is
recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved
property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other
sales of proved properties.
Unproved properties. The unproved oil and gas properties line item on the accompanying balance sheets consists of costs incurred to acquire
unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved
properties and depleted on a units-of-production basis. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there
is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the
portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be
nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair
value of unproved properties, the Company uses a market approach, which takes into account the following significant
71
assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage
value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.
For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on a group basis,
neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the
accompanying statements of operations in the amount of such excess.
Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage
are expensed as incurred. Under the successful efforts method, exploratory well costs are capitalized pending further evaluation of whether economically
recoverable reserves have been found. If economically recoverable reserves are found, exploratory wells costs will be capitalized as proved properties and will
be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well
costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper
designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is
drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are
included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows.
Other Property and Equipment
Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost.
The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes
software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are
capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful
lives of the assets, which range from 3 to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the
capitalized costs and related accumulated depreciation are removed from the accounts.
Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be
recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on
the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and
unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the
assets.
Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities
requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived
asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas
properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes
expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash
paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows.
The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic
lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate
estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities
range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the
liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, or changes in
inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a
reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2019, and 2018.
Derivative Financial Instruments
The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in
commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include
commodity price swaps and costless collars, as well as, basis differential swaps. Commodity derivative instruments are measured at fair value and are included
in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale”
exclusion. The Company does not designate its derivative commodity contracts as hedging instruments. Accordingly, the Company reflects changes in the fair
value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on derivatives
72
are included within the cash flows from operating activities section of the accompanying statements of cash flows. For additional discussion on derivatives,
please refer to Note 10 – Derivative Financial Instruments.
Revenue Recognition
The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and
title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded
monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual
amounts received are recorded in the month payment is received. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.
Stock-Based Compensation
At December 31, 2019, the Company had stock-based employee compensation plans that included restricted stock units (“RSUs”) and performance
share units (“PSUs”) issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to
eligible employees. These are more fully described in Note 7 – Compensation Plans. The Company records expense associated with the fair value of stock-
based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of
grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based
compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected
to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company
accounts for forfeitures of stock-based compensation awards as they occur.
Income Taxes
The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary
differences between the carrying amounts on the consolidated financial statements and the tax basis of assets and liabilities, as measured using current
enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are
recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more
likely than not to be realized based upon Company analysis. Please refer to Note 4 – Income Taxes for additional disclosure.
Earnings per Share
The Company uses the treasury stock method to determine the potential dilutive effect of non-vested RSUs, contingent PSUs, and Senior Convertible
Notes. Please refer to Note 9 - Earnings Per Share for additional discussion.
Comprehensive Income (Loss)
Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is
comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income
(loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss)
(“accompanying statements of comprehensive income (loss)”). The Company’s policy for releasing income tax effects within accumulated other comprehensive
loss is an incremental, unit-of-account approach. Please refer to Note 8 – Pension Benefits for detail on the changes in the balances of components comprising
other comprehensive income (loss).
Fair Value of Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which
approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it
bears interest at a floating rate that approximates a current market rate. The Company had a $122.5 million balance under its credit facility as of December 31,
2019, compared with a zero balance as of December 31, 2018. The Company’s Senior Notes and Senior Convertible Notes are recorded at cost, net of any
unamortized discount and deferred financing costs, and their respective fair values are disclosed in Note 11 – Fair Value Measurements. Additionally, the
Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates
provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
Industry Segment and Geographic Information
The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a
single industry segment.
73
Off-Balance Sheet Arrangements
The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities
often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other
contractually narrow or limited purposes.
The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary
beneficiary of a variable interest entity, that entity is consolidated. The Company has not been involved in any unconsolidated SPE transactions in 2019 or 2018.
Recently Issued Accounting Standards
Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting
Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU
2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based arrangements, including income tax effects, accounting for
forfeitures, and net share settlements. The Company adopted the various applicable amendments, which are summarized as follows:
•
•
•
On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was
recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Effective January 1, 2017, excess tax
benefits are presented in net cash provided by operating activities on the accompanying statements of cash flows.
On January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than
applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in
additional paid-in capital of $1.1 million, a decrease in deferred tax assets of $400,000, and a net $700,000 cumulative effect decrease to retained
earnings.
Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between
periods.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and
additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified
retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby lease accounting for previously
reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and
practical expedients the Company implemented in connection with the adoption of ASU 2016-02 include (a) excluding from the balance sheet leases with terms
that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for
them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that
commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of
ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative
resources.
Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for
its operating leases. There was no cumulative effect adjustment to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for
additional discussion.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial
Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users
with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity
at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019,
with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 is not expected to result in a material
impact to the Company’s consolidated financial statements or disclosures.
In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic
Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as
other compensation costs arising from services rendered by employees during the period, and presentation of the remaining components of net benefit cost in a
separate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company adopted
ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost
in the consolidated statements of operations, and prospective application for the capitalization of the service cost component of net benefit costs in assets. While
the adoption of ASU 2017-07 resulted in the Company reclassifying certain amounts from operating expenses to non-operating expenses, ASU 2017-07 did not
result in a material impact to the Company’s consolidated financial statements or disclosures.
74
In February 2018, the FASB issued ASU No. 2018-02, Income Statement–Reporting Comprehensive Income (Topic 220): Reclassification of Certain
Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated
other comprehensive income (loss) to retained earnings as a result of the 2017 Tax Act. The Company early adopted ASU 2018-02 effective January 1, 2018
using a retrospective method. As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other
comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive
loss is an incremental, unit-of-account approach.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting
for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for
capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred
to develop or obtain internal-use software. The Company adopted ASU 2018-15 on January 1, 2020, with prospective application. The adoption of ASU 2018-15
is not expected to have a material impact to the Company’s consolidated financial statements or disclosures.
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”).
ASU 2019-12 was issued as a means to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting
standard. The guidance is to be applied using a prospective method, excluding amendments related to franchise taxes, which should be applied on either a
retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of
the fiscal year of adoption. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company is
evaluating the impact of ASU 2019-12 on its consolidated financial statements.
There are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related
disclosures that have been issued but not yet adopted by the Company as of December 31, 2019, and through the filing of this report.
Note 2 - Revenue from Contracts with Customers
The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Midland Basin and South Texas assets. Following the
divestiture of the Company’s remaining assets in the Rocky Mountain region during the first half of 2018, there has been no production revenue from this region
after the second quarter of 2018. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue
generated from contracts with customers.
The tables below present the oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the years ended
December 31, 2019, 2018, and 2017:
For the year ended December 31, 2019
Midland Basin South Texas
Total
(in thousands)
Oil production revenue
$
1,119,786
$
63,426
$
1,183,212
Gas production revenue
NGL production revenue
Total
Relative percentage
75,827
123
186,702
139,886
262,529
140,009
$
1,195,736
$
390,014
$
1,585,750
75%
25%
100%
____________________________________________
Note: Amounts may not calculate due to rounding.
75
For the year ended December 31, 2018
Midland Basin South Texas
Rocky
Mountain
Total
(in thousands)
Oil production revenue
$
938,004
$
72,821
$
54,851
$
1,065,676
Gas production revenue
NGL production revenue
125,603
1,000
227,252
214,441
1,595
790
354,450
216,231
Total
Relative percentage
$
1,064,607
$
514,514
$
57,236
$
1,636,357
65%
32%
3%
100%
____________________________________________
Note: Amounts may not calculate due to rounding.
For the year ended December 31, 2017
Midland Basin South Texas
Rocky
Mountain
(in thousands)
419,732
$
82,674
$
151,844
$
61,781
547
301,780
226,031
5,849
3,545
Total
654,250
369,410
230,123
482,060
$
610,485
$
161,238
$
1,253,783
38%
49%
13%
100%
Oil production revenue
Gas production revenue
NGL production revenue
Total
Relative percentage
$
$
____________________________________________
Note: Amounts may not calculate due to rounding.
The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the purchaser, which differs
depending on the applicable contractual terms. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production
expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred by the Company prior to control
transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred at or
near the wellhead, sales are based on a wellhead market price that is impacted by fees and other deductions incurred by the purchaser subsequent to the
transfer of control. In general, the Company generates production revenue from a combination of the following types of contracts:
•
•
The Company sells oil and gas production at or near the wellhead and receives an agreed-upon market price from the purchaser. Under this type of
arrangement, control transfers at or near the wellhead.
The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for
processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind.
For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds the processor realizes
from selling the NGLs to third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points
downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees
and other deductions incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the
accompanying statements of operations.
Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers, relate to the point in time when
control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are
required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level
of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the
Company does not consider estimates of variable consideration to be constrained.
The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The
performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s
processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally
less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
76
Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons
and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production
delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within
the accounts receivable line item on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with
customers within the accompanying balance sheets as of December 31, 2019, and 2018, were $146.3 million and $107.2 million, respectively. To estimate
accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index
pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received
for product sales are recorded in the month that payment is received from the purchaser.
Note 3 – Divestitures, Assets Held for Sale, and Acquisitions
2019 Divestiture Activity
No material divestitures occurred during 2019.
2018 Divestiture Activity
PRB Divestiture. On March 26, 2018, the Company completed the PRB Divestiture, divesting of approximately 112,000 net acres for total cash
received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $492.2 million, and recorded a final net gain of $410.6 million
for the year ended December 31, 2018.
Divide County Divestiture and Halff East Divestiture. During the second quarter of 2018, the Company completed the Divide County Divestiture and the
Halff East Divestiture, for combined net divestiture proceeds of $252.2 million, and recorded a combined final net gain of $15.4 million for the year ended
December 31, 2018.
The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the years ended December 31, 2019, 2018,
and 2017. The Divide County Divestiture was considered a disposal of a significant asset group.
For the Years Ended December 31,
2019
2018
2017
(in thousands)
Loss before income taxes (1)
$
— $
(28,975) $
(468,786)
____________________________________________
(1) Loss before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization,
and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity. During the year ended December 31,
2017, the Company recorded a write-down of $523.6 million on these assets.
2017 Divestiture Activity
Eagle Ford Divestiture. On March 10, 2017, the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in
related midstream assets, for final net divestiture proceeds of $744.1 million. The Company recorded a final net gain of $396.8 million related to these divested
assets for the year ended December 31, 2017. This divestiture was considered a disposal of a significant asset group. For the year ended December 31, 2017,
income before income taxes from the outside-operated Eagle Ford shale assets sold was $24.3 million. This amount reflects oil, gas, and NGL production
revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion expense.
During 2017, the Company divested certain non-core properties for net divestiture proceeds of $36.2 million and recognized an insignificant final net
gain.
The Company determined that executed asset sales in 2018 and 2017 did not qualify for discontinued operations accounting under financial statement
presentation authoritative guidance.
2019 Acquisition Activity
During 2019, the Company completed several non-monetary acreage trades of primarily undeveloped properties located in Howard, Martin, and
Midland Counties, Texas, resulting in the exchange of approximately 2,200 net acres, with $73.4 million of carrying value attributed to the properties transferred
by the Company. These trades were recorded at carryover basis with no gain or loss recognized.
77
2018 Acquisition Activity
During the year ended December 31, 2018, the Company acquired approximately 1,030 net acres of primarily unproved properties located in Martin
and Howard Counties, Texas, in two separate transactions which closed in 2018. Combined total cash consideration paid by the Company was $33.3 million.
Under authoritative accounting guidance, these transactions were both individually considered to be asset acquisitions. Therefore, the properties were recorded
based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the
assets acquired.
During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily undeveloped properties located in Howard and
Martin Counties, Texas, which resulted in the exchange of approximately 2,650 net acres, with $95.1 million of carrying value attributed to the properties
transferred by the Company. These trades were recorded at carryover basis with no gain or loss recognized.
2017 Acquisition Activity
During the year ended December 31, 2017, the Company acquired approximately 3,600 net acres of primarily unproved properties in Howard and
Martin Counties, Texas, in multiple transactions for a total of $76.5 million of cash consideration. Under authoritative accounting guidance, these transactions
were individually considered to be asset acquisitions. Therefore, the properties were recorded based on the fair value of the total consideration transferred on
the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired.
Also during the year ended December 31, 2017, the Company completed several non-monetary acreage trades of primarily unproved properties in
Howard and Martin Counties, Texas, resulting in the exchange of approximately 8,125 net acres for approximately 7,580 net acres with $294.0 million of
carrying value attributed to the properties transferred by the Company in such trades. These trades were recorded at carryover basis with no gain or loss
recognized.
Note 4 – Income Taxes
The provision for income taxes consists of the following:
For the Years Ended December 31,
2019
2018
2017
(in thousands)
Current portion of income tax expense (benefit)
Federal
State
Deferred portion of income tax expense (benefit)
Income tax expense (benefit)
$
$
(3,826)
$
— $
1,618
(41,835)
1,662
141,708
(44,043)
$
143,370
$
5,698
3,398
(192,066)
(182,970)
Effective tax rate
19.1%
22.0%
53.2%
78
The components of the net deferred tax liabilities are as follows:
Deferred tax liabilities
Oil and gas properties
Derivative assets
Other
Total deferred tax liabilities
Deferred tax assets
Credit carryover
Pension
Federal and state tax net operating loss
carryovers
Stock compensation
Other liabilities
Total deferred tax assets
Valuation allowance
Net deferred tax assets
Total net deferred tax liabilities
Current federal income tax refundable
Current state income tax payable
As of December 31,
2019
2018
(in thousands)
$
205,028 $
4,646
12,361
222,035
11,270
5,971
4,172
3,503
10,803
35,719
(3,070)
32,649
218,094
35,247
4,812
258,153
22,554
6,427
4,217
3,263
1,497
37,958
(3,083)
34,875
$
$
$
189,386 $
223,278
3,885 $
1,404 $
59
1,331
As of December 31, 2019, the Company estimated its federal net operating loss (“NOL”) carryforward at $3.3 million and state NOL carryforwards at
$77.8 million. The Company has federal research and development (“R&D”) and AMT credit carryforwards of $7.4 million and $4.3 million, respectively. The
majority of federal NOLs do not expire but the state NOLs and state tax credits expire between 2021 and 2038. The federal R&D credit carryforwards expire
between 2028 and 2035. The Company’s AMT credit carryforwards are expected to be fully refunded by 2022. The Company’s current valuation allowance
relates to state NOL carryforwards and state tax credits, which are expected to expire before they can be utilized.
Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate
to income before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based
compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, and the cumulative impact of other smaller
permanent differences, and is reported as follows:
For the Years Ended December 31,
2019
2018
2017
(in thousands)
Federal statutory tax expense (benefit)
$
(48,519) $
136,873 $
(120,335)
Increase (decrease) in tax resulting from:
Federal tax reform changes - 2017 Tax Act
State tax expense (benefit) (net of federal benefit)
Change in valuation allowance
Employee share-based compensation
Other
—
260
(13)
3,346
883
—
2,771
105
2,508
1,113
(63,675)
(3,286)
(2,727)
8,190
(1,137)
Income tax expense (benefit)
$
(44,043) $
143,370 $
(182,970)
Acquisitions, divestitures, drilling activity, and basis differentials, which impact the prices received for oil, gas, and NGLs, impact the apportionment of
taxable income to the states where the Company owns oil and gas properties. As these factors change, the Company’s state income tax rate changes. This
change, when applied to the Company’s total temporary differences, impacts the total state income tax expense (benefit) reported in the current year. Items
affecting state apportionment factors are evaluated upon completion of the prior year income tax return, after significant acquisitions and divestitures, if there are
significant changes in drilling activity, or if estimated state revenue changes occur during the year. As a result of the 2018 divestitures, the Company’s state
apportionment rate reflects its significant Texas presence.
79
During the fourth quarter of 2019, the Company claimed and received a $7.7 million refund for a portion of its deferred AMT credit carryover. An
additional refund of $3.8 million is expected to be claimed in 2020. For all years before 2015, the Company is generally no longer subject to United States
federal or state income tax examinations by tax authorities.
The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit
reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible
amount associated with income taxes. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2020.
The total amount recorded for unrecognized tax benefits for each of the years ended December 31, 2019, 2018, and 2017, was $446,000.
Note 5 – Long-Term Debt
Credit Agreement
On September 19, 2019, the Company and its lenders entered into the Second Amendment to the Sixth Amended and Restated Credit Agreement
which permitted the Company to enter into swap agreements with respect to the price of electricity in order to minimize exposure to electrical price volatility. As
of December 31, 2019, the Credit Agreement provided for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, a borrowing base
of $1.6 billion, and aggregate lender commitments of $1.2 billion. The borrowing base is subject to regular, semi-annual redetermination, and considers the
value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report; and (b) commodity derivative contracts,
each as determined by the Company’s lender group. The next scheduled borrowing base redetermination date is April 1, 2020.
The Credit Agreement is scheduled to mature on the earlier of September 28, 2023, (the “Scheduled Maturity Date”), and August 16, 2022, to the
extent that, on or before such date, the Company’s outstanding 2022 Senior Notes are not repurchased, redeemed, or refinanced to have a maturity date at
least 91 days after the Scheduled Maturity Date unless, on August 16, 2022, both (i) the aggregate outstanding principal amount of the 2022 Senior Notes is not
more than $100.0 million and (ii) after giving pro forma effect to the repayment in full at maturity of the 2022 Senior Notes then outstanding, the aggregate
amount of unrestricted cash and certain types of unrestricted investments held by the Company and its Consolidated Restricted Subsidiaries plus the amount of
unused availability under the Credit Agreement is at least $300.0 million.
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting
dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. The financial covenants under the Credit
Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four
consecutive fiscal quarters (excluding the first three quarters which used annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the
quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot
be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Company was in
compliance with all financial and non-financial covenants as of December 31, 2019, and through the filing of this report.
Interest and commitment fees associated with the credit facility are accrued based on a borrowing base utilization grid set forth in the Credit
Agreement. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline
loans. Eurodollar loans accrue interest at LIBOR, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-
based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender
commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations. The
borrowing base utilization grid as set forth in the Credit Agreement is as follows:
Borrowing Base Utilization Percentage
<25%
≥25% <50% ≥50% <75% ≥75% <90%
≥90%
Eurodollar Loans (1)
ABR Loans or Swingline Loans
Commitment Fee Rate
____________________________________________
1.500%
0.500%
0.375%
1.750%
0.750%
0.375%
2.000%
1.000%
0.500%
2.250%
1.250%
0.500%
2.500%
1.500%
0.500%
(1) The Company’s Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be used for
determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be
established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the borrower.
80
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit
Agreement as of February 6, 2020, December 31, 2019, and December 31, 2018:
Revolving credit facility (1)
Letters of credit (2)
Available borrowing capacity
Total aggregate lender commitment amount
$
$
As of February 6, 2020 As of December 31, 2019 As of December 31, 2018
113,500 $
—
1,086,500
1,200,000 $
(in thousands)
122,500 $
—
1,077,500
1,200,000 $
—
200
999,800
1,000,000
____________________________________________
(1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on
the accompanying balance sheets and totaled $5.9 million and $6.4 million as of December 31, 2019, and 2018, respectively. These costs are being
amortized over the term of the credit facility on a straight-line basis.
(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of
December 31, 2018, was released effective January 8, 2019.
Senior Notes
The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of December 31, 2019, and 2018,
consisted of the following:
As of December 31,
2019
2018
Unamortized
Deferred
Financing
Costs
Principal
Amount
Principal
Amount, Net of
Unamortized
Deferred
Financing
Costs
Unamortized
Deferred
Financing
Costs
Principal
Amount
Principal
Amount, Net of
Unamortized
Deferred
Financing
Costs
(in thousands)
6.125% Senior Notes due
2022
$
476,796 $
5.0% Senior Notes due 2024
500,000
2,920 $
3,766
473,876 $
476,796 $
496,234
500,000
3,921 $
4,688
5.625% Senior Notes due
2025
6.75% Senior Notes due 2026
6.625% Senior Notes due
2027
500,000
500,000
4,903
5,571
495,097
494,429
500,000
500,000
5,808
6,407
500,000
6,601
493,399
500,000
7,533
492,467
Total
$ 2,476,796 $
23,761 $
2,453,035 $ 2,476,796 $
28,357 $
2,448,439
The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured
senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject
to certain covenants under the indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock,
and make restricted payments, including dividends. The Company was in compliance with all such covenants under its Senior Notes as of December 31, 2019,
and through the filing of this report. All Senior Notes are registered under the Securities Act. The Company may redeem some or all of its Senior Notes prior to
their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.
On July 16, 2018, the Company redeemed its 2021 Senior Notes which resulted in the payment of total cash consideration, including accrued interest,
of $355.9 million. Additionally, during the third quarter of 2018, the Company used the proceeds from the issuance of its 2027 Senior Notes, as discussed below,
and cash on hand to fund the cash tender offer and redemption of $395.0 million of its 2023 Senior Notes and $85.0 million of its 2022 Senior Notes. The
Company paid total consideration, including accrued interest, of $497.8 million to complete these transactions. As a result of the redemption of the 2021 Senior
Notes, and the cash tender offer and redemption of all of the 2023 Senior Notes and a portion of the 2022 Senior Notes, the Company recorded a combined loss
on extinguishment of debt of $26.7 million for the year ended December 31, 2018. This amount included combined premiums paid of $20.4 million and $6.3
million of accelerated unamortized deferred financing costs for the redemption.
2022 Senior Notes. On November 17, 2014, the Company issued $600.0 million in aggregate principal amount of 6.125% Senior Notes due 2022 at
par, which mature on November 15, 2022. The Company received net proceeds of $590.0 million after deducting fees of $10.0 million, which are being
amortized as deferred financing costs over the life of the 2022 Senior Notes. During the first quarter of 2016, the Company repurchased $38.2 million in
aggregate principal amount of its 2022 Senior Notes for a
81
472,875
495,312
494,192
493,593
settlement amount of $24.3 million, excluding interest. During the third quarter of 2018, through the tender offer discussed above, the Company retired $85.0
million of its 2022 Senior Notes for total consideration, including accrued interest, of $89.5 million.
2024 Senior Notes. On May 20, 2013, the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024 at par, which
mature on January 15, 2024. The Company received net proceeds of $490.2 million after deducting fees of $9.8 million, which are being amortized as deferred
financing costs over the life of the 2024 Senior Notes.
2025 Senior Notes. On May 21, 2015, the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 at par,
which mature on June 1, 2025. The Company received net proceeds of $491.0 million after deducting fees of $9.0 million, which are being amortized as
deferred financing costs over the life of the 2025 Senior Notes.
2026 Senior Notes. On September 12, 2016, the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026, at
par, which mature on September 15, 2026. The Company received net proceeds of $491.6 million after deducting fees of $8.4 million, which are being amortized
as deferred financing costs over the life of the 2026 Senior Notes.
2027 Senior Notes. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027, at par,
which mature on January 15, 2027. The Company received net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as
deferred financing costs over the life of the 2027 Senior Notes. As discussed above, the net proceeds were used to fund the tender offer and redemption of all of
the Company’s 2023 Senior Notes and a portion of its 2022 Senior Notes.
Senior Convertible Notes
On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021, unless
earlier converted. The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any
future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company received net proceeds of $166.6 million after
deducting fees of $5.9 million, of which a portion is being amortized over the life of the Senior Convertible Notes.
Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under the following circumstances: (1)
during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2016, if the last reported
sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during a 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; (2)
during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price (as defined in the
indenture) per $1,000 principal amount of Notes for each trading day of the measurement period was 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 (3) upon the occurrence of specified corporate events. On or after
January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible
Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common
stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s
common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share,
subject to adjustment.
The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal
amount in cash with any excess conversion in shares of the Company’s common stock. The Senior Convertible Notes were not convertible at the option of
holders as of December 31, 2019, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible
Notes as of December 31, 2019, did not exceed the principal amount.
Upon the issuance of the Senior Convertible Notes, the Company recorded $132.3 million as the initial carrying amount of the debt component, which
approximated its fair value at issuance, and, was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes.
The effective interest rate used was 7.25%. The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt
component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The Company incurred transaction costs of $5.9 million
relating to the issuance of the Senior Convertible Notes, which were allocated between the debt and equity components in proportion to their determined fair
value amounts. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense
through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the
debt discount totaled $11.0 million, $10.5 million, and $9.9 million for the years ended December 31, 2019, 2018, and 2017, respectively.
82
The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets consisted of the
following as of December 31, 2019 and 2018:
Principal amount of Senior Convertible Notes
Unamortized debt discount
Unamortized deferred financing costs
Senior Convertible Notes, net of unamortized discount and deferred financing costs
As of December 31,
2019
2018
(in thousands)
$
$
172,500 $
(13,861)
(1,376)
157,263 $
172,500
(22,313)
(2,293)
147,894
As of both December 31, 2019 and 2018, the net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-
in capital on the accompanying balance sheets was $33.6 million. There have been no changes to this amount since issuance.
If the Company undergoes a fundamental change, as defined by the governing indenture, holders of the Senior Convertible Notes may require the
Company to repurchase for cash all or any portion of their notes at a fundamental change repurchase price equal to 100% of the principal amount of the Senior
Convertible Notes to be repurchased, plus accrued and unpaid interest. The indenture governing the Senior Convertible Notes contains customary events of
default with respect to the Senior Convertible Notes, including that upon certain events of default, the trustee by notice to the Company, or the holders of at least
25% in principal amount of the outstanding Senior Convertible Notes by notice to the Company, may declare 100% of the principal and accrued and unpaid
interest, if any, due and payable immediately. In case of certain events of bankruptcy, insolvency or reorganization involving the Company or a significant
subsidiary, 100% of the principal and accrued and unpaid interest on the Senior Convertible Notes will automatically become due and payable.
The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as
of December 31, 2019, and through the filing of this report.
Capped Call Transactions
In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of
such issuance. The aggregate cost of the capped call transactions was approximately $24.2 million. The capped call transactions are generally expected to
reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in
excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock is greater
than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible
Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call
transactions, there could be dilution or there would not be an offset of such potential cash payments. The Company classified the costs associated with the
capped call transactions as equity instruments with no recurring fair value measurement recorded.
Capitalized Interest
Capitalized interest costs for the Company for the years ended December 31, 2019, 2018, and 2017, totaled $18.5 million, $20.6 million, and $12.6
million, respectively. Capitalized interest costs are included in total costs incurred. Please refer to Costs Incurred in Oil and Gas Producing Activities in Overview
of the Company in Part II, Item 7, and Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
83
Note 6 – Commitments and Contingencies
Commitments
The Company has entered into various agreements, which include drilling rig and completion service contracts of $34.1 million, gathering, processing,
transportation throughput, and delivery commitments of $218.5 million, office leases, including maintenance, of $28.3 million, fixed price contracts to purchase
electricity of $53.2 million, and other miscellaneous contracts and leases of $15.5 million. The annual minimum payments for the next five years and total
minimum payments thereafter are presented below:
Years Ending December 31,
2020
2021
2022
2023
2024
Thereafter
Total
Amount
(in thousands)
$
102,550
94,494
73,826
41,661
12,349
24,697
$
349,577
Drilling Rig and Completion Service Contracts. The Company has several drilling rig and completion service contracts in place to facilitate its drilling
and completion plans. As of December 31, 2019, the Company’s drilling rig and completion service contract commitments totaled $34.1 million, included in the
table above. If all of these contracts were terminated as of December 31, 2019, the Company would avoid a portion of the contractual service commitments;
however, the Company would be required to pay $26.3 million in early termination fees. Excluded from these amounts are variable commitments and potential
penalties determined by the number of completion crews the Company has in operation in a particular area under a completion service arrangement. As of
December 31, 2019, potential penalties under this completion service agreement, which expires on December 31, 2023, range from zero to a maximum of $13.4
million.
