10-K 1 xog-12312018x10k.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
FORM 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
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
 
46-1473923
(State or other jurisdiction of
incorporation or organization)
 
(IRS Employer
Identification No.)
 
 
 
370 17th Street, Suite 5300
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)
 
(720) 557-8300
 
 
(Registrant’s telephone number, including area code)
 
Title of each class
 
Name of exchange on which registered
Common Stock, par value $0.01
 
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  ☐    No  x
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  ☐    No  x
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  x    No  ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  x    No  ☐

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.     ☐
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
x
 
Accelerated filer
Non-accelerated filer
 
Smaller reporting company
 
 
 
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  x



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.
 
DOCUMENTS INCORPORATED BY REFERENCE
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.



EXTRACTION OIL & GAS, INC.
TABLE OF CONTENTS
 
 
    
Page
 
 
 
 
 
 


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: 
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.

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"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


PART I
 
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
 
Company 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. 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.
 
Estimated Total Proved Reserves (1)
 
Average Net
Production
 
 
Oil
 
Natural Gas
 
NGL
 
Total
 
%
 
%
 
%
 
(BOE/d)
 
R/P Ratio
(MBbls)
 
(MMcf)
 
(MBbls)
 
(MBoe)
 
Oil
 
Liquids(2)
 
Developed
 
(1)(3)
 
(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)
 
 
Total
Gross
 
6,436

Net
 
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.

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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
 
As of December 31, 
 
2018
    
2017
    
2016
Proved Developed Producing Reserves:
 
 
 
 
 
Oil (MBbls)
43,477

 
34,350

 
13,345

Natural gas (MMcf)
292,598

 
208,311

 
93,233

NGL (MBbls)
36,361

 
26,368

 
11,453

Total (MBoe)(1) 
128,604

 
95,437

 
40,337

Proved Developed Non-Producing Reserves:
 
 
 
 
 
Oil (MBbls)
3,598

 
2,728

 
3,813

Natural gas (MMcf)
23,901

 
13,925

 
14,685

NGL (MBbls)
3,328

 
1,564

 
1,901

Total (MBoe)(1) 
10,910

 
6,613

 
8,162

Proved Undeveloped Reserves:
 
 
 
 
 
Oil (MBbls)
88,771

 
74,197

 
73,837

Natural gas (MMcf)
386,769

 
403,933

 
399,817

NGL (MBbls)
55,162

 
49,174

 
49,094

Total (MBoe)(1)
208,395

 
190,693

 
189,567

Total Proved Reserves:
 
 
 
 
 
Oil (MBbls)
135,846

 
111,275

 
90,995

Natural gas (MMcf)
703,268

 
626,169

 
507,735

NGL (MBbls)
94,851

 
77,106

 
62,448

Total (MBoe)(1)
347,908

 
292,743

 
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:
 
 
MBoe
Balance, December 31, 2015
    
128,505

Conversion into proved developed reserves
 
(15,923
)
Extensions and discoveries
 
50,882

Acquisitions
 
31,081

Changes in well performance, timing and other
 
(4,978
)
Balance, December 31, 2016
 
189,567

Conversion into proved developed reserves
 
(43,798
)
Extensions and discoveries
 
37,573

Acquisitions
 
12,720

Changes in well performance, timing and other
 
(5,369
)
Balance, December 31, 2017
 
190,693

Conversion into proved developed reserves
 
(39,498
)
Extensions and discoveries
 
64,955

Acquisitions
 
12,325

Changes in well performance, timing and other
 
(20,080
)
Balance, December 31, 2018
 
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.

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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:
 
Productive Wells
 
Gross
 
Net
Oil wells
1,359

 
992

Natural gas wells
179

 
147

Total wells
1,538

 
1,139

 
Developed and Undeveloped Acreage
 
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:
 
 
 
Developed
 
Undeveloped
 
Total
 
 
Acreage(1)
 
Acreage(2)
 
Acreage
Area
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Core DJ Basin
 
119,400

 
96,100

 
163,300

 
83,200

 
282,700

 
179,300

Other Rockies
 
61,600

 
42,900

 
152,600

 
95,200

 
214,200

 
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
    
Gross
    
Net
    
Gross
    
Net
    
Gross
    
Net
    
Gross
    
Net
Core DJ Basin
 
16,400

 
13,900

 
32,900

 
22,800

 
23,100

 
18,900

 
9,600

 
7,100

Other Rockies
 
12,700

 
6,300

 
31,800

 
19,300

 
17,600

 
11,900

 
30,200

 
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.
 
