THE EXTRACTION OIL & GAS 2018 ANNUAL REPORT
E X T R A C T I O N O I L & G A S 2 0 1 8 A N N U A L R E P O R T • A F O U N D A T I O N o f S T R E N G T H
Dear Fellow Shareholders:
Last year was another foundational year for us as we continued to build on our progress made since Extraction’s
inception. As an industry leader in the Denver-Julesburg Basin of Colorado, we have proven leadership and
operating teams focused on creating long term shareholder value. Our people remain the core of who we are,
and we have been recognized for the third consecutive year as one of Denver’s “Top Workplaces.” Our major
triumphs and accomplishments in 2018 will serve as our foundation of strength as we prepare for the road ahead.
2018 was a year of many milestones for us.
Extraction was recognized by the State of Colorado with a Gold Award in its Environmental Leadership Program
for consistently exceeding rules and regulations in one of the strictest-regulated operating environments in the nation. We built on
our impeccable safety record which has now eclipsed 1.3 million man hours without a single recordable employee incident. Keeping
the communities where we operate and our employees and contractors safe and secure is paramount. We also established the
Extraction Foundation with a lasting and sustainable mission providing charitable contributions to the communities in which we
work and our employees live including plans for elementary, secondary and post-secondary educational grants and scholarships, as
well as community-enhancing joint venture projects.
Our growing production combined with our steady capital program culminated in free cash flow generation during the fourth
quarter as previously planned dating back to our IPO in 2016. Robust growth within cash flow has become a cornerstone goal for
us. Our ability to grow within cash flow demonstrates the high quality nature of our 179,000 net acre leasehold position located
within the core of the DJ Basin targeting the oil-prone Codell and Niobrara formations. We grew our total net equivalent production
by 47 percent year-on-year while establishing a new company record quarterly production rate of over 85 thousand barrels of oil
equivalent per day. Our crude oil production grew 53% year-on-year while establishing a new quarterly record high production rate
of 46,584 barrels per day. Proved reserves grew 11% year-on-year to 337 million barrels equivalent.
We also formed and funded Elevation Midstream, our midstream subsidiary that is currently building out oil, gas and water gathering
systems in the southern portion of our acreage encompassing our Southwest Wattenberg and Hawkeye development areas, the
first of which is scheduled to be in service in the third quarter of 2019.
As we focus on the road ahead, we are committed to growing our production within cash flow while continuing to improve our
already low and efficient operating cost structure. With management and employee ownership of over six percent of our common
stock and an industry-leading set of shareholder-friendly compensation incentives, we are very well-aligned with our public
shareholders when it comes to creating long-lasting and sustainable shareholder value for many years to come.
Sincerely,
Mark Erickson
Chairman and CEO
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(cid:2) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
(cid:3)
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the transition period from
to
Commission file number 001-37907
EXTRACTION OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of
incorporation or organization)
370 17th Street, Suite 5300
Denver, Colorado
(Address of principal executive offices)
46-1473923
(IRS Employer
Identification No.)
80202
(Zip Code)
(720) 557-8300
(Registrant’s telephone number, including area code)
Title of each class
Common Stock, par value $0.01
Name of exchange on which registered
NASDAQ Global Select Market
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
Yes (cid:3) No (cid:2)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of Section 15(d) of the Act.
Yes (cid:3) No (cid:2)
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 (cid:2) No (cid:3)
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 (cid:2) No (cid:3)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (cid:3)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company, or an emerging growth company. See the definitions of ‘‘large accelerated filer’’, ‘‘accelerated filer’’, ‘‘smaller reporting
company’’ and ‘‘emerging growth company’’ in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer (cid:2)
(cid:3)
Non-accelerated filer
Accelerated filer
Smaller reporting company (cid:3)
Emerging growth company (cid:3)
(cid:3)
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. (cid:3)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:3) No (cid:2)
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $0.9 billion as
of June 30, 2018, (based on the last sale price of such stock as quoted on the NASDAQ Global Select Market).
The total number of shares of common stock, par value $0.01 per share, outstanding as of February 19, 2019 was 171,554,356.
Portions of the registrant’s definitive proxy statement for the 2019 Annual Meeting of Stockholders, to be filed no later than 120 days
after the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual
Report on Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
(This page has been left blank intentionally.)
EXTRACTION OIL & GAS, INC.
TABLE OF CONTENTS
CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
GLOSSARY
PART I
ITEM 1. AND 2.
BUSINESS AND PROPERTIES
ITEM 1A.
ITEM 1B.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
RISK FACTORS
UNRESOLVED STAFF COMMENTS
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES
PART II
MARKET FOR REGISTRANT’S COMMON STOCK, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES
SELECTED FINANCIAL DATA
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
PART III
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15.
ITEM 16.
SIGNATURES
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY
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1
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report contains "forward-looking statements." All statements, other than statements of historical facts,
included or incorporated by reference herein concerning, among other things, planned capital expenditures, increases in oil and
gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and
borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and
objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use
of terms and phrases such as ''may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate,"
''will," "continue," ''potential," "should," "could," and similar terms and phrases. Although we believe that the expectations
reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties.
Review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in this
report and our other filings with the Securities and Exchange Commission for further information on risk and uncertainties that
could affect our business, financial condition, results of operations and cash flows. Our results could differ materially from
those anticipated in these forward-looking statements as a result of certain factors, including, among others:
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federal and state regulations and laws;
capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;
risks and restrictions related to our debt agreements;
our ability to use derivative instruments to manage commodity price risk;
realized oil, natural gas and NGL prices;
a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for
oil, natural gas and NGL and the availability of capital;
unsuccessful drilling and completion activities and the possibility of resulting write-downs;
geographical concentration of our operations;
constraints in the DJ Basin of Colorado with respect to gathering, transportation and processing facilities and
marketing;
our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in
commercially viable quantities;
shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment,
supplies, services and personnel;
adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our
inability to replace our reserves through exploration and development activities;
incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or
recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of
such acquired properties;
drilling operations associated with the employment of horizontal drilling techniques, and adverse weather and
environmental conditions;
limited control over non-operated properties;
title defects to our properties and inability to retain our leases;
our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;
our ability to retain key members of our senior management and key technical employees;
risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;
impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
changes in tax laws;
effects of competition; and
seasonal weather conditions.
2
Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL that cannot be
measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of
such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule
of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities
of oil, natural gas and NGL that are ultimately recovered.
All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their
entirety by the cautionary statements in this section and elsewhere in this Annual Report. Except as required by law, we do not
assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or
circumstances, changes in expectations or otherwise.
3
GLOSSARY OF OIL AND GAS TERMS
Unless indicated otherwise or the context otherwise requires, references in this report to the "Company," “Extraction,” "us,"
"we," "our," or "ours" or like terms refer to Extraction Oil & Gas, Inc., following the completion of our initial public offering
on October 17, 2016, as described under Note 9 — Equity in Item 8 in this Annual Report. When used in the historical context,
the "Company," “Holdings,” "us," "we," "our" and "ours" or like terms refer to Extraction Oil & Gas Holdings, LLC and its
subsidiaries. Holdings is our accounting predecessor, for which we present the consolidated financial statements in this Annual
Report.
The terms defined in this section are used throughout this Annual Report:
"Bbl" means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
"Bbl/d" means Bbl per day.
"Btu" means one British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound
mass of water one degree Fahrenheit at sea level.
"BOE" means barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids)
to one Bbl of oil.
"BOE/d" means BOE per day.
"CIG" means Colorado Interstate Gas, which is calculated as NYMEX Henry Hub index price less the Rocky Mountains
(CIGC) Inside FERC fixed price.
"Completion" means the installation of permanent equipment for the production of oil or natural gas.
"Developed acreage" means the number of acres that are allocated or assignable to producing wells or wells capable of
production.
"Development well" means a well drilled to a known producing formation in a previously discovered field, usually offsetting a
producing well on the same or an adjacent oil and natural gas lease.
"Exploratory well" means a well drilled either (a) in search of a new and as yet undiscovered pool of oil or gas or (b) with the
hope of significantly extending the limits of a pool already developed (also known as a "wildcat well").
"Field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual
geological structural feature or stratigraphic condition.
"Fracturing" or "hydraulic fracturing" means a procedure to stimulate production by forcing a mixture of fluid and proppant
(usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases
permeability and porosity.
"Gas" or "Natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an
underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
"Gross Acres" or "Gross Wells" means the total acres or wells, as the case may be, in which we have a working interest.
"Henry Hub" means Henry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts
traded on the NYMEX.
"Horizontal drilling" or "horizontal well" means a wellbore that is drilled laterally.
"Leases" means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell
oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private
landowners (fee leases) and from federal and state governments on acreage held by them.
"MBbl" One thousand barrels of oil, condensate or NGL.
4
"MBoe" One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas
liquids) to one Bbl of oil.
"Mcf" is an abbreviation for "1,000 cubic feet," which is a unit of measurement of volume for natural gas.
"MMBtu" One million Btus.
"MMcf" is an abbreviation for "1,000,000 cubic feet," which is a unit of measurement of volume for natural gas.
"Net Acres" or "Net Wells" is the sum of the fractional working interests owned in gross acres or wells, as the case may be,
expressed as whole numbers and fractions thereof.
"Net revenue interest" means all of the working interests less all royalties, overriding royalties, non-participating royalties, net
profits interest or similar burdens on or measured by production from oil and natural gas.
"NGL" means natural gas liquids.
"NYMEX" means New York Mercantile Exchange.
"Overriding royalty" means an interest in the gross revenues or production over and above the landowner’s royalty carved out
of the working interest and also unencumbered with any expenses of operation, development, or maintenance.
"Operator" means the individual or company responsible to the working interest owners for the exploration, development and
production of an oil or natural gas well or lease.
"Prospect" means a geological area which is believed to have the potential for oil and natural gas production.
"Productive well" means a well that is producing oil or natural gas or that is capable of production.
"Proved developed reserves" means reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods.
"Proved reserves" means 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.
"Proved undeveloped reserves" means proved reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for recompletion. 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.
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 specific circumstances justify a longer time. Under no
circumstances shall estimates of proved 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, or by other evidence using reliable technology establishing reasonable
certainty.
"PV-10 value" means the present value of estimated future gross revenue to be generated from the production of estimated net
proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date
indicated (unless such prices or 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 and future income tax expenses or to
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 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.
5
"Reasonable certainty" means a high degree of confidence that the reserves quantities will be recovered, when a deterministic
method is used. A high degree of confidence exists if the reserves quantity is much more likely to be achieved than not, and, as
changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic
data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or
remain constant than to decrease.
"Recompletion" means the completion for production from an existing wellbore in a formation other than that in which the well
has previously been completed.
"Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible natural gas
and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
"Reserve life" represents the estimated net proved reserves at a specified date divided by actual production for the preceding
12-month period.
"Royalty" means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural
gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
"Royalty interest" means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas
production, free of costs of exploration, development and production operations.
"SEC" means the Securities and Exchange Commission.
"SEC pricing" means the price per Bbl for oil or per MMBtu for natural gas as calculated from the unweighted arithmetic
average first-day-of-the-month prices for the prior 12 months.
"Seismic data" means an exploration method of sending energy waves or sound waves into the earth and recording the wave
reflections to indicate the type, size, shape and depth of a subsurface rock formation.
"Spacing" means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres,
e.g., 40-acre spacing, and is often established by regulatory agencies.
"Undeveloped acreage" means lease acres on which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves.
"Undeveloped leasehold acreage" means the leased acreage on which wells have not been drilled or completed to a point that
would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains
estimated net proved reserves.
"Unit" means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for
development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
"Wattenberg Field" means the Greater Wattenberg Area within the Denver-Julesburg Basin of Colorado as defined by the
Colorado Oil and Gas Conservation Commission, which are the lands from and including Townships 2 South to 7 North and
Ranges 61 West to 69 West, Six Principal Median.
"Working interest" means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and
production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the
landowner's royalty, any overriding royalties, production costs, taxes and other costs.
"WTI" means the price of West Texas Intermediate oil on the NYMEX.
6
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Company Overview
PART I
We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas
and NGL reserves, as well as the construction and support of midstream assets to gather and process crude oil and gas
production in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of
Colorado. The Wattenberg Field has been producing since the 1970s and is a premier North American oil and natural gas basin
characterized by high recoveries relative to drilling and completion costs, high initial production rates, long reserve life and
multiple stacked producing horizons. We have assembled, as of December 31, 2018, approximately 179,300 net acres of large,
contiguous acreage blocks in some of the most productive areas of the DJ Basin, indicated by the results of our horizontal
drilling program and the results of offset operators, which we refer to as the “Core DJ Basin”. The 179,300 net acres includes
our new acquisition area (the "Hawkeye Area") in primarily Arapahoe and Adams Counties, which makes up approximately
68,700 of the 179,300 net acres. We believe our acreage in the Core DJ Basin has been significantly delineated by our own
drilling success and by the success of offset operators, providing confidence that our inventory is relatively low-risk, repeatable
and will continue to generate economic returns. We are primarily focused on growing our proved reserves and production
primarily through the development of our large inventory of identified liquids-rich horizontal drilling locations in the DJ Basin.
We were founded in November 2012 with the objective of becoming a Wattenberg focused company with acreage that
has (i) low development risk as a result of being within the vicinity of other successful wells drilled by other oil and gas
companies, (ii) limited vertical well drainage relative to offset operators in a field with significant historical vertical activity,
and (iii) higher oil content than was traditionally targeted when many operators first established their position in the field
seeking natural gas production. We believe these characteristics enhance our horizontal production capabilities, recoveries and
economic results. Our drilling economics are further enhanced by our ability to drill longer laterals due to our large contiguous
acreage position, which our management team built through organic leasing and a series of strategic acquisitions. We operated
96% of our horizontal production for the year ended December 31, 2018 and maintain control of a large majority of our drilling
inventory. In addition, we proactively seek to secure the necessary midstream and operational infrastructure to keep pace with
our production growth.
For the year ended December 31, 2018, we have drilled 286 gross one-mile equivalent horizontal wells and have
completed 268 gross one-mile equivalent horizontal wells. We are currently running a full time two-rig program and our 2019
capital budget anticipates a one to two operated drilling rig program. Our average net daily production during the fourth quarter
and year ended December 31, 2018 was approximately 85,780 BOE/d and 76,019 BOE/d, respectively.
The following table provides summary information regarding our proved reserves as of December 31, 2018, and our
average net daily production for the year ended December 31, 2018.
Oil
Natural Gas
NGL
(MBbls)
(MMcf)
(MBbls)
Total
(MBoe)
%
Oil
%
%
Liquids(2)
Developed
Estimated Total Proved Reserves (1)
Average Net
Production
(BOE/d)
(1)(3)
R/P Ratio
(Years)(4)
135,846
703,268
94,851
347,908
39%
66%
40%
76,019
12.5
(1) Includes de minimis reserves and production attributable to properties in our Other Rockies Area. Please see “—Other
Properties.”
(2) Includes both oil and NGL.
(3) Average net daily production. Consisted of approximately 53% oil, 28% natural gas and 19% NGL.
(4) Represents the number of years proved reserves would last assuming production continued at the average rate for the year
ended December 31, 2018. Because production rates naturally decline over time, the R/P Ratio is not a useful estimate of
how long properties should economically produce.
7
The following table presents information regarding our horizontal drilling locations on a one-mile equivalent basis as
of December 31, 2018. We have not booked proved reserves on all of these drilling locations.
Identified Horizontal Niobrara and Codell Drilling Locations(1)(2)(3)
Gross
Net
Total
6,436
4,175
(1) As adjusted for lateral length to present one-mile equivalents (approximately 4,200 feet). Please see “Business—Drilling
Locations” for more information regarding the process and criteria through which these drilling locations were identified.
The drilling locations on which we actually drill will depend on the availability of capital, regulatory approvals, takeaway
capacity, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on
these identified locations may not be successful and may not result in the addition of proved reserves to our existing
proved reserves base.
(2) Does not include gross and net locations in the Other Rockies Area (as defined below).
(3) Includes 128 drilled but uncompleted one-mile equivalent gross wells as of December 31, 2018.
Our Properties
Core DJ Basin
Our current operations are located in the DJ Basin, primarily in the Wattenberg Field where we target the oil and
liquids-weighted Niobrara and Codell formations. As of December 31, 2018, our position in the Core DJ Basin consisted of
approximately 179,300 net acres.
Our estimated proved reserves at December 31, 2018 were 347.9 MMBoe. As of December 31, 2018, we had a total of
1,538 gross wells capable of producing, of which 865 were horizontal wells. The vertical wells we operate primarily serve to
hold leases until we can drill more efficient horizontal wells on acreage we lease. Therefore, production from vertical wells
does not represent a material amount of our current production and is anticipated to decline as a percentage of total production
in the future as we drill more horizontal wells. Our average net daily production during the year ended December 31, 2018 was
approximately 76,019 BOE/d. Our working interest for all wells capable of producing averages approximately 74% and our net
revenue interest is approximately 61%.
We continue to expand our proved reserves in this area by drilling non-proved horizontal locations. As of
December 31, 2018, we had an identified drilling inventory of approximately 564 gross (364 net) proved undeveloped
horizontal drilling locations with varying lateral lengths on our acreage with average gross well costs of $5.2 million ($2.8
million normalized to 4,200 foot lateral length). During 2018, we drilled 161 gross operated horizontal wells and completed
161 gross operated horizontal wells.
Other Properties
We hold approximately 138,100 net acres outside of the Core DJ Basin, which we refer to as our “Other Rockies
Area,” that we believe is prospective for many of the same formations as our properties in the Core DJ Basin. As of
December 31, 2018, there were de minimis proved reserves associated with this acreage. Average daily production associated
with these properties for the year ended December 31, 2018 was approximately 347 BOE/d.
Gathering Systems and Facilities
Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and an unrestricted subsidiary of ours,
is focused on the construction of gathering systems and facilities operations to serve the development of our acreage in
Hawkeye and Southwest Wattenberg areas. Future revenues and operating expenses associated with the gathering systems and
facilities operations will be primarily derived from intersegment transactions for services provided to our exploration,
development and production operations.
8
2019 Capital Budget
Our 2019 capital budget for the drilling and completion of operated and non-operated wells is approximately $585.0
million to $675.0 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 125 gross
operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. Our capital budget anticipates a
one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party
and any amounts that may be paid for potential acquisitions.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion.
We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but
not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the
availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and
approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any
postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and
related standardized measure. These risks could materially affect our business, financial condition and results of operations.
Recent Developments
Proposition 112
On November 6, 2018, registered voters in the State of Colorado cast their ballots and rejected Proposition 112 (“Prop.
112”), with 55% of ballots cast against the measure. Prop. 112 would have created a rigid 2,500-foot setback from oil and gas
facilities to the nearest occupied structure and other “vulnerable areas,” which included parks, ball fields, open space, streams,
lakes and intermittent streams. It would have dramatically increased the amount of surface area off-limits to new energy
development by 26 times and put 94% of private land in the top five oil and gas producing counties in the State of Colorado
off-limits to new development. Please see "Risk Factors-Changes in the legal and regulatory environment governing the oil and
natural gas industry, particularly changes specific to the DJ Basin of Colorado, could have a material adverse effect on our
business" for more information.
Recent Acquisitions and Divestitures
Proposed March 2019 Divestiture
In January 2019, we entered into a definitive agreement with an unaffiliated oil and gas company to sell approximately
5,000 net acres of leasehold and producing properties primarily in Weld County, Colorado (the "Proposed March 2019
Divestiture"). Upon closing, we will receive total consideration of approximately $22.4 million in cash, subject to customary
purchase price adjustments. The effective date for the Proposed March 2019 Divestiture is July 1, 2018 with purchase price
adjustments calculated as of the closing date, which is scheduled for late March 2019. We continue to explore divestitures, as
part of our ongoing initiative to divest of non-strategic assets.
December 2018 Divestitures
In December 2018, we completed various sales of our interests in approximately 31,200 net acres of leasehold and
primarily non-producing properties for aggregate sales proceeds of approximately $8.5 million, subject to customary purchase
price adjustments. The majority of these assets were from our Other Rockies Area.
August 2018 Divestiture
In August 2018, Elevation Midstream, LLC ("Elevation"), a Delaware limited liability company and subsidiary of the
Company, received proceeds of $83.6 million and recognized a gain of $83.6 million for the year ended December 31, 2018,
upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10%
membership interest. We had acquired our interest in March 2018 in exchange for the contribution of an acreage dedication,
which was considered a nonfinancial asset.
April 2018 Divestitures
In April 2018, we completed various sales of our interests in approximately 15,100 net acres of leasehold and
primarily non-producing properties, for aggregate sales proceeds of approximately $72.3 million, subject to customary
purchase price adjustments. The majority of these assets were from our Other Rockies Area.
9
April 2018 Acquisition
In April 2018, we acquired an unaffiliated oil and gas company's interest in approximately 1,000 net acres of non-
producing leasehold primarily located in Arapahoe County, Colorado. Upon closing the seller received approximately $9.4
million in cash. The acquisition provided new development opportunities in the Core DJ Basin.
January 2018 Acquisition
On January 8, 2018, we acquired an unaffiliated oil and gas company's interest in approximately 1,200 net acres of
non-producing leasehold located in Arapahoe County, Colorado. Upon closing the seller received approximately $11.6 million
in cash. The acquisition provided new development opportunities in the Core DJ Basin.
Amendments to Revolving Credit Facility and Capital Activity
January 2019 Credit Facility Amendment
On January 8, 2019, we amended our revolving credit facility to permit prepayments and redemptions of our
unsecured bonds, subject to certain term, conditions and financial thresholds.
Senior Notes Repurchase Program
On January 4, 2019, our Board of Directors authorized a program, subject to the amendment to our revolving credit
facility, to repurchase up to $100.0 million of our Senior Notes (“Senior Notes Repurchase Program”). Our Senior Notes
Repurchase Program does not obligate us to acquire any specific nominal amount of Senior Notes. As of the date of this filing,
we have repurchased 2026 Senior Notes with a nominal value of $13.1 million for $10.5 million in connection with the Senior
Notes Repurchase Program.
December 2018 Credit Facility Amendment
On December 20, 2018, we amended our revolving credit facility to increase the borrowing base from $800.0 million
to $1.2 billion, associated with the postponed November 1, 2018 scheduled borrowing base determination. The current elected
commitments remained at $650.0 million.
Stock Repurchase Program
On November 19, 2018, we announced that our Board of Directors had approved a stock repurchase program under
which we are authorized to repurchase up to $100.0 million of our outstanding common stock from time to time in the open
market, through negotiated transactions or otherwise (the "Stock Repurchase Program"). The program is expected to be funded
by a combination of internally generated cash flows and our existing liquidity, including cash on hand and short-term revolver
borrowings. The Stock Repurchase Program will expire on March 31, 2019. During the year ended December 31, 2018, we
repurchased approximately 4.1 million shares of our common stock for $26.2 million.
October 2018 Credit Facility Amendment
On October 2, 2018, we amended our revolving credit facility to (i) postpone the November 1, 2018 scheduled
borrowing base redetermination until December 15, 2018 and (ii) permit us to make payments with respect to our own equity,
subject to certain terms, conditions and financial thresholds. See the December 2018 Credit Facility Amendment for the
resulting borrowing base increase.
Elevation Securities Purchase Agreement
On July 3, 2018, Elevation entered into a securities purchase agreement (the “Securities Purchase Agreement”) with a
third party (the "Purchaser"), pursuant to which Elevation agreed to sell 150,000 Preferred Units (the “Elevation Preferred
Units”) of Elevation at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million
(the “Private Placement”), in a transaction exempt from the registration requirements under the Securities Act of 1933, as
amended (the “Securities Act”). The Private Placement closed on July 3, 2018 (the “Preferred Unit Closing Date”) and resulted
in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement to Extraction for previously
10
incurred midstream capital expenditures and general and administrative expenses. These Preferred Units are non-recourse to
Extraction.
During the twenty-eight months following the Preferred Unit Closing Date (the “Preferred Unit Commitment Period”),
subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation
has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities
Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at
least $25.0 million, up to an aggregate amount of $350.0 million. During the Preferred Unit Commitment Period, Elevation is
required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn
amounts of such additional $350.0 million commitment.
As part of the transaction, Extraction also committed to Elevation that it would drill at least 425 wells in the acreage
dedicated to Elevation by December 31, 2023, subject to reductions if Extraction does not sell the full amount of additional
Elevation Preferred Units to the Purchaser. By way of comparison, Extraction drilled a total of 161 wells during 2018.
The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In
respect of quarters ending prior to and including June 30, 2020, such dividend is payable in cash or in kind at the election of
Elevation. After June 30, 2020, such dividend is payable solely in cash.
May 2018 Credit Facility Amendment
On May 23, 2018, we amended the revolving credit facility to, among other things, (i) increase the borrowing base
from $700.0 million to $800.0 million, subject to current elected commitments of $650.0 million and (ii) reduce each of the
applicable interest rate margins for borrowings under the credit facility by 0.50%.
February 2018 Credit Facility Amendment
On February 27, 2018, we entered into a consent agreement and amended the revolving credit facility to (i) provide for
consent by the lenders to (a) the designation of Elevation as an unrestricted subsidiary and (b) the transfer of certain assets by
the Company and one of the guarantors to such unrestricted subsidiary; and (ii) amend certain provisions of the credit
agreement, including the incurrence of indebtedness covenant to permit certain indebtedness in connection with certain
transportation service agreements with such unrestricted subsidiary.
2026 Senior Notes
On January 25, 2018, we issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026
(the "2026 Senior Notes" and the offering, the "2026 Senior Notes Offering"). The 2026 Senior Notes bear an annual interest
rate of 5.625%. The interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year commencing on
August 1, 2018. We received net proceeds of approximately $737.9 million after deducting discounts and fees. We used $534.2
million of the net proceeds from the 2026 Senior Notes Offering to tender for our 2021 Senior Notes, $52.7 million to redeem
any 2021 Senior Notes not tendered and the remainder was used for general corporate purposes. Our borrowing base under our
revolving credit facility was automatically reduced to $700.0 million in connection with the closing of the 2026 Senior Notes
Offering; however, there was no change to the current maximum lending commitments of $650.0 million.
Tender Offer to Purchase 2021 Senior Notes
On January 25, 2018, we announced the results of our cash tender offer to purchase any and all of the outstanding
aggregate principal amount of the 2021 Senior Notes. An aggregate principal amount of $500.6 million (91%) was tendered
and paid, in addition to a make-whole premium of $32.6 million and accrued and unpaid interest of $1.0 million, on January
25, 2018. On February 17, 2018, we redeemed the approximately $49.4 million aggregate principal amount of the 2021 Senior
Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the
remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid
interest of approximately $0.3 million.
11
January 2018 Credit Facility Amendment
On January 5, 2018, we amended the revolving credit facility to (i) increase the borrowing base from $525.0 million to
$750.0 million, subject to the current maximum lending commitments of $650.0 million, (ii) increase the maximum amount for
the letter of credit issued in favor of a purchaser of our crude oil be increased from $25.0 million to $35.0 million, and (iii)
amend certain provisions of the credit agreement, including the commitments and allocations of each lender. Subsequent to this
amendment our borrowing base was reduced in connection with the 2026 Senior Notes Offering and increased to $1.2 billion,
subject to the current maximum lending commitments of $650.0 million, in connection with the December 2018 Credit Facility
Amendment. See "–Liquidity and Capital Resources–Revolving Credit Facility.”
Drilling Locations
As of December 31, 2018, we have identified a total of 6,436 gross identified drilling locations as adjusted to one-mile
equivalents. Our target horizontal location count implies lateral lengths of 4,200 feet per well. Approximately 16% of our gross
identified drilling locations are attributable to proved undeveloped reserves. Our identified drilling locations have been
identified based on our review of structure as well as production data from offsetting wells. We have internally evaluated this
production data based on an extensive geological and engineering database. Information incorporated into this process includes
both our own proprietary information as well as publicly available industry data. Specifically, open hole logging data,
production statistics from operated and non-operated wells, and petrophysical data from cores taken from wellbores have
provided the technical basis from which we identified the potential locations. These data points have allowed us to determine
areas for each reservoir that may produce commercial quantities of hydrocarbons and the viability of the potential locations.
Oil, Natural Gas and NGL Data
Proved Reserves
Evaluation and Review of Proved Reserves
Our historical proved reserves estimates as of December 31, 2018, 2017 and 2016 were prepared based on reports by
Ryder Scott Company, L.P. ("Ryder Scott"), our independent petroleum engineers. Within Ryder Scott, the technical person
primarily responsible for preparing the estimates set forth in the Ryder Scott summary reserve reports incorporated herein for
the year ended December 31, 2018 was Stephen Gardner. Mr. Gardner has been practicing consulting petroleum engineering at
Ryder Scott since 2006. Mr. Gardner is a registered Professional Engineer in the State of Colorado and Texas and has over 13
years of practical experience in the estimation and evaluation of reserves. Mr. Gardner graduated from the Brigham Young
University with a Bachelor of Science Degree in Mechanical Engineering. As technical principal, Mr. Gardner meets or
exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying
industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and
guidelines. Ryder Scott does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Ryder
Scott's report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our
independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves
relating to our assets in the DJ Basin. Our internal technical team members meet with our independent reserve engineers
periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved
reserve estimation process. We provide historical information to the independent reserve engineers for our properties, such as
ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.
These reserve estimates are reviewed and approved by our Lead Reserves and Performance Engineer with final approval by
Senior Vice President of Operations.
Our Senior Vice President of Operations oversees our corporate strategic planning, reservoir, reserves, operations,
environmental and regulatory affairs. He is the technical person primarily responsible for overseeing the preparation of our
reserves estimates and third-party report of our reserves estimates. He holds a Bachelor of Science in environmental
engineering and a Master of Science in petroleum engineering with over 24 years of industry experience and significant DJ
Basin technical and operational expertise. The Senior Vice President of Operations reports directly to our President.
Our policies and processes regarding internal controls over the recording of reserves estimates require reserves to be in
compliance with the SEC definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our internal controls over
12
reserves estimates also include the review and verification of historical production data, which are based on actual production
data as reported by us; preparation of reserve estimates and verification of property ownership by our land department.
Additionally, 100% of our total net proved reserves are evaluated by Ryder Scott, on an annual basis.
Estimation of Proved Reserves
Under SEC rules, proved reserves are those quantities of oil, natural gas and NGL, 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. If deterministic methods are used, the
SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”
All of our proved reserves as of December 31, 2018, 2017 and 2016 were estimated using a deterministic method. The
estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of
recoverable oil, natural gas and NGL and the second determination results in the estimation of the uncertainty associated with
those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the
quantities of recoverable oil, natural gas and NGL reserves relies on the use of certain generally accepted analytical procedures.
These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material
balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in
combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed
producing wells were estimated using production performance methods for the vast majority of properties. Certain new
producing properties with very little production history were forecast using a combination of production performance and
analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing
reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a
combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-
producing and proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for
development and an abundance of subsurface control data.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many
factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot
be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future
production rates.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual
production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that
establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and
repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to
our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been
demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole
completion information, geologic data, electrical logs, radioactivity logs, core analyses, historical well cost and operating
expense data.
13
Summary of Oil, Natural Gas and NGL Reserves.
The following table presents our estimated net proved oil, natural gas and NGL reserves as of December 31, 2018,
2017 and 2016.
Proved Developed Producing Reserves:
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total (MBoe)(1)
Proved Developed Non-Producing Reserves:
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total (MBoe)(1)
Proved Undeveloped Reserves:
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total (MBoe)(1)
Total Proved Reserves:
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total (MBoe)(1)
As of December 31,
2018
2017
2016
43,477
292,598
36,361
128,604
3,598
23,901
3,328
10,910
88,771
386,769
55,162
208,395
135,846
703,268
94,851
347,908
34,350
208,311
26,368
95,437
2,728
13,925
1,564
6,613
74,197
403,933
49,174
190,693
111,275
626,169
77,106
292,743
13,345
93,233
11,453
40,337
3,813
14,685
1,901
8,162
73,837
399,817
49,094
189,567
90,995
507,735
62,448
238,066
(1) One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is
an energy content correlation and does not reflect a value or price relationship between the commodities.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically
recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers
often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly,
reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically
recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which
may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk
Factors” appearing elsewhere in this Annual Report.
Additional information regarding our proved reserves can be found in the notes to our financial statements included
elsewhere in this Annual Report.
Proved Undeveloped Reserves (“PUDs”)
Annually, management develops a five-year capital expenditure plan based on our best available data at the time the
plan is developed. Our capital expenditure plan incorporates a development plan for converting PUD reserves to proved
developed. The development plan includes only PUD reserves that we are reasonably certain will be drilled within five years of
booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-
based returns; estimated well density; commodity prices and cost forecasts; recent drilling recompletion or re-stimulation
results and well performance; anticipated availability of services, equipment, supplies and personnel; and seasonal weather.
This process is intended to ensure that PUD reserves are only booked for locations where a final investment decision has been
14
made. Our five year development plan generally does not contemplate a uniform (i.e. 20% per year) conversion of our PUD
reserves.
Management reviews and revises the development plan throughout the year and may modify the development plan
after evaluating a number of factors, including operating and drilling results; current and expected future commodity prices;
estimated risk-based returns; estimated well density; advances in technology; cost and availability of services, equipment,
supplies and personnel; acquisition and divestiture activity; and our current and projected financial condition and liquidity. If
there are changes that result in certain PUD reserves no longer being scheduled for development within five years from the date
of initial booking, we reclass those PUD reserves to non-proved reserve categories. In addition, PUD locations and reserves
may be removed from the development plan ahead of their five-year life expiration as a result of changes in our development
plan related to factors enumerated above.
As of December 31, 2018, our proved undeveloped reserves were composed of 88,771 MBbls of oil, 386,769 MMcf
of natural gas and 55,162 MBbls of NGL, for a total of 208,395 MBoe. PUDs will be converted from undeveloped to
developed as the necessary and required capital has been invested and the wells are capable of producing.
The following table summarizes our changes in PUDs during the years ended December 31, 2018, 2017 and 2016:
Balance, December 31, 2015
Conversion into proved developed reserves
Extensions and discoveries
Acquisitions
Changes in well performance, timing and other
Balance, December 31, 2016
Conversion into proved developed reserves
Extensions and discoveries
Acquisitions
Changes in well performance, timing and other
Balance, December 31, 2017
Conversion into proved developed reserves
Extensions and discoveries
Acquisitions
Changes in well performance, timing and other
Balance, December 31, 2018
MBoe
128,505
(15,923)
50,882
31,081
(4,978)
189,567
(43,798)
37,573
12,720
(5,369)
190,693
(39,498)
64,955
12,325
(20,080)
208,395
Extensions and discoveries of 64,955 MBoe, 37,573 MBoe and 50,882 MBoe during the years ended
December 31, 2018, 2017 and 2016, respectively, resulted primarily from new proved undeveloped locations added as a result
of the drilling and completion of new wells. Downward revisions of previous estimates of 20,080 MBoe during the year ended
December 31, 2018 resulted primarily from the revisions resulting from changes in timing due to midstream curtailment issues.
We intend to develop these reserves outside the five year PUD window. Downward revisions of previous estimates of 5,369
MBoe, 4,978 MBoe during the years ended December 31, 2017 and 2016, respectively, resulted primarily from the revisions
resulting from price changes and revisions resulting from production and performance.
Estimated future development costs relating to the development of PUDs at December 31, 2018 were projected to be
approximately $396.7 million for the year ending December 31, 2019, $388.0 million in 2020, $398.9 million in 2021, $399.5
million in 2022 and $321.9 million in 2023. Costs incurred relating to the development of PUDs were $392.3 million, $442.5
million and $161.4 million during the years ended December 31, 2018, 2017 and 2016, respectively. As we continue to develop
our properties and have more well production and completion data, we believe we will continue to realize cost savings and
experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.
All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. We converted 39,498
MBoe, 43,798 MBoe and 15,923 MBoe to proved developed producing reserves in the years ended December 31, 2018, 2017
and 2016, respectively. During the year ended December 31, 2018, we converted 113 PUD locations to proved developed
producing reserves, which represent 21% of our PUD reserve volumes and 16% of our PUD locations as of December 31,
2017.
15
Productive Wells
As of December 31, 2018, we owned an average 74% working interest in 1,538 gross (1,139 net) productive wells. As
of December 31, 2017, we owned an average 71% working interest in 1,300 gross (916 net) productive wells. As of
December 31, 2016, we owned an average 73% working interest in 1,014 gross (738 net) productive wells. Productive wells
consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities.
Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional
working interests owned in gross wells.
The following table sets forth information relating to the productive wells in which we owned a working interest as of
December 31, 2018:
Oil wells
Natural gas wells
Total wells
Developed and Undeveloped Acreage
Productive Wells
Gross
Net
1,359
179
1,538
992
147
1,139
The following tables set forth information as of December 31, 2018 relating to our leasehold acreage. Developed
acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the
terms of the lease. Undeveloped acreage is acres on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and/or natural gas, regardless of whether such acreage contains proved
reserves.
The following table sets forth our gross and net acres of developed and undeveloped oil and gas leases as of
December 31, 2018:
Area
Core DJ Basin
Other Rockies
Developed
Acreage(1)
Undeveloped
Acreage(2)
Total
Acreage
Gross
119,400
61,600
Net
96,100
42,900
Gross
163,300
152,600
Net
83,200
95,200
Gross
282,700
214,200
Net
179,300
138,100
(1) Developed acreage is acres spaced or assigned to productive wells.
(2) Undeveloped acreage are acres on which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their
respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event
the lease will remain in effect until the cessation of production. We intend to extend all of our material leases to the extent
possible and expect to incur a maximum of $54.6 million to extend every material lease that is set to expire in the next three
years, without taking into account the drilling of PUDs and holding leases by production and therefore we do not expect a
material reduction in our proved undeveloped reserves as a result of lease expirations. The following table sets forth the
undeveloped acreage, as of December 31, 2018, that will expire in the years indicated below unless production is established
within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to
the primary term expiration dates.
2019
2020
2021
2022+
Area
Core DJ Basin
Other Rockies
Gross
16,400
12,700
Net
13,900
6,300
Gross
32,900
31,800
Net
22,800
19,300
Gross
23,100
17,600
Net
18,900
11,900
Gross
9,600
30,200
Net
7,100
17,700
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Drilling Results
The following table sets forth information with respect to the number of wells completed by us during the periods
indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.
Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate
of return.
Development Wells(1):
Productive(2)
Dry
Exploratory Wells(1):
Productive(2)
Dry
Total Wells(1):
Productive(2)
Dry
For the Year Ended December 31,
2018
2017
2016
Gross
Net
Gross
Net
Gross
Net
160.0
—
1.0
—
161.0
—
136.4
—
1.0
—
137.4
—
196.0
—
2.0
—
198.0
—
157.8
—
1.1
—
158.9
—
72.0
—
—
—
72.0
—
54.9
—
—
—
54.9
—
(1) Includes only wells completed by us.
(2) Although a well may be classified as productive upon completion, future changes in oil, natural gas and NGL prices,
operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there
is no production history.
As of December 31, 2018, we had 128.0 gross wells (97.4 net) wells waiting on commencement of completion
activities.
Operations
General
We operated 96% of our horizontal production for the year ended December 31, 2018. As operator, we design and
manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent
contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum
engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of
operating our oil and natural gas properties.
Marketing and Customers
We sell the majority of the production from properties we operate for both our account and the account of the other
working interest owners in these properties. We sell our production to purchasers at market prices. Our largest purchaser is an
oil marketer who has the ability to sell production into multiple markets.
During the year ended December 31, 2018, approximately 87% of our production was sold to two customers.
However, we do not believe that the loss of a single purchaser, including these two, would materially affect our business
because there are numerous other potential purchasers in the area in which we sell our production. For the year ended
December 31, 2018, Mercuria Energy Trading, Inc. and DCP Midstream, LP represented 76% and 11% of our total oil and gas
revenues, respectively. For the year ended December 31, 2017, Mercuria Energy Trading, Inc., DCP Midstream, LP and Kerr
McGee, LLC represented 65%, 19% and 11% of our total oil and gas revenues, respectively. For the year ended December 31,
2016, Mercuria Energy Trading, Inc., NGL Crude Logistics, LLC, DCP Midstream, LP and United Energy Trading, LLC
represented 25%, 23%, 19% and 16% of our total oil and gas revenues, respectively.
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Future revenues and operating expenses associated with the gathering systems and facilities operations will be
primarily derived from intersegment transactions for services provided to our exploration, development and production
operations by Elevation Midstream, LLC., an unrestricted subsidiary to the Company. As of December 31, 2018, these
gathering systems and facilities operations are not in service, therefore, there are no such revenues for the year ended December
31, 2018.
Transportation and Gathering
During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our
production. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or
pipeline to a tank farm, another pipeline or a refinery. Our natural gas is transported from the wellhead to the purchaser’s meter
and pipeline interconnection point.