Pipeline Transportation Commitments. The Company has gathering, processing, transportation throughput, and delivery commitments with various
third-parties that require delivery of a minimum amount of oil, gas, and produced water. As of December 31, 2019, the Company has commitments to deliver a
minimum of 24 MMBbl of oil and 424 Bcf of gas through 2023, and 18 MMBbl of produced water through 2027. The Company will be required to make periodic
deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. As of December 31, 2019, if the Company fails
to deliver any product, as applicable, the aggregate undiscounted deficiency payments total approximately $218.5 million. This amount does not include
deficiency payment estimates associated with approximately 16.5 MMBbl of future oil delivery commitments where the Company cannot predict with accuracy
the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement. Under certain of the
Company’s commitments, if the Company is unable to deliver the minimum quantity from its production, it may deliver production acquired from third-parties to
satisfy its minimum volume commitments.
Office Leases. The Company leases office space under various operating leases with terms extending as far as 2026. Rent expense for the years
ended December 31, 2019, 2018, and 2017, was $5.5 million, $4.5 million, and $4.8 million, respectively.
Electrical Power Purchase Contracts. During the second quarter of 2019, the Company entered into a fixed price contract for the purchase of electrical
power that increased the purchase commitment under an existing agreement. As of December 31, 2019, the Company had a commitment to purchase electrical
power through 2027 with a total remaining obligation of $53.2 million.
Delivery and Purchase Commitments. During the second quarter of 2019, the Company executed an amendment to its existing sand sourcing
agreement that created certain commitments and potential penalties that vary based on the amount of sand the Company uses in well completions occurring in
a particular area. This amended sand sourcing agreement expires on December 31, 2023. As of December 31, 2019, potential penalties under this sand
sourcing agreement range from zero to a maximum of $10.0 million.
Drilling and Completion Commitments. The Company has an agreement in place that includes minimum drilling and completion requirements on certain
leases. If these minimum requirements are not satisfied by March 31, 2020, the Company would be required to make a liquidated damage payment based on
the difference between actual development progress and the minimum development requirements. As of December 31, 2019, the Company did not expect to
meet certain minimum development requirements.
84
In the fourth quarter of 2019, the Company recognized one-time charges associated with expected payments to lessors related to drilling and
completion obligations and early termination fees for drilling rigs totaling $18.2 million. These amounts are included in the other operating expense line item on
the accompanying statements of operations.
Contingencies
The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both
probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not
expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.
Note 7 – Compensation Plans
Equity Incentive Compensation Plan
There are several components to the Company’s Equity Incentive Compensation Plan (“Equity Plan”) that are described in this section. Various types of
equity awards have been granted by the Company in different periods.
As of December 31, 2019, approximately 4.4 million shares of common stock were available for grant under the Equity Plan. The issuance of a direct
share benefit, such as a share of common stock, a stock option, a restricted share, an RSU, or a PSU, counts as one share against the number of shares
available to be granted under the Equity Plan. Each PSU has the potential to count as two shares against the number of shares available to be granted under
the Equity Plan based on the final performance multiplier.
Performance Share Units
The Company grants PSUs to eligible employees as part of its Equity Plan. The number of shares of the Company’s common stock issued to settle
PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three-year performance
period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Equity Plan. Employees who are
retirement eligible at the time a PSU award was granted, vest in each portion of that award equally in six-month increments over a three-year period beginning at
grant date. Retirement eligible employees must stay with the Company through the entire six-month vesting period to receive that increment of vesting and any
non-vested portions of a PSU award will be forfeited when the employee leaves the Company.
The fair value of PSUs is measured at the grant date with a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). A
stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which
means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company
cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic
simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the
path the stock price may take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method,
specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation
include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a
three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers.
For PSUs granted in 2017, which the Company has determined to be equity awards, the settlement criteria include a combination of the Company’s
Total Shareholder Return (“TSR”) on an absolute basis, and the Company’s TSR relative to the TSR of certain peer companies over the associated three-year
performance period. The fair value of the PSUs granted in 2017 was measured on the grant date using the GBM Model. As these awards depend entirely on
market-based settlement criteria, the associated compensation expense is recognized on a straight-line basis within general and administrative expense and
exploration expense over the vesting period of the awards.
For PSUs granted in 2018 and 2019, the settlement criteria include a combination of the Company’s TSR relative to the TSR of certain peer companies
and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance
period. In addition to these performance measures, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over
the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the
number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair value of the PSUs
granted in 2018 and 2019 was measured on the applicable grant dates using the GBM Model, with the assumption that the associated CRTCI performance
condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs granted in 2018 and 2019 is
recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. As these awards depend on a
combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the
number of units expected to vest increases or decreases based on the Company’s expected CRTCI performance relative to the applicable peer companies.
85
The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total
compensation expense recorded for PSUs was $10.9 million, $10.3 million, and $9.7 million for the years ended December 31, 2019, 2018, and 2017,
respectively. As of December 31, 2019, there was $15.9 million of total unrecognized expense related to PSUs, which is being amortized through 2022.
A summary of the status and activity of non-vested PSUs is presented in the following table:
For the Years Ended December 31,
2019
2018
2017
Non-vested at beginning of
year
Granted
Vested
Forfeited
PSUs (1)
1,711,259
793,125
(346,021)
(135,778)
Non-vested at end of year
2,022,585
Weighted-
Average
Grant-Date
Fair Value
Weighted-
Average
Grant-Date
Fair Value
Weighted-
Average
Grant-Date
Fair Value
PSUs (1)
PSUs (1)
$
$
$
$
$
20.68
1,533,491
12.80
26.32
16.98
572,924
(233,102)
(162,054)
16.87
1,711,259
$
$
$
$
$
22.97
24.45
44.25
21.79
828,923 $
977,731 $
(94,338) $
(178,825) $
20.68
1,533,491 $
43.25
15.86
85.85
44.99
22.97
____________________________________________
(1) The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance
multiplier, which ranges from zero to two.
The fair value of the PSUs granted in 2019, 2018, and 2017 was $10.2 million, $14.0 million, and $15.5 million, respectively.
During the years ended December 31, 2019, 2018, and 2017, PSUs that were granted in 2016, 2015, and 2014, respectively did not satisfy the
minimum performance requirements. This resulted in a multiplier of zero times and therefore no shares of common stock were issued upon settlement.
The total fair value of PSUs that vested during the years ended December 31, 2019, 2018, and 2017 was $9.1 million, $10.3 million, and $8.1 million,
respectively.
Employee Restricted Stock Units
The Company grants RSUs to eligible persons as part of its Equity Plan. Each RSU represents a right to receive one share of the Company’s common
stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest one-third of the total grant on each anniversary date of the
grant over a three-year vesting period or upon other triggering events as set forth in the Equity Plan. Employees who are retirement eligible at the time an RSU
award is granted, vest in each portion of that award equally in six-month increments over a three-year period beginning at grant date. Retirement eligible
employees must stay with the Company through the entire six-month vesting period to receive that increment of vesting and any non-vested portions of an RSU
award will be forfeited when the employee leaves the Company.
The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The
fair value of an RSU is equal to the closing price of the Company’s common stock on the day of the grant. Compensation expense for RSUs is recognized within
general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for
employee RSUs for the years ended December 31, 2019, 2018, and 2017, was $11.1 million, $10.8 million, and $10.3 million, respectively. As of December 31,
2019, there was $16.9 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2022.
86
A summary of the status and activity of non-vested RSUs granted to employees is presented in the following table:
For the Years Ended December 31,
2019
2018
2017
Weighted-
Average
Grant-Date
Fair Value
21.50
12.36
21.94
18.16
16.01
RSUs
1,243,163 $
978,932 $
(466,535) $
(223,429) $
1,532,131 $
Weighted-
Average
Grant-Date
Fair Value
20.25
25.77
24.30
17.26
21.50
RSUs
1,244,262 $
583,552 $
(407,529) $
(177,122) $
1,243,163 $
Weighted-
Average
Grant-Date
Fair Value
37.39
16.64
43.99
26.38
20.25
RSUs
604,116 $
1,020,780 $
(246,025) $
(134,609) $
1,244,262 $
Non-vested at beginning of
year
Granted
Vested
Forfeited
Non-vested at end of year
The fair value of RSUs granted to eligible employees in 2019, 2018, and 2017 was $12.1 million, $15.0 million, and $17.0 million, respectively.
A summary of the shares of common stock issued to settle employee RSUs is presented in the table below:
Shares of common stock issued to settle RSUs (1)
Less: shares of common stock withheld for income and payroll taxes
Net shares of common stock issued
____________________________________________
For the Years Ended December 31,
2019
2018
2017
466,535
(132,136)
334,399
407,529
(115,784)
291,745
246,025
(74,747)
171,278
(1) During the years ended December 31, 2019, 2018, and 2017, the Company issued shares of common stock to settle RSUs that related to awards granted
in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll
tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.
The total fair value of employee RSUs that vested during the years ended December 31, 2019, 2018, and 2017 was $10.2 million, $9.9 million, and
$10.8 million, respectively.
Director Shares
In 2019, 2018, and 2017, the Company issued 96,719, 63,741, and 71,573 shares, respectively, of its common stock to its non-employee directors
under the Equity Plan. In 2017, the Company issued 8,794 RSUs to a non-employee director. For the years ended December 31, 2019, 2018, and 2017, the
Company recorded $1.2 million, $1.7 million, and $1.6 million, respectively, of compensation expense related to director shares and RSUs issued.
All shares issued to non-employee directors fully vest on December 31 of the year granted. The RSUs issued to a non-employee director in 2017 fully
vested on December 31, 2017, and will settle upon the earlier to occur of May 25, 2027, or the director resigning from the Board of Directors.
Employee Stock Purchase Plan
Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through
payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The
purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is
intended to qualify under Section 423 of the Internal Revenue Code (the “IRC”). The Company had approximately 1.3 million shares of its common stock
available for issuance under the ESPP as of December 31, 2019. There were 314,868, 199,464, and 186,665 shares issued under the ESPP in 2019, 2018, and
2017, respectively. Total proceeds to the Company for the issuance of these shares were $3.2 million for each of the years ended December 31, 2019, and
2018, respectively, and $2.6 million for the year ended December 31, 2017.
The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model. Expected volatility is calculated based on
the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a
six-month vesting period.
87
The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions:
Risk free interest rate
Dividend yield
Volatility factor of the expected market
price of the Company’s common stock
Expected life (in years)
For the Years Ended December 31,
2019
2018
2017
2.3%
0.7%
56.6%
0.5
1.8%
0.4%
55.9%
0.5
0.9%
0.5%
62.5%
0.5
The Company expensed $1.1 million for each of the years ended December 31, 2019, and 2018, respectively, and $1.0 million for the year ended
December 31, 2017, based on the estimated fair value of the ESPP grants.
401(k) Plan
The Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k)
Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. For
employees hired before December 31, 2014, the Company matches 100 percent of each employee’s contribution in cash on a dollar for dollar basis, up to six
percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches 150 percent of
contributions made by employees hired after December 31, 2014, up to six percent of the employee’s base salary and performance bonus in lieu of pension plan
benefits, and may make additional contributions at its discretion. Please refer to Note 8 – Pension Benefits for additional discussion of pension benefits. The
Company’s matching contributions to the 401(k) Plan were $5.1 million, $4.9 million, and $4.5 million for the years ended December 31, 2019, 2018, and 2017,
respectively.
88
Note 8 – Pension Benefits
The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began
employment with the Company prior to January 1, 2016 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan
covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company
froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen will
continue to earn benefits.
Obligations and Funded Status for the Pension Plans
The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the
Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other
comprehensive income (loss), net of tax, line item in the accompanying statements of comprehensive income (loss). The projected benefit obligation is the
actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future
salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary
increases. The Company’s measurement date for plan assets and obligations is December 31.
For the Years Ended December 31,
2019
2018
(in thousands)
Change in benefit obligation:
Projected benefit obligation at beginning of year
$
66,086 $
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Projected benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return (loss) on plan assets
Employer contribution
Benefits paid
Fair value of plan assets at end of year
5,582
2,791
2,035
(5,651)
70,843
30,100
3,985
7,200
(5,651)
35,634
Funded status at end of year
$
(35,209) $
71,937
6,730
2,622
(7,155)
(8,048)
66,086
30,978
(964)
8,134
(8,048)
30,100
(35,986)
The Company’s underfunded status for the Pension Plans as of December 31, 2019, and 2018, was $35.2 million and $36.0 million, respectively, and is
recognized in the accompanying balance sheets within the other noncurrent liabilities line item. There are no plan assets in the Nonqualified Pension Plan.
Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans
Projected benefit obligation
Accumulated benefit obligation
Less: fair value of plan assets
Underfunded accumulated benefit obligation
As of December 31,
2019
2018
(in thousands)
70,843 $
66,086
60,877 $
(35,634)
25,243 $
52,368
(30,100)
22,268
$
$
$
Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest
cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan
assets that recognizes changes in fair value over a five-year period. This practice is
89
intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets
and expected returns based on long-term rate of return assumptions. Amortization of the unrecognized net gain or loss resulting from actual experience different
from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of
net periodic benefit cost for the year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected
benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of
participating employees expected to receive benefits under the plan.
The pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in the accumulated other comprehensive loss line item
within the accompanying balance sheets as of December 31, 2019, and 2018, were as follows:
Unrecognized actuarial losses
Unrecognized prior service costs
Accumulated other comprehensive loss
As of December 31,
2019
2018
(in thousands)
$
$
14,406 $
31
14,437 $
15,741
48
15,789
The pension liability adjustments recognized in other comprehensive income (loss) during 2019, 2018, and 2017, were as follows:
Net actuarial gain (loss)
Amortization of prior service cost
Amortization of net actuarial loss
Settlements
Total pension liability adjustment, pre-tax
Tax expense
Cumulative effect of accounting change (1)
Total pension liability adjustment, net
$
$
For the Years Ended December 31,
2019
2018
2017
(in thousands)
377 $
4,329 $
17
958
—
1,352
(291)
—
18
1,327
—
5,674
(4,265)
2,969
1,061 $
4,378 $
(2,995)
17
1,297
3,009
1,328
(561)
—
767
_________________________________________
(1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional
information.