 
For the Year Ended December 31,
 
2018
 
2017
 
2016
 
Gross
    
Net
    
Gross
    
Net
    
Gross
    
Net
Development Wells(1):
 
 
 
 
 
 
 
 
 
 
 
Productive(2) 
160.0

 
136.4

 
196.0

 
157.8

 
72.0

 
54.9

Dry

 

 

 

 

 

Exploratory Wells(1):
 
 
 
 
 
 
 
 
 
 
 
Productive(2) 
1.0

 
1.0

 
2.0

 
1.1

 

 

Dry

 

 

 

 

 

Total Wells(1):
 
 
 
 
 
 
 
 
 
 
 
Productive(2) 
161.0

 
137.4

 
198.0

 
158.9

 
72.0

 
54.9

Dry

 

 

 

 

 

 
(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:
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:
incur additional indebtedness;
sell assets;
make loans to others;
make certain acquisitions and investments;
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;
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:
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:
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:
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:
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:
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

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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.

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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


PART II
 
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Market Information.
 
Our common stock is currently traded on the 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.

cumulativeshareholder.jpg

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
 
Total Number of Shares Purchased
 
Average Price Paid per Share
October 1, 2018 - October 31, 2018
 

 
$

November 1, 2018 - November 30, 2018
 
3,558,145

 
6.68

December 1, 2018 - December 31, 2018
 
500,000

 
4.97

Total
 
4,058,145

 
$
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



 
For the Year Ended December 31, 
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in thousands, except per share data)
Revenues:
 
 
 
 
 
 
 
 
 
Oil sales
$
840,687

 
$
419,904

 
$
194,059

 
$
157,024

 
$
75,460

Natural gas sales
105,629

 
92,322

 
48,652

 
26,019

 
9,247

NGL sales
114,427

 
92,070

 
35,378

 
14,707

 
8,133

Total Revenues
1,060,743

 
604,296

 
278,089

 
197,750

 
92,840

Operating Expenses:
 

 
 

 
 

 
 
 
 
Lease operating expenses
79,413

 
60,358

 
36,743

 
23,949

 
5,067

Transportation and gathering
39,411

 
50,948

 
25,300

 
6,679

 

Production taxes
90,345

 
51,367

 
20,730

 
17,035

 
9,743

Exploration expenses
31,611

 
36,256

 
36,422

 
18,636

 
126

Depletion, depreciation, amortization and accretion
435,775

 
314,999

 
205,348

 
146,547

 
34,042

Impairment of long lived assets and goodwill
70,928

 
1,647

 
23,425

 
15,778

 

Other operating expenses

 

 
10,891

 
2,353

 

(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary
(136,834
)
 
451

 

 

 

Acquisition transaction expenses

 

 
2,719

 
6,000

 

General and administrative expenses
134,604

 
110,167

 
232,388

 
37,149

 
19,598

Total Operating Expenses
745,253

 
626,193

 
593,966

 
274,126

 
68,576

Operating Income (Loss)
315,490

 
(21,897
)
 
(315,877
)
 
(76,376
)
 
24,264

Other Income (Expense):
 

 
 

 
 

 
 
 
 
Commodity derivatives gain (loss)
(8,554
)
 
(36,332
)
 
(100,947
)
 
79,932

 
48,008

Interest expense
(123,330
)
 
(51,889
)
 
(68,843
)
 
(51,030
)
 
(22,454
)
Other income
5,099

 
2,010

 
386

 
210

 
24

Total Other Income (Expense)
(126,785
)
 
(86,211
)
 
(169,404
)
 
29,112

 
25,578

Income (Loss) Before Income Taxes
188,705

 
(108,108
)
 
(485,281
)
 
(47,264
)
 
49,842

Income tax (expense) benefit (1)
(66,850
)
 
63,700

 
29,280

 

 

Net Income (Loss)
$
121,855

 
$
(44,408
)
 
$
(456,001
)
 
$
(47,264
)
 
$
49,842

Net income attributable to noncontrolling interest
7,287

 

 

 

 

Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.
114,568

 
(44,408
)
 