We are subject to long-term delivery commitments for the transportation and gathering of our production. Our oil
marketer is subject to a firm transportation agreement that commenced in November 2016 and has a ten-year term with a
monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three
through seven and 58,000 Bbl/d in years eight through ten. In May 2017, we amended this agreement with our oil marketer that
requires us to sell all of our crude oil from an area of mutual interest in exchange for a make-whole provision that allows us to
satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of
their minimum volume commitment through October 31, 2018. In December 2017, we extended the term of this agreement
through October 31, 2019 and posted a letter of credit in the amount of $35.0 million. We are currently in the process of
amending and extending this agreement. We evaluate our contracts for loss contingencies and accrues for such losses, if the loss
can be reasonably estimated and deemed probable. We also have two long-term crude oil gathering commitments with an
unconsolidated subsidiary, in which we have a minority ownership interest. The first agreement commenced in November 2016
and has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year
two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The second agreement will
commence in or around July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year
two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year
ten. The remaining aggregate amount of estimated payments under these agreements is approximately $875.8 million.
In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017,
we agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two
new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August
2018 and the second plant is expected to be completed by mid-2019, although the exact start-up date is undetermined at this
time. Our share of these commitments will require 51.5 MMcf and 20.6 MMcf per day, respectively, to be delivered after the
plants' in-service dates for a period of seven years thereafter. We may be required to pay a shortfall fee for any volumes under
these commitments. These contractual obligations can be reduced by our proportionate share of the collective volumes
delivered to the plants by other third party incremental volumes available to the midstream provider at the new facilities that
are in excess of the total commitments. We are also required for the first three years of each contract to guarantee a certain
target profit margin on these volumes sold. Under its current drilling plans, the Company expects to meet these volume
commitments.
In February 2019, we entered into two long-term gas gathering agreements with third-party midstream providers. The
first agreement will commence in or around November 2019 and has a term of twenty years with a minimum volume
commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years are to be
delivered on an average 48,000 Mcf/d in year one, 96,000 Mcf/d in year two, 132,000 Mcf/d in year three, 120,000 Mcf/d in
year four, 108,000 Mcf/d in year five, 104,000 Mcf/d in year six and 80,000 Mcf/d in year seven. The aggregate amount of
estimated payments under this agreement is approximately $317.7 million. The second agreement will commence in or around
January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten.
We may be required to pay an annual shortfall fee for any volume deficiencies under this commitment, calculated based on the
weighted average sales price during the corresponding annual period. Under our current drilling plans, we expect to meet these
volume commitments.
We estimate that midstream constraints negatively impacted our production by approximately 18.5 MBOE/d, or 24%,
during the year ended December 31, 2018. We are currently working with various midstream providers to address processing
constraints in the DJ Basin.
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Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater
resources than we do. Many of these companies not only explore for and produce oil and natural gas, but also carry on
midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These
companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define,
evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In
addition, these companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and
NGL market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes
to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive
position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to
evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition,
because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in
bidding for exploratory prospects and producing oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing energy and fuel.
Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation
considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not
possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our
future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil
and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may
be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we
can, which would adversely affect our competitive position.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our
properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on
those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to
commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those
properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling
operations on a property until we have cured any material title defects on such property. We have obtained title opinions on
substantially all of our producing properties and believe that we have satisfactory title to our producing properties in
accordance with standards generally accepted in the oil and natural gas industry.
Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most
significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review
or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and
other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect
our carrying value of the properties.
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to
encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property,
customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental
liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor
encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens
and encumbrances will materially detract from the value of these properties or from our interest in these properties or
materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have
obtained or have the ability to obtain sufficient rights-of-way grants and permits from public authorities and private parties for
us to operate our business in all material respects as described in this Annual Report.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil, natural gas and NGL. Demand for oil, natural gas and
NGL is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of
operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
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Oil and Gas Leases
The typical oil and gas lease agreement covering our properties provides for the payment of royalties to the mineral
owner for all oil and gas produced from any wells drilled on the leased premises. Our interest in our properties after lessor
royalties and other leasehold burdens is generally 80%. Our working interest for all producing wells averages approximately
74% and our net revenue interest is approximately 61%.
Regulation of the Oil and Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with
applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of
doing business and affects profitability. Historically, our compliance costs have not had a material adverse effect on our results
of operations; however, we are unable to predict the future costs or impact of compliance. Additional proposals and
proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy
Regulatory Commission (the “FERC”) and the courts. We cannot predict when or whether any such proposals may become
effective. We do not believe that we would be affected by any such action materially differently than similarly situated
competitors.
Regulation Affecting Production
The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of
regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we
own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production
of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate
wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which
wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our
operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and
spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or
natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain
requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and
regulations may limit the amount of oil and gas we can drill. Moreover, each state generally imposes a production or severance
tax with respect to the production and sale of oil, natural gas and NGL within its jurisdiction. States do not regulate wellhead
prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect
of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the
economics of production from these wells or limit the number of locations we can drill.
The failure to comply with the rules and regulations of oil and natural gas production and related operations can result
in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and
restrictions that affect our operations.
Regulation Affecting Sales and Transportation of Commodities
Sales prices of gas, oil, condensate and NGL are not currently regulated and are made at market prices. Although
prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their
regulation. We cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities
might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state
legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to
certain state and federal reporting requirements.
The price and terms of service of transportation of the commodities, including access to pipeline transportation
capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of oil and natural gas
produced by us, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable
take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil
and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally
require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These
statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over
another source of supply. These statutes may affect whether and to what extent gathering capacity is available for oil and
natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern
rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.
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The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is
continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of
many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly
discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to
promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a
manner materially differently than other similarly situated natural gas producers.
In addition to the regulation of natural gas pipeline transportation, FERC has jurisdiction over the purchase or sale of
gas and the purchase or sale of transportation services subject to FERC’s jurisdiction pursuant to the Energy Policy Act of 2005
(“EPAct 2005”). Under the EPAct 2005, it is unlawful for “any entity,” including producers such as us, that are otherwise not
subject to FERC’s jurisdiction under the Natural Gas Act of 1938 ("NGA"), to use any deceptive or manipulative device or
contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to
regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it
unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of FERC or the purchase or sale of
transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device,
scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to
make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person.
EPAct 2005 also gives FERC authority to impose civil penalties up to approximately $1.2 million per day per violation for
violations of the NGA and the Natural Gas Policy Act of 1978 ("NGPA"). The anti-manipulation rule applies to activities of
otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or
transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No. 704
(defined below).
In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended
by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, certain market participants, including a producer
that engages in certain wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus of physical natural gas in
the previous calendar year, must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year.
Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent
such transactions utilize, contribute to, or may contribute to the formation of price indices. Not all types of natural gas sales are
required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual
transactions should be reported based on the guidance of Order No. 704. Order No. 704 is intended to increase the transparency
of the wholesale gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.
The FERC also regulates rates and terms and conditions of service on interstate transportation of liquids, including oil
and NGL, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ICA”). Prices received from the sale of liquids
may be affected by the cost of transporting those products to market. The ICA requires that certain interstate liquids pipelines
maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the
service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier
pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly
discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of
service before FERC.
The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing
methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an
index adjustment specified by FERC. For the five-year period beginning July 1, 2016, FERC established an annual index
adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review
every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through
application of the indexing methodology by obtaining market-based rate authority (demonstrating the pipeline lacks market
power), establishing rates by settlement with all existing shippers, or through a cost-of-service approach (if the pipeline
establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from
application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows
for us.
In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among
shippers in an equitable manner in the event there are nominations in excess of capacity or for new shippers. Therefore, new
shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the
operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material
adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to
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liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated
competitors.
Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions. The
basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids
pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our
operations in any way that is materially different from the effects on our similarly situated competitors.
In addition to FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our
physical sales of energy commodities. In November 2009, the Federal Trade Commission (“FTC”) issued regulations pursuant
to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry.
Violators of the regulations face civil penalties of up to approximately $1.1 million per violation per day. In July 2010,
Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading
Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to
oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to oil purchases
and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject
violators to a civil penalty of up to the greater of approximately $1.1 million or triple the monetary gain to the person for each
violation.
Regulation of Environmental and Safety and Health Matters
Our operations are subject to numerous stringent and complex federal, state and local laws and regulations governing
safety and health aspects of our operations, the release, disposal, or discharge of materials into the environment or otherwise
relating to environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency
(“EPA”), the U.S. Occupational Safety and Health Administration ("OSHA") and analogous state agencies have the power to
enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly
actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other
regulated activities; (ii) restrict the types, quantities and concentration of various materials that may be released into the
environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial
measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned
wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for
pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal penalties, including the assessment of monetary fines or penalties, the
imposition of investigatory, remedial or corrective obligations, the occurrence of delays or restrictions in permitting or
performance of projects, and the issuance of orders enjoining performance of some or all of our operations in a particular area.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would
otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the
industry and consequently affects profitability. The trend in environmental regulation is to place more restrictions and
limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-
interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water
management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material
adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs
to our customers. Moreover, accidental spills or releases may occur in the course of our operations, and we cannot assure you
that we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for
damage to property, natural resources or persons. Historically, our environmental compliance costs have not had a material
adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future
or that such future compliance will not have a material adverse effect on our business and operating results.
On January 14, 2019, in Martinez v. Colorado Oil and Gas Conservation Commission, the Colorado Supreme Court
overturned ruling by the Colorado Court of Appeals that held that the Colorado Oil & Gas Conservation Commission
("COGCC") had incorrectly concluded that it lacked statutory authority to undertake a proposed rulemaking “to suspend the
issuance of permits that allow hydraulic fracturing until it can be done without adversely impacting human health and safety
and without impairing Colorado’s atmospheric resource and climate system, water, soil, wildlife, other biological resources.”
The Colorado Court of Appeals concluded that Colorado’s Oil and Gas Conservation Act mandated that oil and gas
development “be regulated subject to the protection of public health, safety, and welfare, including protection of the
environment and wildlife resources.” The Colorado Supreme Court held that the COGCC properly denied the petition
requesting the proposed rulemaking, finding that the agency is required under the Oil and Gas Conservation Act to "foster the
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development of oil and gas resources, protecting and enforcing the rights of owners and producers," and that, while the
COGCC must also prevent and mitigate significant adverse environmental impacts to the extent necessary to protect public
health, safety, and welfare, it does so "only after taking into consideration cost-effectiveness and technical feasibility."
The following is a summary of the more significant existing and proposed environmental and safety and health laws,
as amended from time to time, to which our business operations are or may be subject and for which compliance may have a
material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Wastes
The 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 guidance issued by
the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own,
more stringent requirements. In the course of our operations, we generate some amounts of ordinary industrial wastes that may
be regulated as hazardous wastes. We are required to manage the disposal of hazardous and non-hazardous wastes in
compliance with RCRA and analogous state laws. RCRA currently exempts many exploration and production wastes from
classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and
other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However,
these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations, and it is
possible that certain oil and natural gas exploration and production wastes currently classified as non-hazardous could be
classified as hazardous waste in the future. For example, in December 2016, several environmental groups and the EPA entered
into a consent decree to address EPA's alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting
certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. Under
this consent decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D
criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not
necessary. If EPA proposes a rulemaking for revised oil and natural gas regulations, the consent decree requires that the EPA
take final action following notice and comment rulemaking no later than July 15, 2021. Stricter regulation of wastes generated
during our or our customer's operations could result in an increase in our and our customer's, as well as the oil and natural gas
exploration and production industry’s, costs to manage and dispose of wastes, which could have a material adverse effect on
our results of operations and financial position.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the
Superfund law, and comparable state laws impose 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 of a "hazardous substance" into the environment. These
persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or
arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA and any state analogs 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. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to
threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they
incur. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the
course of our operations that may be regulated as hazardous substances.
We currently own, lease, or operate, and in the past have owned, leased or operated, numerous properties that have
been used for oil and natural gas exploration, production and processing and other operations for many years. Hazardous
substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned, leased or
operated by us, or on, under or from other locations where such substances have been taken for treatment or disposal. In
addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and
disposal of substances, including hazardous substances, wastes, or petroleum hydrocarbons, was not under our control. These
properties and the hazardous substances, wastes or petroleum hydrocarbons 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, remediate contaminated property, or perform remedial operations to prevent future contamination, the costs of
which could have a material adverse effect on our business and results of operations.
Water Discharges
The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws,
impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other
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hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters,
including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an
analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate
containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon
tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general
permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge
and fill material in regulated waters, including wetlands, unless authorized by permit. In June 2015, the EPA and the U.S. Army
Corps of Engineers ("Corps") published a final rule to revise the definition of "waters of the United States" ("WOTUS") for all
CWA programs, but legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of
Appeals in October 2015. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies' prior
regulations defining the term "waters of the United States." However, in January 2018, the U.S. Supreme Court ruled that the
rule revising the WOTUS definition must first be reviewed in the federal district courts, which resulted in a withdrawal of the
stay by the Sixth Circuit. In addition, the EPA has proposed to repeal the rule revising the WOTUS definition and, in January
2018, issued a final rule to delay its implementation until 2020 to allow time for EPA to reconsider the definition of the term
"waters of the United States." Subsequent litigation in the federal district courts has resulted in patchwork application of the
rule in some states (e.g. California, Oklahoma), but not others (e.g. Colorado). In December 2018, EPA and the Corps issued a
proposed rule revising the WOTUS definition that would provide discrete categories of jurisdictional waters and tests for
determining whether a particular water body meets any of those classifications. Several groups have already announced their
intentions to challenge the proposed rule. To the extent this rule is enforced in jurisdictions in which we operate or a revised
rule expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for
dredge and fill activities in wetland areas in connection with any expansion activities. Federal and state regulatory agencies
may impose substantial administrative, civil and criminal penalties as well as other enforcement mechanisms for non-
compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations, including spills
and other non-authorized discharges.
The Oil Pollution Act of 1990 (“OPA”), amends the CWA and sets minimum standards for prevention, containment
and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and
production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and
operators of onshore facilities, may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety
of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore
facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.
Subsurface Injections
In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled may be
disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground
injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the Safe
Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous
state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations,
and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability
to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately
increase the cost of our operations. For example, in response to recent seismic events near belowground disposal wells used for
the injection of oil and natural gas-related wastewaters, regulators in some states, including Colorado, have imposed more
stringent permitting and operating requirements for produced water disposal wells. In Colorado, permit applications are
reviewed specifically to evaluate seismic activity and, as of 2011, the state has required operators to identify potential faults
near proposed wells, if earthquakes historically occurred in the area, and to accept maximum injection pressures and volumes
based on fracture gradient as conditions to permit approval. Additionally, legal disputes may arise based on allegations that
disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating
waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by us or by
commercial disposal well vendors whom we may use from time to time to dispose of wastewater, and increased costs of
compliance, which could have a material adverse effect on our capital expenditures and operating costs, financial condition,
and results of operations.
Air Emissions
The Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources,
such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating
permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain
pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase
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air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to
control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural
gas projects. Over the next several years, we may be charged royalties on natural gas losses or required to incur certain capital
expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA
issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone
from 75 parts per billion (“ppb”) for the 8-hour primary and secondary ozone standards to 70 ppb for both standards. In 2018,
EPA finalized the initial area designations for the 2015 ozone standard. Certain areas, such as Denver Metro North Front
Range, were designated as Marginal non-attainment. The Denver Metro North Front Range area is currently under significant
threat of being redesignated as a serious non-attainment area for ozone due to high levels detected in 2016 and 2017. Colorado
is seeking an extension to the attainment date and EPA has proposed to retroactively approve the requested extension by one
year, to July 20, 2019. It is not likely that another one-year extension will be granted and the Denver Metro North Front Range
area may be reclassified to serious non-attainment for 2020. Reclassification of areas or imposition of more stringent standards
(including a lowering of the major source threshold for volatile organic compounds and oxides of nitrogen and the resulting
increased likelihood that a source may be subject to Non-Attainment New Source Review) may make it more difficult to
construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to
implement more stringent requirements as a result of this new final rule, which could apply to our operations. In addition,
during the fall of 2016, EPA issued final Control Techniques Guidelines (“CTGs”) for reducing volatile organic compound
emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver
Metro North Front Range Ozone 8-hour Non-Attainment area. In 2017, as part of the federal CTG process for oil and natural
gas, Colorado undertook a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure
they meet applicable federal requirements, which resulted in revisions to Colorado's Regulation Number 7. The new state
regulations include more stringent air quality control requirements applicable to our operations. In another example, in June
2016, the EPA finalized a revised rule regarding criteria for aggregating multiple small surface sites into a single source for air-
quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis,
to be deemed a major source, thereby triggering more stringent permitting requirements. Compliance with these or other air
pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects and
increase our costs of development and production, which costs could have a material adverse impact on our business and
results of operations.
Regulation of Greenhouse Gas (“GHG”) Emissions
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have
been made and could continue to be made at the international, national, regional and state levels of government to monitor and
limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting
and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no
comprehensive climate change legislation has been implemented to date. However, the EPA has adopted rules under authority
of the CAA that, among other things, establish Potential for Significant Deterioration ("PSD") construction and Title V
operations permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of
certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for
those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from
certain petroleum and natural gas system sources in the United States, including, among other things, onshore producing
facilities, which include certain of our operations.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas
operations. In June 2016, the EPA published the New Source Performance Standards (“NSPS”) Subpart OOOOa standards that
require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and
volatile organic compound emissions. However, in September 2018, under the new administration, EPA proposed amendments
that would relax the requirements of the Subpart OOOOa standards. Similarly, in September 2018, the federal Bureau of Land
Management ("BLM") issued a rule that relaxes or rescinds certain requirements of its November 2016 rule enacted to reduce
methane emissions by regulating venting, flaring, and leaks from oil and gas operations on federal and American Indian lands.
California and New Mexico have challenged the rule in ongoing litigation. In addition, in April 2018, a coalition of states filed
a lawsuit aiming to force EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural
gas section; that lawsuit is currently pending.
On the international level, in December 2015, the United States joined the international community at the 21st
Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an
agreement requiring member countries to review and “represent a progression” in their intended nationally determined
contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed
by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any
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binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future
emissions. In follow-up to an earlier announcement by President Trump, in August 2017, the U.S. Department of State
officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris
Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an
effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United
States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting
of GHG or otherwise limit emissions of GHG from our equipment and operations could result in increased costs to reduce
emissions of GHG associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from
new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil,
natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant. One or more of
these developments could have a materially adverse effect on our business, financial condition and results of operations.
Additionally, it should be noted that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes
that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if
any such effects were to occur, they could have an adverse effect on our exploration and production operations. At this time, we
have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our
operations. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous
intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to
rise and will not peak until after 2040 and oil and gas will continue to represent a substantial percentage of global energy use
over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could
result in limitations or restrictions on certain sources of funding for the energy sector.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil
from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing
involves the injection of water, sand or alternative proppant and chemical additives under pressure into targeted geological
formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and
natural gas commissions or similar state agencies. However, several federal agencies have conducted investigations or asserted
regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the
potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with
hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA published in June
2016 an effluent limitations guideline final rule pursuant to its authority under the SDWA prohibiting the discharge of
wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment
plants; asserted regulatory authority in 2014 under the SDWA over hydraulic fracturing activities involving the use of diesel
and issued guidance covering such activities; and issued in 2014 a prepublication of its Advance Notice of Proposed
Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic
fracturing. Also, the BLM published a final rule in March 2015 establishing new or more stringent standards for performing
hydraulic fracturing on federal and American Indian lands including well casing and wastewater storage requirements and an
obligation for exploration and production operators to disclose what chemicals they are using in fracturing activities. Following
years of litigation, the BLM rescinded the rule in December 2017; however, that rescission has been challenged by several
environmental groups and states in ongoing litigation. Also, from time to time, legislation has been introduced, but not enacted,
in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the
fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is
adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be
significant in nature, and also could become subject to additional permitting requirements and experience added delays or
curtailment in the pursuit of exploration, development, or production activities.
At the state level, Colorado, where we conduct operations, is among the states that has adopted, and other states are
considering adopting, regulations that could impose new or more stringent permitting, disclosure or well-construction
requirements on hydraulic fracturing operations. For example, significant new oil and gas-related legislation is expected to be
introduced in Colorado in February or March 2019, and while there is uncertainty regarding the specific contents of and
prospects for the anticipated legislation, the political climate in the state suggests that there is a strong appetite for substantial
and swiftly enacted new laws that provide for greater restrictions on oil and natural gas development within the state.
Moreover, states could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State
of New York in 2015. Also, certain interest groups in Colorado opposed to oil and natural gas development generally, and
hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if approved, would
allow revisions to the state constitution in a manner that would make such exploration and production activities in the state
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more difficult in the future. However, during the November 2016 voting process, one proposed amendment placed on the
Colorado state ballot making it relatively more difficult to place an initiative on the state ballot was passed by the voters. As a
result, there are more stringent procedures now in place for placing an initiative on a state ballot. In addition to state laws, local
land use restrictions may restrict drilling or the hydraulic fracturing process and cities may adopt local ordinances allowing
hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. If new or
more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we
operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to
comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production
activities, and perhaps even be precluded from drilling wells.
In the event that local or state restrictions or prohibitions are adopted in areas where we conduct operations, including
the DJ Basin in Colorado, that impose more stringent limitations on the production and development of oil and natural gas,
including, among other things, the development of increased setback distances, we and similarly situated oil and natural
exploration and production operators in the state may incur significant costs to comply with such requirements or may
experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or
precluded in the drilling of wells or in the amounts that we and similarly situated operates are ultimately able to produce from
our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on
our business, prospects, results of operations, financial condition, and liquidity. If new or more stringent federal, state or local
legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on
federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements,
experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be
precluded from drilling wells.
Moreover, because most of our operations are conducted in a particular area, the DJ Basin in Colorado, legal
restrictions imposed in that area will have a significantly greater adverse effect than if we had our operations spread out
amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted
in the DJ Basin in Colorado that impose more stringent limitations on the production and development of oil and natural gas,
we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of
exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the
amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or
prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and
liquidity.
Activities on Federal Lands
Oil and natural gas exploration, development and production activities on federal lands, including American Indian
lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“NEPA”). NEPA requires
federal agencies, including the BLM, 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 that assesses the potential
direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental
Impact Statement that may be made available for public review and comment. While we currently have minimal exploration,
development and production activities on federal lands, our proposed exploration, development and production activities are
expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or
authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost
of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation,
any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in
Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial.
Endangered Species and Migratory Birds Considerations
The federal Endangered Species Act (“ESA”), and comparable state laws were established to protect endangered and
threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on
activities adversely affecting that species or that species’ habitat. Similar protections are offered to migrating birds under the
Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are
listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or
endangered under the ESA may exist. Moreover, as a result of one or more agreements entered into by the U.S. Fish and
Wildlife Service, the agency is required to make a determination on listing of numerous species as endangered or threatened
under the ESA pursuant to specific timelines. The identification or designation of previously unprotected species as threatened
or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from
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species protection measures, time delays or limitations on our exploration and production activities that could have an adverse
impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or
suitable habitat, it could adversely impact the value of our leases.
Employee Safety and Health
We are subject to the requirements of the Occupational Safety and Health Act and comparable state statutes whose
purpose is to protect the health and safety of workers. In addition, OSHA's hazard communication standard, the Emergency
Planning and Community Right-To-Know Act and comparable state statutes and any implementing regulations require that we
maintain and/or disclose information about hazardous materials used or produced in our operations and that this information be
provided to employees, state and local governmental authorities and citizens. For example, under a new OSHA standard
limiting respirable silica exposure, the oil and gas industry must implement engineering controls and work practices to limit
exposures below the new limits by June 2021. Failure to comply with OSHA requirements can lead to the imposition of
penalties.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before
initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these
permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal,
or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other
operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a
result of our exploration and production activities. However, this insurance is limited to activities at the well site and there can
be no assurance that this insurance will continue to be commercially available or that this insurance will be available at
premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified
against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for
gradual, long-term pollution events.
Employees
As of December 31, 2018, we employed 279 people. We are not a party to any collective bargaining agreements and
have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.
From time to time we utilize the services of independent contractors to perform various field and other services.
Facilities
Our corporate headquarters is located in Denver, Colorado.
Available Information
Our common stock is listed and traded on the NASDAQ under the symbol “XOG.” Our reports, proxy statements and
other information filed with the SEC can be inspected and copied at the offices of the NASDAQ, at One Liberty Plaza, 165
Broadway, New York, New York 10006.
We also make available free of charge through our website, www.extractionog.com, electronic copies of certain
documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
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ITEM 1A. RISK FACTORS
RISK FACTORS
There are many factors that may affect our business and results of operations. If any of the following risks actually
occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be
able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not
occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known
to us or that we currently deem immaterial may also materially affect our business.
Risks Related to the Oil, Natural Gas and NGL Industry and Our Business
Oil and natural gas prices are volatile. An extended or further decline in commodity prices may adversely affect our
business, financial condition or results of operations and our ability to meet our capital expenditure obligations and
financial commitments.
The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access
to capital and future rate of growth. Oil, natural gas and NGL are commodities and, therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been
volatile. For example, during the period from January 1, 2014 to December 31, 2018, NYMEX West Texas Intermediate oil
prices ranged from a high of $107.26 per Bbl to a low of $26.21 per Bbl. Average daily prices for NYMEX Henry Hub gas
ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. The duration and magnitude of
the recent decline in oil prices cannot be predicted. This market will likely continue to be volatile in the future. The prices we
receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors
include the following:
• worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and
NGL;
the price and quantity of foreign imports;
political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South
America and Russia;
the level of global exploration and production;
the level of global inventories;
prevailing prices on local price indices in the areas in which we operate;
the proximity, capacity, cost and availability of gathering and transportation facilities;
localized and global supply and demand fundamentals and transportation availability;
•
•
•
•
•
•
•
• members of the Organization of Petroleum Exporting Countries and other oil exporting nations to agree to and
maintain oil price and production controls;
• weather conditions;
•
•
•
•
•
technological advances affecting energy consumption;
the effect of worldwide energy conservation and environmental protection efforts;
the price and availability of alternative fuels;
domestic, local and foreign governmental regulation and taxes; and
shareholder activism and activities by non-governmental organizations to restrict the exploration, development
and production of oil and natural gas.
Since November 2014, prices for U.S. oil have weakened in response to continued high levels of production, a buildup
in inventories and lower global demand. Prices for oil have showed some recovery beginning in late 2016 and continuing into
2018, but remain significantly below 2014 levels.
Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital
or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop
future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGL that we can produce
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economically and may impact our ability to satisfy our obligations under firm-commitment transportation agreements. We have
historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip
prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may
be limited, and we are not under an obligation to hedge a specific portion of our oil or natural gas production.
Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to
economic limits. While it is difficult to project future economic conditions and whether such conditions will result in
impairment of proved property costs, we consider several variables including specific market factors and circumstances at the
time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and
other factors. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate
strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require
us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved
undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to
continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or
extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of
operations, liquidity or ability to finance planned capital expenditures.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted
returns.
We have acquired significant amounts of unproved property in order to further our development efforts and expect to
continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to
many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties
and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over
time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our
investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us
will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all
or any portion of our investment in such unproved property or wells.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities
associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including
recoverable reserves, development and operating costs and potential liabilities, including environmental liabilities. Such
assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the
future may not produce as projected. In connection with the assessments, we perform a review of the subject properties, but
such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every
well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe
corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities
from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the
physical condition of the properties in addition to the risk that the properties may not perform in accordance with our
expectations.
Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required
capital or financing on satisfactory terms, which could lead to a decline in our reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital
expenditures for the exploitation, development and acquisition of oil and natural gas reserves. We expect to fund our 2019
capital expenditures with borrowings under our revolving credit facility and possibly through asset sales or additional capital
markets transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates
as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and
other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices
from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to
grow production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity
and Capital Resources.”
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Substantially all of our producing properties are located in the DJ Basin of Colorado, making us vulnerable to risks
associated with operating in one major geographic area. Specifically, as the DJ Basin is an area of high industry activity, we
may be unable to hire, train or retain qualified personnel needed to manage and operate our assets.
Substantially all of our producing properties are geographically concentrated in the DJ Basin of Colorado, an area in
which industry activity has increased rapidly. At December 31, 2018, substantially all of our total estimated proved reserves
were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to
the impact of regional supply and demand factors or other regional events, delays or interruptions of production from wells in
this area caused by governmental regulation, including at the state and local level, processing or transportation capacity
constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the
processing or transportation of oil, natural gas or NGL. For example, bottlenecks in processing and transportation that have
occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations. Similarly, the
concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in
field-wide rules that could adversely affect development activities or production relating to those formations. In addition, in
areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field,
the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high
cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and
exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could
have a material adverse effect on our business, financial condition, or results of operations.
Specifically, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has
increased over the past few years and may increase substantially in the future. Moreover, our competitors, including those
operating in multiple basins, may be able to offer better compensation packages to attract and retain qualified personnel than
we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and
planned development activities could have a negative effect on production volumes or significantly increase costs, which could
have a material adverse effect on our results of operations, liquidity and financial condition.
Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes specific
to the DJ Basin of Colorado, could have a material adverse effect on our business
Our business is subject to various forms of government regulation. Some local governments are adopting new
requirements and restrictions on hydraulic fracturing and other oil and natural gas operations. Some local governments in
Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while
other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective.
Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently
prohibiting hydraulic fracturing. Since that time, local district courts have struck down the ordinances for certain of those
Colorado cities, and such decisions were upheld by the Colorado Supreme Court in May 2016. Nevertheless, there is a
continued risk that cities will adopt local ordinances that seek to regulate the time, place, and manner of hydraulic fracturing
activities and oil and natural gas operations within their respective jurisdictions.
In addition, in 2014, 2016 and 2018, opponents of hydraulic fracturing sought statewide ballot initiatives that would
have restricted oil and gas development in Colorado. The 2014 initiatives were withdrawn in return for the creation of a task
force to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities, and none of
the 2016 initiatives were successful. However, in 2018, the Colorado Secretary of State approved a citizen-initiated ballot
measure, referred to as Prop. 112, for inclusion on the statewide voter ballot in November 2018. Prop. 112 sought to amend the
Colorado Revised Statutes to increase setback distances by requiring that all new oil and gas development on non-federal lands
(i.e. state and private lands) be located at least 2,500 feet away from certain occupied structures, including homes, schools and
hospitals, as well as certain defined "vulnerable areas," including playgrounds, permanent sports fields, public parks and open
spaces, public drinking water sources, reservoirs, lakes, rivers, perennial and intermittent streams, and creeks. In contrast, rules
adopted and enforced by the COGCC currently require that wells and production facilities be located at least 500 feet away
from homes and 1,000 feet away from certain defined high occupancy building units, including schools, subject to certain
exceptions. The term "oil and gas development" was broadly defined under Prop. 112 to include oil and gas exploration,
drilling, hydraulic fracturing, flowlines, production and processing activities, including the development and production
activities central to our operations. Under Prop. 112, state and local governments would have been allowed to designate
vulnerable areas beyond those that are defined in the measure, but the proposal provided no additional guidance on procedures
or any limitations with respect to such designations. Prop. 112 further provided that the state or a local government may
increase the setback to a distance larger than 2,500 feet, again without any defined procedure, limitations, or governing
standards. The COGCC conducted a study in 2018 and determined that, if Prop. 112 had been approved by state voters, an
estimated 54% of Colorado's total land surface would be unavailable for new oil and gas development, or 85% of all non-
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federal lands. Focusing on Weld County, located in the DJ Basin, the 2018 COGCC study determined that approval and
adoption of Prop. 112 would have precluded new oil and gas development on approximately 78% of the total land surface and
85% of the non-federal land surface in the county. If Prop. 112 were to have passed and become law in the State of Colorado,
we would have likely encountered updates to our long-term forecast which could have negatively impacted future operating
cash flows, credit facility re-determinations, minimum volume commitments and lead to potential non-cash impairments.
Although Prop. 112 was ultimately unsuccessful, similar efforts are likely to continue in the future, which, if
successful, could result in dramatically reducing the area available for future oil and gas development in Colorado or outright
banning oil and gas development in Colorado. We cannot predict the nature or outcome of future ballot initiatives or other
similar efforts. If we are required to cease operating in any of the areas in which we now operate as the result of bans or
moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition,
and results of operations.
Additionally, we are subject to laws and regulations concerning the location, spacing and permitting of the oil and
natural gas wells we drill, among other matters. In particular, our business utilizes a methodology available in Colorado known
as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling
spacing unit to apply to the Colorado Oil & Gas Conservation Commission ("COGCC") for an order forcing all other holders of
oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. This
methodology is especially important for our operations in the Greeley area, where there are many interest holders. Changes in
the legal and regulatory environment governing our industry, particularly any changes to Colorado forced pooling procedures
that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our
business, financial condition and results of operations.
Our cash flow from operations and access to capital are subject to a number of variables, including:
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our proved reserves;
the level of hydrocarbons we are able to produce from existing wells;
the prices at which our production is sold;
the availability of takeaway capacity;
our ability to acquire, locate and produce new reserves; and
our ability to borrow under our revolving credit facility.
If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil, natural gas
and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the
capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to
obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available
borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional
financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a
decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect
our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, development
and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result
in commercially viable oil and natural gas production.
Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the
evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of
which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these
processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies
in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In
addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
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delays imposed by or resulting from compliance with environmental and other regulatory requirements including
limitations on or resulting from wastewater discharge and disposal, subsurface injections, GHG emissions and
hydraulic fracturing;
pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic
fracturing activities;
lack of available capacity on interconnecting transmission pipelines;
equipment failures or accidents, such as fires or blowouts;
lack of available gathering facilities or delays in construction of gathering facilities;
adverse weather conditions, such as blizzards, tornados and ice storms;
issues related to compliance with environmental and other governmental regulations;
environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally
occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids,
toxic gases or other pollutants into the surface and subsurface environment;
declines in oil, natural gas and NGL prices;
limited availability of financing at acceptable terms;
title problems or legal disputes regarding leasehold rights; and
limitations in the market for oil, natural gas and NGL.
Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could
materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of
capital that would be necessary to drill such locations.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future
multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our
ability to drill and develop these locations depends on a number of uncertainties, including oil, natural gas and NGL prices, the
availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results,
lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and
distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the
numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from
these or any other potential locations. In addition, unless production is established within the spacing units covering the
undeveloped acres on which some of the potential locations are obtained or if existing producing wells that are holding leases
with other potential locations cease to continue to produce in commercial quantities, the leases for such acreage will expire. As
such, our actual drilling activities may materially differ from those presently identified.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development
of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able
to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our
overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material
adverse effect on our future business and results of operations.
A substantial portion of our reserves are located in urban areas, which could increase our costs of development and delay
production.
A substantial portion of our reserves are located in urban portions of the DJ Basin, which could disproportionately
expose us to operational and regulatory risk in that area. Much of our operations are within the city limits of various
municipalities in northeastern Colorado. In such urban and other populated areas, we may incur additional expenses, including
expenses relating to mitigation of noise, odor and light that may be emitted in our operations, expenses related to the
appearance of our facilities and limitations regarding when and how we can operate. The process of obtaining permits for
drilling or for gathering lines to move our production to market in such areas may be more time consuming and costly than in
more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our
operations or facilities in such highly populated areas.
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Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to
truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas
production, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.
The marketing of oil and natural gas production depends in large part on the capacity and availability of trucks,
pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities. Access to such
facilities is, in many respects, beyond our control. If there is insufficient capacity available on these systems, or if these
facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production
or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect
to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell our oil and
gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the
inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or
otherwise, especially in areas of planned expansion where such facilities do not currently exist. The amount of oil and gas that
can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and
unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack
of capacity on such facilities. For example, recent increases in activity in the DJ Basin have contributed to bottlenecks in
processing and transportation that have negatively affected our results of operations, and these adverse effects may be
disproportionately severe to us compared to our more geographically diverse competitors. Additionally, we continued to
experience constraints on the capacity available in certain pipelines that we use to transport natural gas and have been forced to
shut in some production from time to time. Capacity constraints typically reduce the productivity of some of our older vertical
wells and may on occasion limit incremental production from some of our newer horizontal wells. This constrains our
production and reduces our revenue from the affected wells. Capacity constraints affecting natural gas production also impact
the associated NGL. We are also dependent on the availability and capacity of oil purchasers for our production. Increases in
the amount of oil that we transport out of the DJ Basin for sale would result in an increase in our transportation costs and would
reduce the price we receive for the affected production.
Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as
changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In
addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the DJ
Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel,
which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a
few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances
will arise and their duration.
While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these
initiatives may be delayed or unsuccessful. As a result, our business, financial condition and results of operations could be
adversely affected.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our debt arrangements contain a number of significant covenants, including restrictive covenants that may limit our
ability to, among other things:
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incur additional indebtedness;
sell assets;
• make loans to others;
• make certain acquisitions and investments;
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enter into mergers, consolidations or other transactions resulting in the transfer of all or substantially all of our
assets;
• make certain payments, including paying dividends or distributions in respect of our equity;
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hedge future production or interest rates;
redeem and prepay other debt;
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
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In addition, our debt arrangements require us to maintain certain financial ratios or to reduce our indebtedness if we
are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a
future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also
be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants
under our debt arrangements will impose on us.
Our revolving credit facility limits the amount we can borrow up to the lower of our aggregate lender commitments
and a borrowing base amount, which the lenders, in their sole discretion, will determine on a semi-annual basis based upon
projected revenues from the oil and natural gas properties securing our loan. The lenders will be able to unilaterally adjust the
borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the
borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders does
not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such
lenders. We will be required to repay outstanding borrowings in excess of the borrowing base. Our borrowing base is $1.2
billion, subject to the current maximum lending commitments of $650.0 million.
A breach of any covenant in our revolving credit facility will result in a default under the revolving credit facility after
any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the
facility and a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The
accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the
required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time,
it may not be on terms that are acceptable to us. In addition, our obligations under our revolving credit facility are secured by
perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural
gas properties having at least 90% of the reserve value as determined by reserve reports, and if we are unable to repay our
indebtedness under the revolving credit facility, the lenders could seek to foreclose on our assets.
We may be subject to risks in connection with divestitures
In 2018, we completed divestitures of several of our non-strategic assets and we have additional divestitures pending,
as discussed in Item. "Business-Recent Developments." In addition, in 2019 we announced our ongoing initiative to divest of
non-strategic assets in order to increase capital resources available for other core assets, create organizational and operational
efficiencies or for other purposes. Various factors could materially affect our ability to dispose of such assets, including the
approvals of governmental agencies or third parties and the availability of purchases willing to acquire the assets with terms we
deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance
that this evaluation will result in any specific action.
Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The
magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction
and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from
guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may
remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform
these obligations.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to
satisfy our obligations under our debt arrangements, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving
credit facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to
prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If oil and
natural gas prices remain at their current level for an extended period of time or decline, we may not be able to maintain a level
of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our
indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or
delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our
ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at
such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous
covenants, which could further restrict business operations. The terms of existing or future debt arrangements may restrict us
from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding
indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows
and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or
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operations to meet debt service and other obligations. Our revolving credit facility and the indentures governing our 2024 Notes
and 2026 Notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not
be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt
service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt
service obligations.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development
of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able
to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our
overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material
adverse effect on our future business and results of operations.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas
and NGL, we enter into commodity derivative contracts for a significant portion of our production, primarily consisting of
swaps, put options and call options. See “Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Overview—Sources of Our Revenues.” Accordingly, our earnings may fluctuate significantly as a result of
changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contractual obligations;
there is an increase in the differential between the underlying price in the derivative instrument and actual prices
received; or
there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into
derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our
cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital
expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future
collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas and NGL prices
and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for
oil, natural gas and NGL, which could also have an adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a
contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make
them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are
unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict
sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which
increases our counterparty credit exposure. While we utilize multiple counterparties, if the creditworthiness of our
counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity
derivative contracts.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve
estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data
and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any
significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present
value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We
must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this
data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling
and operating expenses, capital expenditures, taxes and availability of funds.
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Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could
materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to
reflect production history, results of exploration and development, existing commodity prices and other factors, many of which
are beyond our control.
You should not assume that the present value of future net revenues from our reserves is the current market value of
our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on
the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For
example, our estimated proved reserves as of December 31, 2018 were calculated under SEC rules using the unweighted
arithmetic average first-day-of-the-month prices for the prior 12 months of $65.56/Bbl for oil and $3.10/MMBtu for natural
gas, which for certain periods of 2018 were substantially above the available spot oil and natural gas prices. Using lower prices
in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.
There is a limited amount of production data from horizontal wells completed in the DJ Basin. As a result, reserve estimates
associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves
attributable to vertical wells in the same area.
Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a
particular well or field. Horizontal drilling in the DJ Basin is a relatively recent development, whereas vertical drilling has been
utilized by producers in this area for over 50 years. As a result, the amount of production data from horizontal wells available to
reserve engineers is relatively small compared to that of production data from vertical wells. Until a greater number of
horizontal wells have been completed in the DJ Basin, and a longer production history from these wells has been established,
there may be a greater variance in our proved reserves on a year-over-year basis due to the transition from vertical to horizontal
reserves in both the proved developed and proved undeveloped categories. We cannot assure you that any such variance would
not be material and any such variance could have a material and adverse impact on our cash flows and results of operations. If
our horizontal wells do not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate, we
may not realize an acceptable return on our investments in such projects.
Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve
risks and uncertainties in their application.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service
providers. During the year ended December 31, 2018, we have drilled 286 gross one-mile equivalent horizontal wells and have
completed 268 gross one-mile equivalent horizontal wells, and therefore are subject to increased risks associated with
horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face
while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired
drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not
being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing
our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run
tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after
completion of the final fracture stimulation stage. In addition, our horizontal drilling activities may adversely affect our ability
to successfully drill in one or more of our identified vertical drilling locations. Ultimately, the success of these drilling and
completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a
sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program
because of capital constraints, lease expirations, access to gathering systems and/or commodity prices decline, the return on our
investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could
incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the
future.
Approximately 56% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or
become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse
effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
As of December 31, 2018, approximately 56% of our net leasehold acreage was undeveloped, or acreage on which
wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural
gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage
covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future
cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
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We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of
actual volume throughput.
We may enter into firm transportation, gas processing, gathering and compression service, water handling and
treatment, or other agreements that require minimum volume delivery commitments. Our oil marketer is subject to a firm
transportation agreement that commenced in November 2016 and has a ten-year term with a monthly minimum delivery
commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d
in years eight through ten. In May 2017, we amended this agreement with our oil marketer that requires us to sell all of our
crude oil from an area of mutual interest in exchange for a make-whole provision that allows us to satisfy any minimum
volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum
volume commitment through October 31, 2018. In December 2017, we extended the term of this agreement through October
31, 2019 and posted a letter of credit in the amount of $35.0 million. We are currently in the process of amending and extending
this agreement. We evaluate our contracts for loss contingencies and accrues for such losses, if the loss can be reasonably
estimated and deemed probable. We also have two long-term crude oil gathering commitments with an unconsolidated
subsidiary, in which we have a minority ownership interest. The first agreement commenced in November 2016 and has a term
of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/
d for years three through five and 10,000 Bbl/d for years six through ten. The second agreement will commence in or around
July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year
three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The remaining
aggregate amount of estimated payments under these agreements is approximately $875.8 million. If we have insufficient
production to meet the minimum volumes under this agreement or any other firm commitment agreement we may enter into,
our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital
expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results or
operations.
The prices we receive for our production may be affected by local and regional factors.
The prices we receive for our production will be determined to a significant extent by factors affecting the local and
regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in
the region to process, and transport, our production and that of other producers. Those factors result in basis differentials
between the published indices generally used to establish the price received for regional oil and natural gas production and the
actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which
our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.
Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.
Our exploration, exploitation and development activities and equipment could be adversely affected by extreme
weather conditions, such as winter storms, which may cause a loss of production from temporary cessation of activity or lost or
damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including
access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our
access to, necessary third-party services, such as gathering, processing, compression and transportation services. These
constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our
operation and capital costs, which could have a material adverse effect on our business, financial condition and results of
operations.
SEC rules could limit our ability to book additional PUDs in the future.
SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be
drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book
additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill
or plan on delaying those wells within the required five-year timeframe.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital
expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately
developed or produced.
At December 31, 2018, approximately 60% of our total estimated proved reserves were classified as proved
undeveloped. The development of our estimated proved undeveloped reserves of 208,395 MBoe will require an estimated $1.9
billion of development capital over the next five years.
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Development of these reserves may take longer and require higher levels of capital expenditures than we currently
anticipate. The future development of our proved undeveloped reserves is dependent on future commodity prices, costs and
economic assumptions that align with our internal forecast, as well as access to liquidity sources, such as the capital markets,
our revolving credit facility and derivative contracts. Delays in the development of our reserves, increases in costs to drill and
develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped
reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In
addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as
unproved reserves.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other
parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of
drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity
obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other
working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these
working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity
obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare
bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those
costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely
affect our financial position.
We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to
control the operation and profitability of such properties.
We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over
such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint
operating agreements and other similar contractual arrangements.
As a participant in these operations, we may not be able to maximize the value associated with these properties in the
manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on
properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including
such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities,
the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s
operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will
impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A
third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways
that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital
in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their
carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our
properties.
Accounting rules require that we periodically review the carrying value of our properties for possible
impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the
continuing evaluation of development plans, production data, economics and other factors such as lease expirations, changes in
drilling plans and adverse drilling results, we may be required to write down the carrying value of our properties. A write down
constitutes a non-cash charge to earnings. If market or other economic conditions deteriorate or if oil, natural gas and NGL
prices continue to decline, we may incur impairment charges in 2019 or later periods, which may have a material adverse effect
on our results of operations.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline,
which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and
exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those
reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are
highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or
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acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves
to replace our current and future production. If we are unable to replace our current and future production, the value of our
reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
Conservation measures and technological advances could reduce demand for oil, natural gas and NGL.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural
gas and NGL, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas
and NGL. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our
business, financial condition, results of operations and cash flows.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or
more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGL
we produce.
The availability of a ready market for any oil, natural gas and NGL we produce depends on numerous factors beyond
the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity
and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of
oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon
several significant purchasers for the sale of most of our oil and natural gas production. See “Business—Operations—
Marketing and Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future
oil and natural gas production.
The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.
We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. Two,
three and four purchasers accounted for more than 10% of our revenues in the years ended December 31, 2018, 2017 and 2016,
respectively. This concentration of purchasers may impact our overall credit risk in that these entities may be similarly affected
by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The
inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may materially
adversely affect our financial condition and results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we
may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could
materially and adversely affect our business, financial condition or results of operations.
Our exploration and production activities are subject to all of the operating risks associated with drilling for and
producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural
gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental
hazards such as oil spills, natural gas leaks, pipeline and tank ruptures or unauthorized discharges of toxic gases or other
pollutants.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result
of claims for:
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injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is
excessive relative to the risks presented. Moreover, insurance may not be available in the future at commercially reasonable
costs and on commercially reasonable terms. Also, pollution and other environmental risks generally are not fully
insurable. The occurrence of an event that is not covered or fully covered by insurance and any delay in the payment of
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insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of
operations.
Properties that we decide to drill may not yield oil, natural gas or NGL in commercially viable quantities.
Properties that we decide to drill that do not yield oil, natural gas or NGL in commercially viable quantities will
adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing
whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to
be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same
area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil
or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data
from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our
drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
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unexpected drilling conditions;
title problems;
pressure or lost circulation in formations;
equipment failure or accidents;
adverse weather conditions;
compliance with environmental and other governmental or contractual requirements; and
increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or
workover rigs, equipment and services.
We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to
do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of oil and gas properties or businesses that complement or expand our current
business. The successful acquisition of oil and gas properties requires an assessment of several factors, including:
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recoverable reserves;
future oil, natural gas and NGL prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify accretive acquisition
opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be
generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to
become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be
performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even
when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for
environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities,
we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into
our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a
disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and
for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able
to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on
acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the
acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties
could have a material adverse effect on our financial condition and results of operations.
In addition, our debt arrangements will impose certain limitations on our ability to enter into mergers or combination
transactions. Our debt arrangements will also limit our ability to incur certain indebtedness, which could indirectly limit our
ability to engage in acquisitions.
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We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to
examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land
men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a
lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely
affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling
operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may
lose the lease and the right to produce all or a portion of the minerals under the property.
We are subject to stringent environmental and health and safety laws and regulations that could expose us to significant
costs and liabilities.
Our oil and natural gas exploration, development and production operations are subject to numerous stringent and
complex federal, state and local laws and regulations governing safety and health aspects of our operations, the release,
disposal or discharge of materials into the environment or otherwise relating to environmental protection. These laws and
regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before
conducting drilling and other regulated activities; the restriction of types, quantities and concentration of materials that may be
released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness,
wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the
imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the
EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued
under them, often requiring costly actions. For example, on May 2, 2017, following an incident in Firestone, Colorado, the
COGCC issued a Notice to Operators (the “Notice”) that, among other things, required operators of oil and natural gas wells in
Colorado: (i) by May 30, 2017, to re-inspect all existing flowlines and pipelines located within 1,000 feet of a defined “building
unit,” which term includes residences and certain commercial facilities, to identify the well API number and tank battery
location ID number associated with each line; (ii) by May 30, 2017, to inspect all existing flowlines and pipelines, regardless of
distance to a “building unit,” to verify that any existing flowline or pipeline not in use, regardless of when it was installed or
taken out of service, is abandoned in conformity with applicable rules; (iii) by June 30, 2017, to ensure and document that all
flowlines within 1,000 feet of a “building unit” have integrity; and (iv) by June 30, 2017, to complete abandonment of any
flowline or pipeline not actively operated, regardless of distance to a “building unit,” and regardless of when it was installed or
taken out of service, in conformity with the applicable rules and the Notice. In August 2017, the Governor of Colorado
announced several policy initiatives designed to enhance public safety that are to be implemented through rulemaking or
legislation. On February 13, 2018, the COGCC approved new oil and natural gas flowline requirements, which include: (i)
requirements for more-detailed tracking, location data, and record-keeping for flowlines that carry fluids away from a specific
oil and gas location; (ii) requirements that any flowlines not in use, but not yet abandoned, are locked and marked and must
continue to undergo integrity testing under the same standards as active lines until abandonment, and any risers associated with
abandoned flowlines must be cut below grade; (iii) more-detailed requirements for operators to demonstrate flowline integrity,
including updated standards for integrity-testing lines, more testing options that align with newer technology, and the
elimination of pressure-testing exemptions for low-pressure lines; and (iv) requirements for full operator participation in the
Utility Notification Center of Colorado’s “one-call” program to ensure a centralized home for all data on flowline locations and
access to that information through the established 811 “call-before-you-dig” system. Failure to comply with these laws and
regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of
investigatory, remedial or corrective obligations, the occurrence of delays in permitting or development of projects and the
issuance of orders limiting or prohibiting some or all of our operations in a particular area or forcing future compliance with
environmental requirements.
The performance of our operations may result in significant environmental costs and liabilities due to our handling of
petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges
related to our operations, and because of historical operations and waste disposal practices at our leased and owned
properties. Spills or other releases of regulated substances could expose us to material losses, expenditures and liabilities under
environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several
liability for the removal or remediation of previously released materials or property contamination, regardless of whether we
were responsible for the release or contamination and even if our operations met previous standards in the industry at the time
they were conducted. Changes in environmental laws and regulations occur frequently, and any changes that result in more
stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste
handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and
maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or
financial condition. We may not be able to recover some or any of our costs with respect to such developments from
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insurance. See “Business—Regulation of Environmental and Safety and Health Matters” for a further description of
environmental and safety and health laws and regulations that affect us.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could
adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists,
geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in
correlation with oil, natural gas and NGL prices, causing periodic shortages. Historically, there have been shortages of drilling
and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells
being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will
be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget,
which could have a material adverse effect on our business, financial condition or results of operations.
Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could
be subject to substantial penalties and fines.
Under the EPAct 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current
violations of up to $1.0 million per day for each violation. FERC may also impose administrative and criminal remedies and
disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas
company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional
facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by
FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time
to time. Additionally, the FTC has regulations intended to prohibit market manipulation in the petroleum industry with
authority to fine violators of the regulations civil penalties of up to $1.0 million per day, and the CFTC prohibits market
manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and
futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil
penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to comply with
those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and
Gas Industry.”
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as
title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the
ordinary course of our business. Additionally, citizen groups have brought and, in certain instances, may continue to bring legal
proceedings against us to challenge our ability to receive environmental permits that we need to operate. Such legal
proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could
have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In
addition, it is possible that a resolution of one or more such proceedings could result in liability, loss of necessary
environmental permits, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our
business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals
for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses
related to legal and other proceedings could change from one period to the next, and such changes could be material.
Climate change legislation or regulations restricting emissions of GHG could result in increased operating costs and
reduced demand for the oil, natural gas and NGL that we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have
been made and could continue to be made at the international, national, regional and state levels of government to monitor and
limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting
and tracking programs, and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA
has adopted rules under authority of the CAA that, among other things, establish PSD construction and Title V permit reviews
for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant
emissions, which reviews could require meeting “best available control technology” standards for those emissions. In addition,
the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural
gas system sources in the United States, including, among other things, onshore producing facilities, which include certain of
our operations. Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations,
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with the EPA publishing NSPS Subpart OOOOa standards in June 2016 that require certain new, modified or reconstructed
facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions and the BLM
publishing requirements in November 2016 to reduce methane emissions from venting, flaring, and leaking on public lands. In
September 2018, both of the EPA and BLM took steps to relax or rescind certain requirements under their respective methane
rules. EPA proposed amendments that would relax requirements of the NSPS OOOOa standards and BLM issued a rule that
relaxes or rescinds requirements of its November 2016 regulations. California and New Mexico have challenged BLM's
September 2018 rule in ongoing litigation. Additionally, in December 2015, the United States joined the international
community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris,
France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally
determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement”
was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not
create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or
reduce future emissions. In follow-up to an earlier announcement by President Trump, in August 2017, the U.S. Department
officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris
Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an
effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United
States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting
of GHG or otherwise limit emissions of GHG from, our equipment and operations could result in increased costs to reduce
emissions of GHG associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from
new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil,
natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant. One or more of
these developments could have a materially adverse effect on our business, financial condition and results of operations.
Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous
intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to
rise and will not peak until after 2040 and oil and gas will continue to represent a substantial percentage of global energy use
over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could
result in limitations or restrictions on certain sources of funding for the energy sector. Please read “Business-Regulation of
Environmental and Safety and Health Matters-Regulation of Greenhouse Gas (“GHG”) Emissions” for a further description of
the laws and regulations relating to climate change that affect us.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our
production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil
from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing
involves the injection of water, sand or alternative proppant and chemical additives under pressure into targeted geological
formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and
natural gas commissions or similar state agencies but several federal agencies have asserted regulatory authority over certain
aspects of the process. In addition, in December 2016, the EPA released its final report on the potential impacts of hydraulic
fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact
drinking water resources under certain circumstances. Also, from time to time, the U.S. Congress has considered, but not
adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in
the fracturing process. At the state level, Colorado, where we conduct operations, is among the states that has adopted, and
other states are considering adopting, regulations that impose new or more stringent permitting, disclosure or well-construction
requirements on hydraulic fracturing operations. States may elect to prohibit high volume hydraulic fracturing altogether,
following the approach taken by the State of New York. In addition to state laws, local land use restrictions may restrict drilling
or the hydraulic fracturing and cities may adopt local ordinances allowing hydraulic fracturing activities within their
jurisdictions but regulating the time, place and manner of those activities. If new or more stringent federal, state or local legal
restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on
federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements,
experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be
precluded from drilling wells.
Moreover, because most of our operations are conducted in a particular area, the DJ Basin in Colorado, legal
restrictions imposed in that area will have a significantly greater adverse effect than if we had our operations spread out
amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted
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in the DJ Basin in Colorado that impose more stringent limitations on the production and development of oil and natural gas,
we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of
exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the
amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or
prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and
liquidity.
Please read “Business—Regulation of Environmental and Safety and Health Matters—Hydraulic Fracturing
Activities” for a further description of the laws and regulations relating to hydraulic fracturing that affect us.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market
oil or natural gas.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to
evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring
properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital
available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in
acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have
a material adverse effect on our business.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive
markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if
renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of our
drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase
significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual
drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks
are greater at times and in areas where the pace of our exploration and development activity slows.
Declining general economic, business or industry conditions may have a material adverse effect on our results of
operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of
credit and the United States financial market have contributed to increased economic uncertainty and diminished expectations
for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in
the United States or other countries could adversely affect the global economy. These factors, combined with volatile
commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic
slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial
markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for
petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our
vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and
financial condition.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to
obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or
technical personnel could have a material adverse effect on our business, financial condition and results of operations.
We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating
history.
We have grown rapidly since we began operations in late 2012. Our management believes that our future success
depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on
management personnel. The following factors could present difficulties:
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increased responsibilities for our executive level personnel;
increased administrative burden;
increased capital requirements; and
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increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The
historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the
future. In addition, our operating history is limited and the results from our current producing wells are not necessarily
indicative of success from our future drilling operations.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital,
increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit
our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive
disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability
impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows
from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and
operating results.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and
natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to
assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know
whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced
technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of
such expenditures. As a result, our drilling activities may not be successful or economical.
Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or
completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural
gas and NGL. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which
will in turn negatively affect our cash flow from operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have
an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic
fracturing processes. Historically, we have been able to purchase water from local land owners for use in our
operations. Drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for
hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources,
we may be unable to produce oil, natural gas and NGL economically, which could have an adverse effect on our financial
condition, results of operations and cash flows.
Restrictions on drilling activities intended to protect certain species of wildlife and natural resources may adversely affect
our ability to conduct drilling activities areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions
on drilling activities designed to protect various wildlife and natural resources. Seasonal restrictions may limit our ability to
operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified
personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high
costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to
protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation
measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could
cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and
production activities that could have a material adverse impact on our ability to develop and produce our reserves.
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The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce
the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter
derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the
SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, in
November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent
swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging
transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this
time. The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with
clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the
CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for
uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and
margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market
participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any
of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash
available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It
is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of
such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts,
materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and
reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of
the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less
predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was
intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative
trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be
adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these
consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition,
the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To
the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of
which is not clear at this time.
Recent changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations
or financial condition overall.
The final version of the tax reform bill commonly known as the Tax Cuts and Jobs Act (the "TCJA") signed into law
on December 22, 2017 may affect our cash flows, results of operations and financial condition. Among other items, the TCJA
repealed the deduction for certain U.S. Production activities and provided for a new limitation on the deduction for interest
expense. Given the scope of this law and the potential interdependency of its changes, it is difficult at this time to assess
whether the overall effect of the TCJA will be cumulatively positive or negative for our earnings and cash flow, but such
changes may adversely impact our financial results.
Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development
may be eliminated as a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws,
including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Although none of
these changes were included in the TCJA, future adverse changes could include, but are not limited to, (i) the repeal of the
percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and
development costs, and (iii) an extension of the amortization period for certain geological and geophysical
expenditures. Congress could consider, and could include, some or all of these proposals as part of future tax reform
legislation. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws
could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or
increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations
and cash flows.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and
introductions of new products and services using new technologies. As others use or develop new technologies, we may be
placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at
47
substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources
that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before
we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an
acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial
condition or results of operations could be materially and adversely affected.
Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest
and opposition by activists and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain
unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; 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. The potential for such security threats has subjected our operations to increased risks
that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls
to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in
increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient
to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of
financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material
adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are
becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to
data and systems, 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. These events could lead to financial losses from
remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and
other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially
result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely
affecting our financial condition and results of operations.
Loss of our information and computer systems could adversely affect our business.
We are dependent on our information systems and computer-based programs, including our well operations
information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or
create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of
communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process
commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have
a material adverse effect on our business.
Risks Related to our Common Stock
The requirements of being a public company, including compliance with the reporting requirements of the Securities
Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our
resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely
or cost-effective manner.
We completed our IPO in October 2016. As a public company, we must comply with various laws, regulations and
requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the
requirements of the NASDAQ, with which we were not required to comply as a private company. Complying with these
statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and
will significantly increase our costs and expenses. We are now required to:
•
•
•
•
•
institute a more comprehensive compliance function;
comply with rules promulgated by the NASDAQ;
continue to prepare and distribute periodic public reports in compliance with our obligations under the federal
securities laws;
establish new internal policies, such as those relating to insider trading; and
involve and retain to a greater degree outside counsel and accountants in the above activities.
Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or
improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations.
48
Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if in the future we or our
independent registered public accounting firm identifies deficiencies in our internal controls over financial reporting that are
deemed to be material weaknesses, the market price of our stock could decline, and we could be subject to sanctions or
investigations by the SEC or other regulatory authorities, which would require additional financial and management resources.
In addition, we expect that being a public company subject to these rules and regulations may make it more difficult
and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy
limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more
difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our
financial results or prevent fraud. If one or more material weaknesses emerge related to financial reporting, or if we
otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report
our financial results could be adversely affected. As a result, current and potential stockholders could lose confidence in our
financial reporting, which would harm our business and the trading price of our common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate
successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating
results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful,
that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be
able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain
effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our
operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to
lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our
common stock.
Yorktown’s funds collectively hold a substantial portion of the voting power of our common stock.
Yorktown’s funds currently collectively hold approximately 28% of our common stock. See “Security Ownership of
Certain Beneficial Owners and Management” for more information regarding ownership of our common stock by the Yorktown
funds. The existence of affiliated stockholders with significant aggregate holdings that may act as a group may have the effect
of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of
our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, this
concentration of stock ownership may adversely affect the trading price of our common stock to the extent investors perceive a
disadvantage in owning stock of a company with affiliated stockholders with significant aggregate holdings that may act as a
group.
Conflicts of interest could arise in the future between us, on the one hand, and Yorktown and its affiliates, including its
funds and their respective portfolio companies, on the other hand, concerning among other things, potential competitive
business activities or business opportunities.
Yorktown’s funds are in the business of making investments in entities in the U.S. energy industry. As a result,
Yorktown’s funds may, from time to time, acquire interests in businesses that directly or indirectly compete with our business,
as well as businesses that are significant existing or potential customers. Yorktown’s funds and their respective portfolio
companies may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may
not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, Yorktown’s funds and/
or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses
which may compete with our business or do business with any client of ours. Any actual or perceived conflicts of interest with
respect to the foregoing could have an adverse impact on the trading price of our common stock.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition
bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval.
If our board of directors elects to issue preferred stock in addition to the Series A Preferred Stock, it could be more difficult for
a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more
difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders,
including:
•
limitations on the removal of directors;
49
•
•
limitations on the ability of our stockholders to call special meetings;
establishing advance notice provisions for stockholder proposals and nominations for elections to the board of
directors to be acted upon at meetings of stockholders; and
•
providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws.
We do not intend to pay dividends on our common stock, and our debt arrangements and the Series A Preferred Stock place
certain restrictions on our ability to do so. Consequently, it is possible that the only opportunity to achieve a return on an
investment in our common stock will be if the price of our common stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our debt
arrangements and the Series A Preferred Stock restrict our ability to pay cash dividends. Consequently, it is possible that the
only opportunity to achieve a return on an investment in our common stock will be if shareholders sell their common stock at a
price greater than they paid for it. There is no guarantee that the price of our common stock that will prevail in the market will
ever exceed the price that such investors paid for our common stock.
Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of
equity or convertible securities may dilute the ownership in us by current shareholders.
We may sell additional shares of common stock in public or private offerings. We may also issue additional shares of
common stock or convertible securities. Excluding any shares of common stock issued upon the conversion of our Series A
Preferred Stock including any shares of Series A Preferred Stock that may be issued pursuant to our option to pay dividends on
the Series A Preferred Stock in kind pursuant to the terms of the Certificate of Designations setting forth the terms of the Series
A Preferred Stock, we have 171,666,485 outstanding shares of common stock as of December 31, 2018. In connection with the
IPO, we filed a registration statement with the SEC on Form S-8 providing for the registration of 23,000,000 shares of our
common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions,
the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on
Form S-8 will be available for resale immediately in the public market without restriction. Additionally, the Series A Preferred
Stock are convertible into shares of our common stock pursuant to their terms.
We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the
effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock.
Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception
that such sales could occur, may adversely affect prevailing market prices of our common stock.
We may issue additional preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or
series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our
common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more
classes or series of preferred stock, including the Series A Preferred Stock, could adversely impact the voting power or value of
our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in
all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or
redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the
common stock.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their
recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price
could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities
analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish
reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading
volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our
operating results do not meet their expectations, our stock price could decline.
50
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum
for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’
ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the
Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive
forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim for a breach of a
fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a
claim arising pursuant to any provision of the Delaware General Corporation Law, our certificate of incorporation or our
bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject
to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person
or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and
consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum
provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our
directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a
court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or
more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in
other jurisdictions, which could adversely affect our business, financial condition or results of operations.
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. While the outcomes of these proceedings cannot be predicted with certainty, we do not believe the
results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial
condition, results of operations or liquidity.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
51
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
PART II
Market Information.
Our common stock is currently traded on the NASDAQ under the ticker symbol “XOG.”
Dividend Policy
We have not historically paid, and do not anticipate paying any cash dividends in the future, to common stockholders
of our common stock. In addition, our revolving credit facility, our Senior Notes (collectively, our “debt arrangements”) and
the Series A Preferred Stock place certain restrictions on our ability to pay cash dividends. Please see Note 5 — Long Term
Debt included in the notes to the consolidated financial statements included elsewhere in this Annual Report for more
information regarding the restrictions placed on our ability to pay cash dividends.
Comparison of Cumulative Return
The following graph compares the cumulative total shareholder return on a $100 investment in our common stock on
October 12, 2016 through December 31, 2018, to that of the cumulative return on a $100 investment in the S&P 500 Composite
for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. The indices are
included for comparative purpose only. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be
incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the
date hereof and irrespective of any general incorporation language in any such filing.
Holders
Pursuant to the records of the transfer agent, as of February 19, 2019, the number of holders of record of our common
stock was 60.
Sales of Unregistered Securities
We did not have any sales of unregistered securities during the fiscal year ended December 31, 2018.
52
Issuer Purchases of Equity Securities
The following table sets forth our share repurchase activity for each period presented:
Period
October 1, 2018 - October 31, 2018
November 1, 2018 - November 30, 2018
December 1, 2018 - December 31, 2018
Total
Total Number of
Shares Purchased
Average Price
Paid per Share
— $
3,558,145
500,000
4,058,145
$
—
6.68
4.97
6.47
53
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data as of and for the five-years ended
December 31, 2018. The data as of and for the fiscal years ended December 31 for each respective year was derived from our
historical consolidated financial statements and the accompanying notes included elsewhere in this Annual Report.
The following selected consolidated financial information should be read in conjunction with “Item 7. Management’s
Discussion and Analysis of Financial Conditions and Results of Operations” and the consolidated financial statements and the
notes thereto included in “Item 8. Financial Statements and Supplementary Data” presented elsewhere in this Annual Report for
further discussion of the factors affecting the comparability of the Company’s financial data. Also see “Recent Accounting
Pronouncements” included in the notes to the consolidated financial statements included elsewhere in this Annual Report.
54
Revenues:
Oil sales
Natural gas sales
NGL sales
Total Revenues
Operating Expenses:
Lease operating expenses
Transportation and gathering
Production taxes
Exploration expenses
Depletion, depreciation,
amortization and accretion
Impairment of long lived assets
and goodwill
Other operating expenses
(Gain) loss on sale of property
and equipment and assets of
unconsolidated subsidiary
Acquisition transaction
expenses
General and administrative
expenses
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Commodity derivatives gain
(loss)
Interest expense
Other income
Total Other Income
(Expense)
Income (Loss) Before Income
Taxes
Income tax (expense) benefit (1)
Net Income (Loss)
Net income attributable to
noncontrolling interest
Net Income (Loss) Attributable
to Extraction Oil & Gas, Inc.
Adjustments to reflect Series A
Preferred Stock dividends and
accretion of discount
Net Income (Loss) Available to
Common Shareholders, Basic
and Diluted
Income (Loss) Per Common
Share (2)
Basic and diluted
2018
2017
2016
2015
2014
For the Year Ended December 31,
(in thousands, except per share data)
$
840,687
$
419,904
$
194,059
$
157,024
$
105,629
114,427
1,060,743
79,413
39,411
90,345
31,611
92,322
92,070
604,296
60,358
50,948
51,367
36,256
48,652
35,378
278,089
36,743
25,300
20,730
36,422
26,019
14,707
197,750
23,949
6,679
17,035
18,636
75,460
9,247
8,133
92,840
5,067
—
9,743
126
435,775
314,999
205,348
146,547
34,042
70,928
—
(136,834)
—
134,604
745,253
315,490
(8,554)
(123,330)
5,099
1,647
—
451
—
110,167
626,193
(21,897)
(36,332)
(51,889)
2,010
23,425
10,891
—
2,719
232,388
593,966
(315,877)
(100,947)
(68,843)
386
15,778
2,353
—
6,000
37,149
274,126
(76,376)
79,932
(51,030)
210
(126,785)
(86,211)
(169,404)
29,112
188,705
(66,850)
$
121,855
$
(108,108)
63,700
(44,408) $
(485,281)
29,280
(456,001) $
(47,264)
—
(47,264) $
7,287
—
—
—
—
—
—
—
19,598
68,576
24,264
48,008
(22,454)
24
25,578
49,842
—
49,842
—
114,568
(44,408)
(226,107)
(47,264)
49,842
(16,869)
(16,279)
(3,999)
—
—
97,699
$
(60,687) $
(230,106) $
(47,264) $
49,842
0.56
$
(0.35) $
(1.54)
55
$
$
Selected consolidated financial information continued:
Total Production Volumes:
Oil (MBbls)
Natural Gas (MMcf)
NGL (MBbls)
Total (MBOE)
Average net sales (BOE/d)
Proved Reserves:
Oil (MBbls)
Natural Gas (MMcf)
NGL (MBbls)
Total (MBOE)
Consolidated Cash Flow
Information:
Net cash provided by operating
activities (5)
Net cash used in investing
activities (5)
Net cash provided by financing
activities
Consolidated Balance Sheet
Information:
Total Assets
Long-term Debt
Series A Preferred Stock
Total Equity(3)
Other Financial Data (4):
Adjusted EBITDAX
$
$
$
$
$
$
$
$
As of and for the Year Ended December 31,
2018
2017
2016
2015
2014
14,679
46,847
5,260
27,747
76,019
135,846
703,268
94,851
347,908
9,594
32,395
3,901
18,894
51,764
111,275
626,169
77,106
292,743
5,287
20,212
2,284
10,940
29,891
90,995
507,735
62,448
238,066
3,946
10,823
1,335
7,084
19,408
71,500
292,584
38,383
158,647
1,022
2,664
325
1,792
4,908
45,165
166,416
19,451
92,352
684,933
$
316,965
$
120,688
$
166,683
$
77,390
(897,305) $
(1,404,528) $
(873,608) $
(530,077) $
(960,569)
440,590
$
463,395
$
1,286,750
$
371,404
$
972,090
4,166,027
1,417,659
164,367
1,894,686
659,752
$
$
$
$
$
3,384,669
1,023,361
158,383
1,616,765
380,462
$
$
$
$
$
2,784,776
538,141
153,139
1,616,073
192,265
$
$
$
$
$
1,634,140
637,790
$
$
— $
754,232
176,120
$
$
1,201,069
508,903
—
545,188
66,892
(1) Extraction Oil & Gas, Inc. is a subchapter C corporation (“C-Corp”) under the Internal Revenue Code of 1986, as amended
(the "Code"), and is subject to federal and State of Colorado income taxes. Our predecessor, Extraction Oil & Gas
Holdings, LLC was not subject to U.S. federal income taxes. As a result, the consolidated net income (loss) in our
historical financial statements for periods prior to our October 12, 2016 corporate reorganization to a C-Corp does not
reflect the tax expense we would have incurred as a C-Corp during such periods.
(2) See Note 9 — Equity and Note 12 — Earnings (Loss) Per Share in our consolidated financial statements, included herein,
for additional discussion regarding the calculation of income (loss) per share.
(3) Total Equity includes the noncontrolling interest of $147.9 million associated with Elevation Preferred Units for the year
ended December 31, 2018.
(4) Adjusted EBITDAX is a non-GAAP financial measure. Management defines Adjusted EBITDAX as net income (loss)
adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and accretion ("DD&A"),
impairment of long lived assets and goodwill, exploration expenses, rig termination fees, write off of deposit on
acquisition, (gain) loss on sale of property and equipment, gain on sale of assets of unconsolidated subsidiaries, acquisition
transaction expenses, (gain) loss on commodity derivatives, settlements on commodity derivative instruments, premiums
paid for derivatives that settled during the period, unit and stock-based compensation expense, amortization of debt
discount and debt issuance costs, make-whole premiums, interest expense, income tax expense (benefit) and non-recurring
charges. See Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations,
in this Annual Report for additional disclosures related to Adjusted EBITDAX.
(5) Includes the impact of Accounting Standard Update 2018-18 and 2018-15 on prior year data. See Part II, Item 8, Note 2—
Basis of Presentation and Significant Accounting Policies
56
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and
related notes appearing in “Item 8. Financial Statements and Supplementary Data.” The following discussion contains
forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking
statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ
materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences
include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves,
capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors
discussed below and elsewhere in this Annual Report, particularly in “Risk Factors” and “Cautionary Note Regarding
Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the
forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking
statements except as otherwise required by applicable law.
OVERVIEW
We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas
and NGL reserves, as well as the construction and support of midstream assets to gather and process crude oil and gas
production in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of
Colorado. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development
drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the most productive areas
of what we consider to be the core of the DJ Basin. We are focused on growing our proved reserves and production primarily
through the development of our large inventory of identified liquids-rich horizontal drilling locations.
Our Properties
We have assembled, as of December 31, 2018, approximately 179,300 net acres of large, contiguous acreage blocks in
some of the most productive areas of what we consider to be the core of the DJ Basin as indicated by the results of our
horizontal drilling program and the results of offset operators. Additionally, we hold approximately 138,100 net acres outside of
what we consider our Core DJ Basin, which we refer to as our “Other Rockies Area,” that we believe is prospective for many of
the same formations as our properties in the Core DJ Basin. We operated 96% of our horizontal production for the year ended
December 31, 2018, our total estimated proved reserves were approximately 347.9 MMBoe, of which approximately 40% were
classified as proved developed reserves. For more information about our properties, please read “Business—Our Properties.” in
Items 1. and 2. of this Annual Report.
Financial Overview
For the year ended December 31, 2018, we had net income of $121.9 million as compared to a net loss of $44.4
million for the year ended December 31, 2017. The change to net income was primarily driven by an increase in sales revenues
of $456.4 million, partially offset by an increase in operating expenses of $119.1 million, which includes the gain on sale of
property and equipment and assets of unconsolidated subsidiary of $136.8 million. Additionally, we had an increase in interest
expense of $71.4 million, which includes a make-whole premium of $35.6 million and $9.4 million of accelerated amortization
expense upon the redemption of our 2021 Senior Notes.
For the year ended December 31, 2018, crude oil, natural gas and NGL sales, coupled with the impact of settled
derivatives, increased to $930.1 million as compared to $585.7 million in the same prior year period due to an increase in sales
volumes of 8,853 MBoe and an increase of $2.52 in realized price per BOE, including settled derivatives.
Adjusted EBITDAX was $659.8 million for the year ended December 31, 2018, as compared to $380.5 million in the
same period in 2017, reflecting a 73% increase. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of
Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in
accordance with GAAP, please read “Adjusted EBITDAX.”
57
Operational Overview
During the year ended December 31, 2018, we continued to focus on growing production while at the same time
implementing operational efficiencies to reduce drilling and completion costs. We incurred approximately $776.1 million in
drilling 161 gross (129.7 net) wells with an average lateral length of 1.8 miles and completing 161 gross (137.4 net) wells with
an average lateral length of 1.7 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred
approximately $116.4 million of leasehold and surface acreage additions, excluding acquisitions. These capital expenditures
exclude the impact of the decrease in outstanding elections of $6.7 million. In addition, Elevation Midstream, LLC, our wholly
owned midstream subsidiary, incurred $108.2 million of capital expenditures.
Income Taxes
On December 22, 2017, the TCJA was enacted making significant changes to the Internal Revenue Code. Many of the
provisions in the TCJA have an effective date for years beginning after December 31, 2017, including the lowering of the U.S.
corporate rate from 35% to 21%. As a result of the enactment date of December 22, 2017, we were required to remeasure the
deferred tax assets and liabilities at the rate in which they are expected to reverse. We provisionally recorded an income tax
benefit in the amount of $23.4 million related to the remeasurement of the net deferred tax liability as of December 31, 2017.
During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation
under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4
million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. There are no
remaining provision amounts associated with the TCJA as of December 31, 2018.
In connection with the IPO in October 2016, our accounting predecessor, Extraction Oil & Gas Holdings, LLC
("Holdings") was merged into the Company. Prior to this corporate reorganization, we were not subject to federal or state
income taxes. Accordingly, the financial data attributable to us prior to such corporate reorganization contain no provision for
federal or state income taxes because the tax liability with respect to Holdings’ taxable income was passed through to our
members. Beginning October 12, 2016, we began to be taxed as a C corporation under the Code, prior to the TCJA enactment,
and subject to federal and state income taxes at a blended statutory rate of approximately 38% of pretax earnings.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and gas operations,
including:
•
•
Sources of revenue;
Sales volumes;
• Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative
contracts;
• Lease operating expenses (“LOE”);
• Capital expenditures; and
• Adjusted EBITDAX (a Non-GAAP measure).
Sources of Our Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are
extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of
derivatives. For the year ended December 31, 2018, our revenues were derived 79% from oil sales, 10% from natural gas sales
and 11% from NGL sales. For the year ended December 31, 2017, our revenues were derived 70% from oil sales, 15% from
natural gas sales and 15% from NGL sales. For the year ended December 31, 2016, our revenues were derived 70% from oil
sales, 17% from natural gas sales and 13% from NGL sales. Our revenues may vary significantly from period to period as a
result of changes in volumes of production sold or changes in commodity prices.
58
Sales Volumes
The following table presents historical sales volumes for our properties for the periods indicated:
Oil (MBbl)
Natural gas (MMcf)
NGL (MBbl)
Total (MBoe)
Average net sales (BOE/d)
For the Year Ended
December 31,
2018
2017
2016
14,679
46,847
5,260
27,747
76,019
9,594
32,395
3,901
18,894
51,764
5,287
20,212
2,284
10,940
29,891
As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production
and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Accordingly,
we plan to maintain our focus on adding reserves through organic growth as well as acquisitions. Our ability to add reserves
through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of
operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and
successfully identify and consummate acquisitions. We estimate that midstream constraints negatively impacted our production
by approximately 18.5 MBOE/d, or 24%, during the year ended December 31, 2018. We are currently working with various
midstream providers to address processing constraints in the DJ Basin. Please read “Risks Related to the Oil, Natural Gas and
NGL Industry and Our Business” in Item 1A. of this Annual Report for a further description of the risks that affect us.
Realized Prices on the Sale of Oil, Natural Gas and NGL
Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability
to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For
example, during the period from January 1, 2014 to December 31, 2018, average daily prices for NYMEX West Texas
Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $26.21 per Bbl. Average daily prices for NYMEX
Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. Declines in, and
continued depression of, the price of oil and natural gas occurring during 2015 and also during 2018 are due to a combination
of factors including increased U.S. supply, global economic concerns and geopolitical risks. These price variations can have a
material impact on our financial results and capital expenditures.
Oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and
international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil
in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of
quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions
based on NYMEX pricing, adjusted for differentials.
Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline
capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a
widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale
of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example,
wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater
quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the
natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the
processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The
price we receive for our natural gas produced in the DJ Basin is based on CIG prices, adjusted for certain deductions.
Our price for NGL produced in the DJ Basin is based on a combination of prices from the Conway hub in Kansas and
Mont Belvieu in Texas where this production is marketed.
59
The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month
contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies,
but our oil, natural gas and NGL normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, as
applicable.
Oil
NYMEX WTI High ($/Bbl)
NYMEX WTI Low ($/Bbl)
NYMEX WTI Average ($/Bbl)
Average Realized Price ($/Bbl)
Average Realized Price, with derivative settlements ($/Bbl)
Average Realized Price as a % of Average NYMEX WTI
Differential ($/Bbl) to Average NYMEX WTI
Natural Gas
NYMEX Henry Hub High ($/MMBtu)
NYMEX Henry Hub Low ($/MMBtu)
NYMEX Henry Hub Average ($/MMBtu)
Average Realized Price ($/Mcf) (2)
Average Realized Price, with derivative settlements ($/Mcf)(2)
Average Realized Price as a % of Average NYMEX Henry Hub(1)(2)
Differential ($/Mcf) to Average NYMEX Henry Hub(1)(2)
NGL
Average Realized Price ($/Bbl) (2)
Average Realized Price as a % of Average NYMEX WTI (2)
For the Year Ended
December 31,
2018
2017
2016
$
$
$
$
$
$
$
$
$
$
$
$
$
76.41
42.53
64.90
57.27
48.04
88.2%
(7.63)
4.84
2.55
3.07
2.25
2.36
66.7%
(1.12)
21.75
33.5%
$
$
$
$
$
$
$
$
$
$
$
$
$
60.42
42.53
50.85
43.77
41.67
86.1%
(7.08)
3.42
2.56
3.02
2.85
2.90
85.8%
(0.47)
23.60
46.4%
54.06
26.21
43.47
36.70
40.59
84.4%
(6.77)
3.93
1.64
2.55
2.41
2.81
85.9%
(0.40)
15.49
35.6%
$
$
$
$
$
$
$
$
$
$
$
$
$
(1) Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf
using a conversion factor of 1.1 to 1.
(2) As a result of the adoption of ASC 606 - Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, certain
costs previously classified as transportation and gathering expenses are presented on a net basis for proceeds expected to
be received. See "—Historical Results of Operations and Operating Expense" for more information.