Components of Net Periodic Benefit Cost for the Pension Plans
Components of net periodic benefit cost:
Service cost
Interest cost
Expected return on plan assets that reduces
periodic pension benefit cost
Amortization of prior service cost
Amortization of net actuarial loss
Settlements
Net periodic benefit cost
$
$
For the Years Ended December 31,
2019
2018
2017
(in thousands)
5,582 $
2,791
(1,574)
17
958
—
6,730 $
2,622
(1,862)
18
1,327
—
7,774 $
8,835 $
6,638
2,689
(2,244)
17
1,297
3,009
11,406
90
Pension Plan Assumptions
The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows:
Projected benefit obligation:
Discount rate
Rate of compensation increase
As of December 31,
2019
3.6%
4.5%
2018
4.4%
6.2%
The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows:
Net periodic benefit cost:
Discount rate
Expected return on plan assets (1)
For the Years Ended December 31,
2019
4.4%
5.0%
2018
3.8%
5.5%
2017
4.2%
6.5%
Rate of compensation increase
____________________________________________
(1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan.
6.2%
6.2%
6.2%
The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a
manner necessary to meet the future benefit obligation of the Pension Plans. The policy prohibits the direct investment of plan assets in the Company’s
securities. The Qualified Pension Plan’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term
perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification,
assessment of risk, and targeting the optimal expected returns for given levels of risk are applied.
The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The
investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities
having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to
maintain the target allocations.
The weighted-average asset allocation of the Qualified Pension Plan is as follows:
Asset Category
Equity securities
Fixed income securities
Other securities
Total
Target
2020
As of December 31,
2019
2018
35.0%
40.0%
25.0%
36.9%
38.1%
25.0%
100.0%
100.0%
31.8%
41.3%
26.9%
100.0%
There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in the plan. An expected return on plan assets of 5.0
percent, 5.5 percent, and 6.5 percent was used to calculate the Company’s net periodic pension cost under the Qualified Pension Plan for the years ended
December 31, 2019, 2018, and 2017 respectively. The expected long-term rate of return assumption of the Qualified Pension Plan is based upon the target
asset allocation and is determined using forward-looking assumptions in the context of historical returns and volatilities for each asset class, as well as
correlations among asset classes. The Company evaluates the expected rate of return on plan assets assumption on an annual basis.
91
Pension Plan Assets
The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2019, and 2018, utilizing the fair value hierarchy discussed in Note
11 – Fair Value Measurements are as follows:
Actual Asset
Allocation (1)
Total
Level 1 Inputs Level 2 Inputs Level 3 Inputs
Fair Value Measurements Using:
(in thousands)
As of December 31, 2019
Equity securities:
Domestic (2)
International (3)
Total equity securities
Fixed income securities:
Core fixed income (4)
Floating rate corporate loans (5)
Total fixed income securities
Other securities:
Real estate (6)
Collective investment trusts (7)
Hedge fund (8)
Total other securities
Total investments
As of December 31, 2018
Equity securities:
Domestic (2)
International (3)
Total equity securities
Fixed income securities:
Core fixed income (4)
Floating rate corporate loans (5)
Total fixed income securities
Other securities:
Real estate (6)
Collective investment trusts (7)
Hedge fund (8)
Total other securities
Total investments
17.3% $
6,176 $
4,130 $
2,046 $
19.6%
36.9%
31.4%
6.7%
38.1%
5.4%
3.3%
16.3%
25.0%
6,958
13,134
11,199
2,379
13,578
1,929
1,168
5,825
8,922
6,958
11,088
11,199
2,379
13,578
—
—
2,006
2,006
—
2,046
—
—
—
—
1,168
—
1,168
100.0% $
35,634 $
26,672 $
3,214 $
15.4% $
4,639 $
3,197 $
1,442 $
16.4%
31.8%
34.4%
6.9%
41.3%
6.0%
3.1%
17.8%
26.9%
4,941
9,580
10,342
2,078
12,420
1,820
934
5,346
8,100
3,642
6,839
10,342
2,078
12,420
—
—
—
—
1,299
2,741
—
—
—
—
934
1,659
2,593
100.0% $
30,100 $
19,259 $
5,334 $
—
—
—
—
—
—
1,929
—
3,819
5,748
5,748
—
—
—
—
—
—
1,820
—
3,687
5,507
5,507
____________________________________________
(1) Percentages may not calculate due to rounding.
(2) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon
demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying
investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective
investment funds.
International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets,
commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at
attractive valuations.
(3)
(4) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment
(5)
results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index.
Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of
interest rates.
92
(6) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate
entails a long-term time horizon, periodic valuations, and potentially low liquidity.
(7) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as
provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments
held by the fund less its liabilities.
(8) The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that
invests both long and short using a variety of investment strategies.
Included below is a summary of the changes in Level 3 plan assets (in thousands):
Balance at January 1, 2018
Purchases
Realized gain on assets
Unrealized gain on assets
Disposition
Balance at December 31, 2018
Purchases
Realized gain on assets
Unrealized gain on assets
Disposition
Balance at December 31, 2019
Contributions
$
$
$
5,209
—
191
152
(45)
5,507
—
190
51
—
5,748
The Company contributed $7.2 million, $8.1 million, and $7.0 million to the Pension Plans for the years ended December 31, 2019, 2018, and 2017,
respectively. The Company expects to make a $5.6 million contribution to the Pension Plans in 2020.
Benefit Payments
The Pension Plans made actual benefit payments of $5.7 million, $8.0 million, and $10.8 million in the years ended December 31, 2019, 2018, and
2017, respectively. Expected benefit payments over the next 10 years are as follows:
Years Ending December 31,
(in thousands)
2020
2021
2022
2023
2024
2025 through 2029
Note 9 - Earnings Per Share
$
$
$
$
$
$
7,609
3,914
4,022
6,308
4,939
25,065
Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-
average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or
loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive
securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible
Notes are convertible, which are measured using the treasury stock method.
PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the
Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares
related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end
of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading
Performance Share Units.
On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021. Upon conversion, the
Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common
stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal
amount of the Senior Convertible Notes in cash and the excess
93
conversion value in shares. However, the Company has not made an irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in
any manner allowed under the indenture as business circumstances warrant. Shares of the Company’s common stock traded at an average closing price below
the $40.50 conversion price for the years ended December 31, 2019, 2018, and 2017, therefore, the Senior Convertible Notes had no dilutive impact. In
connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would
effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions will always be anti-dilutive and therefore will never be
reflected in diluted net income or loss per share. Please refer to Note 5 – Long-Term Debt for additional discussion.
When the Company recognizes a net loss from continuing operations, as was the case for the years ended December 31, 2019, and 2017, all
potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share.
The following table details the weighted-average anti-dilutive securities for the years presented:
For the Years Ended December 31,
2019
2018
2017
(in thousands)
Anti-dilutive
684
—
264
The following table sets forth the calculations of basic and diluted net income (loss) per common share:
For the Years Ended December 31,
2019
2018
2017
(in thousands, except per share data)
Net income (loss)
$
(187,001) $
508,407 $
(160,843)
Basic weighted-average common shares outstanding
Dilutive effect of non-vested RSUs and contingent PSUs
Diluted weighted-average common shares outstanding
112,544
—
112,544
111,912
1,590
113,502
111,428
—
111,428
Basic net income (loss) per common share
Diluted net income (loss) per common share
$
$
(1.66) $
(1.66) $
4.54 $
4.48 $
(1.44)
(1.44)
Note 10 – Derivative Financial Instruments
Summary of Oil, Gas, and NGL Derivative Contracts in Place
The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in
commodity prices and the associated impact on cash flows. As of December 31, 2019, all derivative counterparties were members of the Company’s Credit
Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap
and collar arrangements for oil and gas production, and swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon
published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed
upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives
the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the
agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor
and ceiling prices.
The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry
benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts
with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland
prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a
portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices.
As of December 31, 2019, the Company had commodity derivative contracts outstanding through the fourth quarter of 2022, as summarized in the
tables below.
94
Oil Swaps
Contract Period
NYMEX WTI Volumes
Weighted-Average
Contract Price
(MBbl)
(per Bbl)
First quarter 2020
Second quarter 2020
Third quarter 2020
Fourth quarter 2020
2021
Total
Oil Collars
2,486 $
2,838 $
3,361 $
3,937 $
667 $
13,289
59.65
58.81
56.43
56.94
56.00
Contract Period
NYMEX WTI Volumes
Weighted-Average
Floor Price
Weighted-Average
Ceiling Price
(MBbl)
(per Bbl)
(per Bbl)
First quarter 2020
Second quarter 2020
Third quarter 2020
Fourth quarter 2020
2021
Total
Oil Basis Swaps
Contract Period
First quarter 2020
Second quarter 2020
Third quarter 2020
Fourth quarter 2020
2021
2022
Total
2,267 $
1,881 $
1,252 $
610 $
329 $
6,339
55.00 $
55.00 $
55.00 $
55.00 $
55.00 $
63.91
62.17
62.90
61.90
56.70
WTI Midland-NYMEX
WTI Volumes
Weighted-Average
Contract Price (1)
NYMEX WTI-ICE Brent
Volumes
Weighted-Average
Contract Price (2)
(MBbl)
(per Bbl)
(MBbl)
(per Bbl)
4,193 $
3,495 $
3,325 $
3,261 $
5,954 $
— $
20,228
(0.68)
(0.68)
(0.74)
(0.73)
0.59
—
— $
910 $
920 $
920 $
3,650 $
3,650 $
10,050
—
(8.06)
(8.01)
(8.01)
(7.86)
(7.78)
____________________________________________
(1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
(2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
Gas Swaps
Contract Period
IF HSC Volumes
Weighted-Average
Contract Price
WAHA Volumes
Weighted-Average
Contract Price
(BBtu)
(per MMBtu)
(BBtu)
(per MMBtu)
First quarter 2020
Second quarter 2020
Third quarter 2020
Fourth quarter 2020
2021
Total (1)
9,123 $
4,160 $
4,493 $
3,722 $
— $
21,498
2.98
2.20
2.41
2.36
—
3,099 $
3,196 $
3,268 $
3,419 $
4,224 $
17,206
1.93
0.56
1.03
1.17
1.51
____________________________________________
(1) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”),
and Platt’s Gas Daily West Texas (“GD WAHA”). As of December 31, 2019, WAHA volumes were comprised of 92 percent IF WAHA and eight percent GD
WAHA.
95
NGL Swaps
Contract Period
First quarter 2020
Second quarter 2020
Third quarter 2020
Fourth quarter 2020
Total
OPIS Ethane Purity Mont Belvieu
OPIS Propane Mont Belvieu Non-TET
Volumes
(MBbl)
Weighted-Average
Contract Price
(per Bbl)
Volumes
(MBbl)
Weighted-Average
Contract Price
(per Bbl)
447 $
264 $
— $
— $
711
11.53
11.13
—
—
382 $
382 $
409 $
466 $
1,639
22.64
22.34
22.33
22.29
Commodity Derivative Contracts Entered Into Subsequent to December 31, 2019
Subsequent to December 31, 2019, the Company entered into the following commodity derivative contracts:
•
•
fixed price NYMEX WTI oil swap contracts for the fourth quarter of 2020 through January 2021 for a total of 0.6 MMBbl of oil production at a
weighted-average contract price of $57.82 per Bbl; and
fixed price WTI Midland-NYMEX WTI oil basis swap contracts for the second quarter of 2020 through the fourth quarter of 2022 for a total of
16.3 MMBbl of oil production at a weighted-average contract price of $1.14 per Bbl.
Derivative Assets and Liabilities Fair Value
The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and
liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its derivative
commodity contracts as hedging instruments. The fair value of the commodity derivative contracts at December 31, 2019, and 2018, was a net asset of $21.5
million and $158.3 million, respectively.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:
Derivative assets:
Current assets
Noncurrent assets
Total derivative assets
Derivative liabilities:
Current liabilities
Noncurrent liabilities
Total derivative liabilities
Offsetting of Derivative Assets and Liabilities
As of December 31, 2019 As of December 31, 2018
(in thousands)
$
$
$
$
55,184 $
20,624
75,808 $
50,846 $
3,444
54,290 $
175,130
58,499
233,629
62,853
12,496
75,349
As of December 31, 2019, and 2018, all derivative instruments held by the Company were subject to master netting arrangements with various financial
institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the
election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an
early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The
Company’s accounting policy is to not offset these positions in its accompanying balance sheets.
96
The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential
effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:
Derivative Assets
Derivative Liabilities
As of December 31,
As of December 31,
2019
2018
2019
2018
(in thousands)
Gross amounts presented in the accompanying balance
sheets
$
75,808 $
233,629 $
(54,290) $
(75,349)
Amounts not offset in the accompanying balance sheets
(35,075)
(56,041)
35,075
56,041
Net amounts
$
40,733 $
177,588 $
(19,215) $
(19,308)
The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring such
amounts in accumulated other comprehensive income (loss). The Company had no derivatives designated as hedging instruments for the years ended
December 31, 2019, 2018, and 2017. Please refer to Note 11 – Fair Value Measurements for more information regarding the Company’s derivative instruments,
including its valuation techniques.