(226,107
)
 
(47,264
)
 
49,842

Adjustments to reflect Series A Preferred Stock dividends and accretion of discount
(16,869
)
 
(16,279
)
 
(3,999
)
 

 

Net Income (Loss) Available to Common Shareholders, Basic and Diluted
$
97,699

 
$
(60,687
)
 
$
(230,106
)
 
$
(47,264
)
 
$
49,842

Income (Loss) Per Common Share (2)
 

 
 

 
 

 
 
 
 
Basic and diluted
$
0.56

 
$
(0.35
)
 
$
(1.54
)
 
 
 
 

55



Selected consolidated financial information continued: 
 
As of and for the Year Ended December 31, 
 
2018
 
2017
 
2016
 
2015
 
2014
Total Production Volumes:
 
 
 
 
 
 
 
 
 
Oil (MBbls)
14,679

 
9,594

 
5,287

 
3,946

 
1,022

Natural Gas (MMcf)
46,847

 
32,395

 
20,212

 
10,823

 
2,664

NGL (MBbls)
5,260

 
3,901

 
2,284

 
1,335

 
325

Total (MBOE)
27,747

 
18,894

 
10,940

 
7,084

 
1,792

Average net sales (BOE/d)
76,019

 
51,764

 
29,891

 
19,408

 
4,908

Proved Reserves:
 
 
 
 
 
 
 
 
 
Oil (MBbls)
135,846

 
111,275

 
90,995

 
71,500

 
45,165

Natural Gas (MMcf)
703,268

 
626,169

 
507,735

 
292,584

 
166,416

NGL (MBbls)
94,851

 
77,106

 
62,448

 
38,383

 
19,451

Total (MBOE)
347,908

 
292,743

 
238,066

 
158,647

 
92,352

Consolidated Cash Flow Information:
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities (5)
$
684,933

 
$
316,965

 
$
120,688

 
$
166,683

 
$
77,390

Net cash used in investing activities (5)
$
(897,305
)
 
$
(1,404,528
)
 
$
(873,608
)
 
$
(530,077
)
 
$
(960,569
)
Net cash provided by financing activities
$
440,590

 
$
463,395

 
$
1,286,750

 
$
371,404

 
$
972,090

Consolidated Balance Sheet Information:
 
 
 
 
 
 
 
 
 
Total Assets
$
4,166,027

 
$
3,384,669

 
$
2,784,776

 
$
1,634,140

 
$
1,201,069

Long-term Debt
$
1,417,659

 
$
1,023,361

 
$
538,141

 
$
637,790

 
$
508,903

Series A Preferred Stock
$
164,367

 
$
158,383

 
$
153,139

 
$

 
$

Total Equity(3)
$
1,894,686

 
$
1,616,765

 
$
1,616,073

 
$
754,232

 
$
545,188

Other Financial Data (4):
 
 
 
 
 
 
 
 
 
Adjusted EBITDAX
$
659,752

 
$
380,462

 
$
192,265

 
$
176,120

 
$
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:
 
For the Year Ended
 
December 31, 
 
2018
 
2017
 
2016
Oil (MBbl)
14,679

 
9,594

 
5,287

Natural gas (MMcf)
46,847

 
32,395

 
20,212

NGL (MBbl)
5,260

 
3,901

 
2,284

Total (MBoe)
27,747

 
18,894

 
10,940

Average net sales (BOE/d)
76,019

 
51,764

 
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.
 

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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.
 
 
For the Year Ended
 
December 31, 
 
2018
  
2017
  
2016
Oil
 
 
 
 
 
NYMEX WTI High ($/Bbl)
$
76.41

 
$
60.42

 
$
54.06

NYMEX WTI Low ($/Bbl)
$
42.53

 
$
42.53

 
$
26.21

NYMEX WTI Average ($/Bbl)
$
64.90

 
$
50.85

 
$
43.47

Average Realized Price ($/Bbl)
$
57.27

 
$
43.77

 
$
36.70

Average Realized Price, with derivative settlements ($/Bbl)
$
48.04

 
$
41.67

 
$
40.59

Average Realized Price as a % of Average NYMEX WTI
88.2
%
 
86.1
%
 
84.4
%
Differential ($/Bbl) to Average NYMEX WTI
$
(7.63
)
 
$
(7.08
)
 
$
(6.77
)
Natural Gas
 
 
 
 
 
NYMEX Henry Hub High ($/MMBtu)
$
4.84

 
$
3.42

 
$
3.93

NYMEX Henry Hub Low ($/MMBtu)
$
2.55

 
$
2.56

 
$
1.64

NYMEX Henry Hub Average ($/MMBtu)
$
3.07

 
$
3.02

 
$
2.55

Average Realized Price ($/Mcf) (2)
$
2.25

 
$
2.85

 
$
2.41

Average Realized Price, with derivative settlements ($/Mcf)(2)
$
2.36

 
$
2.90

 
$
2.81

Average Realized Price as a % of Average NYMEX Henry Hub(1)(2)
66.7
%
 
85.8
%
 
85.9
%
Differential ($/Mcf) to Average NYMEX Henry Hub(1)(2)
$
(1.12
)
 
$
(0.47
)
 
$
(0.40
)
NGL
 
 
 
 
 
Average Realized Price ($/Bbl) (2)
$
21.75

 
$
23.60

 
$
15.49

Average Realized Price as a % of Average NYMEX WTI (2)
33.5
%
 
46.4
%
 
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.
 

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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:
 
 
2019
 
2020
NYMEX WTI Crude Swaps:
 
 
 
Notional volume (Bbl)
900,000

 
1,200,000

Weighted average fixed price ($/Bbl)
$
52.56

 
$
52.66

NYMEX WTI Crude Sold Calls:
 

 
 
Notional volume (Bbl)
11,700,000

 
1,800,000

Weighted average sold call price ($/Bbl)
$
65.40

 
$
67.53

NYMEX WTI Crude Sold Puts:
 

 
 
Notional volume (Bbl)
13,500,000

 
1,800,000

Weighted average sold put price ($/Bbl)
$
41.27

 
$
42.00

NYMEX WTI Crude Purchased Puts:
 

 
 
Notional volume (Bbl)
17,850,000

 
1,800,000

Weighted average purchased put price ($/Bbl)
$
47.67

 
$
50.00

NYMEX HH Natural Gas Swaps:
 

 
 
Notional volume (MMBtu)
32,400,000

 

Weighted average fixed price ($/MMBtu)
$
2.81

 

NYMEX HH Natural Gas Purchased Puts:
 

 
 
Notional volume (MMBtu)
3,600,000

 

Weighted average purchased put price ($/MMBtu)
$
3.04

 

NYMEX HH Natural Gas Sold Calls:
 

 
 
Notional volume (MMBtu)
3,600,000

 

Weighted average sold call price ($/MMBtu)
$
3.46

 

NYMEX HH Natural Gas Sold Puts:
 
 
 
Notional volume (MMBtu)
3,000,000

 

Weighted average sold put price ($/MMBtu)
$
2.50

 

CIG Basis Gas Swaps:
 

 
 
Notional volume (MMBtu)
36,000,000

 

Weighted average fixed basis price ($/MMBtu)
$
(0.75
)
 



62


The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated. 
 
For the Year Ended
 
December 31, 
 
2018
 
2017
 
2016
NYMEX HH Natural Gas Swaps:
 
 
 
 
 
Notional volume (MMBtu)
40,650,000

 
25,240,000

 
13,194,600

Weighted average fixed price ($/MMBtu)
$
3.10

 
$
3.05

 
$
3.13

CIG Basis Gas Swaps:
 

 
 

 
 

Notional volume (MMBtu)
37,935,000

 
12,615,000

 
2,970,000

Weighted average fixed basis price ($/MMBtu)
$
(0.62
)
 
$
(0.34
)
 
$
(0.19
)
NYMEX HH Natural Gas Purchased Puts:
 
 
 
 
 
Notional volume (MMBtu)
2,400,000

 

 

Weighted average strike price ($/MMBtu)
$
3.00

 

 

NYMEX HH Natural Gas Sold Calls:
 

 
 

 
 

Notional volume (MMBtu)
2,400,000

 

 

Weighted average strike price ($/MMBtu)
$
3.15

 

 

NYMEX WTI Crude Swaps:
 

 
 

 
 

Notional volume (Bbl)
5,050,000

 
4,125,000

 
1,989,060

Weighted average fixed price ($/Bbl)
$
51.58