Derivative Arrangements
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from
time to time we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of
price volatility associated with our oil production, we believe we will mitigate, but not eliminate, the potential negative effects
of reductions in oil prices on our cash flow from operations for those periods. However, in a portion of our current positions,
our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to
the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our
derivatives contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our
derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the
terms of current contracts in order to realize the current value of our existing positions. See “—Quantitative and Qualitative
Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the
effects of changes in commodity prices, and our commodity derivative contracts.
We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy
and future hedging transactions will be determined at our discretion and may be different than what we have done on a
historical basis. As a result of recent volatility in the price of oil and natural gas, we have relied on a variety of hedging
strategies and instruments to hedge our future price risk. We have utilized swaps, put options, and call options, which in some
60
instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas
production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future.
A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an
amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the
settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put
option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between
the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor
price, the put option expires worthless. Some of our purchased put options have deferred premiums. For the deferred premium
puts, we agreed to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the
call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference
between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below
the ceiling price, the call option expires worthless.
We combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging
strategies. Some examples of our hedging strategies are collars which include purchased put options and sold call options,
three-way collars which include purchased put options, sold put options, and sold call options, and enhanced swaps, which
include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. We
have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices.
61
We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than
current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative
arrangements at favorable prices may be limited, and we are not obligated to hedge a specific portion of our oil or natural gas
production. The following summarizes our derivative positions related to crude oil and natural gas sales in effect as of
December 31, 2018:
NYMEX WTI Crude Swaps:
Notional volume (Bbl)
Weighted average fixed price ($/Bbl)
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)
Weighted average sold call price ($/Bbl)
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)
Weighted average sold put price ($/Bbl)
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)
Weighted average purchased put price ($/Bbl)
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed price ($/MMBtu)
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)
Weighted average purchased put price ($/MMBtu)
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)
Weighted average sold call price ($/MMBtu)
NYMEX HH Natural Gas Sold Puts:
Notional volume (MMBtu)
Weighted average sold put price ($/MMBtu)
CIG Basis Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed basis price ($/MMBtu)
2019
2020
900,000
52.56
11,700,000
65.40
13,500,000
41.27
17,850,000
47.67
32,400,000
2.81
3,600,000
3.04
3,600,000
3.46
3,000,000
2.50
36,000,000
(0.75)
$
$
$
$
$
$
$
$
$
1,200,000
52.66
1,800,000
67.53
1,800,000
42.00
1,800,000
50.00
$
$
$
$
—
—
—
—
—
—
—
—
—
—
62
The following table summarizes our historical derivative positions and the settlement amounts for each of the periods
indicated.
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed price ($/MMBtu)
CIG Basis Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed basis price ($/MMBtu)
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)
Weighted average strike price ($/MMBtu)
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)
Weighted average strike price ($/MMBtu)
NYMEX WTI Crude Swaps:
Notional volume (Bbl)
Weighted average fixed price ($/Bbl)
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)
Weighted average strike price ($/Bbl)
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)
Weighted average strike price ($/Bbl)
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)
Weighted average strike price ($/Bbl)
NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl)
Weighted average strike price ($/Bbl)
Total Amounts Received/(Paid) from Settlement (in thousands)
Cash provided by (used in) changes in Accounts Receivable and
Accounts Payable related to Commodity Derivatives
Cash Settlements on Commodity Derivatives per Consolidated
Statements of Cash Flows
Lease Operating Expenses
For the Year Ended
December 31,
2018
2017
2016
40,650,000
3.10
$
25,240,000
3.05
$
13,194,600
3.13
37,935,000
12,615,000
(0.62) $
(0.34) $
2,970,000
(0.19)
2,400,000
3.00
2,400,000
3.15
5,050,000
51.58
13,388,800
39.09
12,327,600
44.81
10,090,000
57.46
2,850,000
58.41
$
$
$
$
$
—
—
—
—
4,125,000
48.02
7,720,000
37.67
5,570,000
45.18
4,620,000
54.70
750,000
61.32
$
$
$
$
$
—
—
—
—
1,989,060
41.87
2,100,000
44.93
4,724,150
51.82
2,786,090
59.44
216,000
69.58
(123,518) $
(18,031) $
34,196
(11,106) $
6,046
$
8,631
(134,624) $
(11,985) $
42,827
$
$
$
$
$
$
$
$
$
$
$
$
All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting
part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs,
maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental
to production, but exclude lease acquisition or drilling or completion expenses.
Capital Expenditures
For the year ended December 31, 2018, we incurred approximately $776.1 million in capital expenditures, excluding
outstanding elections, in drilling 161 gross (129.7 net) wells with an average lateral length of 1.8 miles and completing 161
gross (137.4 net) wells with an average lateral length of 1.7 miles. In addition, we incurred approximately $116.4 million of
leasehold and surface acreage additions, excluding acquisitions. These capital expenditures exclude the impact of the decrease
in outstanding elections of $6.7 million. In addition, Elevation, our wholly owned midstream subsidiary, incurred $108.2
63
million of capital expenditures for the year ended December 31, 2018. Our 2018 revised capital budget allocated approximately
$770 million to $840 million to the drilling of 168 to 173 gross operated wells, completion of between 170 to 175 gross
operated wells and turned to sales between 163 to 168 gross operated wells. Approximately $120 million to $150 million was
allocated to acreage leasing, midstream and other capital expenditures, excluding amounts that were paid for acquisitions.
Our 2019 capital budget for the drilling and completion of operated and non-operated wells is approximately $585.0
million to $675.0 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 125 gross
operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. Our capital budget anticipates a
one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party
and any amounts that may be paid for potential acquisitions.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion.
We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but
not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the
availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and
approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any
postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and
related standardized measure. These risks could materially affect our business, financial condition and results of operations.
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income (loss) as determined by United States generally accepted
accounting principles ("GAAP"). Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by
management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We
define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depletion, depreciation,
amortization and accretion ("DD&A"), impairment of long lived assets and goodwill, exploration expenses, rig termination
fees, write off of deposit on acquisition, (gain) loss on sale of property and equipment, gain on sale of assets of unconsolidated
subsidiaries, acquisition transaction expenses, (gain) loss on commodity derivatives, settlements on commodity derivative
instruments, premiums paid for derivatives that settled during the period, unit and stock-based compensation expense,
amortization of debt discount and debt issuance costs, make-whole premiums, interest expense, income tax expense (benefit)
and non-recurring charges. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. See Note
15 — Segment Information in Item 8 in this Annual Report for more information regarding the EBITDAX of reportable
segments.
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating
performance and compare the results of our operations from period to period without regard to our financing methods or capital
structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts
can vary substantially from company to company within our industry depending upon accounting methods and book values of
assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an
alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our
operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and
assessing a company's financial performance, such as a company's cost of capital, hedging strategy and tax structure, as well as
the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted
EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is
a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is
useful to an investor in evaluating our financial performance because this measure:
•
•
•
is widely used by investors in the oil and natural gas industry to measure a company’s operating performance
without regard to items excluded from the calculation of such term, among other factors;
helps investors to more meaningfully evaluate and compare the results of our operations from period to period by
removing the effect of our capital structure from our operating structure; and
is used by our management team for various purposes, including as a measure of operating performance, in
presentations to our board of directors, as a basis for strategic planning and forecasting. Adjusted EBITDAX is
also used by our Board of Directors as a performance measure in determining executive compensation.
64
The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income
(loss) for each of the periods indicated (in thousands).
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net Income (Loss)
Add back:
Depletion, depreciation, amortization and accretion
Impairment of long lived assets and goodwill
Exploration expenses
Rig termination fee
Write-off of deposit on acquisition
(Gain) loss on sale of property and equipment
(Gain) on sale of assets of unconsolidated subsidiary
Acquisition transaction expenses
(Gain) loss on commodity derivatives
Settlements on commodity derivative instruments
Premiums paid for derivatives that settled during the period
Stock-based compensation expense
Amortization of debt discount and debt issuance costs
Make-whole premium on 2021 Senior Notes
Interest expense
Income tax expense (benefit)
Adjusted EBITDAX
Items Affecting the Comparability of Our Financial Results
For the Year Ended
December 31,
2018
2017
2016
$
121,855
$
(44,408) $
(456,001)
435,775
70,928
31,611
—
—
(53,222)
(83,612)
—
8,554
(123,518)
(7,148)
68,349
13,249
35,600
74,481
66,850
$
659,752
$
314,999
1,647
36,256
—
—
451
—
—
36,332
(18,031)
(580)
65,607
4,260
—
47,629
(63,700)
380,462
$
205,348
23,425
36,422
891
10,000
—
—
2,719
100,947
34,196
(5,553)
200,308
19,256
—
49,587
(29,280)
192,265
Our historical results of operations for the periods presented may not be comparable, either to each other or to our
future results of operations, for the reasons described below:
•
For the year ended December 31, 2018, we recognized $136.8 million gain on sale of property and equipment and
assets of unconsolidated subsidiary related to our April 2018 Divestitures, August 2018 Divestiture and December
2018 Divestitures. We also recognized $54.2 million in impairment of goodwill resulting from the conclusion that
the fair value of the reporting unit was not greater than its carrying amount and $16.2 million related to
impairment of the proved oil and gas properties in our northern field.
• On December 22, 2017, the TCJA was enacted making significant changes to the Internal Revenue Code. Many
of the provisions in the TCJA have an effective date for years beginning after December 31, 2017, including the
lowering of the U.S. corporate rate from 35% to 21%. As a result of the enactment date of December 22, 2017,
we were required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to
reverse. We provisionally recorded an income tax benefit in the amount of $23.4 million related to the
remeasurement of the net deferred tax liability as of December 31, 2017. During the third quarter of 2018, we
completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue
Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction
in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. There are no
remaining provision amounts associated with the TCJA as of December 31, 2018.
•
In connection with the consummation of the IPO, we issued 185,280 shares of our Series A Preferred Stock to the
holders of Holdings’ Series B Preferred Units in conversion of such units. The Series A Preferred Stock are
entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay
such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such
quarterly dividends are paid in cash).
65
• We incur additional general and administrative expenses related to being a public company, including Exchange
Act reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with
listing on the NASDAQ Global Select Market; incremental independent auditor fees; incremental legal fees;
investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance
costs; and directors compensation.
•
•
Prior to our initial public offering, we were not subject to federal or state income taxes. Accordingly, the financial
data attributable to us prior to such corporate reorganization contain no provision for federal or state income taxes
because the tax liability with respect to Holdings’ taxable income was passed through to its members. Beginning
October 12, 2016, we began to be taxed as a C corporation under the Code and subject to federal and state income
taxes at a blended statutory rate of approximately 38% of pretax earnings. As a result of the TCJA, we were
subject to federal and state income taxes at a blended statutory rate of approximately 24.7% of pretax earnings for
the years ended December 31, 2018 and 2017.
In October 2016, our board of directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan
("LTIP") and subsequently granted awards to certain directors, officers and employees, including stock options,
restricted stock units and performance stock awards. We recognized $48.7 million, $48.3 million and $8.5 million
of stock-based compensation expense for years ended December 31, 2018, 2017 and 2016, respectively, related to
these awards.
• On October 3, 2016, we acquired additional oil and gas properties primarily located in the Wattenberg Field
located primarily around our existing Greeley and Windsor areas. The October 2016 Acquisition consisted of
working interest in approximately 6,400 net acres and 31 gross (19 net) drilled but uncompleted wells, as of the
date of acquisition. The October 2016 Acquisition provided net daily production of approximately 6,900 BOE/d
during the fourth quarter of 2016.
•
In 2015, we granted certain members of management incentive units pursuant to Holdings’ 2014 Membership
Unit Incentive Plan and its limited liability company agreement. These equity-based awards were subject to time-
based vesting requirements, as well as accelerated vesting upon the occurrence of a change of control. In
connection with the IPO, the Board of Managers of Holdings accelerated the vesting of the Holdings’ Incentive
Units. Our IPO and change of control triggered the conversion of these units into approximately 9.1 million of our
common shares based on the 10-day volume weighted average price of our common stock following its IPO as set
forth in the 2014 Plan and the Holdings LLC Agreement. For the year ended December 31, 2016, we recognized
approximately $172.1 million in non-cash, unit-based compensation expense in connection with the conversion of
the Holdings’ Incentive Units into our common stock.
66
Historical Results of Operations and Operating Expenses
Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense).
The following table provides the components of our revenues, operating expenses, other income (expense) and net
income (loss) for the periods indicated (in thousands):
Revenues:
Oil sales
Natural gas sales
NGL sales
Total Revenues
Operating Expenses:
Lease operating expenses
Transportation and gathering
Production taxes
Exploration expenses
Depletion, depreciation, amortization and accretion
Impairment of long lived assets and goodwill
Other operating expenses
(Gain) loss on sale of property and equipment and assets of
unconsolidated subsidiary
Acquisition transaction expenses
General and administrative expenses
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Commodity derivatives loss
Interest expense
Other income
Total Other Income (Expense)
Income (Loss) Before Income Taxes
Income tax (expense) benefit
Net Income (Loss)
For the Year Ended
December 31,
2018
2017
2016
$
840,687
$
419,904
$
194,059
105,629
114,427
1,060,743
79,413
39,411
90,345
31,611
435,775
70,928
—
(136,834)
—
134,604
745,253
315,490
(8,554)
(123,330)
5,099
(126,785)
188,705
(66,850)
121,855
$
92,322
92,070
604,296
60,358
50,948
51,367
36,256
314,999
1,647
—
451
—
110,167
626,193
(21,897)
(36,332)
(51,889)
2,010
(86,211)
(108,108)
63,700
(44,408) $
$
48,652
35,378
278,089
36,743
25,300
20,730
36,422
205,348
23,425
10,891
—
2,719
232,388
593,966
(315,877)
(100,947)
(68,843)
386
(169,404)
(485,281)
29,280
(456,001)
67
The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE
basis for the periods indicated:
Sales (MBoe)(1):
Oil sales (MBbl)
Natural gas sales (MMcf)
NGL sales (MBbl)
Sales (BOE/d)(1):
Oil sales (Bbl/d)
Natural gas sales (Mcf/d)
NGL sales (Bbl/d)
Average sales prices(2):
Oil sales (per Bbl)
Oil sales with derivative settlements (per Bbl)
Natural gas sales (per Mcf)(3)
Natural gas sales with derivative settlements (per Mcf)(3)
NGL sales (per Bbl)(3)
Average price per BOE(3)
Average price per BOE with derivative settlements(3)
Expense per BOE(1):
Lease operating expenses
Transportation and gathering(3)
Production taxes
Exploration expenses
Depletion, depreciation, amortization, and accretion
Impairment of long lived assets and goodwill
General and administrative expenses
Cash general and administrative expenses
Unit and stock-based compensation
Total operating expenses per BOE(4)
For the Year Ended
December 31,
2018
2017
2016
$
$
27,747
14,679
46,847
5,260
76,019
40,217
128,347
14,411
57.27
48.04
2.25
2.36
21.75
38.23
33.52
2.86
1.42
3.26
1.14
15.71
2.56
4.85
2.39
2.46
31.80
$
$
18,894
9,594
32,395
3,901
51,764
26,284
88,754
10,687
43.77
41.67
2.85
2.90
23.60
31.98
31.00
3.19
2.70
2.72
1.92
16.67
0.09
5.83
2.36
3.47
33.12
$
$
10,940
5,287
20,212
2,284
29,891
14,446
55,223
6,240
36.70
40.59
2.41
2.81
15.49
25.42
28.04
3.36
2.31
1.89
3.33
18.77
2.14
21.24
2.93
18.31
53.04
Production taxes as a percentage of revenue
8.5%
8.5%
7.5%
(1) One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is
an energy content correlation and does not reflect a value or price relationship between the commodities.
(2) Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity
derivative contracts. Our calculation of such effects includes both gains and losses on cash settlements for commodity
derivatives and premiums paid or received on options that settled during the period.
(3) As a result of the adoption of ASC 606 on January 1, 2018, certain costs previously classified as transportation and
gathering expenses are presented on a net basis for proceeds expected to be received. See below for further information.
(4) Excludes (gain) loss on sale of property and equipment, gain on sale of assets of unconsolidated subsidiary, other operating
expenses and acquisition transaction expenses.
68
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Oil sales revenues. Crude oil sales revenues increased by $420.8 million to $840.7 million for the year ended
December 31, 2018 as compared to crude oil sales of $419.9 million for the year ended December 31, 2017. An increase in
sales volumes between these periods contributed to a $222.6 million positive impact, while an increase in crude oil prices
contributed a $198.2 million positive impact.
For the year ended December 31, 2018, our crude oil sales averaged 40.2 MBbl/d. Our crude oil sales volumes
increased 53% to 14,679 MBbl for the year ended December 31, 2018 compared to 9,594 MBbl for the year ended
December 31, 2017. The volume increase was primarily due to an increase in production from the completion of 161 wells for
the year ended December 31, 2018. The increased production from these new wells was partially offset by the natural decline
of our existing producing properties.
The average price we realized on the sale of crude oil was $57.27 per Bbl for the year ended December 31, 2018
compared to $43.77 per Bbl for the year ended December 31, 2017.
Natural gas sales revenues. Natural gas sales revenues increased by $13.3 million to $105.6 million for the year
ended December 31, 2018 as compared to natural gas sales revenues of $92.3 million for the year ended December 31, 2017.
An increase in sales volumes between these periods contributed a $41.2 million positive impact, while a decrease in natural gas
prices contributed a $27.9 million negative impact. The decrease in pricing is partially attributable to our adoption of ASC 606.
Adoption of this new standard was applied to all new contracts entered into on or after January 1, 2018 and all existing
contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. Amounts
previously recognized as transportation and gathering ("T&G") under ASC 605 of $15.6 million are currently recognized
within natural gas sales revenues.
For the year ended December 31, 2018, our natural gas sales averaged 128.3 MMcf/d. Natural gas sales volumes
increased by 45% to 46,847 MMcf for the year ended December 31, 2018 as compared to 32,395 MMcf for the year ended
December 31, 2017. The volume increase was primarily due to the completion of 161 gross wells for the year ended
December 31, 2018, partially offset by the natural decline on existing producing properties.
The average price we realized on the sale of our natural gas was $2.25 per Mcf for the year ended December 31, 2018
compared to $2.85 per Mcf for the year ended December 31, 2017.
NGL sales revenues. NGL sales revenues increased by $22.3 million to $114.4 million for the year ended
December 31, 2018 as compared to NGL sales revenues of $92.1 million for the year ended December 31, 2017. An increase in
sales volumes between these periods contributed a $32.0 million positive impact, while a decrease in price contributed a $9.7
million negative impact. The decrease in pricing is partially attributable to our adoption of ASC 606. Adoption of this new
standard was applied to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or
substantially all) of the revenue has not been recognized under legacy revenue guidance. Amounts previously recognized as
T&G under ASC 605 of $20.1 million are currently recognized within NGL sales revenues.
For the year ended December 31, 2018, our NGL sales averaged 14.4 MBbl/d. NGL sales volumes increased by 36%
to 5,260 MBbl for the year ended December 31, 2018 as compared to 3,901 MBbl for the year ended December 31, 2017. The
volume increase is primarily due to the completion of 161 gross wells for the year ended December 31, 2018, partially offset by
the natural decline on existing producing properties. Our NGL sales are directly associated with our natural gas sales because
our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $21.75 per Bbl for the year ended December 31, 2018
compared to $23.60 per Bbl for the year ended December 31, 2017.
Lease operating expenses ("LOE"). Our LOE, increased by $19.0 million to $79.4 million for the year ended
December 31, 2018, from $60.4 million for the year ended December 31, 2017. The increase in LOE was primarily the result of
an increase in producing wells and an increase in equipment rental and other service rates, partially offset by optimization of
our field cost structure for the year ended December 31, 2018.
On a per unit basis, LOE decreased to $2.86 per BOE sold for the year ended December 31, 2018 from $3.19 per BOE
sold for the year ended December 31, 2017. The decrease in LOE per BOE is primarily a result of flush production on several
new pads turned-in-line for the year ended December 31, 2018.
69
Transportation and gathering. Our T&G expense decreased by $11.5 million to $39.4 million for the year ended
December 31, 2018, from $50.9 million for the year ended December 31, 2017. The decrease in T&G is primarily attributable
to adoption of ASC 606. Adoption of this new standard was applied to all new contracts entered into on or after January 1, 2018
and all existing contracts for which all (or substantially all) of the revenue as not been recognized under legacy revenue
guidance. Amounts previously recognized as T&G under ASC 605 of $35.7 million are currently recognized within natural gas
and NGL sales revenues. This decrease was offset by an increase in producing wells and in both residue natural gas and NGL
sales volumes, resulting in $24.2 million of collectively higher T&G.
On a per unit basis, T&G decreased to $1.42 per BOE sold for the year ended December 31, 2018 from $2.70 per BOE
sold for the year ended December 31, 2017. The decrease in T&G per BOE is primarily the result of the adoption of ASC 606.
Production taxes. Our production taxes increased by $38.9 million to $90.3 million for the year ended December 31,
2018 as compared to $51.4 million for the year ended December 31, 2017. The increase was attributable to increased revenue
as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 8.5%
for the year ended December 31, 2018 as compared to 8.5% for the year ended December 31, 2017. Production taxes were
consistent for the years ended December 31, 2018 and 2017.
Exploration expenses. Our exploration expenses were $31.6 million and $36.3 million for the years ended
December 31, 2018 and 2017, respectively. We recognized $4.6 million in expense attributable to the extension of certain
leases and $25.7 million in expense attributable to the abandonment and impairment of unproved properties for the year ended
December 31, 2018. We recognized $18.7 million in expense attributable to the extension of certain leases and $15.8 million in
expense attributable to the abandonment and impairment of unproved properties for the year ended December 31, 2017.
Depletion, depreciation, amortization and accretion expense. Our DD&A expense increased $120.8 million to $435.8
million for the year ended December 31, 2018 as compared to $315.0 million for the year ended December 31, 2017. This
increase was due to increased volumes sold for the year ended December 31, 2018 as sales increased by approximately 8,853
MBoe. On a per unit basis, DD&A expense decreased from $16.67 per BOE for the year ended December 31, 2017 to $15.71
per BOE for the year ended December 31, 2018. The decrease in DD&A per BOE is due to an increase in reserves related to an
increase in prices and extensions, slightly offset by increased production for the year ended December 31, 2018.
Impairment of long lived assets and goodwill. For the year ended December 31, 2018, our impairment expense was
$70.9 million. We recognized $16.2 million related to impairment of the proved oil and gas properties in our northern field. The
fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field.
Impairment on goodwill of $54.2 million was recognized upon completion of a quantitative assessment noting the fair value of
the reporting unit was not greater than its carrying amount. For the year ended December 31, 2017, we recognized $1.6 million
associated with impairment on other property and equipment and certain well equipment inventory evaluated to have a net
realizable value less than the carrying value, as the equipment was determined to no longer be useful in our current drilling
operations.
(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on sale of property
and equipment and assets of unconsolidated subsidiary was $136.8 million for the year ended December 31, 2018, which was
related to our April 2018 Divestitures, August 2018 Divestiture and December 2018 Divestitures, as compared to $0.5 million
loss on the sale of property and equipment for the year ended December 31, 2017.
General and administrative expenses (“G&A”). General and administrative expenses increased by $24.4 million to
$134.6 million for the year ended December 31, 2018 as compared to $110.2 million for the year ended December 31, 2017.
This increase was primarily due to an increase in our employee head count for the year ended December 31, 2018 compared to
the year ended December 31, 2017. On a per unit basis, G&A expenses decreased by $0.98 per BOE from $5.83 per BOE sold
for the year ended December 31, 2017 to $4.85 per BOE sold for the year ended December 31, 2018.
Our G&A expenses includes the non-cash expense for stock-based compensation for equity awards granted to our
employees and directors. For the year ended December 31, 2018, stock-based compensation expense was $68.3 million as
compared to stock-based compensation expense of $65.6 million for the year ended December 31, 2017. On a per unit basis,
stock-based compensation decreased $1.01 per BOE from $3.47 per BOE sold for the year ended December 31, 2017 to $2.46
per BOE sold for the year ended December 31, 2018.
70
Our other G&A expenses increased by $21.7 million during the year ended December 31, 2018 compared to the year
ended December 31, 2017, primarily due to the growth of the Company, including an increase in employed workforce of 23%,
or 52 additional employees. On a per BOE basis, other G&A expenses per BOE sold increased $0.03 per BOE sold from $2.36
per BOE sold for the year ended December 31, 2017 to $2.39 per BOE sold for the year ended December 31, 2018. The
increase in other G&A expenses on a per BOE basis is partially offset by increased sales volumes for the year ended
December 31, 2018.
Commodity derivative loss. Primarily due to the change in fair value from the execution of new positions during the
year ended December 31, 2018, partially offset by a decrease in NYMEX crude oil futures prices at December 31, 2018 as
compared to December 31, 2017, we incurred a net loss on our commodity derivatives of $8.6 million and $36.3 million for the
years ended December 31, 2018 and 2017, respectively. These losses are a result of our hedging program, which is used to
mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will
continue to change in value until the transactions are settled and we will likely add to our hedging program in the future.
Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will
only be affected upon settlement of the transactions at the current market prices at that time. For the year ended December 31,
2018 and 2017, we paid cash settlements of commodity derivatives totaling $123.5 million and $18.0 million, respectively.
Interest expense. Interest expense consists of interest expense on our long-term debt and debt issuance costs, net of
capitalized interest. For the year ended December 31, 2018, we recognized interest expense of approximately $123.3 million as
compared to $51.9 million for the year ended December 31, 2017, as a result of borrowings under our revolving credit facility,
our 2021 Senior Notes and the associated make-whole premium and accelerated amortization of debt issuance costs upon
redemption, our 2024 Senior Notes, our 2026 Senior Notes, and the amortization of other debt issuance costs.
We incurred interest expense for the year ended December 31, 2018 of approximately $82.7 million related to our
2021 Senior Notes, 2024 Senior Notes, 2026 Senior Notes and credit facility, as well as a make-whole premium of $35.6
million related to our repayment of our 2021 Senior Notes in January and February 2018. We incurred interest expense for the
year ended December 31, 2017 of approximately $58.7 million related to our credit facility, 2021 Senior Notes and 2024 Senior
Notes. Also included in interest expense for the years ended December 31, 2018 and 2017 was the amortization of debt
issuance costs of $13.2 million and $4.3 million, respectively. Amortization expense for the year ended December 31, 2018
includes $9.4 million of acceleration of amortization expense upon the repayment of our 2021 Senior Notes. For the years
ended December 31, 2018 and 2017, we capitalized interest expense of $8.2 million and $11.1 million, respectively.
Income tax (expense) benefit. We recorded income tax expense of approximately $66.9 million and income tax benefit
of $63.7 million resulting in an effective tax rate of approximately 35.4% and 58.9% for the years ended December 31, 2018
and 2017, respectively. Our effective tax rate for 2018 differs from the U.S. statutory income tax rate of 24.7% primarily due to
the effects of state income taxes, estimated permanent taxable differences, including the book impairment of goodwill and
partnership income allocated to a noncontrolling interest owner.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Oil sales revenues. Crude oil sales revenues increased by $225.8 million to $419.9 million for the year ended
December 31, 2017 as compared to crude oil sales of $194.1 million for the year ended December 31, 2016. An increase in
sales volumes between these periods contributed to a $158.0 million positive impact, while an increase in crude oil prices
contributed a $67.8 million positive impact.
For the year ended December 31, 2017, our crude oil sales averaged 26.3 MBbl/d. Our crude oil sales volumes
increased 81% to 9,594 MBbl in the year ended December 31, 2017 compared to 5,287 MBbl for the year ended December 31,
2016. The volume increase was primarily due to the development of our properties. For the year ended December 31, 2017, we
completed 198 gross wells. The increased production from these new wells was offset by the normal decline on the existing
producing properties.
The average price we realized on the sale of crude oil was $43.77 per Bbl for the year ended December 31, 2017
compared to $36.70 per Bbl for the year ended December 31, 2016.
Natural gas sales revenues. Natural gas sales revenues increased by $43.6 million to $92.3 million for the year ended
December 31, 2017 as compared to natural gas sales revenues of $48.7 million for the year ended December 31, 2016. An
increase in sales volumes between these periods contributed a $29.3 million positive impact, while an increase in natural gas
prices contributed a $14.3 million positive impact.
71
For the year ended December 31, 2017, our natural gas sales averaged 88.8 MMcf/d. Natural gas sales volumes
increased by 60% to 32,395 MMcf for the year ended December 31, 2017 as compared to 20,212 MMcf for the year ended
December 31, 2016. The volume increase was primarily due to the development of our properties. For the year ended
December 31, 2017, we completed 198 gross wells. The increased production from these new wells was offset by the normal
decline on the existing producing properties.
The average price we realized on the sale of our natural gas was $2.85 per Mcf for the year ended December 31, 2017
compared to $2.41 per Mcf for the year ended December 31, 2016.
NGL sales revenues. NGL revenues increased by $56.7 million to $92.1 million for the year ended December 31,
2017 as compared to NGL revenues of $35.4 million for the year ended December 31, 2016. An increase in sales volumes
between these periods contributed a $25.0 million positive impact, while an increase in price contributed a $31.7 million
positive impact.
For the year ended December 31, 2017, our NGL sales averaged 10.7 MBbl/d. NGL sales volumes increased by 70%
to 3,901 MBbl for the year ended December 31, 2017 as compared to 2,284 MBbl for the year ended December 31, 2016. The
volume increase was due to the development of our properties. Our NGL sales are directly associated with our natural gas sales
since the majority of our natural gas volumes are processed by third parties which return a percentage of the proceeds from
both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $23.60 per Bbl for the year ended December 31, 2017
compared to $15.49 per Bbl for the year ended December 31, 2016.
Lease operating expenses. Our LOE, increased by $23.7 million to $60.4 million for the year ended December 31,
2017, from $36.7 million for the year ended December 31, 2016. The increase in LOE was due to the development of our
properties. For the year ended December 31, 2017, we completed 198 gross wells. On a per BOE basis there was a decrease in
operating expenses of $0.17 per BOE from $3.36 per BOE for the year ended December 31, 2016 to $3.19 per BOE for the
year ended December 31, 2017. The decrease in LOE per BOE was primarily a result of flush production on several new pads
turn-in-line during the year ended December 31, 2017.
Transportation and gathering. Our T&G expense increased by $25.6 million to $50.9 million for the year ended
December 31, 2017, from $25.3 million for the year ended December 31, 2016. On a per unit basis, there was an increase in
T&G expense of $0.39 per BOE from $2.31 per BOE for the year ended December 31, 2016 to $2.70 per BOE for the year
ended December 31, 2017. These increases were due to the increase in producing wells and in both residue natural gas and
NGL sales volumes and realized prices.
Production taxes. Our production taxes increased by $30.7 million to $51.4 million for the year ended December 31,
2017 as compared to $20.7 million for the year ended December 31, 2016. The increase was attributable to increased revenue
as State of Colorado production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales
revenue was 8.5% for the year ended December 31, 2017 as compared to 7.5% for the year ended December 31, 2016. The
increase in production taxes as a percentage of sales revenue relates to an increase in the estimated ad valorem and severance
tax rates for the year ended December 31, 2017.
Exploration expenses. Our exploration expenses were $36.3 million and $36.4 million for the years ended
December 31, 2017 and 2016, respectively. We recognized $18.7 million in expense attributable to the extension of leases,
$15.8 million in expense attributable to the abandonment and impairment of unproved properties and $1.4 million of costs
associated with exploratory geological and geophysical costs for the year ended December 31, 2017. We recognized $14.1
million in expense attributable to the extension of leases and $22.3 million in expense attributable to the abandonment and
impairment of unproved properties for the year ended December 31, 2016.
Depletion, depreciation, amortization and accretion expense. Our DD&A expense increased $109.7 million to $315.0
million for the year ended December 31, 2017 as compared to $205.3 million for the year ended December 31, 2016. This
increase was due to higher volumes sold for the year ended December 31, 2017 as sales increased by approximately 7,954
MBoe. On a per unit basis, DD&A expense decreased from $18.77 per BOE for the year ended December 31, 2016 to $16.67
per BOE for the year ended December 31, 2017. The decrease in DD&A per BOE is due to an increase in reserves related to an
increase in prices and extensions, slightly offset by increased production for the year ended December 31, 2017.
Impairment of long lived assets. For the year ended December 31, 2017, our impairment expense was $1.6 million,
associated with impairment on other property and equipment and certain well equipment inventory evaluated to have a net
72
realizable value less than the carrying value, as the equipment was determined to no longer be useful in our current drilling
operations. For the year ended December 31, 2016, we recognized $22.5 million in impairment expense on proved oil and gas
properties in our northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its
proved oil and gas properties in our northern field and it was determined that the proved oil and gas properties had no
remaining fair value. Therefore, the full net book value of these proved oil and gas properties were impaired at June 30, 2016.
Additionally, for the year ended December 31, 2016 we recognized $0.9 million of impairment on other property and
equipment.
Loss on sale of property and equipment.
Loss on sale of property and equipment for the for the year ended
December 31, 2017 is comprised of a $0.5 million loss on the sale of property and equipment. There were no such losses on the
sale of property and equipment for the year ended December 31, 2016.
Other operating expenses. Other operating expenses for the year ended December 31, 2016 includes $10.0 million
on the write off of a non-refundable payment related to an option to acquire additional acreage. In March 2017, we entered into
an amendment to this agreement with seller to terminate both our and the seller’s options for no further consideration. Also
included in other operating expenses for the year ended December 31, 2016 is a $0.9 million rig termination fee related to the
early termination of a rig in February 2016. There were no such expenses for the year ended December 31, 2017.
Acquisition transaction expenses. There were no significant acquisition transaction expenses for the year ended
December 31, 2017. As part of the acquisition of properties in August 2016 and October 2016, we incurred $2.7 million of
transaction costs associated with a finder’s fee, legal expenses and due diligence for the year ended December 31, 2016.
General and administrative expenses. General and administrative expenses decreased by $122.2 million to $110.2
million for the year ended December 31, 2017 as compared to $232.4 million for the year ended December 31, 2016. This
decrease was comprised of a decrease in unit and stock-based compensation of $134.7 million, offset by an increase in other
general and administrative expenses of $12.5 million. On a per unit basis, G&A expenses decreased from $21.24 per BOE sold
for the year ended December 31, 2016 to $5.83 per BOE sold for the year ended December 31, 2017.
Our G&A expenses includes the non-cash expense for unit and stock-based compensation for equity awards granted to
our employees, directors, officers and non-employee consultants. For the year ended December 31, 2017, stock-based
compensation expense was $65.6 million as compared to unit and stock-based compensation expense of $200.3 million for the
year ended December 31, 2016. On a per unit basis, unit and stock-based compensation decreased $14.84 per BOE from $18.31
per BOE sold for the year ended December 31, 2016 to $3.47 per BOE sold for the year ended December 31, 2017. The
decrease in unit and stock-based compensation expense was due to accelerated vesting of outstanding Holdings RUAs in
connection with our Corporate Reorganization and IPO in 2016. Additionally, as a result of the IPO in 2016, Holdings incentive
units were converted to common stock resulting in the recognition of $172.1 million of stock-based compensation expense.
Also in 2016, we created a Long Term Incentive Plan, which resulted in the granting of RSUs, stock options and performance
stock awards to certain board members, officers, and employees.
Our other G&A expenses increased by $12.5 million during the year ended December 31, 2017 compared to the year
ended December 31, 2016, primarily due to the growth of the Company, including an increase in employed workforce of
41.0%, or 66 additional employees. However, on a per BOE basis, other G&A expenses per BOE sold decreased $0.57 per
BOE sold from $2.93 per BOE sold for the year ended December 31, 2016 to $2.36 per BOE sold for the year ended
December 31, 2017. The decrease in other G&A expenses on a per BOE basis is due to higher production volumes for the year
ended December 31, 2017.
Commodity derivative gain (loss). Primarily due to the increase in NYMEX crude oil futures prices at
December 31, 2017 as compared to December 31, 2016 and change in fair value from the execution of new positions during
each period, we incurred a net loss on our commodity derivatives of $36.3 million and $100.9 million for the years ended
December 31, 2017 and 2016, respectively. These losses are a result of our hedging program, which is used to mitigate our
exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change
in value until the transactions are settled. Therefore, we expect our net income (loss) to reflect the volatility of commodity price
forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that
time. For the year ended December 31, 2017, we paid cash settlements of commodity derivatives totaling $18.0 million. For
the year ended December 31, 2016, we received cash settlements of commodity derivatives totaling $34.2 million.
Interest expense. Interest expense consists of interest paid and accrued on our long term debt, amortization of debt
discount and debt issuance costs, net of capitalized interest. For the year ended December 31, 2017, we recognized interest
expense of approximately $51.9 million as compared to $68.8 million for the year ended December 31, 2016, as a result of
73
borrowings under our revolving credit facility, our Second Lien Notes in 2016, our 2021 Senior Notes, our 2024 Senior Notes
in 2017 and the amortization of debt issuance costs and debt discount.
We incurred interest expense for the year ended December 31, 2017 of approximately $58.7 million related to our
2024 Senior Notes, 2021 Senior Notes and credit facility. We incurred interest expense for the year ended December 31, 2016
of approximately $50.4 million related to our Second Lien Notes, our 2021 Senior Notes and credit facility. Also included in
interest expense for the years ended December 31, 2017 and 2016 was the amortization of debt issuance costs and debt discount
of $4.3 million and $4.2 million, respectively. For the years ended December 31, 2017 and 2016, we capitalized interest
expense of $11.1 million and $5.2 million, respectively. Also included in interest expense for the year ended December 31,
2016 is a prepayment penalty of $4.3 million and the accelerated amortization of our remaining unamortized debt discount and
debt issuance costs of $15.1 million related to our repayment of the Second Lien Notes in July 2016.
Income tax benefit. We recorded an income tax benefit of approximately $63.7 million and $29.3 million resulting in
an effective tax rate of approximately 58.9% and 6.0% for the years ended December 31, 2017 and 2016, respectively. Our
effective tax rate for 2017 differs from the U.S. statutory income tax rate of 38.0% primarily due to the effects of state income
taxes, estimated permanent taxable differences and a one-time remeasurement of net deferred tax liabilities from 38.0% to
24.7% due to the Tax Cuts and Jobs Act. During the year ended December 31, 2017, our income tax benefit increased $34.4
million compared to the same period in 2016, which was primarily due to the one-time remeasurement of net deferred tax
liabilities in 2017 and our corporate reorganization to a C-Corp in 2016. Excluding the impact of the one-time remeasurement
of net deferred tax liabilities required in 2017, our overall effective tax rate was 37.3% for the year ended December 31, 2017.
Liquidity and Capital Resources
Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings
under our revolving credit facility. Depending upon market conditions and other factors, we may also issue equity and debt
securities, if needed.
Historically, our primary sources of liquidity have been borrowings under our revolving credit facility, proceeds from
notes offerings, equity provided by investors, including our management team, cash from the IPO and Private Placement, cash
from the issuance of preferred units, cash flows from operations and divestitures. To date, our primary use of capital has been
for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and
gas properties. Our borrowings, net of unamortized debt issuance costs, were approximately $1,417.7 million and $1,023.4
million at December 31, 2018, and 2017, respectively. We also have other contractual commitments, which are described in
Note 13 — Commitments and Contingencies in Item 8 of this Annual Report.
We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price
volatility on our cash flow from operations. Under this strategy, we intend to enter into commodity derivative contracts at times
and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 50% to 70% of our
projected oil and natural gas production over a one to two year period at a given point in time, although we may from time to
time hedge more or less than this approximate range.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow
from operations and available borrowings under our revolving credit facility to execute our current capital program, excluding
any acquisitions we may consummate, make our interest payments on the 2024 Senior Notes, 2026 Senior Notes and credit
facility and pay dividends on our Series A Preferred Stock and the Elevation Preferred Units.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures
and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and
equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on
acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the
covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able
to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or
proved reserves.
Our 2019 capital budget for the drilling and completion of operated and non-operated wells is approximately $585.0
million to $675.0 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 125 gross
operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. Our capital budget anticipates a
one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party
and any amounts that may be paid for potential acquisitions.
74
We currently have both a Stock Repurchase Program and a Senior Notes Repurchase Program in place. Spending
under these programs in 2018 was $26.2 million and we expect continued spending under these programs through the first
quarter of 2019.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
For the Year Ended
December 31,
2018
2017
$
$
684,933
(897,305)
440,590
$
316,965
(1,404,528)
463,395
2016
120,688
(873,608)
1,286,750
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Net cash provided by operating activities For the year ended December 31, 2018 as compared to the year ended
December 31, 2017, our net cash provided by operating activities increased by $368.0 million, primarily driven by an increase
in sales volume of 8,853 MBoe and increase in realized price of $6.25 per BOE resulting in an increase in net income of $166.3
million. An increase in changes in current assets and liabilities of $134.4 million also contributed to the increase in cash
provided by operating activities.
Net cash used in investing activities. For the year ended December 31, 2018 as compared to the year ended
December 31, 2017, our net cash used in investing activities decreased by $507.2 million primarily due to a decrease of $354.4
million used in oil and gas property additions, gathering systems and facilities additions, and other property and equipment
additions. An increase of cash provided by the sale of assets of an unconsolidated subsidiary of $83.6 million and the sale of
property and equipment of $75.7 million also contributed to the decrease in cash used in investing activities.