The following table summarizes the commodity components of the net derivative (gain) loss line item presented in the accompanying statements of
operations:
For the Years Ended December 31,
2019
2018
2017
(in thousands)
$
$
$
$
19,685 $
(23,008)
(35,899)
68,860 $
13,029
53,914
(39,222) $
135,803 $
172,055 $
(192,002) $
(41,205)
(33,311)
35,411
(5,241)
97,539 $
(161,832) $
31,176
(87,857)
35,447
(21,234)
71,502
(76,315)
31,227
26,414
Derivative settlement (gain) loss:
Oil contracts
Gas contracts
NGL contracts
Total derivative settlement (gain) loss
Net derivative (gain) loss:
Oil contracts
Gas contracts
NGL contracts
Total net derivative (gain) loss
Credit Related Contingent Features
As of December 31, 2019, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit
Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent
of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral
securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.
Note 11 – Fair Value Measurements
The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value
as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the
measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence
of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
•
•
•
Level 1 – quoted prices in active markets for identical assets or liabilities
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not
active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3 – significant inputs to the valuation model are unobservable
97
Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on the Company’s policies for determining fair value for
the categories discussed below.
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where
they are classified within the fair value hierarchy as of December 31, 2019:
Assets:
Derivatives (1)
Liabilities:
Derivatives (1)
Level 1
Level 2
Level 3
(in thousands)
$
$
— $
— $
75,808 $
54,290 $
—
—
____________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where
they are classified within the fair value hierarchy as of December 31, 2018:
Assets:
Derivatives (1)
Liabilities:
Derivatives (1)
Level 1
Level 2
Level 3
(in thousands)
$
$
— $
233,629 $
— $
75,349 $
—
—
____________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is
significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general
classification of such instruments pursuant to the above fair value hierarchy.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data.
The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit
rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors
result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity
derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity
derivative markets are highly active.
Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment
may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of
its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to
a more stable counterparty.
Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position.
This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any
letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk,
taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date.
The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair
values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance
and other marketplace participants, the Company recognizes that third-parties may use different methodologies or assumptions to determine the fair value of
certain financial instruments that could result in a different estimate of fair value at the reporting date.
Refer to Note 10 – Derivative Financial Instruments for more information regarding the Company’s derivative instruments.
98
Oil and Gas Properties
Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that
associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique to measure the fair value of proved
properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s
management.
Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an
indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes
into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated
reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.
There were no proved or unproved oil and gas properties recorded at fair value on the accompanying balance sheets as of December 31, 2019, or
December 31, 2018.
The following table presents impairment of proved properties expense and abandonment and impairment of unproved properties expense recorded for
the periods presented:
Impairment of proved properties
Abandonment and impairment of unproved properties
Impairment of oil and gas properties
$
$
For the Years Ended December 31,
2019
2018
2017
(in millions)
— $
33.8
33.8 $
— $
49.9
49.9 $
3.8
12.3
16.1
Abandonment and impairment of unproved properties expense recorded during the years ended December 31, 2019, 2018, and 2017 primarily related
to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other
inherent acreage risks.
Long-Term Debt
The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted
secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2019, or 2018, as they
were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 – Long-Term Debt for additional
discussion.
As of December 31,
2019
2018
Principal Amount
Fair Value
Principal Amount
Fair Value
6.125% Senior Notes due 2022
5.0% Senior Notes due 2024
5.625% Senior Notes due 2025
6.75% Senior Notes due 2026
6.625% Senior Notes due 2027
$
$
$
$
$
1.50% Senior Convertible Notes due 2021 $
476,796 $
500,000 $
500,000 $
500,000 $
500,000 $
172,500 $
(in thousands)
481,564 $
479,815 $
475,835 $
494,860 $
493,750 $
164,430 $
476,796 $
500,000 $
500,000 $
500,000 $
500,000 $
172,500 $
452,336
439,265
436,460
448,305
442,500
158,614
The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market
rates.
99
Note 12 - Leases
Effective January 1, 2019, the Company adopted Topic 842, which requires lessees to recognize operating and finance leases with terms greater than
12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition
methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of December 31, 2019,
the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are
included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any
agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s
policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the
recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or
classification of costs incurred for those agreements considered to be leases.
As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability
represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset
available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The
initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to
purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and
corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance.
The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined
by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to
determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease,
which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included
or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the
definition of a lease under Topic 842 include:
•
•
Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental
borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at
lease inception.
Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when
recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the
arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain
financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based
on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably
certain to be exercised by the Company.
Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements,
vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases
with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately six years. The weighted-average
lease term remaining for these leases is approximately three years. Certain leases also contain optional extension periods that allow for terms to be extended for
up to an additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one
year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement.
Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the
underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are
considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to Note 1 – Summary of
Significant Accounting Policies for additional information on its accounting policies for oil and gas development and producing activities. When calculating the
Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments
made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments, which for
the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs.
For the year ended December 31, 2019, total costs related to operating leases, including short-term leases, and variable lease payments made for
leases with initial lease terms greater than 12 months, were $442.9 million. This total does not reflect amounts that may be reimbursed by other third parties in
the normal course of business, such as non-operating working interest owners.
100
Components of the Company’s total lease cost, whether capitalized or expensed, for the year ended December 31, 2019, were as follows:
For the Year Ended December
31, 2019
Operating lease cost
$
Short-term lease cost (1)
Variable lease cost (2)
35,570
301,373
106,006
Total lease cost (3)
____________________________________________
(1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This
442,949
$
amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is
expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term
agreements.
(2) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability
for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream
agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased
office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating
under long-term agreements.
(3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the
nature and use of the underlying ROU asset.
Other information related to the Company’s leases for the year ended December 31, 2019, was as follows:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
Investing cash flows from operating leases
Right-of-use assets obtained in exchange for new operating lease liabilities
For the Year Ended December
31, 2019
(in thousands)
$
$
$
12,074
24,129
25,360
Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2019, were as follows:
2020
2021
2022
2023
2024
Thereafter
Total Lease payments
Less: Imputed interest (1)
Total
As of December 31, 2019
(in thousands)
$
$
$
21,102
12,600
5,749
3,602
2,081
1,639
46,773
(4,447)
42,326
____________________________________________
(1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 6.6 percent.
101
Amounts recorded on the accompanying balance sheets for operating leases as of December 31, 2019, were as follows:
As of December 31, 2019
(in thousands)
Other noncurrent assets
Other current liabilities
Other noncurrent liabilities
$
$
$
39,717
19,189
23,137
As of December 31, 2019, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in
the future.
Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following accruals:
Oil, gas, and NGL production revenue
Amounts due from joint interest owners
State severance tax refunds
Derivative settlements
Other
Total accounts receivable
$
$
As of December 31,
2019
2018
(in thousands)
146,308 $
22,681
4,069
6,868
4,806
184,732 $
Accounts payable and accrued expenses are comprised of the following accruals:
Drilling and lease operating cost accruals
$
Trade accounts payable
Revenue and severance tax payable
Property taxes
Compensation
Derivative settlements
Interest
Other
As of December 31,
2019
2018
(in thousands)
96,925 $
52,094
109,847
24,535
41,540
5,851
44,175
27,041
107,230
31,497
4,415
9,475
14,919
167,536
139,711
56,047
94,806
18,694
31,486
1,287
40,840
20,328
Total accounts payable and accrued expenses
$
402,008 $
403,199
102
Note 14 – Asset Retirement Obligations
Please refer to Asset Retirement Obligations in Note 1 – Summary of Significant Accounting Policies for a discussion of the initial and subsequent
measurements of asset retirement obligation liabilities and the significant assumptions used in the estimates.
A reconciliation of the Company’s total asset retirement obligation liability is as follows:
Beginning asset retirement obligations
Liabilities incurred (1)
Liabilities settled (2)
Accretion expense
Revision to estimated cash flows
Ending asset retirement obligations (3)
____________________________________________
As of December 31,
2019
2018
(in thousands)
94,194 $
3,927
(4,105)
4,016
(11,186)
86,846 $
114,470
4,054
(33,024)
4,438
4,256
94,194
$
$
(1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.
(2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.
(3) Balances as of December 31, 2019, and 2018, included $2.7 million and $2.3 million, respectively, related to the Company’s current asset retirement
obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets.
Note 15 – Suspended Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2019, 2018, and 2017. The table does not include amounts that
were capitalized and either subsequently expensed or reclassified to producing well costs in the same year:
For the Years Ended December 31,
2019
2018
2017
(in thousands)
Beginning balance
$
11,197 $
49,446 $
19,846
Additions to capitalized exploratory well costs pending the
determination of proved reserves
Divestitures
Reclassifications to wells, facilities, and equipment based on the
determination of proved reserves
Capitalized exploratory well costs charged to expense
11,925
—
11,197
(109)
(11,197)
(49,337)
—
—
Ending balance
$
11,925 $
11,197 $
49,446
—
(19,846)
—
49,446
As of December 31, 2019, there were no exploratory well costs that were capitalized for more than one year.
103
Supplemental Oil and Gas Information (unaudited)
Costs Incurred in Oil and Gas Producing Activities
Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
Development costs (1)
Exploration costs
Acquisitions
Proved properties
Unproved properties (2)
For the Years Ended December 31,
2019
2018
2017
(in thousands)
913,959 $
114,957
1,147,574 $
184,930
(310)
11,633
1,312
55,688
675,523
271,502
1,602
91,420
1,040,239 $
1,389,504 $
1,040,047
$
$
Total, including asset retirement obligations (3)(4)
____________________________________________
(1)
(2)
Includes facility costs of $28.3 million, $72.6 million, and $43.8 million for the years ended December 31, 2019, 2018, and 2017, respectively.
Includes amounts related to leasing activity and acquiring surface rights outside of acquisitions of proved and unproved properties totaling $8.7 million,
$23.4 million, and $12.8 million for the years ended December 31, 2019, 2018, and 2017, respectively.
Includes amounts relating to estimated asset retirement obligations of $(9.9) million, $7.1 million, and $13.6 million for the years ended December 31, 2019,
2018, and 2017, respectively.
Includes capitalized interest of $18.5 million, $20.6 million, and $12.6 million for the years ended December 31, 2019, 2018, and 2017, respectively.
(3)
(4)
Oil and Gas Reserve Quantities
The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and
SEC rules for oil and gas reporting of reserve estimation and disclosure.
Proved reserves are the estimated quantities of oil, gas, and NGLs 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. Existing economic conditions include prices and
costs at which economic producibility from a reservoir is to be determined, and the price to be used is 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. All of the Company’s estimated proved
reserves are located in the United States.
104
Revisions of
previous estimate
Discoveries and
extensions
Infill reserves in
an existing
proved field
Sales of reserves
(4)
Purchases of
minerals in place
(4)
Production
End of year
The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended
December 31, 2019. The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the Company’s total calculated proved
reserve PV-10 for each year presented. 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 producing oil and gas properties. Accordingly, these estimates are expected to change
as future information becomes available.
For the Years Ended December 31,
2019 (1)
2018 (2)
2017 (3)
Oil
Gas
NGLs
Oil
Gas
NGLs
Oil
Gas
NGLs
(MMBbl)
(Bcf)
(MMBbl)
(MMBbl)
(Bcf)
(MMBbl)
(MMBbl)
(Bcf)
(MMBbl)
Total proved reserves:
Beginning of year
175.7 1,321.8
107.4
158.2 1,280.1
96.5
104.9 1,111.1
105.7
(19.2)
(212.5)
(40.0)
(24.0)
(219.5)
(8.0)
1.0
63.8
5.4
28.8
2.9
9.3
20.3
0.5
11.5
21.9
4.9
—
41.8
190.2
11.8
80.4
391.5
29.0
79.0
347.4
22.9
(0.2)
(0.7)
—
(29.6)
(48.1)
(2.7)
(25.3)
(143.8)
(26.7)
2.5
5.4
(21.9)
(109.8)
184.1 1,223.2
Proved developed reserves:
Beginning of year
End of year
68.2
85.0
699.1
712.1
Proved undeveloped reserves:
Beginning of year
107.6
622.7
End of year
____________________________________________
Note: Amounts may not calculate due to rounding.
511.1
99.1
—
(8.1)
74.0
60.1
43.4
47.2
30.6
0.2
0.7
(18.8)
(103.2)
—
(7.9)
0.8
2.7
(13.7)
(123.0)
175.7 1,321.8
107.4
158.2 1,280.1
58.6
642.9
68.2
699.1
99.6
637.2
107.6
622.7
49.0
60.1
47.6
47.2
48.5
609.1
58.6
642.9
56.4
99.6
502.0
637.2
—
(10.3)
96.5
58.6
49.0
47.1
47.6
(1) For the year ended December 31, 2019, the Company added 98.4 MMBOE from its drilling program and further development plan optimization. These
additions were offset by net downward revisions of 94.7 MMBOE, which were primarily driven by declining commodity prices during 2019. Please refer to
Areas of Operation in Part I, Items 1 and 2 of this report, and to Oil and Gas Reserve Quantities in Critical Accounting Policies and Estimates in Part II, Item
7 of this report for additional information.
(2) For the year ended December 31, 2018, the Company added 188.0 MMBOE from its drilling program and through development plan optimization. The
Company divested 40.3 MMBOE during 2018, primarily as a result of the PRB Divestiture, Divide County Divestiture, and Halff East Divestiture. The
Company also had net downward revisions of 68.8 MMBOE, which resulted primarily from changes in development plans in its Eagle Ford shale program.
(3) For the year ended December 31, 2017, the Company added 175.0 MMBOE from its drilling program. The Company divested 76.0 MMBOE during 2017,
including 72.5 MMBOE related to its outside-operated Eagle Ford shale assets.
(4) Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional information.
Standardized Measure of Discounted Future Net Cash Flows
The Company computes a standardized measure of future net cash flows (“Standardized Measure”) and changes therein relating to estimated proved
reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices
and costs, including transportation, quality, and basis differentials, to the year end estimated future reserve quantities. Each property the Company operates is
also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax
rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10
percent annual discount factor.
Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reserves
in place at the end of the period using year end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the
central administrative office attributable to operating activities.