Net cash provided by financing activities. For the year ended December 31, 2018 as compared to the year ended
December 31, 2017, our net cash provided by financing activities decreased by $22.8 million, primarily as a result of cash used
in the redemption of the 2021 Senior Notes for $585.6 million, including a make-whole premium of $35.6 million and $28.6
million associated with repurchase of common shares. This decrease was offset by an increase of cash provided by the issuance
of the Senior Notes of $345.7 million, an increase of cash provided by the net borrowings under the credit facility of $105.0
million, and an increase of cash provided by the issuance of Elevation Preferred Units of $141.6 million.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Net cash provided by operating activities For the year ended December 31, 2017 as compared to the year ended
December 31, 2016, our net cash provided by operating activities increased by $196.3 million, primarily driven by an increase
in sales volume of 7,954 MBoe and increase in realized price of $6.56 per BOE resulting in a reduction in net loss of $411.6
million. An increase in deferred income tax benefit of $34.4 million and increase in changes in current assets and liabilities of
$14.7 million also contributed to this increase. This increase was offset by a decrease of stock-based compensation of $134.7
million and settlements on commodity derivatives of $54.8 million.
Net cash used in investing activities. For the year ended December 31, 2017 as compared to the year ended December
31, 2016, our net cash used in investing activities increased by $530.9 million primarily due to an increase of $935.7 million in
cash expended for drilling and completion activities and other property and equipment. This increase was offset by a decrease
in acquired oil and gas properties of $401.8 million.
Net cash provided by financing activities. For the year ended December 31, 2017 as compared to the year ended
December 31, 2016, our net cash provided by financing activities decreased by $823.4 million, primarily as a result of a
decrease of $1,243.1 million in proceeds from the issuance of common stock and members units, net of issuance costs, and a
decrease of $171.6 million in proceeds from the issuance of preferred units and stock in the year ended December 31, 2016.
This decrease was offset by an increase of $315.0 million in borrowings under the credit facility and an increase of $278.3
million in net proceeds and repayments of 2021 Senior Notes, 2024 Senior Notes and Second Lien Notes.
75
Working Capital
Our working capital surplus (deficit) was $62.2 million and $(236.7) million at December 31, 2018 and 2017,
respectively. Our cash balances totaled $235.0 million and $6.8 million at December 31, 2018 and 2017, respectively.
Due to the amounts that we incur related to our drilling and completion program and the timing of such expenditures,
we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability
under our revolving credit facility will be sufficient to fund our working capital needs. We expect that our pace of development,
production volumes, commodity prices and differentials to NYMEX prices for our oil, natural gas and NGL production will be
the largest variables affecting our working capital.
Debt Arrangements
Our revolving credit facility has a maximum credit amount of $1.5 billion and a current borrowing base of $1.2
billion, subject to the current maximum lending commitments of $650.0 million. All of our current and future restricted
subsidiaries will be guarantors under such facility, with the exception of Elevation. Amounts repaid under our revolving credit
facility may be re-borrowed from time to time, subject to the terms of the facility. For more information on the revolving credit
facility, please see Note 5 — Long-Term Debt in Item 8. Financial Statements and Supplementary Data of this Annual Report.
The revolving credit facility is secured by liens on substantially all of our properties.
In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately
$537.2 million. Our 2021 Senior Notes bore interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes was
payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior
Notes would have matured on July 15, 2021. Our 2021 Senior Notes were guaranteed by all of our current and future restricted
subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes). In the first quarter of 2018, we
closed a tender offer for the 2021 Senior Notes and subsequently redeemed all remaining outstanding 2021 Senior Notes. No
2021 Senior Notes remain outstanding.
In August 2017, we closed a private offering of our unsecured 7.375% Senior Notes due 2024 that resulted in net
proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our
2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. Our 2024 Senior
Notes will mature on May 15, 2024. Our 2024 Senior Notes are guaranteed by certain of our current and future restricted
subsidiaries.
In January 2018, we closed a private offering of our unsecured 5.625% Senior Notes due 2026 that resulted in net
proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on our
2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1,
2018. Our 2026 Senior Notes will mature on February 1, 2026. Our 2026 Senior Notes are guaranteed by certain of our current
and future restricted subsidiaries.
Revolving Credit Facility
The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is
redetermined semiannually on each May 1 and November 1, and will depend on the volumes of our proved oil and gas reserves
and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under our
revolving credit facility. As of December 31, 2018, the borrowing base was $1.2 billion, subject to current elected commitments
of $650.0 million, and we had $285.0 million of borrowings outstanding under our revolving credit facility. In December 2018,
we completed the November 1, 2018 borrowing base redetermination.
Principal amounts borrowed will be payable on the maturity date, and interest will be payable quarterly for alternate
base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing in
Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate
(equal to the product of: (a) the LIBOR rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the
number one and the denominator of which is the number one minus the reserve percentages (expressed as a decimal) on such
date at which the administrative agent under our revolving credit facility is required to maintain reserves on ‘Eurocurrency
Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an
applicable margin ranging from 200 to 300 basis points, depending on the percentage of our borrowing base utilized. Alternate
base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds
76
effective rate plus 50 basis points and (iii) the adjusted one-month LIBOR rate (as calculated above) plus 100 basis points, plus
an applicable margin ranging from 100 to 200 basis points, depending on the percentage of our borrowing base utilized. As of
December 31, 2018, we had $285.0 million of outstanding borrowings under our revolving credit facility. We may repay any
amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
The revolving credit facility is secured by liens on substantially all of our properties and guarantees from us and our
current and future subsidiaries, with the exception of Elevation. The revolving credit facility contains restrictive covenants that
may limit our ability to, among other things:
•
•
incur additional indebtedness;
sell assets;
• make loans to others;
• make investments;
• make certain changes to our capital structure;
• make or declare dividends;
•
•
•
•
hedge future production or interest rates;
enter into transactions with our affiliates;
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
The revolving credit facility requires us to maintain the following financial ratios:
•
•
a current ratio, which is the ratio of our and our restricted subsidiaries' consolidated current assets (includes
unused commitments under our revolving credit facility and excludes derivative assets) to our restricted
subsidiaries' consolidated current liabilities (excludes obligations under our revolving credit facility, the senior
notes and certain derivative liabilities), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and
a net leverage ratio, which is the ratio of our and our restricted subsidiaries' (i) consolidated debt less cash
balances to (ii) consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 4.0 to
1.0 as of the last day of such fiscal quarter.
2021 Senior Notes
In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately
$537.2 million. Our 2021 Senior Notes bore interest at an annual rate of 7.875% and matured on July 15, 2021.
Concurrent with the 2026 Notes Offering, we commenced a cash tender offer to purchase any and all of our 2021
Senior Notes. On January 24, 2018 we received approximately $500.6 million aggregate principal amount of the 2021 Senior
Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 we made a cash payment of
approximately $534.2 million, which included principal of approximately $500.6 million, a make-whole premium of
approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, we redeemed the approximately $49.4 million aggregate principal amount of the 2021 Senior
Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the
remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid
interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, we closed a private offering of our 2024 Senior Notes that resulted in net proceeds of approximately
$392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable
on May 15 and November 15 of each year, and the first interest payment was paid on November 15, 2017. Our 2024 Senior
Notes will mature on May 15, 2024.
77
We may, at our option, redeem all or a portion of our 2024 Senior Notes at any time on or after May 15, 2020 at the
redemption prices set forth in the indenture governing the 2024 Senior Notes. We are also entitled to redeem up to 35% of the
aggregate principal amount of our 2024 Senior Notes before May 15, 2020, with an amount of cash not greater than the net
proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of our 2024
Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to May 15,
2020, we may redeem some or all of our 2024 Senior Notes at a price equal to 100% of the principal amount thereof, plus
accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of
changes of control, holders of our 2024 Senior Notes may have the right to require us to repurchase their 2024 Senior Notes at
101% of the principal amount of the 2024 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2024 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other
senior indebtedness and senior to any of our subordinated indebtedness. Our 2024 Senior Notes are fully and unconditionally
guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that
guarantees our indebtedness under a credit facility. The 2024 Senior Notes are effectively subordinated to all of our secured
indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the
collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness
and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2024 Senior Notes.
2026 Senior Notes
On January 25, 2018, we closed a private offering of our 2026 Senior Notes that resulted in net proceeds of
approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on the 2026 Senior
Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. Our
2026 Senior Notes will mature on February 1, 2026. As of the date of this filing, we have repurchased 2026 Senior Notes with a
nominal value of $13.1 million for $10.5 million in connection with the Senior Notes Repurchase Program.
We may, at our option, redeem all or a portion of our 2026 Senior Notes at any time on or after February 1, 2021 at the
redemption prices set forth in the indenture governing the 2026 Senior Notes. We are also entitled to redeem up to 35% of the
aggregate principal amount of our 2026 Senior Notes before February 1, 2021, with an amount of cash not greater than the net
proceeds that we raise in certain equity offerings at a redemption price equal to 105.625% of the principal amount of our 2026
Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to February 1,
2021, we may redeem some or all of our 2026 Senior Notes at a price equal to 100% of the principal amount thereof, plus
accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of
changes of control, holders of our 2026 Senior Notes may have the right to require us to repurchase their 2026 Senior Notes at
101% of the principal amount of the 2026 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2026 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other
senior indebtedness and senior to any of our subordinated indebtedness. Our 2026 Senior Notes are fully and unconditionally
guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that
guarantee our indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of our secured
indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the
collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness
and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2026 Senior Notes.
Convertible Preferred Securities and Series A Preferred Stock
We previously issued investment funds managed by Apollo Global Management ("Apollo") $75.0 million in Series A
Preferred Units to fund a portion of the purchase price for the October 2016 Acquisition. The Series A Preferred Units were
entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. In 2016, we used $90.0 million of the net
proceeds from the IPO to redeem the Series A Preferred Units in full, which included a premium of $15.0 million.
In addition, we issued to, among others, investment funds managed by OZ Management LP and Yorktown $185.3
million in Series B Preferred Units to fund a portion of the purchase price for the October 2016 Acquisition. The Series B
Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and we had the ability to
pay up to 50% of the quarterly dividend in kind. The Series B Preferred Units were converted in connection with the closing of
the IPO into shares of our Series A Preferred Stock that are entitled to receive a cash dividend of 5.875% per year, payable
quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year
(decreased proportionately to the extent such quarterly dividends are partially paid in cash). The Series A Preferred Stock is
convertible into shares of our common stock at the election of the Series A Preferred Holders at a conversion ratio per share of
78
Series A Preferred Stock of 61.9195. Until the three-year anniversary of the closing of the IPO, we may elect to convert the
Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of
our common stock trades at or above a certain premium to our initial offering price, such premium to decrease with time. In
certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to
the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of
return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock mature on October 15, 2021,
at which time they are mandatorily redeemable for cash at the liquidation preference. See Note 9 — Equity— Series A Preferred
Stock and Series B Preferred Units” in Item 8. Financial Statements and Supplementary Data of this Annual Report.
Elevation Preferred Units
On July 3, 2018, Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and subsidiary of the
Company, entered into the Securities Purchase Agreement with the Purchaser, pursuant to which Elevation agreed to sell
150,000 Elevation Preferred Units at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of
$150.0 million, in a transaction exempt from the registration requirements under the Securities Act. The Private Placement
closed on July 3, 2018 and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a
reimbursement to Extraction for previously incurred midstream capital expenditures and general and administrative expenses.
These Elevation Preferred Units are non-recourse to Extraction, minimizing risk to our common shareholders, and represent the
noncontrolling interest presented on the consolidated balance sheets, consolidated statements of operations and consolidated
statements of changes in members' and stockholders' equity and noncontrolling interest. Elevation is a separate entity and the
assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other
subsidiaries. As of December 31, 2018, $136.9 million of cash was held by Elevation and is earmarked for construction of
pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.
During the Preferred Unit Commitment Period, subject to the satisfaction of certain financial and operational metrics
and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation
Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase
additional Elevation Preferred Units, in increments of at least $25.0 million, up to an aggregate amount of $350.0 million.
During the Preferred Unit Commitment Period, Elevation is required to pay the Purchaser a quarterly commitment fee payable
in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $350.0 million commitment.
The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In
respect of quarters ending prior to and including June 30, 2020, such dividend is payable in cash or in kind at the election of
Elevation. After June 30, 2020, such dividend is payable solely in cash.
Commitments, Contingencies and Contractual Obligations
A summary of our commitments, contingencies and contractual obligations as of December 31, 2018 is provided in the
following table (in thousands).
Payments due by Period
Total
Less than
1 year
1 - 3 years
3 - 5 years
More than
5 years
Contractual Obligations
Office leases(1)
$
32,758
$
3,512
$
6,757
$
6,770
$
15,719
Drilling rig obligations(2)
Volume commitments(3)(4)
Revolving credit facility and
interest payable(5)
Senior Notes and Interest
Payable(6)
Total
9,201
875,828
294,864
9,201
105,605
—
221,701
—
224,806
—
323,716
2,429
4,858
287,577
—
1,613,197
2,825,848
$
$
71,340
192,087
$
142,123
375,439
$
142,123
661,276
$
1,257,611
1,597,046
(1) We lease two office spaces in Denver, Colorado, two office spaces in Greeley, Colorado and one office space in Houston,
Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31,
2028. The Greeley, Colorado and Houston, Texas leases expire on October 31, 2019, June 30, 2019 and January 31, 2022,
79
respectively. Total rental commitments under non-cancelable leases for office space were $32.8 million at December 31,
2018.
(2) As of December 31, 2018, we were subject to commitments on three drilling rigs. The three drilling rigs are under contract
and are set to expire on February 19, 2019, May 26, 2019 and November 23, 2019.
(3) As of December 31, 2018, our oil marketer is subject to a firm transportation agreement that commenced in November
2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in
year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, we
amended our agreement with our oil marketer that requires us to sell all of our crude oil from an area of mutual interest in
exchange for a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by
our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31,
2018. In December 2017, we extended the term of this agreement through October 31, 2019 and posted a letter of credit in
the amount of $35.0 million. We are currently in the process of amending and extending this agreement. We evaluate our
contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable.
We also have two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which we have a
minority ownership interest. The first agreement commenced in November 2016 and has a term of ten years with a
minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years
three through five and 10,000 Bbl/d for years six through ten. The second agreement will commence in or around July
2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year
three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The remaining
aggregate amount of estimated payments under these agreements is approximately $875.8 million.
(4) In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, we
agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two
new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in
August 2018 and the second plant is expected to be completed by mid-2019, although the exact start-up date is
undetermined at this time. Our share of these commitments will require 51.5 MMcf and 20.6 MMcf per day, respectively,
to be delivered after the plants' in-service dates for a period of seven years thereafter. We may be required to pay a shortfall
fee for any volumes under these commitments. These contractual obligations can be reduced by our proportionate share of
the collective volumes delivered to the plants by other third party incremental volumes available to the midstream provider
at the new facilities that are in excess of the total commitments. We are also required for the first three years of each
contract to guarantee a certain target profit margin on these volumes sold. Under our current drilling plans, we expect to
meet these volume commitments and they have therefore not been reflected in the table above.
(5) Calculated based on balance of $285.0 million outstanding borrowings under our revolving credit facility as of December
31, 2018 and assumes no borrowings until the maturity date of the facility. Interest on our revolving credit facility is
payable at one of the following two variable rates as selected by us: a base rate based on the Prime Rate or the Eurodollar
rate based in LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the
facility as outlined in the Pricing Grid. Additionally, our revolving credit facility provides for a commitment fee of 0.375%
to 0.50%, depending on borrowing base usage.
(6) Calculated based on the December 31, 2018 outstanding aggregate principal amount on our 2024 Senior Notes of $400.0
million outstanding, at a fixed rate of 7.375%, and outstanding principal amount on our 2026 Senior Notes of $750.0
million outstanding, at a fixed rate of 5.625%. Interest is payable on our 2024 Senior Notes and 2026 Senior Notes on a
semi-annual basis through the maturity dates of May 15, 2024 and February 1, 2026, respectively.
The above contractual obligations schedule does not include the Series A Preferred Stock, future anticipated settlement
of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of our oil
and gas properties, as we cannot determine with accuracy the timing of such payments. Additionally, the above contractual
obligations schedule does not include lease operating expenses or budgeted capital expenditures. For further discussion
regarding our Series A Preferred Stock, derivative contracts and estimated future costs associated with the abandonment of our
oil and gas properties, please refer to Note 9 — Equity, Note 6 — Commodity Derivative Instruments and Note 7 — Asset
Retirement Obligations to our historical audited financial statements for the years ended December 31, 2018 and 2017.
Additionally, for further information regarding our contractual obligations, lease operating expenses and budgeted capital
expenditures as of December 31, 2018, please refer to Note 13 — Commitments and Contingencies to our historical unaudited
financial statements, "Historical Results of Operations and Operating Expenses" for the year ended December 31, 2018 and
2017 and "Capital Expenditures" in Item 7 of this Annual Report.
As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain
acreage positions or wells. If we do not meet such commitments, the acreage positions or wells may be lost or we may be
required to pay damages if certain performance conditions are not met.
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Off Balance Sheet Arrangements
As of December 31, 2018, we do not have material off-balance sheet arrangements, except for our agreement with our
oil marketer. Our oil marketer is subject to a firm transportation agreement with a make-whole provision that allows us to
satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of
their minimum volume commitment through October 31, 2019. We are currently in the process of amending and extending this
agreement. Please see Note 13 - Commitments and Contingencies in Part II, Item 8 of this Annual Report.
Impact of Inflation/Deflation and Pricing
All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated
costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust
downward in proportion to decline commodity prices. Historically, field-level prices received for our oil and natural gas
production have been volatile. During the year ended December 31, 2018, commodity prices increased during the first, second
and third quarter, and subsequently decreased in the fourth quarter, while during the years ended December 31, 2017 and 2016,
commodity prices generally increased. Changes in commodity prices impact our revenues, estimates of reserves, assessments
of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have
the potential to affect our ability to raise capital, borrow money, and retain personnel.
Critical Accounting Policies and Estimates
Use of Estimates in the Preparation of Financial Statements
The preparation of the financial statements in conformity with GAAP requires management to make estimates and
assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and 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. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash
flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion, amortization and
accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business
combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables; (7) valuation
of commodity derivative instruments; (8) accrued liabilities; (9) valuation of unit and stock-based payments, and (10) income
taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. We
evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions
we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different
assumptions or conditions, we believe our estimates are reasonable.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all
property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis
over the remaining life of proved reserves and proved developed reserves, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been
found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that
proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense.
In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and
evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are
capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b)
sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status
of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the
geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an
exploration project and the economics associated with making a determination of its commercial viability.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development
drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based
on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas
of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development
costs and exploration expense.
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We capitalize interest, if debt is outstanding, during drilling operations in our exploration and development activities.
Oil and Gas Reserves
Our estimates of proved reserves are based on the quantities of oil, natural gas and NGL, 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 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. Our independent petroleum
engineers, Ryder Scott, prepare a reserve and economic evaluation of all of our properties on a well-by-well basis. The
accuracy of reserve estimates is a function of the:
•
•
•
•
quality and quantity of available data;
interpretation of that data;
accuracy of various mandated economic assumptions; and
judgment of the independent reserve engineer.
One of the most significant estimates we make is the estimate of oil, natural gas and NGL reserves. Oil, natural gas
and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering
and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but
not limited to, additional development activity, production history, projected future production, economic assumptions relating
to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these
estimates are inherently uncertain. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting
in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to
determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which
would reduce earnings. We cannot predict what reserve revisions may be required in future periods.
Ryder Scott estimated all of our proved reserve quantities as of December 31, 2018, 2017 and 2016. In connection
with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they
review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and
production data and (4) our well ownership interests.
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.
Revisions resulting from price changes (MBOE)
Revisions resulting from production, performance and other (MBOE)
Total revisions (MBOE)
For the Year Ended December 31,
2018
2017
2016
11,082
(14,407)
(3,325)
12,767
(9,873)
2,894
(6,666)
(955)
(7,621)
The recent significant decline in oil, natural gas and NGL prices increases the uncertainty as to the impact of
commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater
precision than the futures market. A prolonged period of depressed commodity prices may have a significant impact on the
value and volumetric quantities of our proved reserve portfolio, assuming no other changes to our development plans or costs.
Depreciation, Depletion, Amortization and Accretion.
Our DD&A rate is dependent upon our estimates of total proved and proved developed reserves, which incorporate
various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at
which we record DD&A expense increases, which in turn reduces our net income. Such a decline in reserves may result from
lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in
reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well
as future economic conditions.
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Impairment of Proved Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a
possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of its
oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties 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. The factors used to determine fair value
include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future
capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing
the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets in
the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization.
For the years ended December 31, 2018 and 2016, we recognized $16.2 million and $22.5 million, respectively, in
impairment expense on proved oil and gas properties in our northern field. As of September 30, 2018, the future undiscounted
cash flows did not exceed the carrying amount associated with our proved oil and gas properties in the northern field. As of
June 30, 2016, it was determined that the proved oil and gas properties had no remaining fair value, therefore, the full net book
value of these proved oil and gas properties were impaired. For the year ended December 31, 2017, we recognized no
impairment expense on proved oil and gas properties.
Our impairment analyses requires us to apply judgment in identifying impairment indicators and estimating future
cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our
assumptions and estimates change due to new information, we may be exposed to an impairment charge.
Forward commodity prices and estimates of future production also play a significant role in determining impairment
of proved oil and gas properties. As a result of lower commodity prices and their impact on our estimated future cash flows, we
have continued to review our proved oil and gas properties for impairment. At December 31, 2018, our expected undiscounted
future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $0.8 billion, or 30%. At
December 31, 2017, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas
properties by approximately $1.6 billion, or 68%. At December 31, 2016, our expected undiscounted future cash flows
exceeded the carrying value of our proved oil and gas properties by approximately $1.7 billion, or 108%. The key assumptions
used to determine the undiscounted future cash flows include estimates of future production, future commodity pricing,
differentials, net estimated operating costs, anticipated capital expenditures and new wells on production. Future commodity
pricing for oil and NGL is based on five-year West Texas Intermediate strip prices, which decreased 8% from an average of
$54.66/Bbl at December 31, 2017 to an average of $50.04/Bbl at December 31, 2018, and on five-year Henry Hub strip prices,
which decreased 14% from an average of $3.14/MMBtu at December 31, 2017 to an average of $2.70/MMBtu at December 31,
2018.
Impairment of Unproved Oil and Gas Properties
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved
reserves. We evaluate significant unproved oil and gas properties for impairment based on remaining lease term, drilling
results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on
undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production
basis. Impairment expense and lease extension payments for unproved properties is reported in exploration expenses in the
consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, we recognized
$25.7 million, $15.8 million and $22.3 million in impairment expense for the years ended December 31, 2018, 2017 and 2016,
respectively.
Goodwill and Other Intangible Assets
We apply the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase
price over the estimated value of the net assets acquired in business combinations. We test goodwill for impairment annually on
September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be
recoverable. The goodwill test is performed at the reporting unit level, which represents our oil and gas operations in the core
DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of
goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued
declines in the quoted market price of our common shares could change the estimates of the fair value of the reporting unit and
could result in an impairment charge. We performed a quantitative assessment as of September 30, 2018, which concluded the
fair value of the reporting unit was greater than its carrying amount. We identified triggering events as of December 31, 2018,
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due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to
September 30, 2018. As such, we performed a quantitative assessment as of December 31, 2018, utilizing an income approach
based on estimates of the expected discounted future cash flows of the reporting unit's oil and gas properties, which concluded
the fair value of the reporting unit was not greater than its carrying amount. As a result, we recorded goodwill impairment of
$54.2 million, the entirety of the balance, for the year ended December 31, 2018. We performed a quantitative assessment as of
September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount. We performed a
qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-
likely-than-not greater than its carrying amount.
Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the
estimated useful life of the license.
Commodity Derivative Instruments
We have entered into commodity derivative instruments, as described below. We have utilized swaps, put options, and
call options to reduce the effect of price changes on a portion of our future oil and natural gas production. A swap has an
established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the
difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement
price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the
fixed price multiplied by the hedged contract volume. A put option has an established floor price. The buyer of the put option
pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the
buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract
volume. When the settlement price is above the floor price, the put option expires worthless. Some of our purchased put options
have deferred premiums. For the deferred premium puts, we agree to pay a premium to the counterparty at the time of
settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the
call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference
between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below
the ceiling price, the call option expires worthless.
We combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging
strategies. Some examples of our hedging strategies are collars which include purchased put options and sold call options,
three-way collars which include purchased put options, sold put options, and sold call options, and enhanced swaps, which
include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap.
The objective of our use of commodity derivative instruments is to achieve more predictable cash flows in an
environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these
commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit our ability to
benefit from favorable price movements. We may, from time to time, add incremental derivatives to hedge additional
production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in
order to realize the current value of our existing positions. We do not enter into derivative contracts for speculative purposes.
The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets
as commodity derivative assets. We have not designated any of the derivative contracts as fair value or cash flow hedges.
Therefore, we do not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity
derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses
on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the statements of operations.
Our cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or
receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as
operating activities in our statements of cash flows.
Our valuation estimate takes into consideration the counterparties’ credit worthiness, our credit worthiness, and the
time value of money. The consideration of the factors result in an estimated exit-price for each derivative asset or liability under
a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and
consistent methodology for valuing commodity derivative instruments. Please see “—How We Evaluate Our Operations—
Derivative Arrangements.”
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Accounting for Business Combinations
We account for all of our business combinations using the purchase method, which is the only method permitted under
FASB ASC 805, Business Combinations, and involves the use of significant judgment. In connection with a business
combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on
fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the
purchase price is recorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase
recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired
and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various
assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas
properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must
prepare estimates. To estimate the fair values of these properties, we prepare estimates of gas, oil and NGL reserves. We
estimate future prices to apply to the estimated reserves quantities acquired and estimate future operating and development
costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted
using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-
based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the
inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future
net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable
information of recent transactions is used to estimate fair value of unproved acreage.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A
higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are
based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases
the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine
fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value.
Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the
impairment is recorded.
Asset Retirement Obligations
Our asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging and
abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in
accordance with applicable local, state and federal laws, and applicable lease terms. The fair value of an ARO liability
is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of
the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions
regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount
rate to be used; and inflation rates. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-
period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original
estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion
expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil
and gas property.
Revenue Recognition
Revenues from the sale of oil, natural gas and NGL are recognized when the product is delivered at a fixed or
determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize
revenues from the sale of oil, natural gas and NGL using the sales method of accounting, whereby revenue is recorded based on
our share of volume sold, regardless of whether we have taken our proportional share of volume produced. A receivable or
liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining
proved reserves. We receive payment one to three months after delivery. At the end of each month, we estimate the amount of
production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts
received are recorded in the month payment is received. A 10% change in our revenue accrual would have impacted total
operating revenues by approximately $9.1 million and $9.3 million for the years ended December 31, 2018 and 2017,
respectively.
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Unit and Stock Based Payments
The Company and its predecessor, Holdings, has granted restricted unit awards (“RUAs”), restricted stock units
(“RSUs”), stock option awards and performance stock awards ("PSAs) to certain employees of the Company, which therefore
required the Company to recognize the expense in its financial statements.
All unit and stock based payments to employees are measured at fair value on the grant date and expensed over the
relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model.
The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation.
All unit and stock based payment expense is recognized using the straight line method and is included within general and
administrative expenses in the consolidated statements of operations and unit and stock-based compensation in the consolidated
statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 11 — Unit and Stock Based Compensation
for additional discussion on unit and stock based payments.
Income Taxes
We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for
the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and
liabilities and their respective tax basis and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are
calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and
liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable
income or loss are subject to examination by deferral and state taxing authorities.
We periodically assess whether it is more likely than not that it will generate sufficient taxable income to realize its
deferred income tax assets, including net operating losses. In making this determination, we consider all the available positive
and negative evidence and makes certain assumptions. We consider, among other things, our deferred tax liabilities, the overall
business environment, its historical earnings and losses, current industry trends, and its outlook for future years. We believe it is
more likely than not that certain net operating losses can be carried forward and utilized.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will
be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized
in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent
likelihood of being realized upon ultimate settlement. We do not currently have uncertain tax positions.
On December 22, 2017, United States legislation referred to as the TCJA was signed into law. Many of the provisions
of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes changes to the Internal
Revenue Code of 1986 (as amended, the "Code"). The most significant change included in the TCJA is a reduction in the
corporate federal income tax rate from 35% to 21%. As a result of the enactment date of December 22, 2017, we were required
to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. This re-measurement of
deferred tax assets and liabilities required us to analyze and record a one-time adjustment to reduce the overall deferred tax
liability in the consolidated balance sheets and affect a corresponding income tax benefit in the consolidated statements of
operations for the year ended December 31, 2017. We believe the accounting is complete regarding the revaluation of the
deferred tax balances. This resulted in the recording of an income tax benefit of $23.4 million, as well as a corresponding
reduction in the deferred tax liability as of December 31, 2017. During the third quarter of 2018, we completed the accounting
for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based
compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as
a provisional amount as of December 31, 2017. There are no remaining provision amounts associated with the TCJA as of
December 31, 2018.
Extraction Oil & Gas Holdings, LLC, our accounting predecessor, was a limited liability company that was not subject
to U.S. federal income tax.
Recent Accounting Pronouncements
Please refer to Recent Accounting Pronouncements in Note 2 — Basis of Presentation and Significant Accounting
Policies in Part II, Item 8 of this Annual Report.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as
described below. The primary objective of the following information is to provide quantitative and qualitative information
about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in
oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future
losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for
purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing
for oil, natural gas and NGL has been volatile and unpredictable for several years, and this volatility is expected to continue in
the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control,
such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of fluctuations in oil prices on our revenues, we periodically enter into commodity derivative
contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of
future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity
price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed
price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars,
whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over
the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure
to oil and natural gas price fluctuations.
The following tables present our derivative positions related to crude oil and natural gas sales in effect as of
December 31, 2018:
NYMEX WTI Crude Swaps:
Notional volume (Bbl)
Weighted average fixed price ($/Bbl)
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)
Weighted average sold call price ($/Bbl)
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)
Weighted average sold put price ($/Bbl)
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)
Weighted average purchased put price ($/Bbl)
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed price ($/MMBtu)
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)
Weighted average purchased put price ($/MMBtu)
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)
Weighted average sold call price ($/MMBtu)
NYMEX HH Natural Gas Sold Puts:
Notional volume (MMBtu)
Weighted average sold put price ($/MMBtu)
CIG Basis Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed basis price ($/MMBtu)
For the Three Months Ended
March 31,
June 30,
September 30,
December 31,
March 31,
June 30,
2019
2019
2019
2019
2020
2020
—
—
—
450,000
— $
52.56
$
450,000
52.56
600,000
52.66
2,850,000
2,850,000
3,000,000
3,000,000
900,000
63.68
$
63.68
$
67.04
$
67.04
$
67.53
$
2,850,000
2,850,000
3,900,000
3,900,000
900,000
40.16
$
40.16
$
42.08
$
42.08
$
42.00
$
4,725,000
4,725,000
4,200,000
4,200,000
900,000
46.05
$
46.05
$
49.50
$
49.50
$
50.00
$
5,400,000
9,000,000
9,000,000
9,000,000
3.11
$
2.75
$
2.75
$
2.75
3,600,000
3.04
3,600,000
3.46
3,000,000
2.50
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9,000,000
9,000,000
9,000,000
9,000,000
(0.75)
$
(0.75)
$
(0.75)
$
(0.75)
—
—
—
—
—
—
—
—
—
—
$
$
$
$
$
$
$
$
600,000
52.66
900,000
67.53
900,000
42.00
900,000
50.00
—
—
—
—
—
—
—
—
—
—
87
As of December 31, 2018, the fair market value of our oil derivative contracts was a net asset of $59.4 million. Based
on our open oil derivative positions at December 31, 2018, a 10% increase in the NYMEX WTI price would decrease our net
oil derivative asset by approximately $43.4 million, while a 10% decrease in the NYMEX WTI price would increase our net oil
derivative asset by approximately $43.9 million. As of December 31, 2018, the fair market value of our natural gas derivative
contracts was a net liability of $2.3 million. Based upon our open commodity derivative positions at December 31, 2018, a 10%
increase in the NYMEX Henry Hub price would increase our net natural gas derivative liability by approximately $7.2 million,
while a 10% decrease in the NYMEX Henry Hub price would decrease our net natural gas derivative liability by approximately
$7.3 million. Please see “—Derivative Arrangements.”
Counterparty and Customer Credit Risk
Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by
investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.
We sell oil, natural gas and NGL to various types of customers, including marketers. Credit is extended based on an
evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for
oil, natural gas and NGL depends on numerous factors outside of our control, none of which can be predicted with certainty.
For the year ended December 31, 2018, we had certain major customers that exceeded 10% of total oil, natural gas and NGL
revenues. We do not believe the loss of any single purchaser would materially impact its operating results because oil, natural
gas and NGL are fungible products with well established markets and numerous purchasers.
At December 31, 2018, we had commodity derivative contracts with eleven counterparties, all of whom are lenders
under our credit agreement. We do not require collateral or other security from counterparties to support derivative instruments;
however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with
counterparties that are creditworthy financial institutions deemed by management as competent and competitive
market makers. Additionally, we use master netting agreements to minimize credit risk exposure. The creditworthiness of our
counterparties is subject to periodic review. For the years ended December 31, 2018, 2017 and 2016, we did not incur any
losses with respect to counterparty contracts. None of our existing derivative instrument contracts contains credit risk related
contingent features.
Interest Rate Risk
At December 31, 2018, we had $285.0 million of variable rate debt outstanding. The impact on interest expense of a
1% increase or decrease in the average interest rate would be approximately $2.9 million. We may begin entering into interest
rate swap arrangements on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR if we have variable-
rate debt outstanding in the future. See “—Liquidity and Capital Resources—Debt Arrangements.”
88
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EXTRACTION OIL & GAS, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Statements:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Changes in Members' and Stockholders' Equity and Noncontrolling Interest
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Page
90
92
93
94
96
98
89
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Extraction Oil & Gas, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Extraction Oil & Gas, Inc. and its subsidiaries (the “Company”)
as of December 31, 2018 and 2017, and the related consolidated statements of operations, of changes in members’ and stockholders’
equity and noncontrolling interest and of cash flows for each of the three years in the period ended December 31, 2018, including
the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal
control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position
of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America.
Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in
Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to
express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting
based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United
States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether
due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement
of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits
also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
90
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 21, 2019
We have served as the Company’s auditor since 2014.
91
EXTRACTION OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable
Trade
Oil, natural gas and NGL sales
Inventory and prepaid expenses
Commodity derivative asset
Assets held for sale
Total Current Assets
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties
Unproved oil and gas properties
Wells in progress
Less: accumulated depletion, depreciation and amortization
Net oil and gas properties
Gathering systems and facilities (Note 2)
Other property and equipment, net of accumulated depreciation (Note 2)
Net Property and Equipment
Non-Current Assets:
Commodity derivative asset
Goodwill and other intangible assets, net of accumulated amortization
Other non-current assets
Total Non-Current Assets
Total Assets
Current Liabilities:
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities
Revenue payable
Production taxes payable
Commodity derivative liability
Accrued interest payable
Asset retirement obligations
Liabilities related to assets held for sale
Total Current Liabilities
Non-Current Liabilities:
Credit facility
Senior Notes, net of unamortized debt issuance costs (Note 5)
Production taxes payable
Commodity derivative liability
Other non-current liabilities
Asset retirement obligations
Deferred tax liability
Total Non-Current Liabilities
Total Liabilities
Commitments and Contingencies—Note 13
December 31,
2018
December 31,
2017
$
234,986
$
6,768
41,695
91,225
26,816
48,907
21,008
464,637
3,916,622
609,284
144,323
(1,152,590)
3,517,639
114,469
39,849
3,671,957
8,432
2,156
18,845
29,433
46,047
93,301
13,017
4,132
—
163,265
3,011,526
686,968
127,418
(709,662)
3,116,250
4,889
32,429
3,153,568
—
55,453
12,383
67,836
$
$
4,166,027
$
3,384,669
186,218
$
211,581
117,344
57,516
196
22,249
15,729
3,146
402,398
285,000
1,132,659
115,607
—
8,072
54,062
109,176
1,704,576
2,106,974
52,805
37,444
67,428
23,807
6,873
—
399,938
90,000
933,361
57,982
17,274
5,973
62,667
42,326
1,209,583
1,609,521
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 and 185,280 issued and
outstanding, respectively
164,367
158,383
Stockholders' Equity:
Common Stock, $0.01 par value; 900,000,000 shares authorized; 171,666,485 and 172,059,814 issued and outstanding,
respectively
Treasury Stock, at cost, 4,543,262 and 165,385 shares, respectively
Additional paid-in capital
Accumulated deficit
Total Extraction Oil & Gas, Inc. Stockholders' Equity
Noncontrolling interest—(Note 9)
Total Stockholders' Equity
Total Liabilities and Stockholders' Equity
1,678
(32,737)
2,153,661
(375,788)
1,746,814
147,872
1,894,686
$
4,166,027
$
1,718
(2,105)
2,114,795
(497,643)
1,616,765
—
1,616,765
3,384,669
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART
OF THESE CONSOLIDATED FINANCIAL STATEMENTS
92
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Revenues:
Oil sales
Natural gas sales
NGL sales
Total Revenues
Operating Expenses:
Lease operating expenses
Transportation and gathering
Production taxes
Exploration expenses
Depletion, depreciation, amortization and accretion
Impairment of long lived assets and goodwill
Other operating expenses
(Gain) loss on sale of property and equipment and assets of
unconsolidated subsidiary
Acquisition transaction expenses
General and administrative expenses
Total Operating Expenses
Operating Income (Loss)
Other Income (Expense):
Commodity derivatives loss
Interest expense
Other income
Total Other Income (Expense)
Income (Loss) Before Income Taxes
Income tax (expense) benefit
Net Income (Loss)
Net income attributable to noncontrolling interest
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.
Adjustments to reflect Series A Preferred Stock dividends and
accretion of discount
Net Income (Loss) Available to Common Shareholders, Basic and
Diluted
Net Income (Loss) Per Common Share (Note 12)
Basic and diluted
Weighted Average Common Shares Outstanding
Basic and diluted
For the Year Ended
December 31,
2018
2017
2016
$
840,687
$
419,904
$
194,059
105,629
114,427
1,060,743
79,413
39,411
90,345
31,611
435,775
70,928
—
(136,834)
—
134,604
745,253
315,490
(8,554)
(123,330)
5,099
(126,785)
188,705
(66,850)
121,855
7,287
114,568
92,322
92,070
604,296
60,358
50,948
51,367
36,256
314,999
1,647
—
451
—
110,167
626,193
(21,897)
(36,332)
(51,889)
2,010
(86,211)
(108,108)
63,700
(44,408)
—
(44,408)
48,652
35,378
278,089
36,743
25,300
20,730
36,422
205,348
23,425
10,891
—
2,719
232,388
593,966
(315,877)
(100,947)
(68,843)
386
(169,404)
(485,281)
29,280
(456,001)
—
(226,107)
$
$
(16,869)
(16,279)
(3,999)
97,699
$
(60,687) $
(230,106)
0.56
$
(0.35) $
(1.54)
174,748
171,910
149,029
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
93
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95
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Net income (loss)
Reconciliation of net income (loss) to net cash provided by operating activities:
For the Year Ended
December 31,
2018
2017
2016
$
121,855
$
(44,408)
$
(456,001)
Depletion, depreciation, amortization and accretion
Abandonment and impairment of unproved properties
Impairment of long lived assets and goodwill
(Gain) loss on sale of property and equipment
Gain on sale of assets of unconsolidated subsidiary
Amortization of debt issuance costs and debt discount
Deferred rent
Commodity derivatives loss
Settlements on commodity derivatives
Premiums paid on commodity derivatives
Earnings in unconsolidated subsidiaries
Distributions from unconsolidated subsidiary
Make-whole premium expense on 2021 Senior Notes
Prepayment penalty expense on Second Lien Notes
Deferred income tax expense (benefit)
Unit and stock-based compensation
Changes in current assets and liabilities:
Accounts receivable—trade
Accounts receivable—oil, natural gas and NGL sales
Inventory and prepaid expenses
Accounts payable and accrued liabilities
Revenue payable
Production taxes payable
Accrued interest payable
Asset retirement expenditures
Net cash provided by operating activities
Cash flows from investing activities:
Oil and gas property additions
Acquired oil and gas properties
Sale of property and equipment
Gathering systems and facilities additions
Other property and equipment additions
Investment in unconsolidated subsidiaries
Distributions from unconsolidated subsidiary, return of capital
Sale of assets of unconsolidated subsidiary
Net cash used in investing activities
Cash flows from financing activities:
Borrowings under credit facility
Repayments under credit facility
Proceeds from the issuance of Senior Notes
Repayments of Second Lien Notes
Prepayment penalty paid on Second Lien Notes
Repayments of 2021 Senior Notes
Make-whole premium paid on 2021 Senior Notes
Proceeds from issuance of Preferred Units
Preferred Unit issuance costs
Proceeds from the issuance of units
Repurchase of stock and units
96
435,775
25,704
70,928
(53,222)
(83,612)
13,250
348
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(134,624)
(22,749)
(2,862)
1,684
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68,349
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66,276
79,106
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(13,669)
684,933
314,999
15,808
1,647
451
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(294)
36,332
(11,985)
(475)
(415)
415
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(63,700)
65,607
(22,634)
(59,235)
(523)
31,202
17,643
32,252
4,186
(4,168)
316,965
(958,399)
(1,370,787)
—
80,879
(81,406)
(15,991)
(6,000)
—
83,612
(17,225)
5,155
(4,452)
(17,737)
—
518
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205,348
22,318
23,425
—
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19,088
551
100,947
42,827
(611)
—
—
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4,300
(29,280)
200,308
(574)
(18,128)
(1,110)
(19,187)
(6,602)
14,585
19,171
(687)
120,688
(449,600)
(419,009)
2,656
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—
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(897,305)
(1,404,528)
(873,608)
635,000
(440,000)
739,664
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(35,600)
148,500
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565,000
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394,000
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(2,105)
263,000
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550,000
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(4,300)
—
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121,370
(2,867)
Payment of employee payroll withholding taxes
(5,327)
(1,804)
Issuance of common stock
Issuance of Series A Preferred Units
Redemption of Series A Preferred Units
Dividends on Series A Preferred Stock
Proceeds from the issuance of Series B Preferred Units
Dividends on Series B Preferred Units
Debt issuance costs
Equity issuance costs
Net cash provided by financing activities
Increase (decrease) 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 the period
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities
Cash paid for interest
Issuance of promissory note to unconsolidated subsidiary
Extinguishment of promissory note in exchange for equity with unconsolidated subsidiary
Write-off of deposit on acquisition
Accretion of beneficial conversion feature
Noncash settlement of promissory notes issued to officers
Increase in dividends payable
Non-cash contribution to unconsolidated subsidiary
Preferred Units commitment fees and dividends paid-in-kind
—
—
—
—
—
—
(10,885)
(10,401)
—
—
(3,166)
(9)
440,590
228,218
6,768
234,986
141,952
84,224
35,329
(35,329)
$
$
$
$
$
— $
5,984
$
— $
— $
— $
7,287
$
—
—
(4,627)
(1,668)
463,395
(624,168)
630,936
6,768
151,571
54,492
$
$
$
— $
— $
— $
5,394
$
— $
484
8,738
$
$
— $
$
$
$
$
$
$
$
$
$
$
$
—
1,185,332
75,000
(88,688)
—
185,280
(721)
(14,102)
(64,554)
1,286,750
533,830
97,106
630,936
105,450
31,280
—
—
10,000
1,041
5,562
—
—
—
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
97
EXTRACTION OIL & GAS, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Business and Organization
Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the
acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the
Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The Company and its subsidiaries are focused
on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, as well as
the construction and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin of
Colorado. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol "XOG".
Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and an unrestricted subsidiary of the
Company, focused on the construction of gathering systems and facilities operations to serve the development of acreage in the
Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the gathering systems
and facilities line item within the consolidated balance sheet. As of December 31, 2018, these gathering systems and facilities
operations are not in service, therefore, there are no such revenues for the year then ended.
The consolidated financial statements for the period January 1, 2016 through October 12, 2016 are based on the
financial statements of the Company's accounting predecessor, Extraction Oil & Gas Holdings, LLC ("Holdings") prior to the
corporate reorganization (the "Corporate Reorganization"), pursuant to which, in connection with the initial public offering of
the Company (the "Offering" or "IPO"), (i) on October 11, 2016, a former subsidiary of Extraction Oil & Gas Holdings, LLC,
Extraction Oil & Gas, LLC, converted into the Company, and (ii) on October 17, 2016, Holdings merged with and into the
Company with Extraction as the surviving entity.
Note 2—Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The consolidated financial statements include the accounts of the Company, including its wholly owned subsidiaries.
All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements
included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in
the United States (“GAAP”). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals
that are considered necessary for a fair statement of the consolidated financial information, have been included.
Use of Estimates in the Preparation of Financial Statements
The preparation of the consolidated financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and 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. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas
reserves; (2) cash flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion,
amortization and accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection
with business combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables;
(7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of unit and stock-based payments, and
(10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these
estimates. The Company evaluates its estimates on an on going basis and bases its estimates on historical experience and on
various other assumptions the Company believes to be reasonable under the circumstances.
Cash and Cash Equivalents
Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have
original maturities of three months or less when purchased.
Restricted Cash
Restricted cash represents cash that is unavailable for use in the Company's general operations. The Company had no
restricted cash as of December 31, 2018 and 2017.
98
Cash Held in Escrow
Cash held in escrow includes deposits for the purchase of certain oil and gas properties as required under the related
purchase and sale agreements. The Company had no cash held in escrow as of December 31, 2018 and 2017.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The
Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the
ability to withhold future revenue disbursements to recover non payment of joint interest billings. On an on going basis,
management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables
under the specific identification method. The Company did not record any allowance for uncollectible receivables as of or for
the years ended December 31, 2018 and 2017.
Credit Risk and Other Concentrations
The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and
controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the
federally insured limits.
The Company sells oil, natural gas and NGL to various types of customers, including oil marketers, pipelines and
refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The
future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control,
none of which can be predicted with certainty. For the three years ended December 31, 2018, the Company had the following
customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single
purchaser would materially impact its operating results because crude oil, natural gas and NGL are fungible products with
well established markets and numerous purchasers.
Customer A
Customer B
Customer C
Customer D
Customer E
For the Year Ended
December 31,
2018
2017
2016
76%
11%
—%
—%
—%
65%
19%
11%
—%
—%
25%
19%
—%
23%
16%
At December 31, 2018, the Company had commodity derivative contracts with eleven counterparties, all of whom are
lenders under our credit agreement. The Company does not require collateral or other security from counterparties to support
derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into
derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent
and competitive market makers. Additionally, the Company uses master netting agreements to minimize credit risk exposure.
The credit worthiness of the Company’s counterparties is subject to periodic review. For the years ended December 31, 2018,
2017 and 2016, the Company did not incur any losses with respect to counterparty contracts. None of the Company’s existing
derivative instrument contracts contains credit risk related contingent features.
99
Inventory and Prepaid Expenses
The Company records well equipment inventory at the lower of cost or net realizable value. Prepaid expenses are
recorded at cost. Inventory and prepaid expenses are comprised of the following (in thousands):
Well equipment inventory
Prepaid expenses
As of December 31,
2018
2017
$
$
19,916
6,900
26,816
$
$
9,971
3,046
13,017
Additionally, the Company recognized approximately $0.1 million, $0.7 million and $0.4 million of impairment
expense on well equipment inventory for the years ended December 31, 2018, 2017 and 2016, respectively.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of
accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a
units of production basis over the remaining life of proved reserves and proved developed reserves, respectively. For the years
ended December 31, 2018, 2017 and 2016, the Company excluded $144.3 million, $127.4 million and $98.7 million of
capitalized costs from depletion related to wells in progress, respectively. For the years ended December 31, 2018, 2017 and
2016, the Company recorded depletion expense on capitalized oil and gas properties of $426.8 million, $306.7 million and
$197.4 million, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been
found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that
proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense.
In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and
evaluation of the wells. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are
capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and
(b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The
status of suspended well costs is monitored continuously and reviewed at each period end. Due to the capital intensive nature
and the geological characteristics of certain projects, it may take an extended period of time to evaluate the future potential of
an exploration project and the economics associated with making a determination of its commercial viability. As of
December 31, 2018, the Company had approximately $6.1 million of suspended well costs, all capitalized less than one year
and included in wells in progress at December 31, 2018. These exploratory well costs are pending further engineering
evaluation and analysis to determine if economic quantities of oil and gas reserves have been discovered. The Company
expects its analysis to be complete in the second half of 2019. As of December 31, 2017, $15.7 million of suspended well costs,
all capitalized less than one year and included in wells in progress as of December 31, 2017. At September 30, 2018, the
Company completed its evaluation and moved $17.9 million of these suspended well costs to proved oil and gas properties
based on the determination of proved reserves. As of December 31, 2016, the Company had no suspended well costs recorded.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development
drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based
on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas
of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs
and exploration expense. The Company expensed $0.4 million and $1.4 million of costs associated with exploratory geological
and geophysical costs for the years ended December 31, 2018 and 2017, respectively. There were no exploratory geological and
geophysical costs incurred for the year ended December 31, 2016.
The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development
activities. For the years ended December 31, 2018, 2017 and 2016, the Company capitalized interest of approximately $8.2
million, $11.1 million and $5.2 million, respectively.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable
property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so
100
significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or
losses from the disposal of complete units of depreciable property are recognized to earnings.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference
between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved
properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Impairment of Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a
possible decline in the recoverability of the carrying amount of such property. For all of its fields, the Company estimates the
expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of
the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated
undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value.
The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future
production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate
with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is
reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases
accumulated depletion, depreciation and amortization. For the years ended December 31, 2018 and 2016, the Company
recognized $16.2 million and $22.5 million, respectively, in impairment expense on proved oil and gas properties in the
Company's northern field. As of September 30, 2018, the future undiscounted cash flows did not exceed its carrying amount
associated with its proved oil and gas properties in its northern field. As of June 30, 2016, it was determined that the proved oil
and gas properties had no remaining fair value, therefore, the full net book value of these proved oil and gas properties were
impaired. For the year ended December 31, 2017, the Company recognized no impairment expense on proved oil and gas
properties.
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved
reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term,
drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are
drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a
unit of production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration
expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties,
the Company recognized $25.7 million, $15.8 million and $22.3 million in impairment expense for the years ended
December 31, 2018, 2017 and 2016, respectively.
Other Property and Equipment
Other property and equipment consists of (i) other property and equipment including, office furniture and fixtures,
leasehold improvements and computer hardware and software, (iii) compressors used in Extraction’s oil and gas operations,
(iii) land, compressor stations, central tank batteries, and disposal well facilities and (iv) rights of ways, pipeline, and
engineering costs. Impairment expense for other property and equipment is reported in impairment of long lived assets and
goodwill in the consolidated statements of operations. The Company recognized $0.4 million, $0.9 million and $0.5 million in
impairment expense related to midstream facilities for the years ended December 31, 2018, 2017 and 2016, respectively, which
increased accumulated depreciation recognized in other property and equipment, net of accumulated depreciation. The
Company recognized the impairment expense for the year ended December 31, 2018 and 2017 primarily as the result of right-
of-way options that were no longer in the Company's plans for developing midstream infrastructure. The Company recognized
the impairment expense for the years ended December 31, 2016, as the result of contraction in the local oil and gas industry’s
near term growth profile, therefore decreasing the need and support for a specifically proposed gas processing facility. Gain or
loss on the sale of other property and equipment is reported in (gain) loss on sale of property and equipment in the consolidated
statement of operations. The Company recognized $0.5 million of loss on the sale of other property and equipment related to
the disposal of an oil pipeline that was not yet placed into service in the first quarter of 2017. Other property and equipment is
recorded at cost and depreciated using the straight line method.
101
The estimated useful lives of those assets depreciated under the straight-line basis are as follows:
Rental equipment
Office leasehold improvements
Other
Other property and equipment is comprised of the following (in thousands):
Rental equipment
Land
Right-of-ways and pipeline
Office leasehold improvements
Other
Less: accumulated depreciation and impairment
Gathering Systems and Facilities
1-10 years
3-10 years
3-5 years
As of December 31,
2018
2017
$
4,043
$
27,595
8,008
7,231
6,946
(13,974)
39,849
$
$
3,805
22,991
7,447
4,405
5,578
(11,797)
32,429
Gathering systems and facilities consist of midstream assets such as land, rights of way, pipelines, equipment and
construction and engineering costs associated with the construction of pipeline infrastructure to serve the development of the
Company's acreage in its Hawkeye and Southwest Wattenberg areas. Approximately $112.3 million of gathering system and
facilities assets have not been placed into service and therefore are not currently being depreciated. The Company will
determine the estimated use lives of these assets when they are placed into service.
Gathering systems and facilities is comprised of the following (in thousands):
Gathering systems and facilities
Land associated with gathering systems and facilities
Less: accumulated depreciation
Equity Method Investments
As of December 31,
2018
2017
112,281
2,188
—
4,889
—
—
$
114,469
$
4,889
Investments in entities for which the Company exercises significant influence, but not control, are accounted for under
the equity method. The Company recorded $15.5 million and $8.3 million of such investments included in other non-current
assets on the consolidated balance sheets as of December 31, 2018 and 2017, respectively. The Company recognized $2.9
million and $0.4 million of income from such investments, including the accretion of any basis difference between the carrying
amount of the investment and the amount of underlying equity in net assets, included in other income on the consolidated
statements of operations and equity in earnings of unconsolidated subsidiary, in which we have a minority ownership interest
on the consolidated statements of cash flows for the year ended December 31, 2018 and 2017, respectively. The Company held
no such investments during the years ended December 31, 2016.
On August 3, 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for year
ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of
which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an
acreage dedication, which is considered a nonfinancial asset.
102
Deferred Lease Incentives
All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and
amortized over the term of the respective lease on a straight line basis as a reduction of rental expense. Please refer to Recent
Accounting Pronouncements for discussion related to Accounting Standard Update No. 2016-02, which updates the GAAP
related to deferred lease incentives and will be effective as of January 1, 2019.
Debt Discount Costs
The $430.0 million in Second Lien Notes issued in May of 2014 were issued at a 1.5% original issue discount (“OID”)
and the debt discount of $6.5 million was recorded as a reduction of the Second Lien Notes. The debt discount costs related to
Second Lien Notes were amortized to interest expense using the effective interest method over the term of the debt.
Debt Issuance Costs
Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with
the Company’s credit facility, 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes").
Debt issuance costs related to the credit facility are included in other non-current assets on the consolidated balance sheets and
amortized to interest expense on the consolidated statement of operations on a straight line basis over the respective borrowing
term. Debt issuance costs related to the Senior Notes are amortized to interest expense using the effective interest method over
the term of the debt.
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of
the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are
included in the accompanying balance sheets as commodity derivative assets and commodity derivative liabilities. The
Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not
apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments
are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity
derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations.
The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in
making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are
reflected as operating activities in the Company’s consolidated statements of cash flows.
Any premiums paid on derivative contracts are capitalized as part of the derivative assets or derivative liabilities, as
appropriate, at the time the premiums are paid. Premium payments are reflected in cash flows from operating activities in the
Company's consolidated statements of cash flows. Over time, as the derivative contracts settle, the differences between the cash
received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or
interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in the Company's
consolidated statements of cash flows.
The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit
worthiness, and the time value of money. The consideration of these factors result in an estimated exit price for each derivative
asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable,
non biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to
Note 6 — Commodity Derivative Instruments for additional discussion on commodity derivative instruments.
Goodwill and Other Intangible Assets
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of
the purchase price over the estimated fair value of the net assets acquired in business combinations. The Company tests
goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying
amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the
Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment
charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the
prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could
change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed a
quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its
103
carrying amount. The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing
and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company
performed a quantitative assessment as of December 31, 2018, utilizing an income approach based on estimates of the expected
discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit
was not greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety
of the balance, for the year ended December 31, 2018. The Company performed a quantitative assessment as of September 30,
2017, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company performed a
qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-
likely-than-not greater than its carrying amount.
Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the
estimated useful life of the license, which is typically one to three years. The Company recorded $3.0 million, $2.3 million and
$0.3 million of internal-use software for the years ended December 31, 2018, 2017 and 2016, respectively, on the consolidated
balance sheets within the goodwill and other intangible assets line item. Accumulated amortization for the years ended
December 31, 2018, and 2017 was $3.1 million and $1.1 million, respectively. The Company recognized $2.1 million, $1.0
million and $0.1 million amortization expense for the years ended December 31, 2018, 2017 and 2016, respectively.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts
payable, commodity derivative instruments (discussed above) and long term debt. The carrying values of cash and cash
equivalents, accounts receivable and accounts payable are representative of their fair values due to their short term maturities.
The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term
of the loan. The Company’s Senior Notes are recorded at cost and the fair value is disclosed in Note 8 — Fair Value
Measurements. 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.
Asset Retirement Obligation
The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas
properties. 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 the Company makes the decision to complete the well or a well is acquired. For
additional discussion on asset retirement obligations please refer to Note 7 — Asset Retirement Obligations.
Environmental Liabilities
The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the
release, disposal or discharge of materials into the environment or otherwise relating to environmental protection and may
require the Company to remove or mitigate the environmental effects of the discharge, disposal or release of petroleum
substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are
expensed.
Liabilities for expenditures of a non capital nature are recorded when environmental assessments and/or remediation is
probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash
payments for the liability or component is fixed or determinable. Management has determined that no significant environmental
liabilities existed as of December 31, 2018.
Revenue Recognition
Revenues from the sale of oil, natural gas and NGL are recognized when the product is delivered at a fixed or
determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company
recognizes revenues from the sale of oil, natural gas and NGL using the sales method of accounting, whereby revenue is
recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of
volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific
property greater than the expected remaining proved reserves. As of December 31, 2018, the Company has an oil imbalance of
22 MBbl, which the Company intends to settle with the counterparty in crude oil barrels. There were no material imbalances at
December 31, 2017 or 2016.
104
On January 1, 2018, the Company adopted ASC 606 - Revenue from Contracts with Customers ("ASC 606"). See
Adoption of ASC 606 for more information regarding the adoption of this standard.
Unit and Stock Based Payments
The Company and its predecessor, Holdings, has granted restricted unit awards ("RUAs"), restricted stock units
("RSUs"), stock option awards and performance stock awards ("PSAs") to certain directors, officers and employees of the
Company, which therefore required the Company to recognize the expense in its financial statements.
All unit and stock based payments to directors, officers and employees are measured at fair value on the grant date and
expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes
option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a
Monte Carlo simulation. All unit and stock based payment expense is recognized using the straight line method and is included
within general and administrative expenses in the consolidated statements of operations and unit and stock-based compensation
in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 11 — Unit and
Stock Based Compensation for additional discussion on unit and stock based payments.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are
recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax basis and operating loss and tax credit carry forwards. Deferred tax assets
and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax
assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of
taxable income or loss are subject to examination by deferral and state taxing authorities.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to
realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all
the available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its
deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its
outlook for future years. The Company believes it is more likely than not that certain net operating losses can be carried
forward and utilized.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax
position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax
benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater
than fifty percent likelihood of being realized upon ultimate settlement. The Company does not currently have uncertain tax
positions.
On December 22, 2017, United States legislation referred to as the Tax Cuts and Jobs Act (the "TCJA") was signed
into law. Many of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA
includes changes to the Internal Revenue Code of 1986 (as amended, the "Code"). The most significant change included in the
TCJA is a reduction in the corporate federal income tax rate from 35% to 21%. As a result of the enactment date of December
22, 2017, the Company was required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to
reverse. This re-measurement of deferred tax assets and liabilities required the Company to analyze and record a one-time
adjustment to reduce the overall deferred tax liability in the consolidated balance sheets and affect a corresponding income tax
benefit in the consolidated statements of operations for the year ended December 31, 2017. The Company believes the
accounting is complete regarding the revaluation of the deferred tax balances. This resulted in the recording of an income tax
benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability as of December 31, 2017. During the
third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation under
Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million
reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. There are no
remaining provisional amounts associated with the TCJA as of December 31, 2018.
Extraction Oil & Gas Holdings, LLC, the Company’s accounting predecessor, was a limited liability company that was
not subject to U.S. federal income tax.
Earnings Per Share
105
Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to
common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the
potential dilution of securities that could share in the earnings available to common shareholders of the Company. The
Company uses the “if-converted” method to determine the potential dilutive effects of its Series A Preferred Stock, and the
treasury stock method to determine the potential dilutive effect of outstanding restricted stock units and stock option awards.
The Company’s EPS calculation for the year ended December 31, 2016 includes only the net income (loss) for the period
subsequent to IPO and Corporate Reorganization which occurred on October 12, 2016 and has omitted EPS prior to this date.
In addition, the basic weighted average shares outstanding calculation for the year ended December 31, 2016 is based on the
actual days in which the shares were outstanding for the period from October 12, 2016, to December 31, 2016.
Segment Reporting
Beginning in the fourth quarter of 2018, the Company had two operating segments, (i) the exploration, development
and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction and support of
midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior to the fourth
quarter of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment is
currently under development. Capital expenditures associated with gathering systems and facilities are being incurred to
develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party
activity. The activity of the exploration and production segment and gathering systems and facilities operating segment are
being monitored by our chief operating decision maker ("CODM"). The Company expects the first phase of the gathering
systems and facilities to be operational during the second half of 2019. Revenues associated with the exploration and
production segment are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted
from our natural gas during processing. Revenues and operating expenses associated with the gathering systems and facilities
operations will be primarily derived from intersegment transactions for services provided to the Company's exploration,
development and production operations by Elevation Midstream, LLC., an unrestricted subsidiary to the Company. All
intersegment transactions are and will be eliminated upon consolidation, including revenues and operating expenses during the
construction of and from gathering services provided by Elevation Midstream to the Company. The CODM considers Adjusted
EBITDAX as the measure of segment performance under ASC 280, Segment Reporting. Accounting policies for each segment
are the same as the accounting policies as described herein. For more information about Segments, see Note 15 — Segment
Information.
All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived
from customers located in the United States.
Recent Accounting Pronouncements
The accounting standard setting organizations frequently issue new or revised accounting rules. The Company
regularly reviews new pronouncements to determine their impact, if any, on its consolidated financial statements and related
disclosures.
In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)
No. 2018-15, which 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
and hosting arrangements that include an internal-use software license. For public entities, the new guidance is effective for
fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company
is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.
In August 2018, the FASB issued ASU No. 2018-13, which improves the disclosure requirements on fair value
measurements. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including
interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the
potential impact to its financial statements and related disclosures.
In May 2017, the FASB issued ASU No. 2017-09, which provides clarification and reduces both (1) diversity in
practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a
change to the terms or conditions of a share-based payment award. For public entities, the new guidance was effective for fiscal
years beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company
adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial
statements and related disclosures.
106
In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on
accounting for the derecognition of nonfinancial assets. For public entities, the new guidance was effective for fiscal years
beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company adopted this ASU
on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and
related disclosures.
In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for
impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by
comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance
is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill
impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating the impact of adopting
this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating
whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new
guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The
Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the
consolidated financial statements and related disclosures; however, this standard may result in more transactions being
accounted for as asset acquisitions rather than business combinations.
In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted
cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting
periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018 and the retrospective adoption
increased the Company's beginning cash balances within the statement of cash flows for the prior period presented in the table
below. The adoption had no other material impact on the cash flow statement and had no impact on the Company's results of
operations or financial position.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the
consolidated balance sheets to the consolidated statement of cash flows:
Cash and cash equivalents
Restricted cash included in cash held in escrow
As of
December 31,
2018
December 31,
2017
December 31,
2016
December 31,
2015
$
$
234,986
—
234,986
$
$
6,768
—
6,768
$
$
588,736
42,200
630,936
$
$
97,106
—
97,106
In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including
presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice.
For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods
within those fiscal years. The Company adopted this ASU on January 1, 2018, which requires current period make-whole
premiums to be presented in financing activities in the statement of cash flows and prior period debt prepayment costs to be
reclassified from operating activities to financing activities in the statement of cash flows; however, there was no impact to the
total change in cash and cash equivalents from period to period.
In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a
right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires
recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term
on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the
statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted.
The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which
provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on the
consolidated financial statements and related disclosures and expects certain lease agreements with terms over one year to be
classified as right-of-use assets and right-of-use liabilities, which will gross up the consolidated balance sheet as of January 1,
2019. The Company will adopt the accounting standard using a modified retrospective transition approach, which applies the
provisions of the new guidance at the effective date without adjusting the comparative periods presented. The Company has
elected the package of practical expedients permitted under the transition guidance with the new standard, which among other
107
things, requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease
classification for existing leases upon adoption. The Company has also elected the optional practical expedient permitted under
the transition guidance within the new standard related to land easements that allows it to carry forward its current accounting
treatment for land easements on existing agreements upon adoption. The Company made an accounting policy election to keep
leases with an initial term of twelve months or less off of the consolidated balance sheet. The Company is finalizing its
evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements and
on our future consolidated balance sheet upon adoption. As a part of the implementation work, the Company is validating the
inputs and outputs of the software tool used to calculate the initial and ongoing accounting balances for right-of-use assets and
liabilities and finalizing the completeness of the lease population.
In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model,
referred to as ASC 606 - Revenue from Contracts with Customers, designed to depict the transfer of goods or services to a
customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The
ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU
No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after
December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No.
2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13, ASU No. 2017-14
and ASU No. 2019-20, which provided additional implementation guidance. Refer to —Adoption of ASC 606 for more
information.
Adoption of ASC 606
On January 1, 2018, the Company adopted ASC 606. The Company adopted ASC 606 using the modified
retrospective method to apply the new standard to all new contracts entered into on or after January 1, 2018 and all existing
contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. ASC 606
supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict
the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be
entitled in exchange for those goods or services.
The impact of adoption in the year ended December 31, 2018 results are as follows (in thousands):
Revenues:
Oil sales
Natural gas sales
NGL sales
Total Revenues
Operating Expenses:
Transportation and gathering
Revenues less transportation and gathering
Under ASC
606
Under ASC
605
Change
$
$
$
$
840,687
105,629
114,427
1,060,743
$
840,687
121,180
134,558
1,096,425
39,411
1,021,332
$
$
75,093
1,021,332
$
$
—
(15,551)
(20,131)
(35,682)
(35,682)
—
Changes to sales of natural gas and NGL, and transportation and gathering expenses are due to the conclusion that
certain midstream processing entities are the Company's customers in natural gas processing and marketing agreements in
accordance with the five-step process in ASC 606. This is a change from previous conclusions reached for these agreements
utilizing the principal versus agent indicators under ASC 605 where the Company determined it was the principal, the
midstream processor was the agent and the third-party end user was its customer. As a result, the Company modified its
presentation of revenues and operating expenses for these agreements. Revenues related to these agreements are now presented
on a net basis for proceeds expected to be received from the midstream processing entity. Revenues from the sale of oil, natural
gas and NGL, where the Company is a non-operating interest partner, are considered in the scope of ASC 808 - Collaborative
Arrangements. Therefore, ASC 606 did not change the presentation of these revenues.
Transportation and gathering expense related to other agreements incurred prior to the transfer of control to the
customer at the tailgate of the natural gas processing facilities will continue to be presented as transportation and gathering
expense.
108
Revenues from Contracts with Customers
Sales of oil, natural gas and NGL are recognized at the point control of the commodity is transferred to the customer
and collectability is reasonably assured. The majority of the Company's contracts' pricing provisions are tied to a commodity
market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission
line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas
and NGL fluctuates to remain competitive with the other available oil, natural gas and NGL supplies.
Oil Sales
Under the Company's crude purchase and marketing contracts, the Company generally sells oil production at the
wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue
when control transfers to the purchaser at the wellhead at the net price received.
The Company utilizes the sales method to account for producer imbalances, which continues to be applicable under
ASC 606. As of December 31, 2018, the Company has an oil imbalance of 22 MBbl, which the Company intends to settle with
the counterparty in crude oil barrels.
Natural Gas and NGL Sales
Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing
entity at the wellhead or the inlet of the midstream processing entity's system. The midstream processing entity gathers and
processes the natural gas and remits proceeds to the Company for the resulting sales of NGL and residue gas. In these
scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the
hydrocarbons transfer to the customer. For those contracts where the Company has concluded the midstream processing entity
is the Company's agent and the third-party end user is its customer (generally the Company's fixed-fee gathering and processing
agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an
operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has
concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company's percentage
of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net
amount of the proceeds received from the midstream processing company.
In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGL in-kind at the
tailgate of the midstream entity's processing plant and subsequently market the product. Through the marketing process, the
Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified
index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at
the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to
the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are
presented as transportation and gathering expense in the consolidated statements of operations.
Performance Obligations
A significant number of the Company's product sales are short-term in nature with a contract term of one year or less.
For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from
disclosure of the transaction price of a contract that has an original expected duration of one year or less.
For the Company's product sales that have a contract term greater than one year, the Company has utilized the
practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price
allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied
performance obligation. Under these sales contracts, each unit of product generally represents a separate performance
obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining
performance obligations is not required.
The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the
purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after
the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the
customer and the net commodity price that will be received for the sale of these commodity products. The Company records the
differences between the revenue estimated and the actual amounts received for product sales in the month that payment is
received from the customer. The Company has internal controls over its revenue estimation process and related accruals, and
109
any identified differences between its revenue estimates and actual revenue received historically have not been significant. For
the period from January 1, 2018 to December 31, 2018, revenue recognized in the reporting period related to performance
obligations satisfied in prior reporting periods was not material.
Contract Balances
Under the Company's various sales contracts, the Company invoices customers once its performance obligations have
been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to
contract assets or liabilities under ASC 606.
The following table presents the Company's revenues disaggregated by revenue source. Transportation and gathering
costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses
that are netted against revenues pursuant to ASC 606. Prior period amounts have not been adjusted under the modified
retrospective method.
Revenues:
Oil sales
Natural gas sales
NGL sales
Transportation and gathering included in revenues
Total Revenues
For the Year Ended December 31,
2018
2017
2016
$
$
840,687
$
419,904
$
194,059
121,180
134,558
(35,682)
1,060,743
92,322
92,070
—
48,652
35,378
—
$
604,296
$
278,089
There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the
Company as of December 31, 2018, and through the date of this filing that would have a material impact on the Company’s
consolidated financial statements and related disclosures.
Note 3—Oil and Gas Properties
The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the
Company’s oil and gas producing activities were as follows (in thousands):
Proved oil and gas properties
Unproved oil and gas properties(1)
Wells in progress(2)
Total capitalized costs(3)
Accumulated depletion, depreciation and amortization
Net capitalized costs
As of December 31,
2018
3,916,622
609,284
144,323
4,670,229
(1,152,590)
3,517,639
$
$
$
$
$
$
2017
3,011,526
686,968
127,418
3,825,912
(709,662)
3,116,250
(1) Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until
proved reserves are established or impairment is determined.
(2) Costs from wells in progress are excluded from the amortization base until production commences.
(3) Includes accumulated interest capitalized of $32.6 million, $24.5 million and $13.4 million as of December 31, 2018, 2017
and 2016, respectively.
110
The following table presents information regarding the Company’s net costs incurred in oil and gas property
acquisition, exploration and development activities (in thousands):
For the Year Ended
December 31,
2018
2017
Property acquisition costs:
Proved
Unproved
Exploration costs(1)
Development costs
Total
Total excluding asset retirement costs
$
$
$
46,052
$
79,708
8,840
776,528
911,128
902,241
139,481
382,213
17,074
894,040
$
$
1,432,808
1,420,235
(1) Exploration costs do not include impairment and abandonment costs of unproved properties, which are included in the line
item exploration expenses in the consolidated statements of operations.
Note 4—Acquisitions and Divestitures
Assets Held for Sale
In January 2019, the Company entered into a definitive agreement with an unaffiliated oil and gas company to sell
approximately 5,000 net acres of leasehold and producing properties primarily in Weld County, Colorado (the "Proposed March
2019 Divestiture") from its exploration and production segment. Upon closing, the Company will receive total consideration of
approximately $22.4 million in cash, subject to customary purchase price adjustments. The effective date for the Proposed
March 2019 Divestiture is July 1, 2018 with purchase price adjustments calculated as of the closing date, which is scheduled
for late March 2019. These assets are classified as held for sale on the consolidated balance sheets.
The following table presents the information related to the assets held for sale in the December 31, 2018 consolidated
balance sheet (in thousands):
Assets:
Property and equipment
Proved oil and gas properties, net
Unproved oil and gas properties
Total Assets Held for Sale
Liabilities:
Revenue payable
Production taxes payable
Total liabilities held for sale
Total Assets Held for Sale, Net
December 31,
2018
$
$
$
$
$
11,945
9,063
21,008
1,737
1,409
3,146
17,862
The assets held for sale as of December 31, 2018 do not qualify for discontinued operations as they do not represent a
strategic shift that will have a major effect of the Company's operations or financial results.
December 2018 Divestitures
In December 2018, the Company completed various sales of its interests in approximately 31,200 net acres of
leasehold and primarily non-producing properties, for aggregate sales proceeds of approximately $8.5 million, subject to
customary purchase price adjustments, and recognized a loss of $6.1 million.
111
August 2018 Divestiture
On August 3, 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the year
ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of
which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an
acreage dedication, which is considered a nonfinancial asset.
April 2018 Divestitures
In April 2018, the Company completed various sales of its interests in approximately 15,100 net acres of leasehold and
primarily non-producing properties for aggregate sales proceeds of approximately $72.3 million and recognized a gain of $59.3
million for the year ended December 31, 2018.
April 2018 Acquisition
On April 19, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,000 net
acres of non-producing leasehold primarily located in Arapahoe County, Colorado (the "April 2018 Acquisition"). Upon closing
the seller received approximately $9.4 million in cash. This transaction has been accounted for as an asset acquisition. The
acquisition provided new development opportunities in the Core DJ Basin.
January 2018 Acquisition
On January 8, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,200 net
acres of non-producing leasehold located in Arapahoe County, Colorado, (the "January 2018 Acquisition"). Upon closing the
seller received approximately $11.6 million in cash. This transaction has been accounted for as an asset acquisition. The
acquisition provided new development opportunities in the Core DJ Basin.
November 2017 Acquisition
On November 15, 2017, the Company acquired an unaffiliated oil and gas company's interest in approximately 36,600
net acres of leasehold and primarily non-producing properties located in Arapahoe County, Colorado, (the "November 2017
Acquisition"). Upon closing the seller received $214.3 million in cash, subject to customary purchase price adjustments. The
Company also recorded a liability of $12.2 million for the final settlement payment due in April 2018 in conjunction with
November 2017 Acquisition, which was reflected in the December 31, 2017 consolidated balance sheets within the accounts
payable and accrued liabilities line item. This transaction has been accounted for as an asset acquisition. The acquisition
provided new development opportunities in the Core DJ Basin.
July 2017 Acquisition
On July 7, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 12,500 net
acres of leasehold and primarily non-producing properties located primarily in Adams County, Colorado, (the "July 2017
Acquisition"). Upon closing the seller received total consideration of $84.0 million in cash. The effective date for the July 2017
Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition provided new
development opportunities in the Core DJ Basin.
June 2017 Acquisition
On June 8, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 160 net acres
of leasehold and related producing properties located in Weld County, Colorado (the “June 2017 Acquisition”). The Company
paid approximately $13.4 million in cash consideration in connection with the closing of the June 2017 Acquisition. The
effective date for the acquisition was January 1, 2017, with purchase price adjustments calculated as of the closing date of
June 8, 2017. The acquisition increased the Company's interest in existing operated wells. The acquired producing properties
contributed $3.3 million of revenue and $2.5 million of earnings, respectively, for the year ended December 31, 2018. The
acquired producing properties contributed $3.7 million of revenue and $3.0 million of earnings, respectively, for the year ended
December 31, 2017. The acquired producing properties contributed no revenue and earnings for the years ended December 31,
2016. No significant transaction costs related to the acquisition were incurred for the years ended December 31, 2018, 2017 and
2016.
112
The June 2017 Acquisition was accounted for using the acquisition method under ASC 805, Business Combinations,
which required the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In
August 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase
price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
Purchase Price
Consideration given
Cash
Total consideration given
Allocation of Purchase Price
Proved oil and gas properties
Total fair value of oil and gas properties acquired
Asset retirement obligations
Fair Value of Net Assets Acquired
November 2016 Acquisition
June 8, 2017
$
$
$
$
$
$
13,395
13,395
13,495
13,495
(100)
13,395
On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200
net acres of leaseholds located in the Core DJ Basin for approximately $120.0 million, including customary closing
adjustments. The Company also made a $41.1 million deposit in November 2016 in conjunction with the November 2016
Acquisition. The deposit was made for two additional closings of leaseholds located in the Core DJ Basin. The first closing
occurred in January 2017 and added approximately 5,300 net acres for approximately $26.8 million. The second closing
occurred in July 2017 and added approximately 640 net acres for approximately $10.9 million. This transaction has been
accounted for as an asset acquisition.
October 2016 Acquisition
On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net
acres of leasehold, and related producing and non producing properties located primarily in Weld County, Colorado, along with
various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “October 2016
Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the
acquisition was July 1, 2016, with purchase price adjustments calculated as of the closing date on October 3, 2016. The
acquisition provided new development opportunities in the DJ Basin as well as increases the Company’s existing working
interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest
and operates. The acquired producing properties contributed revenue of $17.2 million for the year ended December 31,
2016. The Company determined that it is not practical to calculate net income associated with October 2016 Acquisition. The
Company incurred $2.6 million of transaction costs related to the acquisition for year ended December 31, 2016. These
transaction costs are recorded in the consolidated statements of operations within the acquisition transaction expenses line item.
No transaction costs related to the acquisition were incurred for the years ended December 31, 2018 and 2017.
113
The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires
the acquired assets and liabilities to be recorded at fair value as of the acquisition date of October 3, 2016. In February 2017,
the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the
final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
Purchase Price
Consideration given
Cash
Total consideration given
Allocation of Purchase Price
Proved oil and gas properties
Unproved oil and gas properties
Total fair value of oil and gas properties acquired
Goodwill (1)
Working capital
Asset retirement obligations
Fair Value of Net Assets Acquired
Working capital acquired was estimated as follows:
Accounts receivable
Revenue payable
Production taxes payable
Accrued liabilities
Total working capital
October 3, 2016
$
$
$
$
$
$
$
$
405,335
405,335
252,522
109,800
362,322
54,220
(7,185)
(4,022)
405,335
955
(3,012)
(4,244)
(884)
(7,185)
(1) Goodwill was primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated and
commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the
acquisition. Goodwill recognized as a result of the October 2016 Acquisition was not deductible for income tax purposes.
Option to Acquire Additional Assets from October 2016 Acquisition
Upon the closing of the October 2016 Acquisition, the Company made a $10.0 million non refundable payment for an
option to purchase additional assets from the seller of the October 2016 Acquisition (the “Additional Assets”) for an additional
$190.0 million, for a total purchase price for the Additional Assets of $200.0 million. The option may have been exercised at
any time until March 31, 2017. If the Company did not exercise the option to acquire the Additional Assets, the seller would
have had the right until April 30, 2017 to elect to sell those assets to the Company for an additional $120.0 million, for a total
purchase price for the Additional Assets of $130.0 million. In March 2017, the Company entered into an amendment to this
agreement with the seller to terminate both the Company's and seller’s options for no further consideration. The $10.0 million
was expensed in the fourth quarter of 2016 to other operating expenses within the consolidated statements of operations.
August 2016 Acquisition
On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net
acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts,
equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of
approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price
adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new development opportunities in
the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of
transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of
operations within the acquisition transaction expenses line item in the third quarter of 2016.
114
The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which
required the acquired assets and liabilities to be recorded at fair value as of the acquisition date of August 23, 2016. In March
2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and
the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
Purchase Price
Consideration given
Cash
Total consideration given
Allocation of Purchase Price
Proved oil and gas properties
Unproved oil and gas properties
Total fair value of oil and gas properties acquired
Working capital
Asset retirement obligations
Fair Value of Net Assets Acquired
Working capital acquired was estimated as follows:
Production taxes payable
Total working capital
Pro Forma Financial Information (Unaudited)
August 23, 2016
$
$
$
$
$
$
$
17,504
17,504
12,362
8,566
20,928
(9)
(3,415)
17,504
(9)
(9)
For the years ended December 31, 2017 and 2016, the following pro forma financial information represents the
combined results for the Company and the properties acquired in June 2017 and in October 2016 as if the acquisitions and
related financing had occurred on January 1, 2016. For purposes of the pro forma financial information, it was assumed that the
June 2017 Acquisition was funded through cash. For purposes of the pro forma financial information, it was assumed that the
October 2016 Acquisition was funded through the issuance of $260.3 million in convertible preferred securities and borrowings
under the revolving credit facility. The pro forma information includes the effects of adjustments for depletion, depreciation,
amortization and accretion expense of $1.6 million and $23.1 million for the years ended December 31, 2017 and 2016,
respectively. No pro forma adjustments were made for non-recurring transaction costs for the year ended December 31, 2017.
The pro forma information includes the effects of a decrease in non-recurring transaction costs that are included in general and
administrative expenses and acquisition transaction expenses of $2.6 million for the year ended December 31, 2016. No pro
forma adjustments were made for incremental interest expense on acquisition financing for the year ended December 31, 2017.
The pro forma information includes the effects of adjustments for the incremental interest expense on acquisition financing
of $4.0 million for the year ended December 31, 2016. The pro forma information includes the effects of adjustments for
income taxes of $0.6 million for the year ended December 31, 2017. No pro forma adjustments were made for the effect of
income taxes for the year ended December 31, 2016 as the acquisition occurred before the Corporate Reorganization.
Additionally, the pro forma financial information excludes the effects the August 2016 Acquisition as these pro forma
adjustments were de minimis.
115
The following pro forma results (in thousands, except per share data) do not include any cost savings or other
synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to
integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if
the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Net
income (loss) per share is not applicable for the period prior to the Corporate Reorganization.
Revenues
Net loss
Loss per share
Basic and diluted
Note 5—Long Term Debt
For the Year Ended
December 31,
2017
2016
606,460
$
325,355
(44,231) $
(441,571)
(0.35) $
(1.54)
$
$
$
As of the dates indicated the Company’s long term debt consisted of the following (in thousands):
As of December 31,
2018
2017
Credit facility due August 16, 2022 (or an earlier time as set forth below in the credit facility)
$
285,000
$
2021 Senior Notes due July 15, 2021
2024 Senior Notes due May 15, 2024
2026 Senior Notes due February 1, 2026
Unamortized debt issuance costs on Senior Notes
Total long-term debt
Less: current portion of long-term debt
Total long-term debt, net of current portion
Credit Facility
—
400,000
750,000
(17,341)
1,417,659
—
90,000
550,000
400,000
—
(16,639)
1,023,361
—
$
1,417,659
$
1,023,361
On September 4, 2014, Holdings entered into a credit facility with a syndicate of banks, which is subject to a
borrowing base. In connection with the IPO and the merger of Holdings into the Company, the Company assumed all of the
obligations of Holdings under the credit facility and became the borrower thereunder.
In August 2017, the Company entered into an amendment and restatement of its existing credit facility (prior to
amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of
banks, which is subject to a borrowing base. The credit facility matures on the earlier of (a) August 16, 2022, (b) January 15,
2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior
to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred
Stock") have not been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021, the
maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16,
2022 or (d) the earlier termination in whole of the commitments. No principal payments are generally required until the credit
agreement matures or in the event that the borrowing base falls below the outstanding balance.
In January 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $525.0
million to $750.0 million, subject to the current elected commitments of $650.0 million, (ii) increase the maximum amount for
the letter of credit issued in favor of a purchaser of its crude oil from $25.0 million to $35.0 million, and (iii) amend certain
provisions of the credit agreement, including the commitments and allocations of each lender. In connection with the 2026
Senior Notes Offering (as defined below), the borrowing base was automatically reduced to $700.0 million; however, the
current elected commitments remained at $650.0 million.
In February 2018, the Company entered into a consent agreement and amended its revolving credit facility to (i)
provide for consent by the lenders to (a) the designation of Elevation as an unrestricted subsidiary and (b) the transfer of certain
116
assets by the Company and one of the guarantors to such unrestricted subsidiary; and (ii) amend certain provisions of the credit
agreement, including the incurrence of indebtedness covenant to permit certain indebtedness in connection with certain
transportation service agreements with such unrestricted subsidiary.
In May 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $700.0
million to $800.0 million, subject to current elected commitments of $650.0 million and (ii) reduce each of the applicable
interest rate margins for borrowings by 0.50%.
In October 2018, the Company amended its revolving credit facility to (i) postpone the November 1, 2018 scheduled
borrowing base redetermination until December 15, 2018 and (ii) permit the Company to make payments with respect to its
own equity, subject to certain terms, conditions and financial thresholds.
In December 2018, the Company amended its revolving credit facility to increase the borrowing base from $800.0
million to $1.2 billion, associated with the postponed November 1, 2018 scheduled borrowing base determination. The current
elected commitments remained at $650.0 million.
In January 2019, the Company amended its revolving credit facility to permit prepayments and redemptions of the
Company’s unsecured bonds, subject to certain terms, conditions and financial thresholds.
As of December 31, 2018, the credit facility was subject to a borrowing base of $1.2 billion, subject to current elected
commitments of $650.0 million. As of December 31, 2018, the Company had $285.0 million of borrowings outstanding. As of
December 31, 2017, the Company had $90.0 million outstanding borrowings. As of December 31, 2018 and 2017, the
Company had standby letters of credit of $35.7 million and $25.7 million, respectively, which reduce the availability of the
undrawn borrowing base. At December 31, 2018, the undrawn balance under the credit facility was $365.0 million. As of the
date of this filing, the Company had $285.0 million borrowings outstanding under the credit facility.
The amount available to be borrowed under the Company's revolving credit facility is subject to a borrowing base that
is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company's proved oil
and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative
agent under the Company's revolving credit facility.
Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base
rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin,
based on the utilization percentage of the facility as outlined in the Pricing Grid. Additionally, the credit facility provides for a
commitment fee of 0.375% to 0.50%, depending on borrowing base usage. The grid below shows the Base Rate Margin and
Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of
the date of this filing:
Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage
Level 1
Utilization
< 25
Level 2
Level 3
Level 4
Level 5
LIBOR
Margin
Base Rate
Margin
Commitment
Fee
1.50%
1.75%
2.00%
2.25%
2.50%
0.50%
0.75%
1.00%
1.25%
1.50%
0.375%
0.375%
0.500%
0.500%
0.500%
The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions
of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends,
distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants;
and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the
credit facility limits the Company from hedging in excess of 85% of its anticipated production volumes.
The credit facility also contains financial covenants requiring the Company and its restricted subsidiaries to comply
with a current ratio of its consolidated current assets (includes availability under the revolving credit facility and excludes
117
derivative assets) to its consolidated current liabilities (excludes the current portion of long-term debt and derivative liabilities),
of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of consolidated debt less cash balances to its
consolidated EBITDAX (EBITDAX is defined as net income adjusted for certain cash and non-cash items including DD&A,
exploration expense, gains/losses on derivative instruments, amortization of certain debt issuance costs, non-cash compensation
expense, interest expense and prepayment premiums on extinguishment of debt) for the four fiscal quarter period most recently
ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter. The Company was in compliance with all financial
covenants under the credit facility as of December 31, 2018.
Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and its
subsidiaries, including oil and gas properties, personal property and the equity interests of the subsidiaries of the Company. The
Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the
credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit
facility.
Second Lien Notes
On May 29, 2014, Holdings entered into a five year, $430.0 million term loan facility with a syndicate of lenders (the
“Second Lien Notes”). The Second Lien Notes would have matured on May 29, 2019. Holdings had drawn the full $430.0
million under the Second Lien Notes that bore an average interest rate of approximately 10.7%. The interest rates were fixed
and interest was payable semi annually.
In July 2016, the Second Lien Notes were repaid and terminated in conjunction with the 2021 Senior Notes Offering.
The Company used the proceeds from the 2021 Senior Notes (as discussed below) to repay the outstanding $430.0 million of
principal and a $4.3 million prepayment penalty. The prepayment penalty was expensed during the year ended December 31,
2016 in the consolidated statements of operations within the interest expense line item. Additionally, during the year ended
December 31, 2016, the Company wrote off approximately $15.1 million of unamortized debt discount and debt issuance costs
that were related to the Second Lien Notes. The write off of the unamortized debt discount and debt issuance costs were
recorded in the consolidated statements of operations within the interest expense line item.
2021 Senior Notes
In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021
(the “2021 Senior Notes” and the offering, the "2021 Senior Notes Offering"). The 2021 Senior Notes bore an annual interest
rate of 7.875%. The interest on the 2021 Senior Notes was payable on January 15 and July 15 of each year commencing on
January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.
Concurrent with the 2026 Notes Offering, the Company commenced a cash tender offer to purchase any and all of its
2021 Senior Notes. On January 24, 2018, the Company received approximately $500.6 million aggregate principal amount of
the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 the Company
made a cash payment of approximately $534.2 million, which included principal of approximately $500.6 million, a make-
whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021
Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the
remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid
interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15,
2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bear an annual
interest rate of 7.375%. The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year
commencing on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting
discounts and fees.
The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of
its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully
and unconditionally guaranteed on a senior unsecured basis by certain of its current subsidiaries and by certain future restricted
118
subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The 2024 Senior Notes
are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under
its revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated
in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future
subsidiaries that do not guarantee the 2024 Senior Notes.
The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's
and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the
Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or
redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into
agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or
substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business
other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes (the
“2024 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising
from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall become due and payable immediately without any
declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of
default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may
declare all outstanding 2024 Senior Notes to be due and payable immediately. The Company was in compliance with all
financial covenants under the 2024 Senior Notes Indenture as of December 31, 2018.
2026 Senior Notes
In January 2018, the Company closed a private offering of its 2026 Senior Notes (the “2026 Senior Notes” and the
offering, the "2026 Senior Notes Offering") that resulted in net proceeds of approximately $737.9 million after deducting
discounts and fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to tender for its
2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate
purposes. The Company's 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on the Company's 2026 Senior
Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. The
Company's 2026 Senior Notes will mature on February 1, 2026.
The Company's 2026 Senior Notes are the Company's senior unsecured obligations and rank equally in right of
payment with all of the Company's other senior indebtedness and senior to any of the Company's subordinated indebtedness.
The Company's 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the
Company's current subsidiaries and by certain future restricted subsidiaries that guarantee the Company's indebtedness under a
credit facility. The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all
borrowings and other obligations under the Company's revolving credit facility) to the extent of the value of the collateral
securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other
liabilities (including trade payables) of any of the Company's future subsidiaries that do not guarantee the 2026 Senior Notes.
The 2026 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company’s
and the Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the
Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or
redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into
agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or
substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business
other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes (the
“2026 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising
from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall become due and payable immediately without any
declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon the occurrence of certain other events of
default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may
declare all outstanding 2026 Senior Notes to be due and payable immediately. The Company was in compliance with all
financial covenants under the 2026 Senior Notes Indenture as of December 31, 2018.
119
Debt Discount Costs on Second Lien Notes
The Company’s Second Lien Notes were issued with an original issue discount (OID) of $6.5 million. In July 2016,
the Company repaid the Second Lien Notes in full and accelerated the remaining unamortized balance of $4.3 million. This
expense was recorded in the consolidated statements of operations within the interest expense line item. As of December 31,
2017, there was no remaining balance on the OID.
Debt Issuance Costs
As of December 31, 2018 and 2017, the Company had debt issuance costs net of accumulated amortization of $3.3
million and $3.8 million, respectively, related to its credit facility which has been reflected on the Company’s consolidated
balance sheet within the line item other non current assets. As of December 31, 2018, the Company had debt issuance costs net
of accumulated amortization of $17.3 million related to its 2024 and 2026 Senior Notes (collectively, the "Senior Notes"), and
as of December 31, 2017, the Company had debt issuance costs net of accumulated amortization of $16.6 million related to its
2021 and 2024 Senior Notes, which has been reflected on the Company's consolidated balance sheet within the line item Senior
Notes, net of unamortized debt issuance costs. Upon the repayment of the Company’s Second Lien Notes in July 2016, the
Company accelerated the amortization of the remaining $10.8 million of unamortized debt issuance costs. As of December 31,
2018 and 2017, there was no remaining balance on debt issuance costs associated with the Second Lien Notes. Upon the
redemption of the Company's 2021 Senior Notes in January and February 2018, the Company accelerated the amortization of
the remaining $9.4 million of unamortized debt issuance costs. These expenses were recorded in the consolidated statements of
operations within the interest expense line item. Debt issuance costs include origination, legal, engineering, and other fees
incurred in connection with the Company’s credit facility and Senior Notes. For the years ended December 31, 2018, 2017, and
2016, the Company recorded amortization expense related to the debt issuance costs of $13.2 million, $4.3 million and $14.4
million, respectively.
Interest Incurred on Long Term Debt
For the years ended December 31, 2018, 2017 and 2016, the Company incurred interest expense on long term debt of
$82.7 million, $58.7 million and $50.5 million, respectively, and capitalized interest of $8.2 million, $11.1 million and $5.2
million, respectively, for the years ended December 31, 2018, 2017 and 2016. Included in interest expense for the year ended
December 31, 2018 is a make-whole premium of $35.6 million related to the Company's redemption of its 2021 Senior Notes
in January and February 2018. Also included in interest expense for the year ended December 31, 2017 is a prepayment penalty
of $4.3 million related to the Company’s repayment of its Second Lien Notes in July 2016.
Senior Note Repurchase Program
On January 4, 2019, the Board of Directors authorized a program, subject to the amendment to the Company's
revolving credit facility, to repurchase up to $100.0 million of the Company’s Senior Notes. The Company’s Senior Notes
Repurchase Program does not obligate it to acquire any specific nominal amount of Senior Notes. As of the date of this filing,
the Company has repurchased 2026 Senior Notes with a nominal value of $13.1 million for $10.5 million in connection with
the Senior Notes Repurchase Program.
120
Note 6—Commodity Derivative Instruments
The Company has entered into commodity derivative instruments, as described below. The Company has utilized
swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural
gas production.
A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the
Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract
volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the
difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put
option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between
the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor
price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the
deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the
call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference
between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below
the ceiling price, the call option expires worthless.
The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options
in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include
purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold
call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled
into an enhanced fixed price swap.
The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in
an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these
commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the
Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental
derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the
terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not
enter into derivative contracts for speculative purposes.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial
terms of such contracts. The Company’s derivative contracts are currently with eleven counterparties, all of whom are lenders
under our credit agreement. The Company has netting arrangements with the counterparties that provide for the offset of
payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination.
The derivative contracts may be terminated by a non defaulting party in the event of default by one of the parties to the
agreement. There are no credit risk related contingent features or circumstances in which the features could be triggered in
derivative instruments that are in a net liability position at the end of the reporting period.
121
The Company’s commodity derivative contracts as of December 31, 2018 are summarized below:
NYMEX WTI Crude Swaps:
Notional volume (Bbl)
Weighted average fixed price ($/Bbl)
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)
Weighted average sold call price ($/Bbl)
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)
Weighted average sold put price ($/Bbl)
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)
Weighted average purchased put price ($/Bbl)
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed price ($/MMBtu)
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)
Weighted average purchased put price ($/MMBtu)
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)
Weighted average sold call price ($/MMBtu)
NYMEX HH Natural Gas Sold Puts:
Notional volume (MMBtu)
Weighted average sold put price ($/MMBtu)
CIG Basis Gas Swaps:
Notional volume (MMBtu)
Weighted average fixed basis price ($/MMBtu)
2019
2020
900,000
1,200,000
52.56
$
52.66
11,700,000
1,800,000
65.40
$
67.53
13,500,000
1,800,000
41.27
$
42.00
17,850,000
1,800,000
47.67
$
50.00
32,400,000
2.81
3,600,000
3.04
3,600,000
3.46
3,000,000
2.50
36,000,000
(0.75)
—
—
—
—
—
—
—
—
—
—
$
$
$
$
$
$
$
$
$
The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and
adjustments made to net the derivative instruments for the presentation in the balance sheets (in thousands):
Gross Amounts
of Recognized
Gross Amounts
As of December 31, 2018
Net Amounts of
Assets and
Liabilities
Gross Amounts
Location on Balance Sheet
Current assets (4)
Non-current assets
Current liabilities (4)
Non-current liabilities
Assets and
Liabilities
$
$
$
$
115,852
17,217
$
$
(67,141) $
(8,785) $
Offset in the
Presented in the
not Offset in the
Net
Balance Sheet(1)
Balance Sheet
Balance Sheet(2)
Amounts(3)
(66,945) $
(8,785) $
$
66,945
$
8,785
48,907
$
8,432
$
(196) $
— $
(192) $
— $
192
$
— $
57,147
—
(4)
—
122
Gross Amounts
of Recognized
Gross Amounts
As of December 31, 2017
Net Amounts of
Assets and
Liabilities
Gross Amounts
Location on Balance Sheet
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Assets and
Liabilities
Offset in the
Presented in the
not Offset in the
Net
Balance Sheet(1)
Balance Sheet
Balance Sheet(2)
Amounts(3)
$
$
$
$
22,118
13,686
$
$
(85,414) $
(30,960) $
(17,986) $
(13,686) $
$
17,986
13,686
$
4,132
$
— $
(67,428) $
(17,274) $
— $
— $
— $
— $
4,132
—
(84,702)
—
(1) Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of
offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
(2) Netting for balance sheet presentation is performed by current and non current classification. This adjustment represents
amounts subject to an enforceable master netting arrangement, which are not netted on the balance sheet. There are no
amounts of related financial collateral received or pledged.
(3) Net amounts are not split by current and non current. All counterparties in a net asset position are shown in the current
asset line item and all counterparties in a net liability position are shown in the current liability line item.
(4) Gross current liabilities include a deferred premium liability of $7.7 million related to the Company's deferred put
premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred put
premiums.
The table below sets forth the commodity derivatives loss for the years ended December 31, 2018, 2017 and 2016 (in
thousands). Commodity derivatives loss are included under other income (expense).
Commodity derivatives loss
Note 7—Asset Retirement Obligations
For the Year Ended
December 31,
2018
2017
$
(8,554) $
(36,332) $
2016
(100,947)
The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and
Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in
the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement
obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and
remediate producing and shut in wells at the end of their productive lives in accordance with applicable local, state and federal
laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by
calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs
used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates,
inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and
the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method.
123
The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated
(in thousands):
Balance beginning of period
Liabilities incurred or acquired
Liabilities settled
Revisions in estimated cash flows
Accretion expense
Balance end of period
Note 8—Fair Value Measurements
For the Year Ended
December 31,
2018
2017
$
69,540
$
2,136
(13,869)
6,800
5,184
$
69,791
$
56,108
9,802
(4,169)
2,630
5,169
69,540
ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that
maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable
inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability
developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect
the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best
information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs
as follows:
• Level 1: Quoted prices are available in active markets for identical assets or liabilities;
• Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or
liability;
• Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted
cash flow models or valuations.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires
judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value
hierarchy levels. There were no transfers between levels during any periods presented below.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a
recurring basis as of December 31, 2018 and December 31, 2017 by level within the fair value hierarchy (in thousands):
Financial Assets:
Commodity derivative assets
Financial Liabilities:
Commodity derivative liabilities
Fair Value Measurements at
December 31, 2018 Using
Level 1
Level 2
Level 3
Total
$
$
— $
57,339
— $
196
$
$
— $
57,339
— $
196
124
Financial Assets:
Commodity derivative assets
Financial Liabilities:
Commodity derivative liabilities
Fair Value Measurements at
December 31, 2017 Using
Level 1
Level 2
Level 3
Total
$
$
— $
4,132
— $
84,702
$
$
— $
4,132
— $
84,702
The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table
above:
Commodity Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market based approach that
takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes
from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty
credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to
make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has
the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
Derivative instruments utilized by the Company consist of swaps, put options, and call options. The oil and natural gas
derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the
instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the
Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts
payable, commodity derivative instruments (discussed above) and long term debt. The carrying values of cash and cash
equivalents, accounts receivable and accounts payable are representative of their fair values due to their short term maturities.
The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term
of the loan. The fair value of the 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes (collectively, the "Senior
Notes") was derived from available market data. As such, the Company has classified the Senior Notes as Level 2. Please refer
to Note 5 — Long Term Debt for further information. The Company’s policy is to recognize transfers between levels at the end
of the period. This disclosure (in thousands) does not impact the Company’s financial position, results of operations or cash
flows.
Credit facility
2021 Senior Notes(1)
2024 Senior Notes(2)
2026 Senior Notes(3)
At December 31, 2018
At December 31, 2017
Carrying
Amount
Fair Value
Carrying
Amount
$
$
$
$
285,000
$
285,000
$
— $
393,866
738,793
$
$
— $
330,000
558,750
$
$
90,000
540,382
392,979
$
$
$
— $
Fair Value
90,000
583,000
427,000
—
(1) The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million as of
December 31, 2017. There were no unamortized debt issuance costs as of December 31, 2018.
(2) The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $6.1 million and $7.0 million
as of December 31, 2018 and 2017, respectively.
(3) The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $11.2 million as of
December 31, 2018. There were no unamortized debt issuance costs as of December 31, 2017.
Non Recurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a non recurring basis to its
non financial assets and liabilities, including proved property and goodwill. These assets and liabilities are not measured at fair
125
value on a recurring basis, but are subject to fair value adjustments when facts are circumstances arise that indicate a need for
measurement.
The Company utilizes fair value on a non recurring basis to review its proved oil and gas properties for potential
impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such
property. The Company uses an income approach analysis based on the net discounted future cash flows of producing property.
The future cash flows are based on Management’s estimates for the future. Unobservable inputs included future estimates of oil
and gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract
terms or forward price curves, operating and development costs, and a discount rate based on a market-based weighted average
cost of capital (all of which are Level 3 inputs within the fair value hierarchy). For the years ended December 31, 2018 and
2016, the Company recognized $16.2 million and $22.5 million in impairment expense on proved oil and gas properties,
respectively. The impairment expense for the years ended December 31, 2018 and 2016 is related to impairment of the assets in
the Company’s northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its
proved oil and gas properties in the Company’s northern field. A portion of the net book value of these proved oil and gas
properties were impaired at September 30, 2018 and the proved oil and gas properties in the northern field were written down
to their fair value. The full net book value of these proved oil and gas properties were impaired at June 30, 2016 as it was
determined that the proved oil and gas properties had no remaining fair value. No impairment expense was recognized for the
year ended December 31, 2017 on proved oil and gas properties.
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of
the purchase price over the estimated value of the net assets acquired in business combinations. The Company tests goodwill
for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of
goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil
and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is
recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil
and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the
estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed a
quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its
carrying amount. The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing
and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company
performed a quantitative assessment as of December 31, 2018, utilizing an income approach based on estimates of the expected
discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit
was not greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety
of the balance, for the year ended December 31, 2018. The Company performed a quantitative assessment as of September 30,
2017, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company performed a
qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-
likely-than-not greater than its carrying amount.
The Company’s other non recurring fair value measurements include the purchase price allocations for the fair value
of assets and liabilities acquired through business combinations, please refer to Note 4 — Acquisitions and Divestitures. The
fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach
using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of
factors, including risk adjusted oil and gas reserves, commodity prices, development costs, and operating costs, based on
market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is measured on
a non recurring basis and is not measured in periods after initial recognition.
Note 9—Equity
Stock Repurchase Program
On November 19, 2018, the Company announced the Board of Directors had authorized a program to repurchase up to
$100.0 million of the Company's common stock ("Stock Repurchase Program"). During the year ended December 31, 2018, the
Company repurchased 4.1 million shares of its common stock for $26.2 million, at a weighted average per share price of $6.47
per share, in connection with the Stock Repurchase Program. The Company's Stock Repurchase Program does not obligate it to
acquire any specific number of shares and will expire on March 31, 2019. The Company intends to conduct any open market
stock repurchase activities in compliance with the safe harbor provisions of Rule 10b-18 of the Securities Exchange Act of
1934, as amended (the "Exchange Act").
126
Preferred Units
On July 3, 2018, Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and subsidiary of the
Company, entered into a securities purchase agreement (the “Securities Purchase Agreement”) with a third party (the
"Purchaser"), pursuant to which Elevation agreed to sell 150,000 Preferred Units (the “Elevation Preferred Units”) of Elevation
at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million (the “Private
Placement”), in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended (the
“Securities Act”). The Private Placement closed on July 3, 2018 (the “Preferred Unit Closing Date”), funded on July 19, 2018
and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement for previously
incurred midstream capital expenditures and general and administrative expenses. These Preferred Units are non-recourse to
Extraction and represent the noncontrolling interest presented on the consolidated balance sheets, consolidated statement of
operations and consolidated statement of changes in members' and stockholders' equity and noncontrolling interest. Elevation is
a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the
Company or its other subsidiaries. As of December 31, 2018, $136.9 million of cash was held by Elevation and is earmarked
for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.
As of December 31, 2018 and 2017, Elevation capital expenditures represented all of the gathering systems and facilities line
item in the consolidated balance sheet and the gathering systems and facilities additions in the consolidated statement of cash
flows.
During the twenty-eight months following the Preferred Unit Closing Date (the “Preferred Unit Commitment Period”),
subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation
has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities
Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at
least $25.0 million, up to an aggregate amount of $350.0 million. During the Preferred Unit Commitment Period, Elevation is
required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn
amounts of such additional $350.0 million commitment. Elevation recognized $1.8 million of commitment fees paid-in-kind
for the year ended December 31, 2018, included under the Preferred Unit commitment fees and dividends paid-in-kind line
item in the consolidated statement of changes in members' and stockholders' equity and noncontrolling interest. No such fees
were recognized for the year ended December 31, 2017 or 2016.
The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In
respect of quarters ending prior to and including June 30, 2020, such dividend is payable in cash or in kind at the election of
Elevation. After June 30, 2020, such dividend is payable solely in cash. Elevation recognized $5.5 million of dividends paid-in-
kind for the year ended December 31, 2018, included under the Preferred Unit commitment fees and dividends paid-in-kind
line item in the consolidated statement of changes in members' and stockholders' equity and noncontrolling interest. No such
fees were recognized for the years ended December 31, 2017 or 2016.
Private Placement of Common Stock
On December 15, 2016, the Company completed the issuance of 25.0 million shares of common stock, at a price of
$18.25 per share, in connection with the Private Placement (the “Private Placement”). The Private Placement resulted in
approximately $457.0 million of gross proceeds and approximately $441.9 million of net proceeds, after deducting placement
agent commissions and offering expenses. Proceeds from the Private Placement were to be used for general corporate purposes,
including to fund the Company’s 2017 capital expenditures.
Initial Public Offering
On October 17, 2016, the Company completed its initial public offering, issuing 38.3 million shares of common stock,
par value $0.01 per share (“common stock”), which included the full exercise of the underwriters’ over-allotment option of 5.0
million shares at a price of $19.00 per share. The net proceeds of the offering were $681.0 million, after deducting underwriting
discounts and commissions and offering expenses, of approximately $47.3 million. The proceeds from the Offering were used
to (i) redeem in full the Series A Preferred Units for $90.0 million and (ii) to repay borrowings under the Company’s revolving
credit facility for $291.6 million. The remaining net proceeds were to be used for general corporate purposes, including to fund
2017 capital expenditures. The material terms of the Offering are described in the Company’s final prospectus, dated October
11, 2016 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on October 13, 2016.
127
Series A Preferred Units
On October 3, 2016, the Company issued $75.0 million in Series A Preferred Units (the “Series A Preferred Units”) to
fund a portion of the purchase price for the October 2016 Acquisition. The Series A Preferred Units were entitled to receive a
cash dividend of 10% per year, payable quarterly in arrears. All holders of Series A Preferred Units were also members of
Holdings. The Company used $90.0 million of the net proceeds from its IPO to redeem the Series A Preferred Units in full on
October 17, 2016, including a premium of $15.0 million which is recorded within additional paid in capital in the consolidated
statement of changes in members' and stockholders' equity and noncontrolling interest. For further discussion on the October
2016 Acquisition, please refer to Note 4 — Acquisitions and Divestitures.
Series A Preferred Stock and Series B Preferred Units
On October 3, 2016, the Company issued $185.3 million in convertible preferred securities ("Series B Preferred
Units") to fund a portion of the purchase price for the October 2016 Acquisition. The Series B Preferred Units were entitled to
receive a cash dividend of 10% per year, payable quarterly in arrears, and the Company had the ability to pay up to 50% of the
quarterly dividend in kind. For the year ended December 31, 2016, the Company paid $0.7 million of dividends associated with
the Series B Preferred Units. The Company did not make any payments in kind on the Series B Preferred Units from the date of
issuance of the Series B Preferred Units through the Offering. The Series B Preferred Units converted in connection with the
closing of the IPO into 185,280 shares of Series A Convertible Preferred Stock (the "Series A Preferred Stock") that are entitled
to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and the Company has the ability to pay such
quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends
are paid in cash). For the year ended December 31, 2018, the Company accrued $2.7 million of dividends associated with the
Series A Preferred Stock, or $14.69 per share, which were paid in January 2019. The Company did not make any payments in
kind on the Series A Preferred Stock from the date of the Offering through December 31, 2017. Beginning on or after the later
of (a) 90 days after the closing of the Offering and (b) the earlier of 120 days after the closing of the Offering and the expiration
of the lock-up period contained in the underwriting agreement entered into in connection with the Offering ("Lock-Up Period
End Date"), the Series A Preferred Stock will be convertible into shares of the Company's common stock at the election of the
holders of the Series A Preferred Stock ("Series A Preferred Holders") at a conversion ratio per share of Series A Preferred
Stock of 61.9195. Beginning on or after the Lock-Up Period End Date until the three year anniversary of the closing of the
Offering, the Company may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred
Stock of 61.9195, but only if the closing price of the Company’s common stock trades at or above a certain premium to the
Company’s initial offering price, such premium to decrease with time. In accordance with ASC Topic 470, Debt ("ASC 470"),
the Company determined that the conversion feature of the Series A Preferred Stock represented a beneficial conversion
feature. The fair value of the Company's common stock on the closing of the IPO was greater than the Series A Preferred Stock
conversion price by approximately $32.7 million in aggregate. Under ASC 470, $32.7 million (the fair value of the beneficial
conversion feature) of the proceeds received from the issuance of the Series B Preferred Units, subsequently converted to the
Series A Preferred Stock, was allocated to additional paid-in capital. The beneficial conversion feature is required to be accreted
on a non-cash basis over the approximate 60 month period between the issuance date and the required redemption date of
October 15, 2021, or fully accreted upon an accelerated date of redemption or conversion, resulting in an increase of the Series
A Convertible Preferred Stock presented on the Consolidated Balance Sheets. The accretion of the beneficial conversion feature
of Series A Preferred Stock is presented as a decrease to additional paid-in capital on the changes in members' and stockholders'
equity and noncontrolling interest. As a result, approximately $6.0 million and $5.4 million was accreted during the years
ended December 31, 2018 and 2017. In certain situations, including a change of control, the Series A Preferred Stock may be
redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock
and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A
Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation
preference.
Note 10—Income Taxes
On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted making significant changes to the
Internal Revenue Code. Many of the provisions in the TCJA have an effective date for years beginning after December 31,
2017, including the lowering of the U.S. corporate rate from 35 percent to 21 percent. As a result, the Company was required to
remeasure the deferred tax assets and liabilities as of December 31, 2017 at the rate in which they are expected to reverse. This
re-measurement of deferred tax assets and liabilities required the Company to analyze and record a one-time adjustment to
reduce the overall deferred tax liability in the consolidated balance sheets and reflect a corresponding income tax benefit in the
consolidated statements of operations for the year ended December 31, 2017. This resulted in the recording of an income tax
benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability as of December 31, 2017.
128
During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on
compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted
in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. The
Company believes the accounting is complete regarding the revaluation of the deferred tax balances and there are no remaining
provisional amounts associated with the TCJA as of December 31, 2018. The Company is aware that the Internal Revenue
Service has issued proposed regulations regarding the TCJA and has incorporated this guidance into its current tax policy. The
Company will continue to monitor and analyze the impact of future guidance and any final regulations as they become
available.
The components of the income tax expense (benefit) were as follows (in thousands):
Current:
Federal
State, net of federal benefit
Total current income tax expense (benefit)
Deferred:
Federal
State, net of federal benefit
Total deferred income tax expense (benefit)
Income tax expense (benefit)
For the Year Ended
December 31,
2018
2017
— $
—
— $
—
—
—
56,943
9,907
66,850
66,850
$
$
$
(61,719)
(1,981)
(63,700)
(63,700)
$
$
$
$
$
The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate
(in thousands):
Net income (loss) before income taxes
Federal income taxes at statutory rate
Impact of goodwill impairment
State income taxes, net of federal benefit
Nondeductible stock-based compensation
Enactment of the Tax Cuts and Jobs Act
Other
Income tax expense (benefit)
Net income (loss)
For the Year Ended
December 31,
2018
$
188,705
$
39,628
11,386
9,907
5,088
—
841
66,850
$
121,855
$
2017
(108,108)
(37,838)
—
(3,118)
2,264
(23,412)
(1,596)
(63,700)
(44,408)
129
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax
liabilities were as follows (in thousands):
Deferred Tax Assets:
Net operating loss carryforward
Commodity derivatives
Stock-based compensation
Intangible drilling costs - Section 59(e)
Property taxes
Other
Total deferred tax assets
Deferred Tax Liabilities:
Excess basis of oil and gas properties
Commodity derivatives
Total deferred tax liabilities
Deferred Tax Liability, net
As of December 31,
2018
2017
$
149,399
$
205,806
—
17,242
127,604
22,277
10,856
19,984
13,853
—
12,667
4,386
$
$
$
327,378
$
256,696
(426,428) $
(10,126)
(436,554)
(109,176) $
(299,022)
—
(299,022)
(42,326)
Management considers whether some portion or all of the deferred tax assets will be realized based on a more likely
than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences become deductible. Management considers the scheduled
reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. The
Company has net operating loss carryforwards (NOLs) for U.S. income tax purposes that have been generated from the
Company's operations in 2017 of approximately $605.9 million, which expire in 2037 and are not subject to the 80 percent
limitation of taxable income. As of December 31, 2018, the Company also had $517.5 million of indirect drilling costs that
were capitalized under Code Section 59(e). As of December 31, 2017, the Company had no indirect drilling costs that were
capitalized under Code Section 59(e).
The utilization of such NOL carryforwards may be limited upon the occurrence of certain ownership changes as
stipulated in Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"). As of December 31, 2018, the
Company determined that the statutory provision of Section 382 will not limit the Company’s ability to realize future tax
benefits. As of December 31, 2018, the Company believes it will be able to generate sufficient future taxable income and
accordingly, believes that it is more likely than not that its deferred income tax assets will be fully realized. The Company files
income tax returns in the U.S. federal jurisdiction and in Colorado. The statute of limitations related to the 2016 and 2017 tax
returns are open through 2020 and 2021 respectively, however, the ability for the tax authority to adjust the NOL will continue
until three years after the NOL is utilized.
As of December 31, 2018, the Company believes that it has no liability for uncertain tax positions. If the Company
were to determine there were any uncertain tax positions, the Company would recognize the liability and related interest and
penalties within income tax expense. As of December 31, 2018, the Company had no provision for interest or penalties related
to uncertain tax positions.
Note 11—Unit and Stock-Based Compensation
Extraction Long Term Incentive Plan
In October 2016, the Board of Directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the
“2016 Plan” or “LTIP”), pursuant to which employees, consultants, and directors of the Company and its affiliates performing
services for the Company are eligible to receive awards. The 2016 Plan provides for the grant of stock options, stock
appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards,
substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of
stockholders. In accordance with the terms of the LTIP, 20.2 million shares of common stock have been reserved for issuance
pursuant to awards under the LTIP. Extraction has granted awards under the LTIP to certain directors, officers and employees,
including stock options, restricted stock units and performance stock awards.
130
Restricted Stock Units (“RSUs”)
Restricted stock units granted under the LTIP (“RSUs”) vest over either (i) a one-year service period, with 100% of the
units vesting at the end of the service period, or (ii) a three-year service period with 25%, 25% and 50% of the units vesting in
year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock on
the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As
of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the
adoption of ASU No. 2016-09.
The Company recorded $27.9 million, $31.8 million and $5.5 million of stock-based compensation costs related to
RSUs for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, there was $32.2 million
of total unrecognized compensation cost related to the unvested RSUs granted to certain employees that is expected to be
recognized over a weighted average period of 1.4 years.
The following table summarizes the RSU activity from January 1, 2016 through December 31, 2018 and provides
information for RSUs outstanding at the dates indicated.
Non-vested RSUs at January 1, 2016
Granted
Forfeited
Vested
Non-vested RSUs at December 31, 2016
Granted
Forfeited
Vested
Non-vested RSUs at December 31, 2017
Granted
Forfeited
Vested
Non-vested RSUs at December 31, 2018
Stock Options
Weighted
Average
Grant Date
Fair Value
—
21.41
—
—
21.41
16.37
19.85
20.85
19.51
12.53
14.94
19.44
16.91
Number of
Shares
— $
3,237,500
$
— $
— $
3,237,500
$
1,369,083
$
(445,366) $
(1,254,744) $
$
2,906,473
1,226,768
$
(95,725) $
(935,181) $
$
3,102,335
Expense on the stock options are recognized on a straight-line basis over the service period of the award less awards
forfeited. The fair value of the stock options was measured at the grant date using the Black Scholes valuation model. The
Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited
historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the
volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury
instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the
LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date.
To fulfill options exercised, the Company issues new shares.
The Company recorded $15.1 million, $15.7 million and $2.9 million of stock-based compensation costs related to the
stock options for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, there was $12.1
million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted-
average period of 0.8 years.
131
The following table summarizes the assumptions used for the Black-Scholes valuation model to calculate the stock-
based compensation expense for the years ended December 31, 2017 and 2016. No stock options were granted for the year
ended December 31, 2018.
Risk free rates
Dividend yield
Expected volatility
Expected term (in years)
For the Year Ended
December 31,
2017
December 31,
2016
2.0%
—
58.9%
6.0
1.4%
—
47.2%
6.0
The weighted average fair value at the date of grant for stock options granted is as
follows:
Weighted average per share
Total options granted
Total weighted average fair value of options granted (in thousands)
$
$
8.66
744,428
6,445
$
$
8.75
4,500,000
39,375
The following table summarizes the stock option activity from January 1, 2016 through December 31, 2018 and
provides information for stock options outstanding at the dates indicated.
Number of
Shares
Weighted
Average
Exercise Price
Aggregate
Intrinsic
Value
(thousands)
—
Non-vested Stock Options at January 1, 2016
— $
— $
Granted
Forfeited
Vested
Non-vested Stock Options at December 31, 2016
Granted
Forfeited
Vested
Non-vested Stock Options at December 31, 2017
Granted
Forfeited
Vested
Non-vested Stock Options at December 31, 2018
4,500,000
$
19.00
$
11,295
— $
— $
4,500,000
744,428
$
$
— $
(1,748,138) $
$
3,496,290
— $
— $
(1,748,142) $
$
1,748,148
— $
— $
19.00
15.53
$
$
— $
18.52
18.50
$
$
— $
— $
18.49
18.50
$
$
—
—
4,680
—
—
—
—
—
—
—
—
132
The following table summarizes information about outstanding and exercisable stock options as of December 31,
2018.
Outstanding Options
Weighted-Average Weighted-Average
Exercisable Options
Weighted-Average
Exercise
Options
4,500,000
744,428
5,244,428
Remaining
Contractual Life
7.9 years
8.8 years
8.0 years
$
$
$
Exercise Price
Aggregate
Intrinsic Value
Options
Price per Share
Aggregate
Intrinsic Value
19.00
15.53
18.50
$
$
$
—
—
—
3,000,000
496,280
3,496,280
$
$
$
19.00
15.53
18.50
$
$
$
—
—
—
Performance Stock Awards
The Company granted performance stock awards ("PSAs") to certain executives under the LTIP in October 2017 and
March 2018. The number of shares of the Company's common stock that may be issued to settle PSAs ranges from zero to one
times the number of PSAs awarded. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-
based vesting schedule and a weighting of one or more of the following: i) absolute total stockholder return ("ATSR"), ii)
relative total stockholder return ("RTSR"), as compared to the Company's peer group and iii) cash return on capital invested
("CROCI") measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any
PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated
with the RTSR is based on a comparison of the Company's total shareholder return for the measurement period compared to
that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the
Company's share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the
awards. The vesting criterion that is associated with the CROCI is considered a performance condition for purposes of
calculating the grant-date fair value of the awards.
The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo
simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those
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 PSAs, the Company cannot predict with certainty the path its stock
price or the stock prices of its peer will take over the 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 most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some
direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to
determine the fair value of the PSAs. Significant assumptions used in this simulation include the Company's expected volatility,
risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well
as the volatilities for each of the Company's peers.
The assumptions used in valuing the PSAs granted were as follows:
Risk free rates
Dividend yield
Expected volatility
For the Year
Ended
December 31,
2018
For the Year
Ended
December 31,
2017
2.3%
—
59.9%
1.5%
—
45.0%
The Company recorded $5.7 million and $0.8 million of stock-based compensation costs related to PSAs for the years
ended December 31, 2018 and 2017, respectively. The Company did not record any stock-based compensation expense related
to PSAs for the year ended December 31, 2016. As of December 31, 2018, there was $9.1 million of unrecognized
compensation cost related to the PSAs that is expected to be recognized over a weighted-average period of 1.7 year.
133
The following table summarizes the PSA activity from January 1, 2017 through December 31, 2018 and provides
information for PSAs outstanding at the dates indicated.
Non-vested PSAs as of January 1, 2017
Granted
Forfeited
Vested
Non-vested PSAs as of December 31, 2017
Granted
Forfeited
Vested
Non-vested PSAs as of December 31, 2018
Weighted
Average
Grant Date
Fair Value
—
8.85
—
—
8.85
9.06
—
—
9.00
Number of
Shares (1)
— $
832,163
$
— $
— $
832,163
1,961,920
$
$
— $
— $
2,794,083
$
(1) The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final
number of shares of the Company's common stock issued may vary depending on the performance multiplier, which
ranges from zero to one, depending on the level of satisfaction of the vesting condition.
Incentive Restricted Stock Units (“Incentive RSUs”)
Officers of the Company contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC
(“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock
units (“Incentive RSUs”) to certain employees. Incentive RSUs vest over a three-year service period, with 25%, 25% and 50%
of the units vesting in year one, two and three, respectively. On July 10, 2017, the partners of Employee Incentive amended the
vesting schedule in which 25% vested on July 17, 2017 and the remaining Incentive RSUs will vest 25%, 25% and 25% each
six months thereafter, over the remaining 18 months service period. Grant date fair value was determined based on the value of
Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date
estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation
forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. As the vesting of any Incentive RSUs will be satisfied
with shares of common stock that are already issued and outstanding, the Incentive RSUs do not have any impact on the
Company’s diluted earnings per share calculation.
The Company recorded $19.6 million, $17.3 million and $2.4 million of stock-based compensation costs related to
Incentive RSUs for the years ended December 31, 2018, 2017 and 2016, respectively. These costs were included in the
consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2018, there
was $0.9 million of total unrecognized compensation cost related to the unvested Incentive RSUs granted to certain employees
that is expected to be recognized over a weighted average period of 0.1 years.
134
The following table summarizes the Incentive RSU activity from January 1, 2016 through December 31, 2018 and
provides information for Incentive RSUs outstanding at the dates indicated.
Non-vested Incentive RSUs at January 1, 2016
Granted
Forfeited
Vested
Non-vested Incentive RSUs at December 31, 2016
Granted
Forfeited
Vested
Non-vested Incentive RSUs at December 31, 2017
Granted
Forfeited
Vested
Non-vested Incentive RSUs at December 31, 2018
Holdings’ Membership Unit Incentive Plan
Weighted
Average
Grant Date
Fair Value
Number of
Shares
— $
2,717,968
$
(3,600) $
— $
2,714,368
$
— $
(710,993) $
(507,200) $
$
1,496,175
— $
(41,400) $
(978,775) $
$
476,000
—
20.45
20.45
—
20.45
—
20.45
20.45
20.45
—
20.45
20.45
20.45
On May 29, 2014, Holdings adopted the 2014 Membership Unit Incentive Plan (“2014 Plan”). The 2014 Plan
provided for the compensation of employees, non employee managers and consultants of the Company and its affiliates
through grants of restricted unit awards (“Holdings’ RUAs”) and incentive units (“Holdings’ Incentive Units”). The 2014 Plan
was terminated as a result of the Corporate Reorganization in October 2016.
Holdings’ RUAs
Holdings’ RUAs vested over a three year service period, with 25%, 25% and 50% of the units vesting in year one, two
and three, respectively. The Company estimated fair value of the RUAs on their grant date based upon estimated volatility,
market comparable risk free rate, estimated forfeiture rate and a discount for lack of marketability. Grant date fair value was
determined based on the value of Holdings’ Equity Units on the date of the grant. Due to a lack of historical data, the Company
used the experience of other entities in the same industry to estimate a forfeiture rate. Expected forfeitures are then included as
part of the grant date estimate of compensation cost.
No unit-based compensation costs related to Holdings' RUA grants were recorded for December 31, 2018 and 2017.
The Company recorded $16.8 million of unit-based compensation costs related to Holdings’ RUA grants for the year ended
December 31, 2016. These costs are included in the consolidated statements of operations within the general and administrative
expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit Incentive Plan
("2014 Plan") was terminated. As of December 31, 2018, there is no unrecognized compensation cost related to unvested RUAs
granted to employees.
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The following table summarizes the Holdings’ RUA activity from January 1, 2016 through December 31, 2016 and
provides information for Holdings’ RUAs outstanding at the dates indicated.
Non-vested RUAs at January 1, 2016
Granted
Forfeited
Vested
Non-vested RUAs at December 31, 2016
PRL RUAs
Weighted
Average
Grant Date
Fair Value
2.23
5.84
2.68
2.94
—
Number of
Shares
6,311,242
$
1,531,542
$
(181,817) $
(7,660,967) $
— $
PRL granted RUAs to certain employees, including Extraction employees (“PRL RUAs”). PRL RUAs vested over a
three years service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair
value was determined based on the value of PRL’s Equity Units on the date of the grant. PRL uses its past experience to
estimate a forfeiture rate and expected forfeitures are included as part of the grant date estimate of compensation cost.
No unit-based compensation costs related to PRL RUA grants were recorded for the year ended December 31, 2018
and 2017. The Company recorded $0.5 million of unit-based compensation costs related to PRL RUA grants for the year
ended December 31, 2016. These costs are included in the consolidated statements of operations within the general and
administrative expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit
Incentive Plan ("2014 Plan") was terminated. As of December 31, 2018, there was no unrecognized compensation cost related
to the PRL RUAs as all awards were fully vested.
Holdings’ Incentive Units
In accordance with the 2014 Plan and the Holdings LLC Agreement, Holdings issued 3.0 million Holdings’ incentive
units to certain members of management in the fourth quarter of 2015. All of Holdings’ Incentive Units were non voting and
subject to certain vesting and performance conditions. The Holdings’ Incentive Units vested over a three year service period,
with 25%, 25% and 50% of the units vesting in year 1, year 2 and year 3, respectively (with vesting between the first and third
anniversaries occurring pro-rata based on the number of full months elapsed since the last vesting date), and in full upon a
change of control, as defined in the Holdings LLC Agreement. The Holdings’ Incentive Units were accounted for as liability
awards under ASC 718, Compensation-Stock Compensation, with compensation expense based on period end fair value.
In connection with the IPO, the Board of Managers of Holdings accelerated the vesting of the Holdings’ Incentive
Units. The Company’s IPO and change of control triggered the conversion of these units into approximately 9.1 million
common shares of the Company based on the 10-day volume weighted average price of the Company’s common stock
following its IPO as set forth in the Holdings Third Amended and Restated LLC Agreement. For the year ended December 31,
2016, the Company recognized approximately $172.1 million in non-cash, stock-based compensation expense in connection
with the conversion of the Holdings’ Incentive Units into the Company’s common stock. As of December 31, 2018 and 2017,
there was no unrecognized compensation cost related to the Holdings' Incentive Units.
Note 12—Earnings (Loss) Per Share
Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to
common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the
potential dilution of securities that could share in the earnings available to common shareholders of the Company. The
Company uses the “if-converted” method to determine potential dilutive effects of Series A Preferred Stock and the treasury
method to determine the potential dilutive effects of outstanding restricted stock awards and stock options.
EPS for the year ended December 31, 2016 is calculated for the period from October 12, 2016, the effective date of the
Corporate Reorganization, to December 31, 2016. EPS information is not applicable for reporting periods prior to the Corporate
Reorganization. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were
136
outstanding for the period from October 12, 2016 to December 31, 2016. Please refer to Note 1 — Business and Organization
and Note 9 — Equity for additional discussion regarding the Corporate Reorganization.
The components of basic and diluted EPS were as follows:
Year Ended
December 31,
2018
Year Ended
December 31,
2017
From October 12,
2016 to
December 31,
2016
Basic and Diluted EPS (in thousands, except per share data)
Net income (loss)
Less: Noncontrolling interest
Less: Adjustment to reflect Series A Preferred Stock dividend
Less: Adjustment to reflect accretion of Series A Preferred Stock
discount
Net income (loss) available to common shareholders, basic and diluted
Weighted Average Common Shares Outstanding (1) (2) (3)
Basic and diluted
Net Income (Loss) Allocated to Common Shareholders per
Common Share
Basic and diluted
$
$
$
$
121,855
(7,287)
(10,885)
(44,408) $
—
(10,885)
(226,107)
—
(2,958)
(5,984)
(5,394)
(1,041)
97,699
$
(60,687) $
(230,106)
174,748
171,910
149,029
0.56
$
(0.35) $
(1.54)
(1) For the year ended December 31, 2018, 3,102,335 potentially dilutive shares associated with restricted stock awards
outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428
common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated
with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect
on EPS.
(2) For the year ended December 31, 2017, 8,566,983 potentially dilutive shares were not included in the calculation above, as
they had an anti-dilutive effect on EPS, including restricted stock awards, stock options outstanding and performance stock
awards contingently issuable, if December 31, 2017 was the end of the measurement period. Additionally, the 11,472,445
common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
(3) For the period of October 12 through December 31, 2016, 7,737,500 potentially dilutive shares were not included in the
calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards and stock options
outstanding for the period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series
A Preferred Stock were also excluded.
Note 13—Commitments and Contingencies
Leases
The Company leases two office spaces in Denver, Colorado, two office spaces in Greeley, Colorado and one office
space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020
and May 31, 2028, respectively. The Greeley and Houston leases expire on October 31, 2019, June 30, 2019 and January 31,
2022, respectively. Total rental commitments under non-cancelable leases for office space were $32.8 million at December 31,
2018. The future minimum lease payments under these non-cancelable leases are as follows: $3.5 million in 2019, $3.4 million
in 2020, $3.4 million in 2021, $3.4 million in 2022, $3.4 million in 2023 and $15.7 million thereafter. Rent expense was $3.4
million, $2.3 million, and $1.9 million for the years ended December 31, 2018, 2017, and 2016, respectively.
On June 4, 2015, the Company subleased the remaining term of one of its Denver office leases that expires February
29, 2020. The sublease will decrease the Company’s future lease payments by $0.3 million.
137
Drilling Rigs
As of December 31, 2018, the Company was subject to commitments on three drilling rigs. In the event of early
termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $9.2 million as
of December 31, 2018, as required under the terms of the contracts. In February 2016, the Company provided notice to
terminate one of its drilling rigs that was subject to commitment at December 31, 2015. As part of this termination, the
Company was obligated to pay $1.0 million in the second quarter of 2016, which was recorded in the consolidated statements
of operations within the other operating expenses line item. In January 2017, the Company provided notice for termination on
one drilling rig and paid no termination fees.
Delivery Commitments
As of December 31, 2018, the Company’s oil marketer is subject to a firm transportation agreement that commenced
in November 2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800
Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, the
Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest
in exchange for a make-whole provision that allows the Company to satisfy any minimum volume commitment deficiencies
incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October
31, 2018. In December 2017, the Company extended the term of this agreement through October 31, 2019 and has posted a
letter of credit in the amount of $35.0 million. The Company is currently in the process of amending and extending this
agreement. The Company evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be
reasonably estimated and deemed probable. The Company also has two long-term crude oil gathering commitments with an
unconsolidated subsidiary, in which the Company has a minority ownership interest. The first agreement commenced in
November 2016 and has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one,
17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The second
agreement will commence in or around July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000
Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000
Bbl/d in year ten. The remaining aggregate amount of estimated payments under these agreements is approximately $875.8
million.
In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017,
the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan
includes two new processing plants as well as the expansion of related gathering systems. The first plant commenced
operations in August 2018 and the second plant is expected to be completed by mid-2019, although the exact start-up date is
undetermined at this time. The Company’s share of these commitments will require 51.5 MMcf and 20.6 MMcf per day,
respectively, to be delivered after the plants' in-service dates for a period of seven years thereafter. The Company may be
required to pay a shortfall fee for any volumes under these commitments. These contractual obligations can be reduced by the
Company’s proportionate share of the collective volumes delivered to the plants by other third party incremental volumes
available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also
required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. Under its
current drilling plans, the Company expects to meet these volume commitments.
In February 2019, the Company entered into two long-term gas gathering agreements with third-party midstream
providers. The first agreement will commence in or around November 2019 and has a term of twenty years with a minimum
volume commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years are to
be delivered on an average 48,000 Mcf/d in year one, 96,000 Mcf/d in year two, 132,000 Mcf/d in year three, 120,000 Mcf/d in
year four, 108,000 Mcf/d in year five, 104,000 Mcf/d in year six and 80,000 Mcf/d in year seven. The aggregate amount of
estimated payments under this agreement is approximately $317.7 million. The second agreement will commence in or around
January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten.
The Company may be required to pay an annual shortfall fee for any volume deficiencies under this commitment, calculated
based on the weighted average sales price during the corresponding annual period. Under its current drilling plans, the
Company expects to meet these volume commitments.
Acquisition of Undeveloped Leasehold Acreage
The Company was party to an agreement during 2017 with an unrelated third party for which it has paid $247.6
million through December 31, 2018 to complete its leasing program of approximately 38,800 net acres of undeveloped
leasehold.
138
General
The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other
proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically
below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably
estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and
its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there
will be changes in the estimates of future costs, which management currently believes will not have a material effect on the
Company’s financial position, results of operations, or cash flows.
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn
certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost
or the Company may be required to pay damages if certain performance conditions are not met.
Legal Matters
From time to time, the Company is party to ongoing legal proceedings in the ordinary course of business. While the
outcome of these proceedings cannot be predicted with certainty, the Company does not believe the results of these
proceedings, individually or in the aggregate, will have a material adverse effect on the Company's business, financial
condition, results of operations or liquidity.
Note 14—Related Party Transactions
Office Lease with Related Affiliate
In April 2016, the Company subleased office space to Star Peak Capital, LLC, of which a member of the Board of
Directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020.
Units Repurchased from Officer
In May 2016, the Company repurchased 60,605 Tranche A Units and 82,578 Tranche C Units from its former Chief
Accounting Officer, for $3.25 per unit for an aggregate purchase price of approximately $0.5 million.
Promissory Notes
In May 2014, the Company received full recourse promissory notes from two officers under which the Company
advanced $5.4 million to the employees to meet their capital contributions. The promissory notes were due on May 29, 2021, or
earlier in the event of termination or certain change in control events as stipulated in the individual promissory notes and any
distributions of capital contributions were considered mandatory prepayments. The promissory notes had a stated interest rate
of LIBOR plus 1% per annum. The promissory notes were recorded as a reduction of members’ equity.
In September 2016, the Company redeemed 1.2 million units from two of its executive officers, for an aggregate
purchase price of $7.8 million. On the same date, the executive officers used $5.6 million of the redemption value to settle in
full and terminate their obligations under the promissory notes, including accrued interest thereon.
Second Lien Notes
Several holders of Second Lien Notes were also members of Holdings. Of the $430.0 million outstanding on the
Second Lien Notes as of December 31, 2015, members held approximately $311.7 million. These members were paid $314.8
million upon repayment and termination of the Second Lien Notes in July 2016, including the prepayment penalty.
2021 Senior Notes
Several 5% stockholders of the Company were also holders of the 2021 Senior Notes prior to the Tender Offer and the
redemption of the 2021 Senior Notes. As of the initial issuance of the $550.0 million principal amount on the 2021 Senior
Notes, such stockholders held $63.5 million.
139
2024 Senior Notes
Several 5% stockholders of the Company were also holders of the 2024 Senior Notes. As of the initial issuance in
August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million.
2026 Senior Notes
Several 5% stockholders of the Company were also holders of the 2026 Senior Notes. As of the initial issuance in
January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million.
Series A Preferred Units
All holders of the $75.0 million of Series A Preferred Units were also members of Holdings. The Company used $90.0
million of the net proceeds from its IPO to redeem the Series A Preferred Units in full on October 17, 2016, which included a
premium of $15.0 million.
Series A Preferred Stock and Series B Preferred Units
As of the initial issuance of the $185.3 million of Series B Preferred Units, members of Holdings held approximately
$135.3 million. Several holders of the Series A Preferred Stock are also 5% stockholders of the Company. As of the initial
issuance in October 2016 of the $185.3 million of Series A Preferred Stock, such stockholders held $105.0 million.
Private Placement of Common Stock
Several 5% stockholders of the Company were also participants in the Private Placement. As of the initial issuance of
$457.0 million of common stock in December 2016, such stockholders purchased 2,503,370 shares for $45.7 million.
Increased Ownership in an Unconsolidated Subsidiary
In May 2018, the Company exercised an option to increase its ownership percentage in an unconsolidated subsidiary
funded with a $35.3 million promissory note. This note was extinguished with the transfer of units to the unconsolidated
subsidiary. The Company also contributed an acreage dedication and minimum volume commitment.
Related Party—Employee
Mr. Troy Owens, brother of Mr. Matthew R. Owens, the Company's President and a member of the Company's Board
of Directors, is employed by the Company as an engineer. Consistent with market compensation for his services, Mr. Troy
Owens received approximately $0.2 million and $0.2 million in aggregate cash compensation relating to the fiscal years ended
December 31, 2018 and 2017, respectively. In addition, Mr. Troy Owens received certain long-term incentives during the same
periods in the form of restricted stock units that vest over a period of three years.
Note 15—Segment Information
See Note 2 — Basis of Presentation and Significant Accounting Policies, Segment Reporting for a description of the
Company's determination of its reportable segments. The Company's exploration and production segment revenues are derived
from third parties. The Company’s gathering and facilities segment is currently in the construction phase and no revenue
generating activities have commenced.
140
Financial information of the Company's reportable segments was as follows for the year ended December 31, 2018.
Capital expenditures for fixed assets later attributed to the gathering and facilities segment were $4.9 million for the year ended
December 31, 2017. There were no such capital expenditures for the year ended December 31, 2016. There were no revenues,
operating expenses or other income (expense) attributed to the gathering and facilities segment for the years ended December
31, 2017 and 2016.
For the Year Ended December 31, 2018
Exploration
and Production
Gathering and
Facilities
Elimination of
Intersegment
Transactions
Consolidated
Total
Revenues:
Revenues from external customers
Intersegment revenues
Total Revenues
Operating Expenses and Other Income
(Expense):
Depletion, depreciation, amortization and
accretion
Interest income
Interest expense
Earnings in unconsolidated subsidiaries
Total Operating Expenses and Other
Income (Expense):
Segment Assets
Capital Expenditures
Investment in Equity Method Investees
Segment EBITDAX
$
$
$
$
$
$
$
$
1,060,743
—
1,060,743
$
$
— $
—
— $
— $
1,060,743
—
—
— $
1,060,743
435,736
$
39
$
— $
—
—
—
435,775
1,928
(123,330)
2,863
— $
317,236
(276) $
— $
— $
— $
4,166,027
1,000,745
15,487
659,752
461
(123,330)
319
313,186
3,896,966
892,548
$
$
$
— $
658,565
$
1,467
—
2,544
4,050
269,337
108,198
15,487
1,187
$
$
$
$
$
141
The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of
income (loss) before income taxes for the year ended December 31, 2018 (in thousands). The Company had a single reportable
segment during the years ended December 31, 2017 and 2016, therefore no reconciliation is provided for these periods.
Reconciliation of Adjusted EBITDAX to Income Before Income Taxes
Exploration and production segment EBITDAX
Gathering and facilities segment EBITDAX
Subtotal of Reportable Segments
Less:
Depletion, depreciation, amortization and accretion
Impairment of long lived assets and goodwill
Exploration expenses
Gain on sale of property and equipment
Gain on sale of assets of unconsolidated subsidiary
Loss on commodity derivatives
Settlements on commodity derivative instruments
Premiums paid for derivatives that settled during the period
Stock-based compensation expense
Amortization of debt issuance costs
Interest expense
Make-whole premium on 2021 Senior Notes
Income Before Income Taxes
Note 16—Supplemental Oil and Gas Reserve Information (Unaudited)
Results of Operations for Oil, Natural Gas and NGL Producing Properties
For the Year Ended
December 31, 2018
$
$
$
$
658,565
1,187
659,752
(435,775)
(70,928)
(31,611)
53,222
83,612
(8,554)
123,518
7,148
(68,349)
(13,249)
(74,481)
(35,600)
188,705
The following are the results of operations (in thousands) of the Company’s oil and gas producing activities, before
corporate overhead and interest expenses. The Company assumed a statutory rate of 24.7% for the year ended December 31,
2018 and 2017. The Company assumed a statutory tax rate of 38.0% for the year ended December 31, 2016, although the
Company was not subject to federal and state income taxes prior to the Corporate Reorganization.
Revenues
Operating Expenses:
Production expenses
Exploration expenses
Depletion and accretion
Impairment of proved properties
Results of operations before income tax (expense) benefit
Income tax (expense) benefit
Results of Operations
For the Year Ended
December 31,
2018
1,060,743
$
2017
2016
$
604,296
$
278,089
209,169
31,611
431,946
16,166
371,851
(91,847)
280,004
$
162,673
36,256
311,916
—
93,451
(23,082)
70,369
$
82,773
36,422
203,073
22,438
(66,617)
25,314
(41,303)
$
142
Oil, Natural Gas and NGL Reserve Quantities (Unaudited)
The reserves at December 31, 2018, 2017 and 2016 presented below were prepared by the independent engineering
firm Ryder Scott Company, L.P. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the
estimated quantities of oil, natural gas and NGL which geological and engineering data demonstrate, with reasonable certainty,
to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs)
existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be
expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time
the estimates were made. The principal methodologies employed are decline curve analysis and analogy. The Company
emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are
more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are
expected to change as future information becomes available.
The following table sets forth information for the years ended December 31, 2018, 2017 and 2016 with respect to
changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:
Balance as of December 31, 2015
Revisions of previous estimates
Purchase of reserves
Extensions, discoveries, and other additions
Sale of reserves
Production
Balance as of December 31, 2016
Revisions of previous estimates
Purchase of reserves
Extensions, discoveries, and other additions
Sale of reserves
Production
Balance as of December 31, 2017
Revisions of previous estimates
Purchase of reserves
Extensions, discoveries, and other additions
Sale of reserves
Production
Balance as of December 31, 2018
Proved Developed Reserves, included above
Balance as of December 31, 2016
Balance as of December 31, 2017
Balance as of December 31, 2018
Proved Undeveloped Reserves, included above
Balance as of December 31, 2016
Balance as of December 31, 2017
Balance as of December 31, 2018
Crude Oil
Mbbls
71,500.2
(15,576.8)
18,473.6
21,885.4
—
(5,287.4)
90,995.0
(625.9)
10,761.2
19,738.4
—
(9,593.7)
111,275.0
6,264.3
6,296.3
32,475.3
(5,786.1)
(14,679.3)
135,845.5
17,158.0
37,078.0
47,075.0
73,837.0
74,197.0
88,771.0
Natural Gas
MMcf
292,583.9
35,803.1
78,761.6
120,798.3
—
(20,211.5)
507,735.4
9,349.8
11,183.6
130,295.4
—
(32,395.2)
626,169.0
(49,239.2)
24,667.8
164,424.0
(15,906.5)
(46,846.6)
703,268.5
107,918.0
222,236.0
316,499.0
399,817.4
403,933.0
386,769.0
NGL
Mbbls
38,382.9
1,988.8
9,680.7
14,679.9
—
(2,284.0)
62,448.3
1,961.6
1,563.3
15,033.6
—
(3,900.8)
77,106.0
(1,382.9)
3,264.4
22,853.4
(1,730.0)
(5,260.1)
94,850.8
13,354.0
27,932.0
39,689.0
49,094.3
49,174.0
55,162.0
MBoe
Total
158,647.1
(7,620.8)
41,281.2
56,698.5
—
(10,940.0)
238,066.0
2,894.0
14,188.3
56,487.9
—
(18,893.7)
292,742.5
(3,325.1)
13,672.0
82,732.7
(10,167.2)
(27,747.2)
347,907.7
48,498.4
102,049.2
139,514.0
189,567.5
190,693.2
208,395.0
• The values for the 2018 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of
the month prices for the period from January through December 31, 2018. The unweighted arithmetic average first-day-of-
the-month prices for the prior twelve months were $65.56 per barrel (West Texas Intermediate price) for crude oil and NGL
and $3.10 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and
143
basis differentials. The average resulting price used as of December 31, 2018 was $57.65 per barrel for oil, $1.47 per Mcf
for natural gas and $20.45 per barrel for NGL.
• The values for the 2017 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of
the month prices for the period from January through December 31, 2017. The unweighted arithmetic average first-day-of-
the-month prices for the prior twelve months were $51.34 per barrel (West Texas Intermediate price) for crude oil and NGL
and $2.98 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and
basis differentials. The average resulting price used as of December 31, 2017 was $42.89 per barrel for oil, $1.73 per Mcf
for natural gas and $20.28 per barrel for NGL.
• The values for the 2016 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of
the month prices for the period from January through December 31, 2016. The unweighted arithmetic average first-day-of-
month prices for the prior twelve months were $42.75 per barrel (West Texas Intermediate price) for crude oil and NGL
and $2.49 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and
basis differentials. The average resulting price used as of December 31, 2016 was $34.91 per barrel for oil, $1.39 per Mcf
for natural gas and $11.63 per barrel for NGL.
For the year ended December 31, 2018, the Company had downward revisions of previous estimates of 3,325.1 MBoe.
As a result of ongoing drilling and completion activities during 2018, the Company reported extensions, discoveries, and other
additions of 82,732.7 MBoe. Additionally, during 2018 the Company sold reserves of 10,167.2 MBoe and purchased reserves
of 13,672.0 MBoe.
For the year ended December 31, 2017, the Company had upward revisions of previous estimates of 2,894.0 MBoe.
As a result of ongoing drilling and completion activities during 2017, the Company reported extensions, discoveries, and other
additions of 56,487.9 MBoe. Additionally, during 2017 the Company purchased reserves of 14,188.3 MBoe.
For the year ended December 31, 2016, the Company had downward revisions of previous estimates of 7,620.8 MBoe.
As a result of ongoing drilling and completion activities during 2016, the Company reported extensions, discoveries, and other
additions of 56,698.5 MBoe. Additionally, during 2016 the Company purchased reserves of 41,281.2 MBoe.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves
The Company follows the guidelines prescribed in ASC 932, Extractive Activities-Oil and Gas for computing a
standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following
summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized
measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of
standardized measures from year to year.
The information is based on estimates of proved reserves attributable to the Company’s interest in oil and gas
properties as of December 31 of the years presented. These estimates were prepared by Ryder Scott Company L.P., independent
petroleum engineers.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as
follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be
produced based on year-end economic conditions. (2) The estimated future cash flows are compiled by applying the trailing
twelve-month average of the first of the month prices applied to the Company’s proved reserve year-end quantities. (3) The
future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and
abandonment costs, all based on year-end economic conditions, plus Company overhead incurred. (4) Future net cash flows are
discounted to present value by applying a discount rate of 10%.
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. 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 Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and
undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The
standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value
of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the
144
recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor
more representative of the time value of money and the risks inherent in reserve estimates.
The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL
reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands):
Future crude oil, natural gas and NGL sales
Future production costs
Future development costs
Future income tax expense
Future net cash flows
10% annual discount
Standardized measure of discounted future net cash flows(1)
For the Year Ended December 31,
2018
10,805,063
(3,215,840)
(1,912,641)
(694,398)
4,982,184
(2,082,201)
2,899,983
$
$
$
$
$
$
2017
7,422,335
(2,227,370)
(1,662,859)
(212,923)
3,319,183
(1,440,177)
1,879,006
$
$
$
2016
4,610,848
(1,429,202)
(1,579,628)
(42,859)
1,559,159
(836,163)
722,996
(1) For the years ended December 31, 2018, 2017 and 2016, future income tax expenses in the Company’s calculation of the
standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the
remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved
reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are
attributable to the Company’s oil and gas assets.
The following are the principal sources of change in the standardized measure (in thousands):
For the Year Ended December 31,
Balance at beginning of period
$
Sales of crude oil, natural gas and NGL, net
Net change in prices and production costs
Net change in future development costs
Extensions and discoveries
Acquisitions of reserves
Sale of reserves
Revisions of previous quantity estimates
Previously estimated development costs incurred
Net changes in income taxes
Accretion of discount
Changes in production timing and other
Balance at end of period
2017
2016
2018
1,879,006
(851,574)
902,762
(174,112)
629,304
88,124
(55,042)
132,373
306,546
(253,044)
197,580
98,060
$
$
722,996
(441,623)
586,271
3,959
330,160
59,745
—
188,421
331,550
(79,181)
74,061
102,647
835,883
(195,316)
(325,236)
(49,213)
96,982
156,675
—
19,161
123,085
(17,611)
83,588
(5,002)
722,996
$
2,899,983
$
1,879,006
$
145
Note 17—Unaudited Quarterly Financial Data
The following is a summary of the unaudited quarterly financial data for each of the quarters from first quarter 2017
through fourth quarter 2018 (in thousands, except per share data). Historical results are not necessarily indicative of the results
to be expected in future periods. You should read this data together with the Company's consolidated financial statements and
the related notes included elsewhere in this Annual Report:
Oil, Natural Gas and NGL Sales
Operating Income (1)
Net Income (Loss)
Basic Income (Loss) Per Common Share
Diluted Income (Loss) Per Common Share
Oil, Natural Gas and NGL Sales
Operating Income (Loss) (1)
Net Income (Loss)
$
$
$
$
$
$
$
$
Basic and Diluted Income (Loss) Per Common Share $
Three Months Ended
March 31,
June 30,
September 30, December 31,
2018
2018
2018
2018
230,215
$
260,196
$
85,443
(51,995) $
(0.32) $
(0.32) $
98,300
8,848
0.03
0.03
$
$
$
$
$
282,160
121,171
65,150
0.33
0.33
$
$
$
$
$
288,172
110,885
99,852
0.52
0.51
Three Months Ended
March 31,
June 30,
September 30, December 31,
2017
2017
2017
2017
89,639
10,210
8,716
0.03
$
$
$
$
119,766
16,480
7,240
0.02
$
$
$
$
180,861
$
214,030
41,084
$
(29,796) $
(0.20) $
58,850
(30,568)
(0.20)
(1) Oil, Natural gas and NGL sales revenue less lease operating expenses, transportation and gathering expenses, production
taxes and depreciation, depletion, amortization and accretion.
146
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
In accordance with the Securities Exchange Act of 1934, as amended (the "Exchange Act"), Rules 13a-15(b) and 15d-15(b), we
have evaluated, under the supervision and with the participation of our management, including our principal executive officer
and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2018. Our disclosure controls and
procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we
file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive
officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded,
processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that
evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and
procedures were effective as of December 31, 2018 at the reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
Our management, including our principal executive officer and principal financial officer, 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. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with
generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
Our management assessed the effectiveness of the Company's internal control over financial reporting as of December 31,
2018, using the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment, management determined that our internal control over
financial reporting was effective as of December 31, 2018.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial
statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial
reporting at December 31, 2018. Their "Report of Independent Registered Public Accounting Firm," which expresses an
unqualified opinion on the effectiveness of our internal control over financial reporting at December 31, 2018, is included in
Item 8.
Changes in Internal Control over Financial Reporting
There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f)
under the Exchange Act) during the fourth quarter of 2018 that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
147
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The information responsive to Items 401, 405, 406 and 407 of Regulation S-K to be included in our definitive Proxy
Statement for our 2019 Annual Meeting of Shareholders, to be filed within 120 days of December 31, 2018, pursuant to Regulation
14A under the Securities Exchange Act of 1934, as amended (the “2019 Proxy Statement”), is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information responsive to Items 402 and 407 of Regulation S-K to be included in our 2019 Proxy Statement is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
The information responsive to Items 201(d) and 403 of Regulation S-K to be included in our 2019 Proxy Statement is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information responsive to Items 404 and 407 of Regulation S-K to be included in our 2019 Proxy Statement is
incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information responsive to Item 9(e) of Schedule 14A to be included in our 2019 Proxy Statement is incorporated
herein by reference.
148
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
(a) Documents Filed With This Report
1. FINANCIAL STATEMENTS
The following consolidated financial statements of the Company are filed as a part of this report:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Changes in Members’ and Stockholders' Equity and Noncontrolling Interest
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES
PAGE
90
92
93
94
96
98
All financial statement schedules have been omitted because they are not applicable or the required information is
presented in the consolidated financial statements and related notes.
3. EXHIBITS
The exhibits to this report required to be filed pursuant to Item 15(b) are listed below in the “Index to Exhibits”
attached hereto and are incorporated herein by reference.
149
Exhibit
Number
**2.1
**3.1
**3.2
**3.3
**4.1
**4.2
**4.3
**4.4
**4.5
†**10.1
†**10.2
†**10.3
INDEX TO EXHIBITS
Description
Agreement and Plan of Merger, dated October 17, 2016, by and between Extraction Oil & Gas, Inc. and
Extraction Oil & Gas Holdings, LLC. (incorporated by reference to Exhibit 2.1 to the Company’s Current
Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21, 2016).
Certificate of Incorporation of Extraction Oil & Gas, Inc., dated October 11, 2016 (incorporated by reference
to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission
on October 14, 2016).
Certificate of Designations of Series A Preferred Stock of Extraction Oil & Gas, Inc., filed with the Secretary
of State of the State of Delaware on October 17, 2016 (incorporated by reference to Exhibit 3.1 to the
Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21,
2016).
Bylaws of Extraction Oil & Gas, Inc., dated October 11, 2016 (incorporated by reference to Exhibit 3.2 to the
Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 14,
2016).
Amended and Restated Registration Rights Agreement, dated October 17, 2016, by and among Extraction Oil
& Gas, Inc. and the other persons named therein (incorporated by reference to Exhibit 4.1 to the Company’s
Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21, 2016).
Registration Rights Agreement, dated October 3, 2016, by and among Extraction Oil & Gas, LLC, Extraction
Oil & Gas Holdings, LLC and the other persons named therein (incorporated by reference to Exhibit 4.2 to the
Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21,
2016).
Registration Rights Agreement, dated December 15, 2016, by and among Extraction Oil & Gas, Inc. and the
purchasers named therein (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on
Form 8-K (File No. 001-37907) filed with the Commission on December 16, 2016).
Indenture, dated August 1, 2017, by and between Extraction Oil & Gas, Inc. and Wells Fargo Bank, National
Association, as trustee (incorporated by reference to exhibit 4.1 to the Company’s Current Report on Form 8-K
(File No. 001-37907) filed with the Commission on August 3, 2017).
Indenture, dated as of January 25, 2018, by and among Extraction Oil & Gas, Inc., the guarantors party thereto
and Wells Fargo Bank, National Association, as trustee (incorporated by reference to exhibit 4.1 to the
Company's Current Report on Form 8-K (File No. 001-37907) filed with the Commission on January 25,
2018).
Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 4.4 to the
Company’s Registration Statement on Form S-8 (File No. 333-214089) filed with the Commission on October
13, 2016).
Form of Restricted Stock Unit Award Agreement (for Employees) (incorporated by reference to Exhibit 4.5 to
the Company’s Registration Statement on Form S-8 (File No. 333-214089) filed with the Commission on
October 13, 2016).
Form of Restricted Stock Unit Award Agreement (for Directors) (incorporated by reference to Exhibit 4.6 to
the Company’s Registration Statement on Form S-8 (File No. 333-214089) filed with the Commission on
October 13, 2016).
150
†**10.4
Form of Stock Option Award Agreement (incorporated by reference to Exhibit 4.7 to the Company’s
Registration Statement on Form S-8 (File No. 333-214089) filed with the Commission on October 13, 2016).
†**10.5
†**10.6
†**10.7
Employment Agreement dated as of October 11, 2016 among the Company, XOG Services, LLC, and Mark A.
Erickson (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (File No.
001-37907) filed with the Commission on October 14, 2016).
Employment Agreement dated as of October 11, 2016 among the Company, XOG Services, LLC, and
Matthew R. Owens (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K
(File No. 001-37907) filed with the Commission on October 14, 2016).
Employment Agreement dated as of October 11, 2016 among the Company, XOG Services, LLC, and Russell
T. Kelley, Jr. (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K (File
No. 001-37907) filed with the Commission on October 14, 2016).
†**10.8
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.8 to the Company's Annual
Report on Form 10-K (File No. 001-37907) filed with the Commission on February 27, 2018).
†**10.9
Employment Agreement effective as of November 1, 2016 among the Company and Tom L. Brock
(incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No.
001-37907) filed with the Commission on October 31, 2016).
†**10.10
Amended and Restated Employment Agreement effective as of November 1, 2016 among the Company and
Tom L. Brock (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File
No. 001-37907) filed with the Commission on November 22, 2016).
†**10.11
Employment Agreement effective as of November 7, 2016 among the Company and Eric J. Christ
(incorporated by reference to Exhibit 10.11 to the Company's Annual Report on Form 10-K (File No.
001-37907) filed with the Commission on February 27, 2018).
†**10.12
Amendment to Employment Agreement effective as of February 17, 2017 among the Company and Eric J.
Christ (incorporated by reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K (File No.
001-37907) filed with the Commission on February 27, 2018).
**10.13
**10.14
**10.15
**10.16
Common Stock Subscription Agreement, dated as of December 12, 2016, by and among Extraction Oil & Gas,
Inc. and the purchasers named therein (incorporated by reference to Exhibit 10.1 to the Company’s Current
Report on Form 8-K (file No. 001-37907) filed with the Commission on December 12, 2016).
Amended and Restated Credit Agreement, dated as of August 16, 2017, by and between Extraction Oil & Gas,
Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent and issuing lender, and the
lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K
(File No. 001-37907) filed with the Commission on August 21, 2017).
Increase Agreement, Joinder and Amendment No. 1 to Amended and Restated Credit Agreement, dated as of
October 11, 2017, by and between Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of the
Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent and issuing lender
and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on
Form 8-K (File No. 001-37907) filed with the Commission on October 13, 2017).
Master Assignment, Increase Agreement and Amendment No.2 to Amended and Restated Credit Agreement,
dated as of January 5, 2018, by and between Extraction Oil & Gas, Inc., as borrower, Wells Fargo Bank,
National Association, as administrative agent and issuing lender, and the lenders party thereto (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (File No. 001-37907) filed with the
Commission on January 9, 2018).
151
**10.17
**10.18
**10.19
**10.20
**10.21
Consent Agreement and Amendment No. 3 to Amended and Restated Credit Agreement, dated as of February
27, 2018, by and between Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of the Company, as
guarantors, Wells Fargo Bank, National Association, as administrative agent and issuing lender and the lenders
party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (File
No. 001-37907) filed with the Commission on March 2, 2018).
Amendment No. 4 to Amended and Restated Credit Agreement, dated as of May 23, 2018, by and between
Extraction Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent and
issuing lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's
Current Report on Form 8-K (File No. 001-37907) filed with the Commission on May 29, 2018).
Consent and Amendment No. 5 to Amended and Restated Credit Agreement, dated as of October 2, 2018, by
and among Extraction Oil & Gas, Inc., as borrower, certain of its subsidiaries, as guarantors, the lenders party
thereto, and Wells Fargo Bank, National Association, as administrative agent and issuing lender (incorporated
by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (File No. 001-37907) filed with
the Commission on October 9, 2018).
Borrowing Base Increase Agreement, dated as of December 20, 2018, among Extraction Oil & Gas, Inc., as
borrower, certain subsidiaries of Extraction Oil & Gas, Inc., as guarantors, the lenders party thereto and Wells
Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K (File No. 001-37907) filed with the Commission on December 26,
2018).
Consent and Amendment No. 6 to Amended and Restated Credit Agreement, dated as of January 8, 2019, by
and among Extraction Oil & Gas, Inc., as borrower, certain of its subsidiaries, as guarantors, the lenders party
thereto, and Wells Fargo Bank, National Association, as administrative agent and issuing lender (incorporated
by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (File No. 001-37907) filed with
the Commission on January 14, 2019).
*21.1
Subsidiaries of the Registrant
*23.1
Consent of PricewaterhouseCoopers LLP
*23.2
Consent of Ryder Scott Company, L.P.
*31.1
*31.2
*32.1
*32.2
Certification of Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange
Act of 1934.
Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange
Act of 1934.
Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
*99.1
Report of Ryder Scott Company, L.P.
*101
Interactive Data Files
† Management contract or compensatory plan or agreement.
* Filed herewith.
** Previously filed.
152
ITEM 16. FORM 10-K SUMMARY
None.
153
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 21, 2019.
Extraction Oil & Gas, Inc.
By:
/s/ MARK A. ERICKSON
Mark A. Erickson
Chairman and Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ RUSSELL T. KELLEY, JR.
Chief Financial Officer (Principal Financial Officer)
February 21, 2019
Russell T. Kelley, Jr.
/s/ TOM L. BROCK
Tom L. Brock
Vice President, Chief Accounting Officer (Principal
Accounting Officer)
February 21, 2019
/s/ MATTHEW R. OWENS
President and Director
February 21, 2019
Matthew R. Owens
/s/ JOHN S. GAENSBAUER
Director
February 21, 2019
John S. Gaensbauer
/s/ PETER A. LEIDEL
Peter A. Leidel
Director
February 21, 2019
/s/ MARVIN M. CHRONISTER
Director
February 21, 2019
Marvin M. Chronister
/s/ PATRICK D. O’BRIEN
Director
February 21, 2019
Patrick D. O’Brien
/s/ WAYNE W. MURDY
Director
February 21, 2019
Wayne W. Murdy
/s/ DONALD L. EVANS
Director
February 21, 2019
Donald L. Evans
154
E X T R A C T I O N O I L & G A S 2 0 1 8 A N N U A L R E P O R T • A F O U N D A T I O N o f S T R E N G T H
CORPORATE INFORMATION
Management Team
Management Team
Board of Directors
Board of Directors
Additional Resources
Additional Resources
Mark Erickson
Chairman and CEO
Chairman and CEO
Matt Owens
President
President
Wayne Murdy
Lead Director
Lead Director
Peter Leidel
Director
Director
Marvin Chronister
Director
Director
John Gaensbauer
Director
Director
Pat O’Brien
Director
Director
Donald Evans
Director
Director
Common Stock Information
The Common Stock is traded
on the NASDAQ MKT under
the symbol XOG.
Transfer Agent
American Stock Transfer
& Trust Company
800-937-5449
800-937-5449
help@astfinancial.com
help@astfinancial.com
Auditor
PricewaterhouseCoopers LLP
Reserve Engineers
Ryder Scott, Denver, CO
Form 10-K
Additional copies of the
Company’s Form 10-K as
filed with the Securities and
Exchange Commission, are
available at our website,
www.extractionog.com,
under Investors.
Mark Erickson
Chairman of the Board
and Chief Executive
Officer
Matt Owens
President
Russell Kelley
Chief Financial Officer
Eric Jacobsen
Senior Vice President,
Operations
Tom Brock
Chief Accounting
Officer
Eric Christ
General Counsel and
Corporate Secretary
Extraction Oil & Gas Inc. • 370 17th Street, Suite 5300 • Denver, CO 80202
www.extractionog.com