105
The assumptions used to compute the Standardized Measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily
reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve
quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations since these reserve quantity estimates
are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the
Standardized Measure:
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
For the Years Ended December 31,
2019
2018
2017
$
$
$
53.68 $
2.49 $
18.88 $
57.76 $
3.49 $
26.23 $
48.57
3.20
23.33
The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the Standardized
Measure.
Future cash inflows
Future production costs
Future development costs
Future income taxes
Future net cash flows
10 percent annual discount
As of December 31,
2019
2018
2017
(in thousands)
$
14,327,131 $
17,579,432 $
14,035,704
(4,579,119)
(2,108,859)
(579,815)
7,059,338
(2,955,340)
(5,386,264)
(2,679,488)
(1,012,209)
8,501,471
(3,847,088)
(5,594,226)
(2,638,459)
(205,694)
5,597,325
(2,573,183)
Standardized measure of discounted future net cash flows
$
4,103,998 $
4,654,383 $
3,024,142
The principle sources of changes in the Standardized Measure were:
For the Years Ended December 31,
2019
2018
2017
(in thousands)
Standardized Measure, beginning of year
$
4,654,383 $
3,024,142 $
1,152,113
Sales of oil, gas, and NGLs produced, net of production costs
Net changes in prices and production costs
Extensions, discoveries and other including infill reserves in an
existing proved field, net of related costs
Sales of reserves in place
Purchase of reserves in place
Previously estimated development costs incurred during the period
Changes in estimated future development costs
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes
Changes in timing and other
(1,085,041)
(1,539,042)
(1,148,991)
1,010,335
887,254
(2,788)
57,519
736,770
132,825
(398,409)
510,427
191,040
(40,940)
2,218,475
(147,887)
1,818
445,638
(34,871)
(611,168)
305,657
(449,884)
41,119
(745,877)
1,181,447
1,638,734
(226,528)
12,032
121,879
(116,609)
103,916
115,211
(32,426)
(179,750)
Standardized Measure, end of year
$
4,103,998 $
4,654,383 $
3,024,142
106
Quarterly Financial Information (unaudited)
The Company’s quarterly financial information for fiscal years 2019 and 2018 is as follows (in thousands, except per share data):
Year Ended December 31, 2019 (1)
Total operating revenues and other income
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
Basic net income (loss) per common share
Diluted net income (loss) per common share
Dividends declared per common share
Year Ended December 31, 2018 (2)
Total operating revenues and other income
Total operating expenses
Income (loss) from operations
Income (loss) before income taxes
Net income (loss)
Basic net income (loss) per common share
Diluted net income (loss) per common share
Dividends declared per common share
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$
$
$
$
$
$
$
$
$
$
$
$
$
$
340,930 $
407,172 $
390,317 $
526,239
303,005
290,840
(185,309) $
104,167 $
(223,606) $
(177,568) $
(1.58) $
(1.58) $
0.05 $
63,978 $
50,388 $
0.45 $
0.45 $
— $
99,477 $
58,345 $
42,234 $
0.37 $
0.37 $
0.05 $
769,595 $
443,916 $
459,369 $
310,527
387,768
568,013
459,068 $
416,392 $
317,401 $
2.84 $
2.81 $
0.05 $
56,148 $
(108,644) $
16,296 $
(172,671) $
17,197 $
(135,923) $
0.15 $
0.15 $
— $
(1.21) $
(1.21) $
0.05 $
451,686
539,989
(88,303)
(129,761)
(102,055)
(0.90)
(0.90)
—
394,192
(35,573)
429,765
391,760
309,732
2.76
2.73
—
____________________________________________
(1) Results of operations during 2019 were primarily impacted by the following:
a net derivative loss of $177.1 million recorded in the first quarter of 2019,
a net derivative gain of $79.7 million recorded in the second quarter of 2019,
a net derivative gain of $100.9 million recorded in the third quarter of 2019, and
a net derivative loss of $101.0 million recorded in the fourth quarter of 2019.
•
•
•
•
Please refer to Note 10 – Derivative Financial Instruments for greater detail.
(2) For the first quarter of 2018, the Company recorded an estimated $409.2 million net pre-tax gain on divestiture activity related to the PRB Divestiture, which
was partially offset by a $24.1 million write-down on certain assets. During the second quarter of 2018, the Company recorded an estimated $15.7 million
net pre-tax gain on divestiture activity related to the Divide County Divestiture and Halff East Divestiture (please refer to Note 3 – Divestitures, Assets Held
for Sale, and Acquisitions). During the third quarter of 2018, the Company recorded a $26.7 million loss on the early extinguishment of its 2021 Senior
Notes, 2023 Senior Notes, and a portion of its 2022 Senior Notes (please refer to Note 5 – Long-Term Debt). For the first, second, third, and fourth quarters
of 2018, the Company recorded net derivative losses of $7.5 million, $63.7 million, $178.0 million, and a net derivative gain of $411.1 million. Please refer to
Note 10 – Derivative Financial Instruments for greater detail.
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
We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our
SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that
such information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to
allow for timely decisions regarding required disclosure.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well
conceived and operated, can provide only reasonable, not absolute,
107
assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and
the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities
that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented
by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also
is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its
stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may
occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will
be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this
report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief
Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a
reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the fourth quarter of 2019 that have materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
108
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-
15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is 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.
The 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 Company; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets
that have a material effect on the financial statements.
Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined
to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of
compliance with the policies and procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019. In making this
assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated
Framework (2013 framework).
Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of
December 31, 2019.
The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal control over financial
reporting. That report immediately follows this report.
109
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of SM Energy Company and subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited SM Energy Company and subsidiaries’ internal control over financial reporting as of December 31, 2019, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO
criteria). In our opinion, SM Energy Company and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance
sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), stockholders’
equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and our report dated February 20, 2020
expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to
express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the company; (2) 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 company; and (3) 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/ Ernst & Young LLP
Denver, Colorado
February 20, 2020
110
ITEM 9B. OTHER INFORMATION
None.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
PART III
The information required by this Item concerning the Company’s Directors, Executive Officers, and corporate governance is incorporated by reference
to the information provided under the captions “Proposal 1 - Election of Directors,” “Information about Executive Officers,” and “Corporate Governance” in the
Company’s definitive proxy statement for the 2020 annual meeting of stockholders to be filed within 120 days from December 31, 2019.
The information required by this Item concerning compliance with Section 16(a) of the Exchange Act is incorporated by reference to the information
provided under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement for the 2020 annual meeting
of stockholders to be filed within 120 days from December 31, 2019.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information provided under the captions “Executive Compensation” and
“Director Compensation” in the Company’s definitive proxy statement for the 2020 annual meeting of stockholders to be filed within 120 days from December 31,
2019.
111
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the
information provided under the caption “Security Ownership of Certain Beneficial Owners and Management” in the Company’s definitive proxy statement for the
2020 annual meeting of stockholders to be filed within 120 days from December 31, 2019.
Securities Authorized for Issuance Under Equity Compensation Plans. The Company has equity compensation plans under which options and shares
of the Company’s common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of
Directors. The Company’s stockholders have approved these plans. Please refer to Note 7 – Compensation Plans in Part II, Item 8 of this report for further
information about the material terms of the Company’s equity compensation plans. The following table is a summary of the shares of common stock authorized
for issuance under equity compensation plans as of December 31, 2019:
(a)
(b)
(c)
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants,
and rights
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
1,540,925
2,044,882
3,585,807 $
—
—
3,585,807 $
N/A
N/A
—
—
—
—
4,385,709
1,299,003
—
5,684,712
Plan category
Equity compensation plans approved by security holders:
Equity Incentive Compensation Plan (1)
Restricted stock units (2)
Performance share units (2)(3)
Total for Equity Incentive Compensation Plan
Employee Stock Purchase Plan (4)
Equity compensation plans not approved by security holders
Total for all plans
____________________________________________
(1)
In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options,
incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and
members of the Board of Directors of the Company or any affiliate of the Company. The Company’s Board of Directors approved amendments to the Equity
Plan in 2009, 2010, 2013, 2016, and 2018 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The
number of shares of the Company’s common stock underlying awards granted in 2019, 2018, and 2017 under the Equity Plan were 1,868,776, 1,220,217,
and 2,078,878, respectively.
(2) RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per unit fair value, which is presented in order to provide
additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per unit fair value for the outstanding RSUs and
PSUs was $16.04 and $16.89, respectively. Please refer to Note 7 – Compensation Plans in Part II, Item 8 of this report for additional discussion.
(3) The number of awards to be issued assumes a one multiplier. The final number of shares of the Company’s common stock issued upon settlement may
vary depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two.
(4) Under the ESPP, eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible
compensation. The purchase price of the common stock is 85 percent of the lower of the fair market value of the common stock on the first or last day of the
six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to
qualify under Section 423 of the IRC. The number of shares of the Company’s common stock issued in 2019, 2018, and 2017 under the ESPP were
314,868, 199,464, and 186,665, respectively.
112
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the information provided under the captions “Certain Relationships and Related
Transactions” and “Corporate Governance” in the Company’s definitive proxy statement for the 2020 annual meeting of stockholders to be filed within 120 days
from December 31, 2019.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference to the information provided under the captions “Independent Registered Public
Accounting Firm” and “Audit Committee Pre-approval Policy and Procedures” in the Company’s definitive proxy statement for the 2020 annual meeting of
stockholders to be filed within 120 days from December 31, 2019.
113
ITEM 15. EXHIBITS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Consolidated Financial Statements and Financial Statement Schedules:
PART IV
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
63
65
66
67
68
69
70
All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.
(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:
Exhibit
Number Description
2.1
2.2
2.3
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
Membership Interest Purchase Agreement dated January 1, 2017 between SM Energy Company and Venado EF LLC
(filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, and
incorporated herein by reference)
Second Amendment to Membership Interest Purchase Agreement dated March 4, 2017 between SM Energy and Venado
EF L.P. (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, and
incorporated herein by reference)
Purchase and Sale Agreement dated January 8, 2018 by and between SM Energy Company and Converse Energy
Acquisitions, LLC (filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed on January 11, 2018 and
incorporated herein by reference)
Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the
registrant’s Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)
Indenture related to the 5.0% Senior Notes due 2024, dated May 20, 2013, by and between SM Energy Company, as
issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K
filed on May 20, 2013, and incorporated herein by reference)
Indenture related to the 6.125% Senior Notes due 2022, dated November 17, 2014, by and between SM Energy Company,
as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-
K filed on November 18, 2014, and incorporated herein by reference)
Indenture related to senior debt securities of SM Energy Company by and between SM Energy Company and U.S. Bank
National Association, as trustee (filed as Exhibit 4.1 to the registrant’s Registration Statement on Form S-3 filed on May 7,
2015 (Registration No. 333-203936) and incorporated herein by reference)
2025 Notes Supplemental Indenture (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on May 21,
2015, and incorporated herein by reference)
Base Indenture, dated as of May 21, 2015, by and between SM Energy Company and U.S. Bank National Association, as
trustee (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated
herein by reference)
Second Supplemental Indenture, dated August 12, 2016, by and between SM Energy Company and U.S. Bank, National
Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and
incorporated herein by reference)
Third Supplemental Indenture, dated September 12, 2016 by and between SM Energy Company and U.S. Bank National
Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on September 12, 2016,
and incorporated herein by reference)
Fourth Supplemental Indenture, dated as of August 20, 2018, by and between SM Energy Company and U.S. Bank
National Association, as trustee (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed on August 20,
2018, and incorporated herein by reference)
114
4.9
4.10†
4.11*
10.1
10.2
10.3†
10.4***
10.5††
10.6†
10.7+
10.8***
10.9***
Supplemental Indenture, dated as of August 20, 2018, by and between SM Energy Company and U.S. Bank National
Association, as trustee (filed as Exhibit 4.3 to the registrant’s Current Report on Form 8-K filed on August 20, 2018, and
incorporated herein by reference)
SM Energy Company Equity Incentive Compensation Plan, amended and restated effective as of May 22, 2018 (filed as
Annex A in the registrant’s Definitive Proxy Statement on Schedule 14A, filed on April 12, 2018, and incorporated herein by
reference)
Description of Securities
Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement,
Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent,
dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20,
2009, and incorporated herein by reference)
Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed
as Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by
reference)
Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC (filed
as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, and
incorporated herein by reference)
Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the
registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by
reference)
Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit
10.30 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein
by reference)
SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of December 31, 2010 (filed
as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and
incorporated herein by reference)
Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company (filed as
Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated
herein by reference)
Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company and ETC
Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2011, and incorporated herein by reference)
10.10*** Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM Energy Company (filed
as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated
herein by reference)
10.11†
10.12†
10.13†
10.14†
10.15†
10.16†
Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to the registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)
Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as
Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and
incorporated herein by reference)
Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as
Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, and
incorporated herein by reference)
SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to the
registrant’s Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference)
Cash Bonus Plan, As Amended and Restated as of February 1, 2014 (filed as Exhibit 10.41 to the registrant’s Annual
Report on Form 10-K filed for the year ended December 31, 2013, and incorporated herein by reference)
Section 162(m) Cash Bonus Plan, effective as of May 21, 2014 (filed as Exhibit 10.1 to the registrant’s Current Report on
Form 8-K filed on May 28, 2014, and incorporated herein by reference)
10.17*†
Summary of Compensation Arrangements for Non-Employee Directors
10.18
Sixth Amended and Restated Credit Agreement dated as of September 28, 2018, among SM Energy Company, Wells
Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the
registrant’s Current Report on Form 8-K filed on October 4, 2018, and incorporated herein by reference)
10.19†
Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
filed on October 20, 2015, and incorporated herein by reference)
115
10.20†
10.21***
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29†
10.30†
10.31
10.32†
10.33
21.1*
23.1*
23.2*
24.1*
31.1*
31.2*
32.1**
99.1*
101.INS
Amendment No. 3 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2016 (filed as
Exhibit 10.29 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2015, and
incorporated herein by reference)
Amendment to Amended and Restated Gas Gathering Agreement, effective as of September 1, 2015, by and between SM
Energy Company and Regency Field Services LLC (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K
filed on September 15, 2015, and incorporated herein by reference)
Amendment to Amended and Restated Gas Gathering Agreement, effective as of February 1, 2016, by and between SM
Energy Company and ETC Field Services LLC (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on
February 22, 2016, and incorporated herein by reference)
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and Wells Fargo Bank, National
Association (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated
herein by reference)
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and Bank of America, N.A. (filed as
Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)
Call Option Confirmation, dated August 8, 2016, by and between SM Energy Company and JPMorgan Chase Bank,
National Association (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and
incorporated herein by reference)
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and Wells Fargo Bank, National
Association (filed as Exhibit 10.4 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated
herein by reference)
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and Bank of America, N.A. (filed
as Exhibit 10.5 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by
reference)
Call Option Confirmation, dated August 10, 2016, by and between SM Energy Company and JPMorgan Chase Bank,
National Association (filed as Exhibit 10.6 to the registrant’s Current Report on Form 8-K filed on August 12, 2016, and
incorporated herein by reference)
SM Energy Company Employee Stock Purchase Plan, amended and restated effective as of April 6, 2017 (filed as Annex
A in the registrant’s Definitive Proxy Statement on Schedule 14A, filed on April 13, 2017, and incorporated herein by
reference)
Performance Share Unit Award Agreement as of July 1, 2018 (filed as Exhibit 10.1 to the registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2018, and incorporated herein by reference)
First Amendment to Sixth Amended and Restated Credit Agreement, dated April 18, 2019 among SM Energy Company,
Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the
registrant’s Current Report on Form 8-K filed on April 18, 2019, and incorporated herein by reference)
Performance Share Unit Award Agreement as of July 1, 2019 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2019, and incorporated herein by reference)
Second Amendment to Sixth Amended and Restated Credit Agreement, dated September 19, 2019 among SM Energy
Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit
10.1 to the registrant’s Current Report on Form 8-K filed on September 24, 2019, and incorporated herein by reference)
Subsidiaries of Registrant
Consent of Ernst & Young LLP
Consent of Ryder Scott Company L.P.
Power of Attorney
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002
Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
Ryder Scott Audit Letter
Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL
tags are embedded within the Inline XBRL document.
101.SCH* Inline XBRL Schema Document
101.CAL*
Inline XBRL Calculation Linkbase Document
101.LAB*
Inline XBRL Label Linkbase Document
101.PRE*
Inline XBRL Presentation Linkbase Document
101.DEF*
Inline XBRL Taxonomy Extension Definition Linkbase Document
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)
116
* Filed with this report.
** Furnished with this report.
*** Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange
Commission pursuant to Rule 24b-2 under the Exchange Act.
Exhibit constitutes a management contract or compensatory plan or agreement.
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to
reflect the change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material
changes to the substantive terms and conditions in this document.
Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on
†
††
+
November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal
Revenue Code. There were no material changes to the substantive terms and conditions in this document.
(c) Financial Statement Schedules. Please refer to Item 15(a) above.
ITEM 16. FORM 10-K SUMMARY
None.
117
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
SIGNATURES
Date:
February 20, 2020 By:
/s/ JAVAN D. OTTOSON
SM ENERGY COMPANY
(Registrant)
Javan D. Ottoson
President and Chief Executive Officer
(Principal Executive Officer)
GENERAL POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Javan D. Ottoson
and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone,
for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal
year ended December 31, 2019, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange
Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
Signature
Title
Date
/s/ JAVAN D. OTTOSON
Javan D. Ottoson
President, Chief Executive Officer, and Director
February 20, 2020
(Principal Executive Officer)
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial Officer
February 20, 2020
(Principal Financial Officer)
/s/ PATRICK A. LYTLE
Patrick A. Lytle
Controller and Assistant Secretary
(Principal Accounting Officer)
February 20, 2020
118
Signature
Title
Date
/s/ WILLIAM D. SULLIVAN
William D. Sullivan
/s/ CARLA J. BAILO
Carla J. Bailo
/s/ LARRY W. BICKLE
Larry W. Bickle
/s/ STEPHEN R. BRAND
Stephen R. Brand
/s/ LOREN M. LEIKER
Loren M. Leiker
/s/ RAMIRO G. PERU
Ramiro G. Peru
/s/ JULIO M. QUINTANA
Julio M. Quintana
/s/ ROSE M. ROBESON
Rose M. Robeson
Chairman of the Board of Directors
February 20, 2020
Director
Director
Director
Director
February 20, 2020
February 20, 2020
February 20, 2020
February 20, 2020
Director
February 20, 2020
Director
Director
119
February 20, 2020
February 20, 2020
EXHIBIT 4.11
As of December 31, 2019, SM Energy Company has registered one class of securities under Section 12 of the Securities Exchange Act of 1934, as
DESCRIPTION OF SECURITIES
amended (the “Exchange Act”).
Description of Common Stock
The following description of our Common Stock is a summary and does not purport to be complete. It is subject to, and qualified in its entirety by,
reference to our Restated Certificate of Incorporation (the “Certificate of Incorporation”) and our Amended and Restated By-laws (the “Bylaws”), each of
which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit is a part. We encourage you to read our Certificate of
Incorporation, our Bylaws and the applicable provisions of the Delaware General Corporate Law, for additional information.
Authorized Capital Shares
Our authorized capital shares consist of 200,000,000 shares of capital stock, $0.01 par value per share. We have outstanding shares of common stock
(“Common Stock”). The outstanding shares of our Common Stock are fully paid and non-assessable. This means the full purchase price for the outstanding
shares of Common Stock has been paid and the holders of such shares will not be assessed any additional amounts for such shares. Any additional shares of
Common Stock that the Company may issue in the future will also be fully paid and non-assessable.
The Certificate of Incorporation provides that authorized but unissued shares of Common Stock are available for future issuance without stockholder
approval, subject to various limitations imposed by the New York Stock Exchange (“NYSE”). These additional shares of Common Stock may be utilized for a
variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of
authorized but unissued shares of Common Stock could make it more difficult or discourage an attempt to obtain control of the Company by means of a proxy
contest, tender offer, merger or otherwise.
Voting Rights
Each share of Common Stock is entitled to one vote on all matters submitted to a vote of the stockholders, including the election of directors. Our
Common Stock does not have cumulative voting rights. This means a holder of a single share of Common Stock cannot cast more than one vote for each
position to be filled on the Board of Directors. It also means the holders of a majority of the shares of Common Stock entitled to vote in the election of directors
can elect all directors standing for election and the holders of the remaining shares will not be able to elect any directors.
Dividend Rights
The holders of Common Stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the Board of Directors in
its discretion out of funds legally available for the payment of dividends. Delaware law allows a corporation to pay dividends only out of surplus, as determined
under Delaware law.
Liquidation Rights
Upon the liquidation, dissolution or winding up of the Company, the holders of Common Stock are entitled to receive ratably the net assets of the
Company legally available for distribution.
Other Rights and Preferences
Our Common Stock has no sinking fund provision or preemptive, subscription or conversion rights. The holders of Common Stock may act by
unanimous written consent.
Listing
Our Common Stock is traded on the NYSE under the trading symbol “SM.”
EXHIBIT 10.17
SUMMARY OF COMPENSATION ARRANGEMENTS FOR NON-EMPLOYEE DIRECTORS
The following is a description of the standard arrangements pursuant to which directors of SM Energy are compensated for services
provided as a director, including additional amounts payable for committee participation:
DIRECTOR COMPENSATION
Employee directors do not receive additional compensation for serving on the Board of Directors or any committee.
For service in 2019 - 2020 as it relates to the period from May 2019 through May 2020, target compensation for each member of the Board
of Directors has been set at $126,000 annually, plus a retainer paid in lieu of committee and attendance fees. As described more fully below, the
actual value of compensation may be higher or lower depending on the results of the restricted stock component of director compensation. Primary
director compensation is in the form of stock grants and is fully described below. The retainer component of director compensation for non-employee
directors consists of an annual retainer of $90,000 for committee and board meeting fees paid in SM Energy common stock or cash as selected by
the director; provided that in the event any director attends in excess of 30 Board and Committee meetings in the aggregate during the period from
May 2019 through May 2020, such director shall receive $1,500 per meeting for each meeting in excess of 30. In addition, each non-employee
director is reimbursed for expenses incurred in attending Board and Committee meetings and director education programs.
The committee chairs receive the cash payments identified in the list below in recognition of the additional workload of their respective
committee assignments. These amounts are paid at the beginning of the annual service period.
•
•
•
Audit Committee - $20,000
Compensation Committee - $15,000
Nominating and Corporate Governance Committee - $10,000
The stock compensation for non-employee directors is as follows:
Annual compensation payable upon election to the Board by the stockholders, valued at $126,000. This resulted in a grant of
restricted stock to each non-employee director of 10,345 shares of SM Energy common stock issued on May 30, 2019, under SM
Energy's Equity Incentive Compensation Plan. These shares vested on December 31, 2019.
A retainer for the Non-Executive Chairman of the Board valued at $80,000. This resulted in a grant of 6,569 shares of SM Energy
common stock issued on May 30, 2019, under SM Energy's Equity Incentive Compensation Plan. These shares vested on
December 31, 2019.
William Sullivan elected to receive SM Energy common stock for his retainer, which resulted in a grant of 7,390 shares of SM
Energy common stock issued on May 30, 2019, under SM Energy's Equity Incentive Compensation Plan. These shares vested on
December 31, 2019. Carla Bailo, Larry Bickle, Stephen Brand, Loren Leiker, Ramiro Peru, Julio Quintana and Rose Robeson each
elected to receive a $90,000 cash payment for their retainer.
EXHIBIT 21.1
SUBSIDIARIES
OF
SM ENERGY COMPANY
A. Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:
1. SMT Texas LLC, a Colorado limited liability company
2. Belring GP LLC, a Delaware limited liability company
3. St. Mary Energy Louisiana LLC, a Delaware limited liability company
4. Hilltop Investments, a Colorado general partnership
5. Parish Ventures, a Colorado general partnership
6. Green Canyon Offshore LLC, a Delaware limited liability company
B. Partnership or limited liability company interests held by SM Energy Company:
1. Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)
2.
3.
4.
1977 H.B Joint Account, a Colorado general partnership (8%)
1976 H.B Joint Account, a Colorado general partnership (9%)
1974 H.B Joint Account, a Colorado general partnership (4%)
C. Partnership interests held by SMT Texas, LLC:
1. St. Mary Land East Texas LP, a Texas limited partnership (99%) (the remaining 1% interest is held by SM Energy Company)
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the following Registration Statements:
(1) Post-Effective Amendment No. 1 to Registration Statement (Form S-8 Nos. 333-30055, 333-106438, 333-35352, and 333-88780) of SM Energy Company,
(2) Registration Statement (Form S-8 Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351, 333-194305, 333-212359, 333-219719, and 333-
226660) of SM Energy Company,
(3) Post-Effective Amendment No. 1 to Registration Statement (Form S-3 No. 333-203936 and 333-226597) of SM Energy Company, and
(4) Registration Statement (Form S-3 No. 333-216843) of SM Energy Company;
of our reports dated February 20, 2020, with respect to the consolidated financial statements of SM Energy Company and subsidiaries, and the effectiveness of
internal control over financial reporting of SM Energy Company and subsidiaries, included in this Annual Report (Form 10-K) of SM Energy Company and
subsidiaries for the year ended December 31, 2019.
/s/ Ernst & Young LLP
Denver, Colorado
February 20, 2020
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of SM Energy
Company for the year ended December 31, 2019. We hereby further consent to the use of information contained in our reports, and the use of our audit letter,
as of December 31, 2019, relating to estimates of revenues from SM Energy Company's oil, gas, and NGL reserves. We further consent to the incorporation by
reference thereof into SM Energy Company’s Post-Effective Amendment No. 1 to Registration Statement Nos. 333-30055, 333-106438, 333-35352, and 333-
88780 on Form S-8, Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351, 333-194305, 333-212359, 333-219719, and
333-226660 on Form S-8, Post-Effective Amendment No. 1 to Registration Statement No. 333-203936 and 333-226597 on Form S-3, and Registration
Statement No. 333-216843 on Form S-3.
EXHIBIT 23.2
Houston, Texas
February 20, 2020
/s/ RYDER SCOTT COMPANY, L.P.
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
CERTIFICATION
EXHIBIT 31.1
I, Javan D. Ottoson, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of SM Energy Company;
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;
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;
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)
(b)
(c)
(d)
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;
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;
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
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)
(b)
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
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: February 20, 2020
/s/ JAVAN D. OTTOSON
Javan D. Ottoson
President and Chief Executive Officer
CERTIFICATION
EXHIBIT 31.2
I, A. Wade Pursell, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of SM Energy Company;
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;
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;
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)
(b)
(c)
(d)
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;
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;
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
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)
(b)
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
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: February 20, 2020
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial and Accounting Officer
EXHIBIT 32.1
CERTIFICATION
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of SM Energy Company (the “Company”) for the fiscal year ended December 31, 2019 as filed with
the Securities and Exchange Commission on the date hereof (the “Report”), Javan D. Ottoson, as President and Chief Executive Officer of the Company, and A.
Wade Pursell, as Executive Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to and solely for the purpose of 18
U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge and belief, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ JAVAN D. OTTOSON
Javan D. Ottoson
President and Chief Executive Officer
February 20, 2020
/s/ A. WADE PURSELL
A. Wade Pursell
Executive Vice President and Chief Financial and Accounting Officer
February 20, 2020
EXHIBIT 99.1
SM ENERGY COMPANY
Estimated
Future Reserves
Attributable to Certain
Leasehold Interests
SEC Parameters
As of
December 31, 2019
/s/ Michael F. Stell
Michael F. Stell, P.E.
TBPE License No. 56416
Advising Senior Vice President
/s/ Val Rick Robinson
Val Rick Robinson
TBPE License No. 105137
Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
January 3, 2020
Mr. Levi J. Briese
Reserves Engineering Supervisor
SM Energy Company
1775 Sherman Street, Suite 1200
Denver, Colorado 80203
Gentlemen:
At the request of SM Energy Company (SM Energy), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves
audit of the estimates of the proved reserves as of December 31, 2019 prepared by SM Energy’s engineering and geological
staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC)
contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14,
2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on December 23, 2019 and presented
herein, was prepared for public disclosure by SM Energy in filings made with the SEC in accordance with the disclosure
requirements set forth in the SEC regulations. The estimated reserves shown herein represent SM Energy’s estimated net
reserves attributable to the leasehold interests in certain properties owned by SM Energy and the portion of those reserves
reviewed by Ryder Scott, as of December 31, 2019. The properties reviewed by Ryder Scott incorporate 1,141 SM Energy
reserves determinations and are located in the state of Texas.
The properties reviewed by Ryder Scott account for a portion of SM Energy’s total net proved reserves as of December
31, 2019. Based on the estimates of total net proved reserves prepared by SM Energy, the reserves audit conducted by Ryder
Scott addresses 96 percent of the total proved developed net liquid hydrocarbon reserves, 98 percent of the total proved
developed net gas reserves, 69 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 63 percent of the
total proved undeveloped net gas reserves of SM Energy.
As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating
and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of
reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or
Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies
employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation
process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the
estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to
the extent and value of petroleum properties
SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790
621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258
SM Energy Company
January 3, 2020
Page 2
Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our
opinion that the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved reserves
as of December 31, 2019 comply with the current SEC regulations and that the overall proved reserves for the reviewed
properties as estimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance guidelines of 10
percent as set forth in the SPE auditing standards.
The estimated reserves presented in this report are related to hydrocarbon prices. SM Energy has informed us that in the
preparation of their reserves and income projections, as of December 31, 2019, they used average prices during the 12-month
period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-
day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the
SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable
reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received;
therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report.
The net reserves as estimated by SM Energy attributable to SM Energy's interest in properties that we reviewed and for those
that we did not review are summarized below:
SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold Interests of
SM Energy Company
As of December 31, 2019
Developed
Proved
Producing
Non-Producing
Undeveloped
76,295
42,884
687,964
3,588
253
10,928
79,883
43,137
698,892
3,804
115
9,697
1,277
156
3,467
5,081
271
13,164
76,781
12,471
321,346
22,342
18,135
189,772
99,123
30,606
511,118
Total
Proved
156,880
55,470
1,019,007
27,207
18,544
204,167
184,087
74,014
1,223,174
Net Reserves of Properties
Audited by Ryder Scott
Oil/Condensate - MBBL
Plant Products - MBBL
Gas – MMCF
Net Reserves of Properties
Not Audited by Ryder Scott
Oil/Condensate - MBBL
Plant Products - MBBL
Gas – MMCF
Total Net Reserves
Oil/Condensate - MBBL
Plant Products - MBBL
Gas – MMCF
Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBBL).
All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and
pressure bases of the areas in which the gas reserves are located.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 3, 2020
Page 3
Reserves Included in This Report
In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and
Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a)
entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.
The proved reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS
DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the
shut-in category.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve
an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than
the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of
reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative
degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.
Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and
possible reserves to denote progressively increasing uncertainty in their recoverability. At SM Energy’s request, this report
addresses only the proved reserves attributable to the properties reviewed herein.
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.” The proved reserves
included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves,
when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or
as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of
geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate
recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”
Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental
agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should
not be construed as being exact quantities. They may or may not be actually recovered and actual recovery could be more or
less than the estimated amounts.
Audit Data, Methodology, Procedure and Assumptions
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the
quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with
those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s
Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of
certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1)
performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in
combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select
the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of
reliable geoscience and
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 3, 2020
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engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir
being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this
data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a
range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental
quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty
for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.
Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent
uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty
wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable
reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with
proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that
are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low
probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves
category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional
geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves
categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects
of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves, prepared by SM Energy, for the properties that we reviewed were estimated by performance
methods, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or
reservoirs were estimated by performance methods. The performance methods, such as decline curve analysis, utilized
extrapolations of historical production data available through November 2019 in those cases where such data were considered
to be definitive. The data utilized in this analysis were furnished to Ryder Scott by SM Energy or obtained from public data
sources and were considered sufficient for the purpose thereof.
All of the proved non-producing and undeveloped reserves included herein were estimated by analogy. The analogs
utilized data furnished to Ryder Scott by SM Energy or which we have obtained from public data sources that were available
through November 2019.
To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered
including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which
cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future
production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be
economically producible from a given date forward based on existing economic conditions including the prices and costs at
which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and other costs relating to such production may increase or decrease
from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in conducting this review.
As stated previously, proved reserves must be anticipated to be economically producible from a given date forward
based on existing economic conditions including the prices and costs at which economic
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 3, 2020
Page 5
producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC
requirements to be economically producible, we have reviewed certain primary economic data utilized by SM Energy relating to
hydrocarbon prices and costs as noted herein.
The hydrocarbon prices furnished by SM Energy for the properties reviewed by us are based on SEC price parameters
using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted
arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were
defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and
determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration,
the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
The initial SEC hydrocarbon prices in effect on December 31, 2019 for the properties reviewed by us were determined
using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the
hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table
below summarizes the “benchmark prices” and “price reference” used by SM Energy for the geographic area reviewed by us. In
certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.
The product prices which were actually used by SM Energy to determine the future gross revenue for each property
reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market,
referred to herein as “differentials.” The differentials used by SM Energy were accepted as factual data and reviewed by us for
their reasonableness; however, we have not conducted an independent verification of the data used by SM Energy.
The table below summarizes SM Energy’s net volume weighted benchmark prices adjusted for differentials for the
properties reviewed by us and referred to herein as SM Energy’s “average realized prices.” The average realized prices shown
in the table below were determined from SM Energy’s estimate of the total future gross revenue before production taxes for the
properties reviewed by us and SM Energy’s estimate of the total net reserves for the properties reviewed by us for the
geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for the
geographic area reviewed by us.
Geographic Area
North America
United States
Product
Oil/Condensate
NGLs
Gas
Price
Reference
WTI, Cushing
OPIS Composite(1)
Henry Hub
Average
Benchmark
Prices
$55.69/BBL
$22.68/BBL
$2.58/MMBTU
Average
Realized
Prices
$53.67/BBL
$18.62/BBL
$2.53/MCF
(1) Price reflects composition of ethane, propane, and butane
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in SM
Energy’s individual property evaluations.
Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates
reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 3, 2020
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Operating costs furnished by SM Energy are based on the operating expense reports of SM Energy and include only
those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of
general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include
an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties
include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The
operating costs furnished by SM Energy were accepted as factual data and reviewed by us for their reasonableness; however,
we have not conducted an independent verification of the data used by SM Energy. No deduction was made for loan
repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or
wells.
Development costs furnished by SM Energy are based on authorizations for expenditure for the proposed work or actual
costs for similar projects. The development costs furnished by SM Energy were accepted as factual data and reviewed by us for
their reasonableness; however, we have not conducted an independent verification of the data used by SM Energy. The
estimated net cost of abandonment and salvage was included by SM Energy for properties where abandonment costs and
salvage were material. SM Energy’s estimates of the net abandonment costs were accepted without independent verification.
The proved undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with
SM Energy’s plans to develop these reserves as of December 31, 2019. The implementation of SM Energy’s development plans
as presented to us is subject to the approval process adopted by SM Energy’s management. As the result of our inquiries during
the course of our review, SM Energy has informed us that the development activities for the properties reviewed by us have
been subjected to and received the internal approvals required by SM Energy’s management at the appropriate local, regional
and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to
specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to SM
Energy. SM Energy has provided written documentation supporting their commitment to proceed with the development activities
as presented to us. Additionally, SM Energy has informed us that they are not aware of any legal, regulatory, or political
obstacles that would significantly alter their plans. While these plans could change from those under existing economic
conditions as of December 31, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in making this evaluation.
Current costs used by SM Energy were held constant throughout the life of the properties.
SM Energy’s forecasts of future production rates are based on historical performance from wells currently on production.
If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of
curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied
until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future
production rates.
Test data and other related information were used by SM Energy to estimate the anticipated initial production rates for
those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence
at an anticipated date furnished by SM Energy. Wells or locations that are not currently producing may start producing earlier or
later than anticipated in SM Energy’s estimates due to unforeseen factors causing a change in the timing to initiate production.
Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting
wells and/or constraints set by regulatory bodies.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 3, 2020
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The future production rates from wells currently on production or wells or locations that are not currently producing may
be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions
related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market
demand and/or allowables or other constraints set by regulatory bodies.
SM Energy’s operations may be subject to various levels of governmental controls and regulations. These controls and
regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce
hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes
and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and
policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ
significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a review of the properties in which SM Energy
owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report
to potential environmental liabilities that may exist nor were any costs included by SM Energy for potential liabilities to restore
and clean up damages, if any, caused by past operating practices.
Certain technical personnel of SM Energy are responsible for the preparation of reserves estimates on new properties
and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary
data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had
access to their workpapers and supporting data in the course of our audit.
SM Energy has informed us that they have furnished us all of the material accounts, records, geological and engineering
data, and reports and other data required for this investigation. In performing our audit of SM Energy’s forecast of future proved
production, we have relied upon data furnished by SM Energy with respect to property interests owned, production and well tests
from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing
fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after
salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and
isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its
reasonableness; however, we have not conducted an independent verification of the data furnished by SM Energy. The data
described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our
examination, a matter of question came to our attention in which case the data were not accepted until all questions were
satisfactorily resolved. We consider the factual data furnished to us by SM Energy to be appropriate and sufficient for the
purpose of our review of SM Energy’s estimates of reserves. In summary, we consider the assumptions, data, methods and
analytical procedures used by SM Energy and as reviewed by us appropriate for the purpose hereof, and we have used all such
methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set
forth herein.
Audit Opinion
Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our
opinion that the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved reserves
as of December 31, 2019 comply with the current SEC regulations and that the overall proved reserves for the reviewed
properties as estimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance guidelines of 10
percent as set forth in the
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 3, 2020
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SPE auditing standards. Ryder Scott found the processes and controls used by SM Energy in their estimation of proved
reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these
properties.
We were in reasonable agreement with SM Energy's estimates of proved reserves for the properties which we reviewed;
although in certain cases there was more than an acceptable variance between SM Energy's estimates and our estimates due to
a difference in interpretation of data or due to our having access to data which were not available to SM Energy when its
reserves estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented
herein for the properties that we reviewed fairly reflects the estimated net reserves owned by SM Energy.
Other Properties
Other properties, as used herein, are those properties of SM Energy which we did not review. The proved net reserves
attributable to the other properties account for 18 percent of the total proved net liquid hydrocarbon reserves and 17 percent of
the total proved net gas reserves based on estimates prepared by SM Energy as of December 31, 2019. The other properties
represent 13 percent of the total proved discounted future net income at 10% based on the unescalated pricing policy of the
SEC as taken from reserves and income projections prepared by SM Energy as of December 31, 2019.
The same technical personnel of SM Energy were responsible for the preparation of the reserves estimates for the
properties that we reviewed as well as for the properties not reviewed by Ryder Scott.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting
services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver,
Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By
virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a
material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and
gas company and are separate and independent from the operating and investment decision-making process of our clients. This
allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused
on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on
the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively
participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received
professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified
professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-
regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of
continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical
and ethics training with our internal requirement mentioned above.
We are independent petroleum engineers with respect to SM Energy. Neither we nor any of our employees have any
financial interest in the subject properties, and neither the employment to do this
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
SM Energy Company
January 3, 2020
Page 9
work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and
engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for
overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure
requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by SM
Energy.
SM Energy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, SM Energy
has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K
is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-8 of
SM Energy, of the references to our name, as well as to the references to our third party report for SM Energy, which appears in
the December 31, 2019 annual report on Form 10-K of SM Energy. Our written consent for such use is included as a separate
exhibit to the filings made with the SEC by SM Energy.
We have provided SM Energy with a digital version of the original signed copy of this report letter. In the event there are
any differences between the digital version included in filings made by SM Energy and the original signed report letter, the
original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our
offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
/s/ Michael F. Stell
Michael F. Stell, P.E.
TBPE License No. 56416
Advising Senior Vice President
/s/ Val Rick Robinson
Val Rick Robinson
TBPE License No. 105137
Managing Senior Vice President
MFS-VRR (LPC)/pl
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers
from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate
of the reserves, future production and income.
Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is
responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation
studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and
Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer
to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science
Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in
the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation
Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers
requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional
ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours
of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the
United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas
Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized
in-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the
SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum
economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education
hours, Mr. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training
covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve
reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves,
evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2019, as of the date of
this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 37 years of practical experience in the estimation and
evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves
Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”
promulgated by the Society of Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 1
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil
and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The
“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of
Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies
Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to
Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take
effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after
January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part
210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC
document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an
assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than
the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of
reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative
degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.
Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and
possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of
December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil
and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of
oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the
SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202
Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as
economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include
all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples
of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use
of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum
technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations
are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method
applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or
coalseam methane (CBM/CSM), basin-
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 2
centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require
specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from
different reserves categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or
there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production,
installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement
the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults
until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that
are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low
reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from
undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves 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.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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(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.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be
made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following
reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the
aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
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.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-
classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and
producing at the effective date of the estimate.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
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Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1) completion intervals that are open at the time of the estimate but which have not yet started producing;
(2) wells which were shut-in for market conditions or pipeline connections; or
(3) wells not capable of production for mechanical reasons.
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion
work or future re-completion before start of production with minor cost to access these reserves.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new
well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as
follows:
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.
(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 paragraph
(a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS