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Table of Contents

As filed with the Securities and Exchange Commission on September 14, 2016

Registration No. 333-                


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



Extraction Oil & Gas, LLC
to be converted as described herein into a corporation named

Extraction Oil & Gas, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  46-1473923
(IRS Employer
Identification No.)

370 17th Street, Suite 5300
Denver, Colorado 80202
(720) 557-8300
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Russell T. Kelley, Jr.
Chief Financial Officer
370 17th Street, Suite 5300
Denver, Colorado 80202
(720) 557-8300
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Douglas E. McWilliams
Julian J. Seiguer
Vinson & Elkins L.L.P.
1001 Fannin, Suite 2500
Houston, Texas 77002
(713) 758-2222

 

Sean T. Wheeler
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400

Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after the effective date of this Registration Statement.

          If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:    o

          If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o

CALCULATION OF REGISTRATION FEE

       
 
Title of Each Class of Securities
to be Registered

  Proposed Maximum
Aggregate Offering
Price(1)(2)

  Amount of
Registration Fee

 

Common stock, par value $0.01 per share

  $100,000,000   $10,070.00

 

(1)
Includes shares issuable upon exercise of the underwriters' option to purchase additional shares of common stock.

(2)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

          The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

   


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state or jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED SEPTEMBER 14, 2016



             Shares

LOGO

Extraction Oil & Gas, Inc.

Common Stock



        This is the initial public offering of the common stock of Extraction Oil & Gas, Inc., a Delaware corporation. We are offering                            shares of our common stock.

        No public market currently exists for our common stock. We anticipate that the initial public offering price will be between $             and $             per share. We have applied to list our common stock on the NASDAQ Global Select Market under the symbol "XOG."

        We have granted the underwriters the option to purchase up to                           additional shares of common stock on the same terms and conditions set forth above if the underwriters sell more than                           shares of common stock in this offering.

        We are an "emerging growth company" as the term is used in the Jumpstart Our Business Startups Act of 2012 and, as such, are eligible for reduced reporting requirements. Please see "Prospectus Summary—Emerging Growth Company Status."

        Investing in our common stock involves risks. Please see "Risk Factors" beginning on page 22 of this prospectus.

 
  Price to
the public
  Underwriting
discounts and
commissions
  Proceeds to us
(before expenses)

Per share

  $   $   $

Total

  $            $            $       

        The underwriters expect to deliver the shares on or about                           , 2016.

        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Credit Suisse   Barclays   Goldman, Sachs & Co.

   

The date of this prospectus is                           , 2016.


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GRAPHIC


Table of Contents


TABLE OF CONTENTS

 
  Page  

PROSPECTUS SUMMARY

    1  

RISK FACTORS

    22  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

    54  

USE OF PROCEEDS

    56  

DIVIDEND POLICY

    57  

CAPITALIZATION

    58  

DILUTION

    60  

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

    61  

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    63  

BUSINESS

    99  

CORPORATE REORGANIZATION

    131  

MANAGEMENT

    135  

EXECUTIVE COMPENSATION

    140  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    149  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

    152  

DESCRIPTION OF CAPITAL STOCK

    154  

SHARES ELIGIBLE FOR FUTURE SALE

    159  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

    162  

UNDERWRITING

    166  

LEGAL MATTERS

    172  

EXPERTS

    172  

WHERE YOU CAN FIND MORE INFORMATION

    173  

INDEX TO FINANCIAL STATEMENTS

    F-1  

APPENDIX A—GLOSSARY OF OIL AND GAS TERMS

    A-1  



        You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

        This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please see "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

        Through and including                    (the 25th day after the date of this prospectus), all dealers effecting transactions in our shares, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers' obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.


BASIS OF PRESENTATION

        The financial information and certain other information presented in this prospectus have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this prospectus. In addition, certain percentages presented in this prospectus reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers or may not sum due to rounding.

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PRESENTATION OF FINANCIAL AND OPERATING DATA

        Extraction Oil & Gas Holdings, LLC, a Delaware limited liability company and our accounting predecessor, was formed on May 29, 2014 by PRE Resources, LLC ("PRL") as a holding company with no independent operations. Extraction Oil & Gas, LLC, formally a wholly owned subsidiary of PRL, is a wholly owned subsidiary of Extraction Oil & Gas Holdings, LLC. Extraction Oil & Gas, LLC was formed on November 14, 2012 as a Delaware limited liability company. Concurrent with the formation of Extraction Oil & Gas Holdings, LLC, PRL contributed all of its membership interests in Extraction Oil & Gas, LLC, to Extraction Oil & Gas Holdings, LLC and distributed all of its interests in Extraction Oil & Gas Holdings, LLC to its members in a pro rata distribution (the "Reorganization"). The Reorganization was accounted for as a reorganization of entities under common control and the assets and liabilities of Extraction Oil & Gas, LLC were recorded at Extraction Oil & Gas, LLC's historical costs. The historical consolidated financial statements presented in this prospectus have been retrospectively recast for all periods prior to May 29, 2014 to reflect the Reorganization as if the transfer of net assets occurred at the beginning of the period. Results of operations for the 2014 period presented in this prospectus include the results of operations from Extraction Oil & Gas, LLC, the previously separate entity, from January 1, 2014 to May 29, 2014, the date the transfer was completed. In connection with the consummation of this offering, Extraction Oil & Gas Holdings, LLC will be merged with and into Extraction Oil & Gas, LLC and such merger will be treated as a reorganization of entities under common control, and Extraction Oil & Gas, LLC will convert from a Delaware limited liability company into a Delaware corporation. For more information please see "Corporate Reorganization."

        Locations in this document presented at 1-mile (approximately 4,200 feet), 1.5-mile (approximately 6,800 feet) and 2-mile (approximately 9,400 feet) equivalents are shown to present the actual length of such lateral lengths after accounting for the setback distance on each side of the lease line.


WATTENBERG FIELD

        References herein to the "Wattenberg Field" or the "Wattenberg" refer to the Greater Wattenberg Area within the Denver-Julesburg Basin of Colorado as defined by the Colorado Oil and Gas Conservation Commission (the "COGCC"). The COGCC defines the Greater Wattenberg Area as those lands from and including Townships 2 South to 7 North and Ranges 61 West to 69 West, Sixth Principal Meridian.


INDUSTRY AND MARKET DATA

        The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled "Risk Factors." These and other factors could cause results to differ materially from those expressed in these publications.


TRADEMARKS AND TRADE NAMES

        We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties' trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.

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PROSPECTUS SUMMARY

        This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully before making an investment decision, including the information under the headings "Risk Factors," "Cautionary Note Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical and pro forma financial statements and the related notes thereto appearing elsewhere in this prospectus. References to our estimated proved reserves as of June 30, 2016 and as of December 31, 2015 and 2014 are derived from our proved reserve reports prepared by Ryder Scott Company, L.P. ("Ryder Scott") for Extraction Oil & Gas Holdings, LLC.

        Unless indicated otherwise or the context otherwise requires, references in this prospectus to "Extraction," the "Company," "us," "we," "our," or "ours" or like terms refer to Extraction Oil & Gas, Inc. following the completion of our corporate reorganization as described in "—Corporate Reorganization." When used in the historical context, "Extraction," the "Company," "us," "we," "our" and "ours" or like terms refer to Extraction Oil & Gas Holdings, LLC and its subsidiaries for periods after May 29, 2014 and to Extraction Oil & Gas, LLC and its subsidiaries prior to May 29, 2014. References in this prospectus to "Holdings" refer to Extraction Oil & Gas Holdings, LLC, our accounting predecessor, which before the completion of our corporate reorganization and this offering owned 100% of the equity interests of Extraction Oil & Gas, LLC. References in this prospectus to "XOG" refer to Extraction Oil & Gas, LLC. Unless indicated otherwise or the context otherwise requires, references to our net acreage, drilling locations, working interest, proved reserves and well count as of June 30, 2016 and our estimated average net daily production for the month ended July 31, 2016 in this prospectus are adjusted to give pro forma effect to the transactions described in "—Recent Developments—Bayswater Acquisition—Bayswater Assets."


Overview

        We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and natural gas liquid ("NGL") reserves in the Rocky Mountains, 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 June 30, 2016, approximately 100,000 net acres of large, contiguous acreage blocks in some of the most productive areas of the Wattenberg Field as indicated by the results of our horizontal drilling program and the results of offset operators. These properties have extensive production histories, high drilling success rates, and significant horizontal development potential. We believe our acreage in the Wattenberg Field 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 Wattenberg Field.

        We were founded in November 2012 with the objective of becoming a pure-play Wattenberg company focusing on acreage with (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 95% of our horizontal production for the six months ended June 30, 2016 and maintain control of a large majority of our drilling inventory.

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In addition, we proactively seek to secure the necessary midstream and operational infrastructure to keep pace with our production growth.

        As of July 31, 2016, we have drilled 259 gross one-mile equivalent horizontal wells and have completed 230 gross one-mile equivalent horizontal wells. We are currently running a two-rig program and retain the flexibility to adjust our rig count based on the commodity price environment. We have demonstrated our ability to manage a drilling program of larger size, operating four rigs as recently as the first quarter of 2015. Due to significant improvements in our drilling efficiency since late 2014, each of our rigs is currently able to drill over twice as many wells per year as we were previously able to drill. Our estimated average net daily production during the month ended July 31, 2016 was approximately 37,328 BOE/d. The charts below demonstrate the substantial growth in our average net daily production and well count since the second quarter of 2014.

Average Net
Daily Production (BOE/d)

 

Wells Drilled and Completed(1)


GRAPHIC

 


GRAPHIC


(1)
Reflects one-mile equivalent wells drilled or completed by us.

(2)
Reflects 27,121 BOE/d attributable to our historically owned properties and 10,207 BOE/d attributable to the Bayswater Assets (as defined below).

        The following table provides summary information regarding our proved reserves as of June 30, 2016, and our estimated average net daily production during the month ended July 31, 2016.




Estimated Total Proved Reserves
   
   
 
Oil
(MBbls)
  Natural
Gas
(MMcf)
  NGL
(MBbls)
  Total
(MBoe)
  %
Oil
  %
Liquids(2)
  %
Developed
  Average Net
Production
(BOE/d)(1)(3)
  R/P
Ratio
(Years)(4)
 
  79,111     365,702     47,227     187,288     42 %   67 %   23 %   37,328     13.7  

(1)
Includes de minimis reserves and production attributable to properties in our Northern Extension Area. Please see "—Other Properties."

(2)
Includes both oil and NGL.

(3)
Estimated average net daily production. Consisted of approximately 51% oil, 30% natural gas and 19% NGL.

(4)
Represents the number of years proved reserves would last assuming production continued at the average rate for the month ended July 31, 2016. Because production rates naturally decline over time, the reserve-to-production ratio (the "R/P Ratio") is not a useful estimate of how long properties should economically produce.

        Our management team has significant experience in the Wattenberg Field. Our management team members were key participants in the shift from vertical to horizontal drilling that recently occurred during their tenures at key Wattenberg operators, such as Anadarko Petroleum Corporation ("Anadarko Petroleum"), Noble Energy, Inc. ("Noble Energy"), PDC Energy, Inc. ("PDC Energy") and others. Our management and technical teams have collectively participated in the drilling of over 500 horizontal wells in the Niobrara and Codell formations in the Wattenberg Field. To date, we have

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focused our horizontal drilling program primarily in the Niobrara and Codell formations; however, based on results from our horizontal drilling program and those of offset operators such as Anadarko Petroleum and Noble Energy, we believe significant development opportunities exist in the J-Sand, Greenhorn and Sussex formations as well as via additional downspacing in the Niobrara formation, which are not captured in the inventory numbers below. As of June 30, 2016, we had a drilling inventory consisting of 3,510 gross (2,236 net) identified locations within the Wattenberg Field, as adjusted to one-mile equivalents. The table below sets forth a summary of our identified gross horizontal drilling locations in the Wattenberg Field by target zone as of June 30, 2016.

 
  Identified Gross Horizontal Drilling Locations(1)(2)(3)    
 
 
  Horizontal Drilling
Inventory (Years)(7)
 
Net
Acreage(4)
  Niobrara   Codell   Total(5)(6)  
  100,000     2,134     1,376     3,510     19  

(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. See "Risk Factors—Risks Related to the Oil, Natural Gas and NGL Industry and Our Business—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."

(2)
Excludes 89 drilled but uncompleted one-mile equivalent wells as of June 30, 2016, 53 of which are attributable to the Bayswater Assets.

(3)
As adjusted to give effect to 90 gross drilling locations from the Bayswater Assets.

(4)
As of June 30, 2016. Approximate net acreage represents only our oil and gas properties in the Wattenberg Field and does not include the approximately 124,000 net acres associated with our Northern Extension Area. We have not identified any drilling locations at this time on our Northern Extension Area. Please see "—Other Properties."

(5)
Includes 853 identified drilling locations associated with proved undeveloped reserves as of June 30, 2016, as adjusted for lateral length to present one-mile equivalents (approximately 4,200 feet).

(6)
If converted to 1.5-mile equivalent locations (approximately 6,800 feet), we would have an estimated 2,340 identified gross horizontal drilling locations. If converted to 2.0-mile equivalent locations (approximately 9,400 feet), we would have an estimated 1,755 identified gross horizontal drilling locations.

(7)
Based on a continuous two-rig drilling program and a four day spud-to-spud drilling time.

        Based on the results of our horizontal drilling program, and as evidenced by our 30-day, 90-day and 180-day production rates as shown in the table below, we believe our wells are among the most productive in the Wattenberg Field.

 
   
   
  30-day    
  90-day    
  180-day  
 
   
   
  Oil
(Bbl)
  Gas
(Mcf)
  NGL
(Bbl)
  Equivalent
(BOE)
   
  Oil
(Bbl)
  Gas
(Mcf)
  NGL
(Bbl)
  Equivalent
(BOE)
   
  Oil
(Bbl)
  Gas
(Mcf)
  NGL
(Bbl)
  Equivalent
(BOE)
 
Rate per 6,800 ft lateral
cumulative
  Wells    
   
   
 

Codell

    62         14,812     18,625     2,485     20,406         39,183     64,787     8,660     58,650         67,947     138,355     18,364     109,382  

Niobrara

    97         13,168     15,987     2,070     17,906         37,339     59,425     7,658     54,907         61,113     116,760     15,008     95,589  

Average Daily 6,800 ft equivalent (Boe/d)

                                                                                           

Codell

              494     621     83     680         435     720     96     652         377     769     102     608  

Niobrara

              439     533     69     597         415     660     85     610         340     649     83     531  

Note:
Averages based on 97 operated Niobrara wells and 62 operated Codell wells that had at least 30 days of production history as of June 30, 2016. Excludes information related to one well drilled in the J-Sand formation, one well drilled by a previous operator and four exploratory wells. Production data normalized to 1.5 mile (approximately 6,800 feet) equivalents and adjusted for operational downtime. Average data based on average of all operating wells normalized to 6,800 feet. For more information on our drilling results, please see "Business—Drilling Results."

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Other Properties

        We hold approximately 124,000 net acres in the DJ Basin outside of the Wattenberg, which we refer to as our "Northern Extension Area," that we believe is prospective for many of the same formations as our properties in the Wattenberg Field. As of June 30, 2016, there were de minimis proved reserves associated with this acreage. Average daily production associated with these properties for the quarter ended June 30, 2016 was approximately 1,044 BOE/d. We have not identified any drilling locations at this time on our Northern Extension Area.

Historical Capital Expenditures and Capital Budget

        For the year ended December 31, 2015 and the six months ended June 30, 2016, our aggregate drilling, completion and leasehold capital expenditures were approximately $398.4 million and $137.8 million, respectively, excluding acquisitions. Our 2016 capital budget is approximately $365 million, substantially all of which we intend to allocate to the Wattenberg Field. We intend to allocate approximately $335 million of our 2016 capital budget to the drilling of 100 gross (90 net) wells and the completion of 92 gross (82 net) wells, approximately $5 million to midstream, and approximately $25 million to leaseholds. Our 2016 capital expenditures budget contemplates that we will drill approximately 77 gross (70 net) wells targeting proved undeveloped locations in 2016. Such wells are associated with 24,083 MBoe of net proved undeveloped reserves. As of August 15, 2016, 40 gross (36 net) of such wells have been spud. Our capital budget excludes any amounts that were or may be paid for potential acquisitions, including the Bayswater Acquisition.

        Our 2017 capital budget is approximately $590 million, substantially all of which we intend to allocate to the Wattenberg Field. We intend to allocate approximately $535 million of our 2017 capital budget to the drilling of 138 gross (102 net) operated wells and the completion of 120 gross (102 net) operated wells, approximately $2 million to midstream, and approximately $53 million to leaseholds. Our 2017 capital expenditures budget contemplates that we will drill approximately 98 gross (74 net) operated wells targeting proved undeveloped locations in 2017. Such wells are associated with 37,967 MBoe of net proved undeveloped reserves. In addition to the operated wells above, our capital budget includes estimated non-operated activity on our acreage consisting of the drilling of 69 gross (18 net) non-operated wells and the completion of 51 gross (15 net) non-operated wells. Our capital budget excludes 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.

Our Business Strategies

        Our business strategy is to increase stockholder value through the following:

    Grow proved reserves and production by developing our extensive horizontal drilling inventory.  As of June 30, 2016, we identified a horizontal drilling inventory of 3,510 gross locations targeting the Niobrara and Codell zones, as adjusted to one-mile equivalents. While horizontal development of the Wattenberg Field is a relatively recent development, we consider our large inventory of horizontal drilling locations in the Wattenberg Field to be relatively low-risk based on information gained from the large number of existing wells in the area, industry activity

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      surrounding our acreage, and the consistent and predictable geology surrounding our positions. We believe the combination of our large inventory of relatively low-risk drilling locations with long-lived reserves leads to a predictable production profile. We are able to enhance our drilling economics and generate higher EURs per well drilled by taking advantage of our large contiguous acreage position to drill longer laterals. Based on results from our horizontal drilling program and those of offset operators such as Anadarko Petroleum and Noble Energy, we believe significant development opportunities exist in the J-Sand, Greenhorn and Sussex formations as well as via additional downspacing in the Niobrara formation, thus potentially increasing our horizontal drilling inventory significantly.

    Maintain a high degree of operational control in order to continuously improve operating and cost efficiencies.  We operated approximately 95% of our horizontal production for the six months ended June 30, 2016 and intend to maintain operational control of substantially all of our producing properties. We believe that retaining control of our production enables us to increase recovery rates, lower well costs, improve drilling performance and increase ultimate hydrocarbon recovery through optimization of our drilling and completion techniques. Additionally, operating our production allows us to more efficiently manage the pace of our horizontal development program and the gathering and marketing of our production. We continually monitor and adjust our drilling program with the objective of achieving the highest total returns on our portfolio of drilling opportunities.

    Leverage our experience operating in the Wattenberg Field to maximize returns.  Members of our management and technical teams have spent the majority of their careers focused on operations in the Wattenberg Field. These team members were key participants in the shift from vertical to horizontal drilling that recently occurred during their tenures at key Wattenberg operators, including Anadarko Petroleum, Noble Energy, PDC Energy and others. As a result, we believe our management and technical teams are among the best operators in the Wattenberg Field today. Our team regularly benchmarks our operating data in order to evaluate our performance and identify opportunities to optimize our drilling and completion techniques and make informed decisions about our capital program and drilling activity levels. We intend to leverage our management and technical teams' experiences in applying unconventional drilling and completion techniques in the Wattenberg Field to maximize our returns. As an example, our management team initially designed and utilized new and improved drilling and completion techniques, which were different than the industry standard, to avoid having to compete with larger operators on prices for services and products.

    Continue expanding our access to midstream infrastructure to keep pace with our production growth.  We proactively seek to secure the necessary midstream and operational infrastructure necessary to support our drilling schedule and keep pace with our expected production growth. We are an anchor tenant on the Grand Mesa pipeline, which will transport oil and gas out of the Wattenberg Field to Cushing, Oklahoma and which is expected to be in service in late 2016. We are committed to meet delivery commitments of 40,000 Bbls/d out of the basin when the Grand Mesa pipeline commences service, increasing to 58,000 Bbls/d by November 2018 and through 2026.

    Strategically augment acreage position through opportunistic acquisitions.  Since inception, we have consummated five significant acquisitions in the Wattenberg Field, acquiring approximately 70,000 net acres, as of June 30, 2016. We intend to continue to strategically make opportunistic acquisitions as well as pursue additional leasing opportunities to further supplement our oil and

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      natural gas properties in our areas of operation, but expect such expenditures to represent a smaller proportion of our total capital budget.

    Maintain financial flexibility and apply a disciplined approach to capital allocation.  We intend to maintain a conservative financial profile that will afford us flexibility through commodity price cycles. As of June 30, 2016, after giving effect to this offering, the Financing Transactions (as defined below) and the use of the proceeds therefrom, and the consummation of the Bayswater Acquisition, we would have had $             million of liquidity, with $             million of cash and cash equivalents and $             million of available borrowing capacity under our revolving credit facility. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations, enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities.

Our Competitive Strengths

        We believe that the following strengths will allow us to successfully execute our business strategies:

    Large, contiguous acreage blocks concentrated in the Wattenberg Field.  We own extensive and contiguous acreage blocks in the Wattenberg Field, which we believe to be one of the most prolific and economic fields in the nation. Based on the results of our horizontal drilling program, and as evidenced by our 30-day, 90-day and 180-day production rates, we believe our wells are among the most productive in the Wattenberg Field. Our large, contiguous acreage blocks and focus on maintaining operational control allow us the flexibility to adjust our drilling and completion techniques, primarily through the length of our laterals, in order to optimize our well results and drilling economics. Additionally, our contiguous acreage allows us to leverage existing infrastructure for more cost efficient development and transportation as compared to non-contiguous acreage. We believe our approximately 100,000 net acres in the Wattenberg Field as of June 30, 2016 position us to continue growing our proved reserves and production in the current commodity price environment.

    Low-risk Wattenberg acreage position with multi-year inventory of liquids-rich drilling locations.  We view our large identified horizontal drilling inventory targeting liquids-rich drilling opportunities to be relatively low-risk based on information gained from the large number of existing wells in the area, industry activity surrounding our acreage, and the consistent and predictable geology underlying our positions. We have used the subsurface and 3-D seismic data from our development programs, as well as vertical well penetration, to demonstrate the subsurface consistency of our inventory. We currently have 3-D seismic data on all locations in our drilling plan, which we believe reduces the risk associated with our development plan. As of June 30, 2016, our horizontal drilling inventory consisted of 3,510 gross (2,236 net) identified locations targeting the Niobrara and Codell formations, as adjusted to one-mile equivalents. Based on the results from our horizontal drilling program and those of offset operators such as Anadarko Petroleum and Noble Energy, we believe significant development opportunities exist in the J-Sand, Greenhorn and Sussex formations as well as via additional downspacing in the Niobrara formation. Based on a four day spud-to-spud and a two-rig drilling program, we have a drilling inventory of approximately 19 years, prior to considering locations other than those in the Niobrara and Codell formations.

    Significant operational control with low development costs.  We operated 95% of our horizontal production for the six months ended June 30, 2016. We intend to maintain operational control of a substantial majority of our drilling inventory. We believe that maintaining operating control enables us to increase our reserves while lowering our development costs. Our control over operations also allows us to utilize cost-effective operating practices, including the selection of

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      drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques. Our average feet drilled per day has increased to 6,096 as of June 30, 2016 from 1,456 as of March 31, 2014. We have been successful in achieving significant reductions in our drilling, completion and facilities costs. In addition, our drilling contract structure allows us to proactively adjust our rig count based on the commodity price environment. These factors contribute to our ability to grow production and reserves in lower commodity price environments.

    High caliber management team with substantial technical expertise and demonstrated record navigating through commodity price volatility.  Our management and technical teams have extensive experience and a history of working together on the cost-efficient management of large scale drilling programs in the Wattenberg Field. Our management and technical teams are also experienced in the disciplined allocation of capital focused on growing reserves and production and identifying, executing and integrating acquisitions. Members of our management team have significant experience in the Wattenberg Field and were key participants in the shift from vertical to horizontal drilling that recently occurred during their tenures at industry leaders, including Anadarko Petroleum, Noble Energy, PDC Energy and others. Our management and technical teams have collectively participated in the drilling of over 500 horizontal wells in the Niobrara and Codell formations in the field. Through the significant decrease and volatility in commodity prices in late 2014, we have demonstrated our ability to responsibly grow our production and proved reserves while maintaining a conservative balance sheet.

    Financial strength and flexibility.  We have a strong financial position and a prudent financial management strategy, which will allow us to actively allocate capital in order to grow our proved reserves and production, both organically and through strategic acquisitions. As of June 30, 2016, after giving effect to this offering, the Financing Transactions described below and the use of the proceeds therefrom, and the consummation of the Bayswater Acquisition, we would have had $             million of liquidity, with $             million of cash and cash equivalents and $             million of available borrowing capacity under our revolving credit facility. We believe this borrowing capacity, along with our cash flow from operations and existing cash on the balance sheet, will provide us with sufficient liquidity to execute on our 2016 and 2017 capital program. We have an established hedging program to protect our future cash flows and provide some certainty for the budgeting of our capital plan.

Recent Developments

2016 Equity Offering

        In April, June and July 2016, we closed a private offering of units to existing and new members that resulted in net proceeds of approximately $120 million (the "2016 Equity Offering"). The proceeds of the 2016 Equity Offering were used for general business purposes, including to repay amounts borrowed under our revolving credit facility.

2016 Notes Offering

        On July 18, 2016, we closed a private offering (the "2016 Notes Offering") of $550 million principal amount of 7.875% senior unsecured notes due 2021 (the "2021 Notes"), which resulted in net proceeds to us of approximately $537 million after deducting estimated expenses and the initial purchasers' discount. We used a portion of the net proceeds from the 2016 Notes Offering to repay all of the outstanding borrowings and related premium, fees and expenses under our second lien notes (the "Second Lien Notes") which were terminated concurrently with such repayment, and we applied the remaining proceeds to repay borrowings under our revolving credit facility and for general business purposes.

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Bayswater Acquisition

    Bayswater Assets

        On July 29, 2016, we entered into a definitive agreement with Bayswater Exploration & Production, LLC and certain of its affiliates to acquire additional oil and gas properties primarily located in the Wattenberg Field (the "Bayswater Assets") for total consideration of $420 million in cash, subject to customary purchase price adjustments (the "Bayswater Acquisition"). Upon completion of the Bayswater Acquisition, we will be acquiring producing and non-producing assets primarily located in the central and northwest portions of the Wattenberg Field from an existing working interest partner, primarily around our existing Greeley and Windsor areas.

        The Bayswater Assets consist of working interests in approximately 6,100 net acres and produced approximately 10,000 net BOE/d during the month ended July 31, 2016, of which approximately 73% was oil or NGLs. As of July 29, 2016, the Bayswater Assets included 36 gross (20 net) drilled but uncompleted wells, representing 53 gross (32 net) wells on a 1-mile equivalent basis. We expect the majority of these drilled but uncompleted wells to be brought online in the first half of 2017. In addition, the Bayswater Assets will result in an additional 1,119 gross drilling locations (or 119 net locations on a 1-mile equivalent basis). A majority of these locations are located on acreage in which we already own a majority working interest and operate, resulting in an additional 90 unique gross drilling locations.

        Based on a reserve report from Ryder Scott, there are approximately 25,992 MBoe of proved reserves associated with the Bayswater Assets as of June 30, 2016, of which 57% were undeveloped.

        We expect to close the Bayswater Acquisition contemporaneously with the closing of this offering. However, the completion of the Bayswater Acquisition is subject to a number of conditions, and we may not be able to consummate it if such conditions are not met. We expect to use a portion of the net proceeds of this offering to fund the purchase price of the Bayswater Acquisition, and intend to fund the balance of the purchase price through the issuance of up to $350 million in convertible preferred securities and borrowings under our revolving credit facility. See "Use of Proceeds."

    Option to Acquire Additional Assets from Bayswater

        If and when we consummate the Bayswater Acquisition, we are required to pay $10 million for an option to purchase additional assets from Bayswater (the "Additional Bayswater Assets") for an additional $190 million, for a total purchase price for the Additional Bayswater Assets of $200 million. The option may be exercised at any time until March 31, 2017. If we do not exercise our option to acquire the Additional Bayswater Assets, Bayswater will have the right until April 30, 2017 to elect to sell those assets to us for an additional $120 million, for a total purchase price for the Additional Bayswater Assets of $130 million. The Additional Bayswater Assets include working interests in approximately 9,100 net acres primarily in the Wattenberg Field.

Convertible Preferred Securities

        We have agreed to issue to affiliates of Apollo Capital Management ("Apollo") up to $125 million in convertible preferred securities (the "Series A Preferred Units") to fund a portion of the purchase price for the Bayswater Acquisition. The Series A Preferred Units are entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. We will use $        of the net proceeds of this offering to redeem the Series A Preferred Units in full, which amount includes a premium of $         million.

        In addition, we have agreed to issue to, among others, investment funds affiliated with OZ Management LP up to $225 million in convertible preferred securities (the "Series B Preferred Units") to fund a portion of the purchase price for the Bayswater Acquisition. The Series B Preferred Units are

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entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and we have the ability to pay up to 50% of the quarterly dividend in kind. The Series B Preferred Units will be converted in connection with the closing of this offering into shares of our Series A Convertible Preferred Stock (the "Series A Preferred Stock") that are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% (decreased proportionately to the extent such quarterly dividends are paid in cash). Beginning on or after the later of a) 90 days after the closing of this offering and b) the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering (the "Lock-Up Period End Date"), the Series A Preferred Stock will be convertible into shares of our common stock at the election of the holders of the Series A Preferred Stock (the "Series A Preferred Holders") at a conversion ratio per share of Series A Preferred Stock of            . Beginning on or after the Lock-Up Period End Date, we may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of            , but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, such premium to decrease with time. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at par. See "Description of Capital Stock—Preferred Stock—Series A Preferred Stock."

        We refer to the 2016 Notes Offering, the 2016 Equity Offering and the issuance of the Series A Preferred Units and Series B Preferred Units as the "Financing Transactions."

Amendment to Revolving Credit Facility

        On September 14, 2016, we entered into an amendment to our revolving credit facility that, among other things, increased the borrowing base to $350 million. The amendment also provides that upon consummation of the Bayswater Acquisition, the borrowing base will be increased to $450 million. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility."

Corporate Reorganization

        At or prior to the closing of this offering:

    XOG will convert from a Delaware limited liability company into a Delaware corporation;

    We will redeem the Series A Preferred Units in full with a portion of the net proceeds of this offering; and

    Holdings will merge with and into us, and we will be the surviving entity to such merger, with the equity holders in Holdings, other than the holders of the Series B Preferred Units (which will be converted in connection with the closing of this offering into shares of Series A Preferred Stock), but including the holders of restricted units and incentive units, receiving an aggregate number of shares of our common stock based on an implied valuation for us based on the initial public offering price set forth on the cover page of this prospectus and the current relative levels of ownership in Holdings, pursuant to the terms of the limited liability company agreement of Holdings, with the allocation of such shares among our existing equity holders to be later determined, pursuant to the terms of the limited liability company agreement of Holdings, by reference to an implied valuation for us based on the 10-day volume weighted average price of our common stock following the closing of this offering. See "Corporate Reorganization—Existing Owners Ownership."

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        As part of Holdings' merger with and into us, Holdings' other subsidiaries will become our direct or indirect subsidiaries.

        The following diagram indicates our simplified ownership structure immediately after this offering and the transactions described above (assuming that the underwriters' option to purchase additional shares is not exercised):

GRAPHIC


(1)
Includes funds managed by Yorktown Partners LLC, investment funds affiliated with OZ Management LP, BlackRock, Inc., Neuberger Berman Group LLC and management, among others.

(2)
Includes        shares of our common stock issuable upon conversion of all of the shares of our Series A Preferred Stock, assuming that all of the shares of Series A Preferred Stock were converted by the Series A Preferred Holders immediately after the consummation of this offering at a conversion ratio per share of Series A Preferred Stock of            .

        For more information, please see "Corporate Reorganization."

Risk Factors

        An investment in our common stock involves a number of risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors.

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Importantly, due to an abundance of supply in the global crude oil market and the domestic natural gas market, oil and natural gas prices have decreased significantly. While we continue to believe our inventory of drilling opportunities is repeatable and relatively low-risk, should oil and natural gas prices materially decrease even further, we may reevaluate our development drilling program. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. You should carefully consider, in addition to the other information contained in this prospectus, the risks described in "Risk Factors" before investing in our common stock. These risks could materially affect our business, financial condition and results of operations and cause the trading price of our common stock to decline. You could lose part or all of your investment. You should bear in mind, in reviewing this prospectus, that past experience is no indication of future performance. You should read "Cautionary Note Regarding Forward-Looking Statements" for a discussion of what types of statements are forward-looking statements, as well as the significance of such statements in the context of this prospectus.

Corporate Sponsorship and Structure Information

        We were formed as a Delaware limited liability company in November 2012 and will convert into a Delaware corporation in connection with this offering. Our principal executive offices are located at 370 17th Street, Suite 5300, Denver, CO 80202 and our telephone number at that address is (720) 557-8300. We have a valuable relationship with funds managed by Yorktown Partners LLC ("Yorktown"), a private investment manager founded in 1991 that invests exclusively in the energy industry with an emphasis on North American oil and gas production and midstream businesses. Upon completion of this offering, Yorktown will own an approximate        % equity interest in us. Please see "Security Ownership of Certain Beneficial Owners and Management."

        Yorktown has raised 11 private equity funds totaling over $8 billion. The investors of Yorktown's funds include university endowments, foundations, families, insurance companies and other institutional investors. Yorktown's investment professionals review a large number of potential energy investments and are actively involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which Yorktown's funds own interests. With their extensive investment experience in the oil and natural gas industry and their extensive network of industry relationships, we believe that Yorktown's funds are well positioned to assist us in identifying and evaluating acquisition opportunities and in making strategic decisions. Yorktown's funds are not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Investment funds managed by Yorktown manage numerous other portfolio companies that are engaged in the oil and natural gas industry and, as a result, Yorktown and its funds may present acquisition opportunities to other Yorktown portfolio companies that compete with us.

Emerging Growth Company Status

        We are an "emerging growth company" as defined in the Jumpstart Our Business Startups Act (the "JOBS Act"). For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:

    provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act");

    provide more than two years of audited financial statements and related management's discussion and analysis of financial condition and results of operations nor more than two years of selected financial data;

    comply with any new requirements adopted by the Public Company Accounting Oversight Board (the "PCAOB") requiring mandatory audit firm rotation or a supplement to the auditor's report

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      in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

    provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"); or

    obtain shareholder approval of any golden parachute payments not previously approved.

        We will cease to be an emerging growth company upon the earliest of:

    the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

    the date on which we become a "large accelerated filer" (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

    the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

    the last day of the fiscal year following the fifth anniversary of our initial public offering.

        In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the "Securities Act"), for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

Corporate Information

        Our principal executive offices are located at 370 17th Street, Suite 5300, Denver, Colorado 80202, and our telephone number at that address is (720) 557-8300. Our website is located at www.extractionog.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

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The Offering

Common stock offered by us

               shares (or             shares, if the underwriters exercise in full their option to purchase additional shares).

Common stock to be outstanding after the offering

 

             shares (or             shares, if the underwriters exercise in full their option to purchase additional shares).

Option to purchase additional shares

 

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional shares of our common stock to cover over-allotments, if any.

Use of proceeds

 

Assuming the midpoint of the price range set forth on the cover of this prospectus, we expect to receive approximately $            of net proceeds from this offering, or $             million if the underwriters exercise their option to purchase            additional shares in full, in each case, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

 

We intend to use (i) $         million of the net proceeds from this offering to redeem in full the Series A Preferred Units, (ii) $       million to pay a portion of the purchase price for the Bayswater Acquisition and (iii)  $        million to repay borrowings under our revolving credit facility. The remaining net proceeds will be used for general corporate purposes, including to fund our 2016 and 2017 capital expenditures.

 

Please see "Use of Proceeds."

Dividend policy

 

We do not anticipate paying any cash dividends on our common stock. In addition, our revolving credit facility and our 2021 Notes (collectively, our "debt arrangements") place certain restrictions on our ability to pay cash dividends.

Risk factors

 

You should carefully read and consider the information set forth under the heading "Risk Factors" and all other information set forth in this prospectus before deciding to invest in our common stock.

Directed share program

 

The underwriters have reserved for sale at the initial public offering price up to            % of the common stock being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing common stock in this offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they make will reduce the number of shares available to the general public. Please see "Underwriting."

Listing and trading symbol

 

We have applied to list our common stock on the NASDAQ Global Select Market (the "NASDAQ"), under the symbol "XOG."

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        The information above excludes            shares of common stock reserved for issuance under our long-term incentive plan (our "LTIP"), which we intend to adopt in connection with the completion of this offering, and            shares of common stock that would be issuable if the holders exercised their option to convert all of their shares of Series A Preferred Stock immediately after the consummation of this offering.

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        The summary historical financial data as of and for the six months ended June 30, 2016 and 2015 and the years ended December 31, 2015 and 2014 were derived from the unaudited and audited historical financial statements, respectively, of Holdings, our accounting predecessor (our "Predecessor"), included elsewhere in this prospectus. The summary unaudited pro forma statement of operations data of our Predecessor for the year ended December 31, 2015 have been prepared to give pro forma effect to (i) the Financing Transactions, (ii) the Bayswater Acquisition and the March 2015 Acquisition as described under "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Condition and Results of Operations—Oil and Gas Property Acquisitions," (iii) the transactions described under "—Corporate Reorganization" and (iv) this offering and the application of the net proceeds from this offering, as if each such transaction had been completed as of January 1, 2015. The summary unaudited pro forma statement of operations data of our Predecessor for the six months ended June 30, 2016 and the year ended December 31, 2015 and the pro forma balance sheet data of our Predecessor as of June 30, 2016 have been prepared to give pro forma effect to (i) the Financing Transactions, (ii) the Bayswater Acquisition, (iii) the transactions described under "—Corporate Reorganization" and (iv) this offering and the application of the net proceeds from this offering, as if each such transaction had been completed on January 1, 2015 for purposes of the statement of operations data and June 30, 2016 for purposes of the balance sheet data. The summary unaudited pro forma financial data of our Predecessor is presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had these transactions been consummated on the dates indicated and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future periods.

        You should read the following summary data in conjunction with "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical and pro forma financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements of our Predecessor include more detailed information regarding the basis of presentation for the following information. The historical financial results of our Predecessor are not necessarily indicative of results to be expected for any future periods.

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  Predecessor   Pro Forma  
 
  Six Months Ended
June 30,
  Year Ended
December 31,
  Six
Months
Ended
June 30,
2016
   
 
 
  Year Ended
December 31,
2015
 
 
  2016   2015   2015   2014  
 
  (unaudited)
   
   
  (unaudited)
 
 
  (in thousands, except per unit/common share data)
 

Statements of Operations Data:

                                     

Revenues:

                                     

Oil sales

  $ 84,135   $ 77,464   $ 157,024   $ 75,460   $            $    

Natural gas sales

    14,937     10,234     26,019     9,247              

NGL sales

    11,424     5,084     14,707     8,133              

Total revenues

    110,496     92,782     197,750     92,840              

Operating Expenses:

                                     

Lease operating expenses

    25,339     11,312     30,628     5,067              

Production taxes

    10,748     7,924     17,035     9,743              

Exploration expenses

    8,752     4,852     18,636     126              

Depletion, depreciation, amortization and accretion

    94,638     59,290     146,547     34,042              

Impairment of long lived assets

    22,884     9,525     15,778                  

Other operating expenses

    891     1,657     2,353                  

Acquisition transaction expenses

        6,000     6,000                  

General and administrative expenses

    15,114     16,870     37,149     19,598              

Total operating expenses

    178,366     117,430     274,126     68,576              

Operating Income (Loss)

    (67,870 )   (24,648 )   (76,376 )   24,264              

Other Income (Expense):

                                     

Commodity derivative gain (loss)

    (78,650 )   (8,407 )   79,932     48,008              

Interest expense

    (26,698 )   (23,668 )   (51,030 )   (22,454 )            

Other income

    84     13     210     24              

Total other income (expense)

    (105,264 )   (32,062 )   29,112     25,578              

Income (loss) before income taxes

    (173,134 )   (56,710 )   (47,264 )   49,842              

Income tax expense (benefit)

                             

Net Income (Loss)

  $ (173,134 ) $ (56,710 ) $ (47,264 ) $ 49,842   $     $    

Net Income (Loss) per Unit/Common Share:

                                     

Basic

  $ (0.53 ) $ (0.22 ) $ (0.17 ) $ 0.28   $     $    

Diluted

  $ (0.53 ) $ (0.22 ) $ (0.17 ) $ 0.26   $     $    

Weighted Average Units/Common Shares Outstanding:

                                     

Basic

    323,967     260,209     277,322     180,429              

Diluted

    323,967     260,209     277,322     189,938              

Statements of Cash Flows Data:

                                     

Cash provided by (used in):

                                     

Operating activities

  $ 41,178   $ 61,958   $ 166,683   $ 77,390              

Investing activities

    (160,080 )   (320,036 )   (520,006 )   (970,640 )            

Financing activities

    125,466     200,780     371,404     972,090              

Balance Sheets Data (at period end):

                                     

Cash and cash equivalents

  $ 103,670         $ 97,106   $ 79,025   $          

Total assets

    1,593,786           1,634,140     1,201,069              

Total liabilities

    895,392           879,908     655,881              

Total member's equity

    698,394           754,232     545,188              

Other Financial Data:

                                     

Adjusted EBITDAX(1)

  $ 89,807   $ 87,025   $ 176,120   $ 66,892   $          

(1)
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 "—Non-GAAP Financial Measures."

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Non-GAAP Financial Measures

Adjusted EBITDAX

        Adjusted EBITDAX is not a measure of net income (loss) as determined by United States generally accepted accounting principles ("GAAP"). Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our Predecessor's financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depreciation, depletion, amortization and accretion ("DD&A"), impairment of long lived assets, exploration expenses, rig termination fees, acquisition transaction expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid for derivatives that settled during the period, unit-based compensation expense, amortization of debt discount and debt issuance costs, interest expense, income taxes and non-recurring charges.

        Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance.

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        The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated.

 
  Predecessor   Pro Forma  
 
  Six Months
Ended
June 30,
  Year Ended
December 31,
  Six
Months
Ended
June 30,
2016
   
 
 
  Year Ended
December 31,
2015
 
 
  2016   2015   2015   2014  
 
  (unaudited)
   
   
  (unaudited)
 
 
  (in thousands)
 

Adjusted EBITDAX reconciliation to net income (loss):

                                     

Net income (loss)

  $ (173,134 )   (56,710 ) $ (47,264 ) $ 49,842   $     $    

Add back (subtract):

                                     

Depreciation, depletion, amortization and accretion

    94,638     59,290     146,547     34,042              

Impairment of long lived assets

    22,884     9,525     15,778                  

Exploration expenses

    8,752     4,852     18,636     126              

Rig termination fee

    891     1,657     1,657                  

Acquisition transaction expenses

        6,000     6,000                  

Commodity derivative loss (gain)           

    78,650     8,407     (79,932 )   (48,008 )            

Settlements on commodity derivatives

    33,160     27,374     59,785     3,974              

Premiums paid for derivatives that settled during the period

    (5,338 )   (112 )   (2,087 )                

Unit-based compensation expense

    2,606     3,074     5,970     4,462              

Amortization of debt discount and debt issuance costs

    2,424     1,956     5,604     1,985              

Interest expense

    24,274     21,712     45,426     20,469              

Adjusted EBITDAX

  $ 89,807   $ 87,025   $ 176,120   $ 66,892   $     $    

PV-10

        PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

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        The following table presents a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure as of the dates indicated.

 
  As of
June 30,
  As of
December 31,
 
 
  2016   2015  
 
  (in thousands)
 

PV-10 of proved reserves

  $ 686,001   $ 835,883  

Present value of future income tax discounted at 10%

         

Standardized Measure(1)

  $ 686,001   $ 835,883  

(1)
If we had been subject to entity-level U.S. federal income taxes, the pro forma, undiscounted, income tax expense at June 30, 2016 would have been $             million ($             million on a discounted basis) and the Standardized Measure would have been $             million. If we had been subject to entity-level U.S. federal income taxes, the pro forma, undiscounted, income tax expense at December 31, 2015 would have been $             million ($             million on a discounted basis) and the Standardized Measure would have been $             million.

Summary Reserve Data and Operating Data

        The following tables present summary data with respect to our estimated net proved oil, natural gas and NGL reserves and operating data as of the dates presented.

        The reserve estimates presented in the table below are based on reports prepared by Ryder Scott, which reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting. The following tables also contain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties.

        In evaluating the material presented below, please read "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business—Oil and Natural Gas Data—Proved Reserves," "Business—Oil, Natural Gas and NGL Production Prices and Production Costs—Production and Price History" and our financial statements and notes thereto. Our historical results of operations are not necessarily indicative of results to be expected for any future periods.

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  As of
June 30,
2016(1)
  As of
December 31,
2015(1)
 

Proved Reserves:

             

Oil (MBbls)

    79,111     71,500  

Natural gas (MMcf)

    365,702     292,584  

NGL (MBbls)

    47,227     38,383  

Total Proved Reserves (MBoe)(2)

    187,288     158,647  

Total Proved PV-10 (Millions)(3)

  $ 686.0   $ 835.9  

Proved Developed Reserves:

             

Oil (MBbls)

    17,391     14,249  

Natural gas (MMcf)

    87,411     53,011  

NGL (MBbls)

    11,340     7,058  

Proved Developed Reserves (MBoe)(2)

    43,299     30,142  

Proved Developed PV-10 (Millions)(3)

  $ 398.7   $ 368.1  

Proved Developed PV-10 as a Percentage of Total Proved PV-10

    58.1 %   44.0 %

Proved Undeveloped Reserves:

             

Oil (MBbls)

    61,720     57,252  

Natural gas (MMcf)

    278,291     239,572  

NGL (MBbls)

    35,887     31,325  

Proved Undeveloped Reserves (MBoe)(2)

    143,989     128,505  

Proved Undeveloped PV-10 (Millions)(3)

  $ 287.3   $ 467.7  

Proved Undeveloped PV-10 as a Percentage of Total Proved PV-10

    41.9 %   56.0 %

(1)
Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $43.12/Bbl for oil and $2.10/MMBtu for natural gas at June 30, 2016 and $50.28/Bbl for oil and $2.58/MMBtu for natural gas at December 31, 2015. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For more information regarding commodity price risk, please see "Risk Factors—Risks Related to the Oil, Natural Gas and NGL Industry and Our Business—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."

(2)
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.

(3)
PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure, please see "—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures."

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  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  2016   2015   2015   2014  
 
  (unaudited)
(in thousands)

 

Summary Historical Operating Data:

                         

Production and Operating Data:

                         

Net production volumes:

                         

Oil (MBbls)

    2,518.0     1,777.5     3,945.6     1,022.2  

Natural gas (MMcf)

    8,060.7     4,471.9     10,823.0     2,664.1  

NGL (MBbls)

    904.6     488.3     1,334.6     325.3  

Total (MBoe)(1)

    4,766.1     3,011.1     7,084.0     1,791.5  

Average net production (BOE/d)(1)

    26,187     16,636     19,408     4,908  

Average sales prices(2):

                         

Oil sales (per Bbl)

  $ 33.41   $ 43.58   $ 39.80   $ 73.82  

Oil sales with derivative settlements (per Bbl)

  $ 41.51   $ 58.06   $ 53.29   $ 77.66  

Natural gas (per Mcf)

  $ 1.85   $ 2.29   $ 2.40   $ 3.47  

Natural gas sales with derivative settlements (per Mcf)

  $ 2.77   $ 2.63   $ 2.82   $ 3.49  

NGL (per Bbl)

  $ 12.63   $ 10.41   $ 11.02   $ 25.00  

Average price per BOE

  $ 23.18   $ 30.81   $ 27.92   $ 51.82  

Average price per BOE with derivative settlements

  $ 29.02   $ 39.87   $ 36.06   $ 54.04  

Average unit costs per BOE:

                         

Lease operating expenses

  $ 5.32   $ 3.76   $ 4.32   $ 2.83  

Production taxes

  $ 2.26   $ 2.63   $ 2.40   $ 5.44  

Exploration expenses

  $ 1.84   $ 1.61   $ 2.63   $ 0.07  

Depreciation, depletion, amortization and accretion

  $ 19.86   $ 19.69   $ 20.69   $ 19.00  

Impairment of long lived assets

  $ 4.80   $ 3.16   $ 2.23   $  

Other operating expenses

  $ 0.19   $ 0.55   $ 0.33   $  

Acquisition transaction expenses

  $   $ 1.99   $ 0.85   $  

General and administrative expenses

  $ 3.17   $ 5.60   $ 5.24   $ 10.94  

Unit-based compensation

  $ 0.55   $ 1.02   $ 0.84   $ 2.49  

Total operating expenses per BOE

  $ 37.42   $ 39.00   $ 38.69   $ 38.28  

(1)
One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)
Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions and premiums paid or received on options, if any, that settled during the period.

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RISK FACTORS

        An investment in our common stock involves a number of risks. You should carefully consider each of the following risk factors and all of the other information set forth in this prospectus before making an investment decision. 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. If any of these risks occur, the trading price of our common stock could decline and you may lose all or part of your investment.

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. Additionally, the value of our proved reserves calculated using SEC pricing may be higher than the fair market value of our proved reserves calculated using current market prices.

        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 August 15, 2016, 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:

        Since November 2014, prices for U.S. oil have weakened in response to continued high levels of production by the Organization of the Petroleum Exporting Companies ("OPEC"), a buildup in

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inventories and lower global demand. Additionally, OPEC has announced that it will continue to maintain current oil production 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 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, following this offering, we will not be 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

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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 the remainder of 2016 capital expenditures and our 2017 capital expenditures with the proceeds of this offering, cash generated by operations, borrowings under our revolving credit facility and possibly through asset sales or additional capital market 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."

Our cash flow from operations and access to capital are subject to a number of variables, including:

        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

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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:

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, 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

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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.

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:

        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. As of June 30, 2016, our borrowing base was $285.0 million. On September 14, 2016, we entered into an amendment to our revolving credit facility that, among other things, increased the borrowing base to $350 million. The amendment also provides that upon consummation of the Bayswater Acquisition, the borrowing base will be increased to $450 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

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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 80% 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 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 2021 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 continue to 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 operations to meet debt service and other obligations. Our revolving credit facility and the indenture governing our 2021 Notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

        In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Our derivative activities could result in financial losses or could reduce our earnings.

        To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGL, we enter into commodity derivative contracts for a significant portion of our production, primarily consisting of swaps, put options and call options. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—Sources of Our Revenues." Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

        Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

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        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. 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.

        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 June 30, 2016 were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $43.12/Bbl for oil and $2.10/MMBtu for natural gas, which for certain periods of 2016 were substantially above the available spot oil and natural gas

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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 Wattenberg Field. 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 Wattenberg Field 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 Wattenberg Field, 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.

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. As of July 31, 2016, we have drilled 259 gross one-mile equivalent horizontal wells and have completed 230 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 57% of our net leasehold acreage is undeveloped, without giving effect to the Bayswater Acquisition, 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 June 30, 2016, approximately 57% of our net leasehold acreage was undeveloped, without giving effect to the Bayswater Acquisition, 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

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reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Substantially all of our producing properties are located in the Wattenberg Field within 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 Wattenberg Field of Colorado, an area in which industry activity has increased rapidly. At June 30, 2016, 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, delays or interruptions of production from wells in this area caused by governmental regulation, 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.

        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.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

        The marketing of oil, natural gas and NGL production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there is insufficient capacity available on these systems, or if these systems are unavailable to us, the price offered for our production could be significantly depressed, or we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while we construct our own facility. We also rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transport and sell our oil, natural gas and NGL 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 transportation, storage or processing facilities to us, especially in areas of planned expansion where such facilities do not currently exist.

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 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

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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. 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 Wattenberg Field 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. 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 Wattenberg area 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 Wattenberg Field, 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.

We are required to pay fees to our service providers based on minimum volumes under a long-term contract 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. We are currently party to a firm transportation agreement that commences in November 2016 and has a ten-year term, which obligates us to meet delivery commitments of 40,000 Bbl/d in year one, 52,000 Bbl/d in year two, and 58,000 Bbl/d in years three through ten. We are obligated to pay fees on minimum volumes to this service provider regardless of actual volume throughput. Lower commodity prices may lead to reductions in our drilling program, which may result in insufficient production to utilize our full firm transportation and processing capacity. As of June 30, 2016, the aggregate amount of estimated payments over the ten-year term of this agreement was $887.3 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.

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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.

Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Colorado forced pooling system, could have a material adverse effect on our business.

        Our business is subject to various forms of government regulation, including 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 (the "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.

SEC rules could limit our ability to book additional proved undeveloped reserves ("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.

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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 June 30, 2016, before giving effect to the Bayswater Acquisition, approximately 80% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 129,234 MBoe of estimated proved undeveloped reserves will require an estimated $1.1 billion of development capital over the next five years. 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

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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, 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 2016 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 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.

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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. Three purchasers accounted for more than 10% of our revenues in the year ended December 31, 2014, and four purchasers accounted for more than 10% of our revenues during the year ended December 31, 2015. 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.

A substantial portion of our reserves is 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 Wattenberg Field, 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.

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, ruptures or discharges of toxic gases.

        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:

        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 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 insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.

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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:

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:

        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

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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.

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 federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

        Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and 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 U.S. Environmental Protection Agency ("EPA") and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. 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 or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.

        There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations 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, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several

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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. We may not be able to recover some or any of these costs from insurance. 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. For example, on October 1, 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard ("NAAQS") for ground-level ozone from the current standard of 75 parts per billion ("ppb") for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. States are expected to implement more stringent requirements as a result of this new final rule, which could apply to our operations. Compliance with this more stringent standard and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant. See "Business—Regulation of Environmental and Occupational Safety and Health Matters" for a further description of the 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 Energy Policy Act of 2005 ("EPAct 2005"), the Federal Energy Regulatory Commission (the "FERC") has civil penalty authority under the Natural Gas Act of 1938 ("NGA") to impose penalties for current violations of up to $1 million/d for each violation. The 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 Federal Trade Commission ("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 million/d, and the Commodity Futures Trading Commission ("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

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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. 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, 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 laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGL that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

        In response to findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration ("PSD") construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations.

        While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France ("Paris Agreement") that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although it is not possible at this time to predict how new laws or regulations in the United States or any legal requirements imposed following the United States' agreeing to the Paris Agreement that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs 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. Finally, it should be noted that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have

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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.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals 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. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has published final Clean Air Act ("CAA") regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting; published on June 28, 2016 an effluent limited guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; 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 federal Bureau of Land Management ("BLM") published a final rule in March 2015, establishing stringent standards relating to 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; however, on June 21, 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked congressional authority to promulgate the rule. 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.

        Several governmental reviews are underway that focus on environmental aspects of hydraulic fracturing activities. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA's Science Advisory Board provided its comments on the draft study, indicating its concern that EPA's conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing.

        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,

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disclosure or well-construction requirements on hydraulic fracturing operations. In addition to state laws, local land use restrictions may restrict drilling in general and/or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective cities' limits in 2012-2013 but, since that time, in response to lawsuits brought by an industry trade group, the Colorado Oil and Gas Association, local district courts struck down the ordinances for certain of those Colorado cities in 2014, primarily on the basis that state law preempts local bans on hydraulic fracturing. The cities of Fort Collins and Longmont, among those cities whose ordinances were struck down in 2014, appealed their decisions to the Colorado Supreme Court, but on May 2, 2016, the state supreme court upheld the lower court rulings in those two cases, holding that a five-year moratorium on hydraulic fracturing adopted by Fort Collins and a ban on fracturing adopted by Longmont were pre-empted by state law and, therefore, unenforceable. Another suit brought by the Colorado trade group against one other city, Broomfield, who had adopted a moratorium on fracturing, has been on hold pending the outcome of the Colorado Supreme Court ruling in the Fort Collins and Longmont cases. Notwithstanding attempts at the local level to prohibit hydraulic fracturing, there exists the opportunity for cities to adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities.

        In addition, 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 aimed at significantly limiting or preventing oil and natural gas development. In response to such initiatives, the Governor of Colorado created a Task Force on State and Local Regulation of Oil and Gas Operations ("Task Force") in September 2014 to make recommendations to the state legislature regarding the responsible development of Colorado's oil and gas resources. In February 2015, the Task Force made nine non-binding recommendations to the Governor that will require legislative or regulatory action to be implemented. Among other things, the recommendations received from the Task Force would require pursuit of state rulemaking targeting increased collaborative efforts between oil and natural gas operators and local governments regarding large-scale oil and natural gas facilities in defined "urban mitigation areas"; operator registration with local government designees and possible advance notice of future oil and natural gas drilling and production facility locations that would be integrated into the local comprehensive planning process; development of enhanced local governmental designee roles and functions to more effectively serve as liaisons between industry, residents and local officials; increased staffing levels at the state environmental and oil and natural gas agencies; establishing an oil and natural gas information clearinghouse; establishing a working group to investigate ways to reduce oil and natural gas vehicular traffic on roadways; pursuit of state air emissions rules including methane emissions capture rules; and establishing a compliance assistance program to assist oil and natural gas operators in complying with applicable rules. On January 25, 2016, two of the recommendations, regarding the collaboration of local governments, the COGCC and oil and natural gas operators in the siting of large scale oil and natural gas facilities in defined urban mitigation areas and long-term planning for including future oil and natural gas development in local comprehensive planning processes, were approved by the COGCC as new rules. It is possible that the COGCC could elect to pursue one or more of the remaining Task Force recommendations or the Colorado state legislature could seek to adopt new policies or legislation relating to oil and natural gas operations, including measures that would give local governments in Colorado greater authority to limit hydraulic fracturing and other oil and natural gas operations or require greater distances between well sites and occupied structures. In addition, it is possible that notwithstanding the recommendations made by the Task Force, certain interest groups in Colorado or even members of the Colorado state legislature may seek to pursue ballot initiatives in the future, perhaps as early as November 2016 and/or legislation that may or may not coincide with the Task Force's recommendations, including, among other things, pursuit of initiatives or legislation for changes in state law that would allow local governments to ban hydraulic fracturing in Colorado.

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        In the event that ballot initiatives or local or state restrictions or prohibitions are adopted in areas where we conduct operations, including the Wattenberg Field 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 Occupational Safety and Health Matters" for a further description of the laws and regulations that affect us.

Ballot initiatives that would impose more stringent restrictions for new oil and natural gas wells and related facilities may serve to limit future oil and natural gas exploration and production activities and could have a material adverse effect on our results of operations, financial position and business.

        Proponents of legal requirements imposing more stringent restrictions on oil and gas exploration and production activities in Colorado have sought to include on the November 2016 ballot certain 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 more difficult in the future. Among the ballot initiatives pursued in 2016 are ballot initiative Number 75 ("Initiative 75"), which seeks to authorize local governmental control over oil and natural gas development in Colorado that could result in the imposition of more stringent requirements than currently implemented under state law, and ballot initiative Number 78 ("Initiative 78"), which proposes a much more stringent 2,500-foot mandatory setback between an oil and natural gas development facility (including oil and natural gas wells, production and processing equipment and pits) and specified occupied structures and areas of special concern. Changes sought under these ballot initiatives would be applied to new oil and gas development facilities in Colorado. Proponents of these measures collected signatures for placing Initiatives 75 and 78 on the November 2016 ballot and submitted those signatures to the Colorado Secretary of State by the August 8, 2016 deadline. However, on August 29, 2016, the Secretary of State announced that the proponents had failed to gather enough valid signatures to put Initiatives 75 and 78 on the November 2016 ballot. Supporters of Initiatives 75 and 78 have 30 days to appeal the decision in state court. Notwithstanding the Colorado Secretary of State's announcement on August 29, 2016, in the event that ballot initiatives or local or state restrictions or prohibitions are adopted in the future in areas where we conduct operations 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.

Recently announced rules regulating methane emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs or delays in production of oil and natural gas, which could have a material adverse effect on our business.

        On June 3, 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, as part of an overall effort to reduce methane emissions in the oil and natural gas source category by up to 45% from 2012 levels by the year 2025. The EPA's final rules include New Source Performance Standards ("NSPS") to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on volatile organic compound ("VOC") emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and

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VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. The new methane and VOC standards require the implementation of the best system of emission reduction to achieve these emission reductions, mirroring the existing VOC standards under Subpart OOOO. These rules could require a number of modifications to our operations, including the installation of new equipment to control methane and VOC emissions from certain hydraulic fracturing wells, which could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact or delay oil and natural gas production activities, which could have a material adverse effect on our business.

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

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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:

        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.

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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 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. 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.

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

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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.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

        The Fiscal Year 2017 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress in prior years that would implement many of these proposals. Such changes 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; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of this legislation or any other similar change in U.S. federal income tax law, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.

        Moreover, the President has proposed to impose an "oil fee" of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

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 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, 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 or to render data or systems unusable; threats to

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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 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.

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 the Offering and 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.

        As a public company, we will need to comply with new 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 are 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 will need to:

        Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act for our fiscal year ending December 31, 2017, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an "emerging growth company" within the meaning of Section 2(a)(19)

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of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2022. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.

        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. 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. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

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.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

        Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price was determined by negotiations between us and representatives of the underwriters, based on numerous factors which we discuss in

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"Underwriting," and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

        The following factors could affect our stock price:

        The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company's securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management's attention and resources and harm our business, operating results and financial condition.

Yorktown's funds will collectively hold a substantial portion of the voting power of our common stock.

        Immediately following the completion of this offering, Yorktown's funds will collectively hold approximately      % 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

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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:

Investors in this offering will experience immediate and substantial dilution of $             per share.

        Based on an assumed initial public offering price of $            per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $            per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of June 30, 2016 on a pro forma basis would be $            per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. Please see "Dilution."

We do not intend to pay dividends on our common stock, and our debt arrangements place certain restrictions on our ability to do so. Consequently, it is possible that your only opportunity to achieve a return on your investment 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 will restrict our ability to pay cash dividends. Consequently, it is possible that your only opportunity to achieve a return on your investment in us will be if you sell your

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common stock at a price greater than you 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 you pay in this offering.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

        We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have            outstanding shares of common stock. This number includes            shares that we may sell in this offering if the underwriters' option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, assuming no exercise of the underwriters' option to purchase additional shares, Yorktown's funds will collectively own            shares of our common stock, or approximately       % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in "Underwriting," but may be sold into the market in the future. Yorktown's funds and certain of our other existing stockholders, including the Series A Preferred Holders, will be party to registration rights agreements with us which will require us to effect the registration of their shares (and shares of certain of their affiliates) in certain circumstances no earlier than the Lock-Up Period End Date. Please see "Shares Eligible for Future Sale" and "Certain Relationships and Related Party Transactions—Agreements Governing the Transaction—Existing Owners Registration Rights Agreement" and "Certain Relationships and Related Party Transactions—Agreements Governing the Transaction—Series A Preferred Registration Rights Agreement."

        In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of            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.

        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.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

        We and all of our directors and executive officers and certain of our stockholders have entered into lock-up agreements with respect to their common stock, pursuant to which we and they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. Credit Suisse Securities (USA) LLC, Barclays Capital Inc. and Goldman, Sachs & Co., at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

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For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

        We are classified as an "emerging growth company" under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

        To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

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.

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Our certificate of incorporation will designate 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 will provide 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 (the "DGCL"), 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.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        The information discussed in this prospectus includes "forward-looking statements." All statements, other than statements of historical facts, included 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. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

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        Reserve engineering is a process of estimating underground accumulations of oil and natural gas 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 and natural gas 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 prospectus. 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.

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USE OF PROCEEDS

        Assuming the midpoint of the price range set forth on the cover of the prospectus, we expect to receive approximately $             million of net proceeds from this offering, or $             million if the underwriters exercise their option to purchase                                    additional shares in full, in each case, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

        We intend to use the net proceeds from this offering to (i) redeem in full the Series A Preferred Units, (ii) pay a portion of the purchase price for the Bayswater Acquisition and (iii) repay borrowings under our revolving credit facility. The remaining net proceeds will be used for general corporate purposes, including to fund our 2016 and 2017 capital expenditures. The following table illustrates our anticipated use of the net proceeds from this offering:

Sources of Funds
   
 
Use of Funds
   
 
(In millions)
 

Net proceeds from this offering

  $               

Redemption of Series A Preferred Units

  $               

       

Bayswater Acquisition

       

       

Repayment of our revolving credit facility

                  

       

General corporate purposes, including to fund our 2016 and 2017 capital expenditures

                  

Total sources of funds

  $               

Total uses of funds

  $               

        Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject to the terms of the facility, and we intend to do so in the future to fund our capital program. The revolving credit facility will mature November 29, 2018. As of June 30, 2016, we had $235.0 million in borrowings outstanding under our revolving credit facility, which bore an interest rate of 3.0%. Borrowings under the revolving credit facility were incurred to fund the development and exploration of our oil and gas properties.

        A $1.00 increase or decrease in the assumed initial public offering price of $            per share (the midpoint of the price range set forth on the cover of this prospectus) would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $             million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus remains the same. If the proceeds increase for any reason, we would use the additional net proceeds for general corporate purposes, including to fund a portion of our development program. If the proceeds decrease for any reason, then we would first reduce by a corresponding amount the net proceeds directed for general corporate purposes and then reduce the amount of net proceeds directed to repay borrowings under our revolving credit facility.

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DIVIDEND POLICY

        We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. Additionally, our debt arrangements will place certain restrictions on our ability to pay cash dividends.

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CAPITALIZATION

        The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2016:

        The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our financial statements and related notes appearing elsewhere in this prospectus.

 
  As of June 30, 2016  
 
  Actual   As Adjusted   As Further
Adjusted(5)
 
 
  (in thousands)
 

Cash and cash equivalents

  $ 103,670   $     $    

Debt obligations:

                   

Revolving credit facility(1)(2)

  $ 235,000   $     $    

Second lien notes(1)(3)

    414,895          

7.875% Senior Notes due 2021(4)

        537,533     537,533  

Series A Preferred Units

               

Total debt obligations

    649,895              

Series A Preferred Stock

   
   
       

Equity

   
 
   
 
   
 
 

Member's equity

    868,762              

Series B Preferred Units

               

Common stock—$0.01 par value; no shares authorized, issued or outstanding (actual and as adjusted) ;            shares authorized and            shares issued and outstanding (as further adjusted)

               

Additional paid-in capital

               

Accumulated deficit

    (170,368 )            

Total Equity

    698,394              

Total capitalization

  $ 1,348,289   $     $    

(1)
Our revolving credit facility and our second lien notes and the related interest expense, debt issuance costs, debt discount costs and the amortization expense on the debt issuance and debt discount costs are reflected in our financial statements. Please refer to Note 4—Long-Term Debt to our unaudited financial statements for the six months ended June 30, 2016 for further information.

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(2)
As of September 14, 2016, the borrowing base under our revolving credit facility was $350.0 million, the outstanding balance totaled $154.0 million and the outstanding letters of credit totaled $0.6 million.

(3)
Net of unamortized debt discount and debt issuance costs.

(4)
$550.0 million principal amount, net of approximately $12.5 million of estimated expenses associated with the debt issuance costs incurred as a result of the 2016 Notes Offering.

(5)
A $1.00 increase or decrease in the assumed public offering price of $            per share (the midpoint of the price range set forth on the cover of the prospectus) would increase or decrease, respectively, additional paid-in capital, total stockholders' equity and total capitalization by approximately $             million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase or decrease of one million shares we are offering would increase or decrease, respectively, additional paid-in capital, total stockholders' equity and total capitalization by approximately $             million, after deducting the estimated underwriting discounts and estimated offering expenses payable by us, assuming the assumed public offering price stays the same.

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DILUTION

        Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of June 30, 2016, after giving effect to the transactions described under "Prospectus Summary—Corporate Reorganization," was $             million, or $            per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering after giving effect to our corporate reorganization. Assuming an initial public offering price of $            per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of June 30, 2016 would have been approximately $             million, or $            per share. This represents an immediate increase in the net tangible book value of $            per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $            per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

Initial public offering price per share

        $    

Pro forma net tangible book value per share as of June 30, 2016

  $          

Increase per share attributable to new investors in this offering

             

As adjusted pro forma net tangible book value per share after giving further effect to this offering

             

Dilution in pro forma net tangible book value per share to new investors in this offering

        $    

        A $1.00 increase (decrease) in the assumed initial public offering price of $            per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $            and increase (decrease) the dilution to new investors in this offering by $            per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. The following table summarizes, on an adjusted pro forma basis as of June 30, 2016, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at our initial public offering price of $            per share, calculated before deduction of estimated underwriting discounts and commissions:

 
   
   
  Total Consideration    
 
 
  Shares Acquired    
 
 
  Amount
(in thousands)
   
  Average
Price Per
Share
 
 
  Number   Percent   Percent  

Existing owners

            % $                % $           

New investors in this offering

                               

Total

            % $                % $           

        The above tables and discussion are based on the number of shares of our common stock to be outstanding as of the closing of this offering. The table does not reflect                         shares of common stock reserved for issuance under our LTIP, which we plan to adopt in connection with this offering. If the underwriters' option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to                        , or approximately        % of the total number of shares of common stock.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

        The selected historical financial data as of and for the six months ended June 30, 2016 and 2015 and the years ended December 31, 2015 and 2014 were derived from the unaudited and audited historical financial statements, respectively, of our Predecessor, included elsewhere in this prospectus. The selected unaudited pro forma statement of operations data of our Predecessor for the year ended December 31, 2015 have been prepared to give pro forma effect to (i) the Financing Transactions, (ii) the Bayswater Acquisition and the March 2015 Acquisition as described under "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of Our Financial Condition and Results of Operations—Oil and Gas Property Acquisitions," (iii) the transactions described under "—Corporate Reorganization" and (iv) this offering and the application of the net proceeds from this offering, as if each such transaction had been completed as of January 1, 2015. The selected unaudited pro forma statement of operations data of our Predecessor for the six months ended June 30, 2016 and the year ended December 31, 2015 and the pro forma balance sheet data of our Predecessor as of June 30, 2016 have been prepared to give pro forma effect to (i) the Financing Transactions, (ii) the Bayswater Acquisition, (iii) the transactions described under "—Corporate Reorganization" and (iv) this offering and the application of the net proceeds from this offering, as if each such transaction had been completed on January 1, 2015 for purposes of the statement of operations data and June 30, 2016 for purposes of the balance sheet data. The selected unaudited pro forma financial data of our Predecessor is presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had these transactions been consummated on the dates indicated and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future periods.

        You should read the following selected data in conjunction with "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical and pro forma financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements of our Predecessor include more detailed information regarding the basis of presentation for the following information. The historical financial results of our Predecessor are not necessarily indicative of results to be expected for any future periods.

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  Predecessor    
   
 
 
  Pro Forma  
 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  Six Months
Ended
June 30,
2016
   
 
 
  Year Ended
December 31,
2015
 
 
  2016   2015   2015   2014  
 
  (unaudited)
   
   
  (unaudited)
 
 
  (in thousands, except per unit/common share data)
 

Statements of Operations Data:

                                     

Revenues:

                                     

Oil sales

  $ 84,135   $ 77,464   $ 157,024   $ 75,460   $     $    

Natural gas sales

    14,937     10,234     26,019     9,247              

NGL sales

    11,424     5,084     14,707     8,133              

Total revenues

    110,496     92,782     197,750     92,840              

Operating Expenses:

                                     

Lease operating expenses

    25,339     11,312     30,628     5,067              

Production taxes

    10,748     7,924     17,035     9,743              

Exploration expenses

    8,752     4,852     18,636     126              

Depletion, depreciation, amortization and accretion

    94,638     59,290     146,547     34,042              

Impairment of long lived assets

    22,884     9,525     15,778                  

Other operating expenses

    891     1,657     2,353                  

Acquisition transaction expenses

        6,000     6,000                  

General and administrative expenses

    15,114     16,870     37,149     19,598              

Total operating expenses

    178,366     117,430     274,126     68,576              

Operating Income (Loss)

    (67,870 )   (24,648 )   (76,376 )   24,264              

Other Income (Expense):

                                     

Commodity derivative gain (loss)

    (78,650 )   (8,407 )   79,932     48,008              

Interest expense

    (26,698 )   (23,668 )   (51,030 )   (22,454 )            

Other income

    84     13     210     24              

Total other income (expense)

    (105,264 )   (32,062 )   29,112     25,578              

Income (loss) before income taxes

    (173,134 )   (56,710 )   (47,264 )   49,842              

Income tax expense (benefit)

                             

Net Income (Loss)

  $ (173,134 ) $ (56,710 ) $ (47,264 ) $ 49,842   $     $    

Net Income (Loss) per Unit/Common Share:

                                     

Basic

  $ (0.53 ) $ (0.22 ) $ (0.17 ) $ 0.28   $     $    

Diluted

  $ (0.53 ) $ (0.22 ) $ (0.17 ) $ 0.26   $     $    

Weighted Average Units/Common Shares Outstanding:

                                     

Basic

    323,967     260,209     277,322     180,429              

Diluted

    323,967     260,209     277,322     189,938              

Statements of Cash Flows Data:

                                     

Cash provided by (used in):

                                     

Operating activities

  $ 41,178   $ 61,958   $ 166,683   $ 77,390              

Investing activities

    (160,080 )   (320,036 )   (520,006 )   (970,640 )            

Financing activities

    125,466     200,780     371,404     972,090              

Balance Sheets Data (at period end):

                                     

Cash and cash equivalents

  $ 103,670         $ 97,106   $ 79,025   $          

Total assets

    1,593,786           1,634,140     1,201,069              

Total liabilities

    895,392           879,908     655,881              

Total member's equity

    698,394           754,232     545,188              

Other Financial Data:

                                     

Adjusted EBITDAX(1)

  $ 89,807   $ 87,025   $ 176,120   $ 66,892   $          

(1)
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 "Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures."

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

        The following discussion and analysis should be read in conjunction with the "Summary Historical and Pro Forma Financial and Operating Data" and the accompanying financial statements and related notes included elsewhere in this prospectus. 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 prospectus, 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 crude oil, natural gas and NGL reserves in the Rocky Mountain region of the United States, primarily in the Wattenberg Field of 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 the Wattenberg Field. 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.

        Extraction Oil & Gas, LLC is a Delaware limited liability company that was formed on November 14, 2012, by PRE Resources, LLC ("PRL"). On May 29, 2014, PRL formed Holdings as a holding company with no independent operations. Concurrent with the formation of Holdings, PRL contributed all of its membership interests in Extraction to Holdings and distributed all of its interests in Holdings to its members in a pro rata distribution. As a result of these transactions, Extraction is now a wholly owned subsidiary of Holdings. In connection with this offering, Holdings will merge with and into Extraction and Extraction will be converted into a Delaware corporation. For more information, please see "Prospectus Summary—Corporate Reorganization."

Our Properties

        We have assembled, as of June 30, 2016, approximately 100,000 net acres of large, contiguous acreage blocks in some of the most productive areas of the Wattenberg Field as indicated by the results of our horizontal drilling program and the results of offset operators. Additionally, we hold approximately 124,000 net acres in the DJ Basin, which we refer to as our "Northern Extension Area," that we believe is prospective for many of the same formations as our properties in the Wattenberg Field. As of December 31, 2015, there were de minimis proved reserves associated with this acreage. We operated 95% of our horizontal production for the six months ended June 30, 2016 and as of December 31, 2015, our total estimated proved reserves were approximately 158.6 MMBoe, of which approximately 19% were classified as proved developed reserves. For more information about our properties, please read "Business—Our Properties."

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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 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 six months ended June 30, 2016, our revenues were derived 76% from oil sales, 14% from natural gas sales and 10% from NGL sales. For the year ended December 31, 2015, our revenues were derived 79% from oil sales, 13% from natural gas sales and 8% from NGL sales. For the year ended December 31, 2014, our revenues were derived 81% from oil sales, 10% from natural gas sales and 9% 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.

Sales Volumes

        The following table presents historical sales volumes for our properties for the six months ended June 30, 2016 and 2015 and for the years ended December 31, 2015 and 2014.

 
  For the Six
Months Ended
June 30,
  For the Years Ended
December 31,
 
 
  2016   2015   2015   2014  

Oil (MBbls)

    2,518.0     1,777.5     3,945.6     1,022.2  

Natural gas (MMcf)

    8,060.7     4,471.9     10,823.0     2,664.1  

NGL (MBbls)

    904.6     488.3     1,334.6     325.3  

Total (MBoe)

    4,766.1     3,011.1     7,084.0     1,791.5  

Average net sales (BOE/d)

    26,187.4     16,636.0     19,408.3     4,908.3  

        Sales volumes directly impact our results of operations. For more information about our sales volumes, please read "—Historical Results of Operations and Operating Expenses."

        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 proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic drill-bit 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. Please read "Risk Factors—Risks Related to the Oil, Natural Gas and NGL Industry and Our Business" for a discussion of these and other risks affecting our proved reserves and production.

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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 August 15, 2016, 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 continuing during 2016 are due to a combination of factors including increased U.S. supply, global economic concerns and a decision by OPEC not to reduce supply. 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 Wattenberg Field, 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 Wattenberg Field is based on CIG prices, adjusted for certain deductions.

        Our price for NGL produced in the Wattenberg Field is based on a combination of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.

        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. In the table below, the NYMEX averages and our average realized prices, with and without derivative settlements, are calculated based on the average of each month's prices for the

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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.

 
  Six Months
Ended June 30,
  Year Ended
December 31,
 
 
  2016   2015   2015   2014  

Oil

                         

NYMEX WTI High ($/Bbl)

  $ 51.23   $ 61.43   $ 61.43   $ 107.26  

NYMEX WTI Low ($/Bbl)

  $ 26.21   $ 43.46   $ 34.73   $ 53.27  

NYMEX WTI Average ($/Bbl)

  $ 39.52   $ 53.29   $ 48.80   $ 93.00  

Average Realized Price ($/Bbl)

  $ 33.72   $ 42.96   $ 39.85   $ 81.48  

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

  $ 41.62   $ 58.31   $ 53.97   $ 83.59  

Averaged Realized Price as a % of Average NYMEX WTI

    85.3 %   80.6 %   81.7 %   87.6 %

Differential ($/Bbl) to Average NYMEX WTI

  $ (5.80 ) $ (10.33 ) $ (8.94 ) $ (11.52 )

Natural Gas

                         

NYMEX Henry Hub High ($/MMBtu)

  $ 2.92   $ 3.23   $ 3.23   $ 6.15  

NYMEX Henry Hub Low ($/MMBtu)

  $ 1.64   $ 2.49   $ 1.76   $ 2.89  

NYMEX Henry Hub Average ($/MMBtu)

  $ 2.12   $ 2.77   $ 2.63   $ 4.28  

Average Realized Price ($/Mcf)

  $ 1.87   $ 2.35   $ 2.43   $ 4.11  

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

  $ 2.79   $ 2.68   $ 2.82   $ 4.11  

Averaged Realized Price as a % of Average NYMEX Henry Hub

    80.2 %   77.1 %   84.0 %   87.3 %

Differential ($/Mcf) to Average NYMEX Henry Hub(1)

  $ (0.46 ) $ (0.70 ) $ (0.46 ) $ (0.60 )

NGL

                         

Average Realized Price ($/Bbl)

  $ 12.50   $ 10.67   $ 11.02   $ 27.20  

Averaged Realized Price as a % of Average NYMEX WTI

    31.6 %   20.0 %   22.6 %   29.2 %

(1)
Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf.

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 sustain 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 instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural

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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. 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, following this offering, we will not be under an obligation to hedge a specific portion of our oil or natural gas production.

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        Our open positions as of June 30, 2016 were as follows:

 
  2016   2017   2018  

NYMEX WTI(1) Crude Swaps:

                   

Notional volume (Bbl)

    1,151,671     2,200,000      

Weighted average fixed price ($/Bbl)

  $ 39.09   $ 44.61        

NYMEX WTI(1) Crude Sold Calls:

                   

Notional volume (Bbl)

    929,000     3,600,000     100,000  

Weighted average fixed price ($/Bbl)

  $ 58.11   $ 53.60   $ 55.00  

NYMEX WTI(1) Crude Sold Puts:

                   

Notional volume (Bbl)

    1,300,000     4,050,000      

Weighted average fixed price ($/Bbl)

  $ 45.00   $ 36.44        

NYMEX WTI(1) Crude Deferred Premium Purchase Puts:

                   

Notional volume (Bbl)

    50,000          

Weighted average purchased put price ($/Bbl)

  $ 45.00              

Weighted average deferred premium ($/Bbl)

  $ (12.36 )            

NYMEX WTI(1) Crude Purchased Puts :

                   

Notional volume (Bbl)

    1,651,671     3,600,000      

Weighted average purchased put price ($/Bbl)

  $ 54.33   $ 46.28        

NYMEX WTI(1) Crude Purchased Calls:

                   

Notional volume (Bbl)

    82,000          

Weighted average purchased put price ($/Bbl)

  $ 69.50   $          

NYMEX HH(2) Natural Gas Swaps:

                   

Notional volume (MMBtu)

    6,776,006     18,220,000        

Weighted average fixed price ($/MMBtu)

  $ 3.11   $ 3.01        

CIG(3) Basis Gas Swaps:

                   

Notional volume (MMBtu)

    1,980,000     990,000      

Weighted average fixed price ($/MMBtu)

  $ (0.19 ) $ (0.19 )      

(1)
NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange

(2)
NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange

(3)
CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) Inside FERC settlement price.

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        The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.

 
  Six Months Ended
June 30,
2016
  Year Ended
December 31,
2015
  Year Ended
December 31,
2014
 

NYMEX HH(1) Natural Gas Swaps:

                   

Notional volume (MMBtu)

    6,418,594     6,444,552     761,766  

Weighted average fixed price ($/MMBtu)

  $ 3.16   $ 3.27   $ 3.92  

CIG(3) Basis Gas Swaps:

                   

Notional volume (MMBtu)

    990,000          

Weighted average fixed price ($/MMBtu)

  $ (0.19 ) $     $    

NYMEX WTI(2) Crude Swaps:

                   

Notional volume (Bbl)

    912,389     1,293,769     262,993  

Weighted average fixed price ($/Bbl)

  $ 45.17   $ 76.24   $ 94.65  

NYMEX WTI(2) Crude Sold Puts:

                   

Notional volume (Bbl)

    800,000          

Weighted average fixed price ($/Bbl)

  $ 44.81   $     $    

NYMEX WTI(2) Crude Purchased Puts:

                   

Notional volume (Bbl)

    2,697,479     1,943,588      

Weighted average purchased put price ($/Bbl)

  $ 51.57   $ 57.67   $    

NYMEX WTI(2) Crude Sold Calls:

                   

Notional volume (Bbl)

    1,457,090     1,943,588      

Weighted average fixed price ($/Bbl)

  $ 63.12   $ 67.21   $    

NYMEX WTI(2) Crude Purchased Calls:

                   

Notional volume (Bbl)

    134,000          

Weighted average fixed price ($/Bbl)

  $ 69.63   $     $    

Total Amounts Received/(Paid) from Settlement (in thousands)

  $ 33,160   $ 59,785   $ 3,974  

Cash provided by (used in) changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives

  $ 9,024   $ (4,015 ) $ (2,250 )

Cash Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows

  $ 42,184   $ 55,770   $ 1,724  

(1)
NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange.

(2)
NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange.

(3)
CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) Inside FERC settlement price.

Principal Components of Our Cost Structure

        Lease Operating Expenses.    All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses. LOEs also include expenses incurred to gather and deliver natural gas to the processing plant and/or selling point.

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        Production Taxes.    Production taxes are paid on produced oil, natural gas and NGL based on a percentage of revenues from production sold at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

        Exploration Expenses.    Exploration expenses are comprised primarily of impairments and abandonment of unproved properties, geological and geophysical expenditures, the cost to carry and retain unproved properties and exploratory dry hole costs.

        Depletion, Depreciation, Amortization and Accretion.    We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method.

        Impairment of Long Lived Assets.    Impairment of long lived assets are comprised primarily of impairment of proved oil and gas properties. We review our proved properties for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. See "—Critical Accounting Policies and Estimates" for further discussion.

        Acquisition Transaction Expenses.    Acquisition transaction expenses consists of non-cash transaction costs associated with acquisitions accounted for using the acquisition method under ASC 805, Business Combinations.

        General and Administrative Expenses.    These are costs incurred for overhead, including payroll and benefits for our corporate staff, unit-based compensation expense, costs of maintaining our headquarters, costs of managing our production and development operations including numerous software applications, audit and other fees for professional services and legal compliance.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

        Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Oil and Gas Property Acquisitions

        The following is a summary of our significant acquisition activity that occurred during 2014, 2015 and 2016:

        May 2014 Acquisition.    On May 29, 2014, we acquired interests in approximately 6,200 net acres of leaseholds and related producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment and other assets (the "May 2014 Acquisition"). The May 2014 Acquisition included 22 producing wells and, at the time of acquisition, had net daily production of approximately 3,000 BOE/d.

        July 2014 Acquisition.    On July 28, 2014, we acquired interests in approximately 9,000 net acres of leaseholds and related producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment and other assets (the "July 2014 Acquisition"). The July 2014 Acquisition included 126 producing wells and, at the time of acquisition, had net daily production of 900 BOE/d.

        August 2014 Acquisition.    On August 21, 2014, we acquired interests in approximately 6,400 net acres of leaseholds and related producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment and other assets (the "August 2014

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Acquisition"). The August 2014 Acquisition included 94 producing wells and, at the time of acquisition, had net daily production of 2,600 BOE/d.

        October 2014 Acquisition.    On October 15, 2014, we acquired interests in approximately 9,178 net acres of leaseholds and related producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment and other assets (the "October 2014 Acquisition"). The October 2014 Acquisition included 29 producing wells and, at the time of acquisition, had net daily production of 232 BOE/d.

        March 2015 Acquisition.    On March 10, 2015, we acquired interests in approximately 39,000 net acres of leaseholds and related producing properties located primarily in Adams, Broomfield, Boulder and Weld Counties, Colorado, along with various related rights, permits, contracts, equipment and other assets (the "March 2015 Acquisition"). The March 2015 Acquisition included 444 producing wells and, at the time of acquisition, had net daily production of approximately 1,100 BOE/d.

        Bayswater Acquisition.    On July 29, 2016, we entered into a definitive agreement with subsidiaries of Bayswater Exploration & Production to acquire the Bayswater Assets for total consideration of $420 million in cash, subject to customary purchase price adjustments. The Bayswater Assets consist of working interests in approximately 6,100 net acres, and had a net daily production of approximately 10,000 net BOE/d during the month ended July 31, 2016. As of July 29, 2016, the Bayswater Assets included 36 gross (20 net) drilled but uncompleted wells. We expect the majority of these drilled but uncompleted wells to be brought online in the first half of 2017. We expect to close the Bayswater Acquisition contemporaneously with the closing of this offering.

Incentive Unit Compensation

        In 2015, we granted certain members of management incentive units pursuant to Holdings' 2014 Membership Unit Incentive Plan and its limited liability company agreement. These equity-based awards are subject to time-based vesting requirements, as well as accelerated vesting upon the occurrence of a change of control. It is expected that this offering will constitute a change in control for purposes of the incentive units. After members that have made capital contributions to us have received cumulative distributions in respect of their membership interests equal to specified rates of return, these incentive units may upon vesting entitle the holders to a disproportionate share of the distributions payable to holders of our membership interests. The incentive units are accounted for as liability awards under ASC 718, Compensation—Stock Compensation. At such time that the occurrence of the performance conditions associated with any of these incentive units, as further described under "Executive Compensation—Narrative Disclosure to Summary Compensation Table and Outstanding Equity Awards at Fiscal Year-End—Long-Term Incentive Compensation—Incentive Units (Profits Interests)," are deemed probable, we will record non-cash compensation expense equal to a percentage of the then-determined fair value of those awards based on the implied service period that has been rendered at that date. As long as we continue to view the achievement of the performance conditions as probable of occurring, we will remeasure the amount of compensation expense to be recognized each period until the awards are settled. No incentive compensation expense was recorded during the year ended December 31, 2015 or the six months ended June 30, 2016, because it was not probable that the performance criterion would be met. Any liquidity event would meet the performance criterion.

        As part of the transactions described under "Corporate Reorganization," Holdings will merge with and into us, and we will be the surviving entity to such merger, with the equity holders in Holdings, other than the holders of the Series B Preferred Units (which will be converted in connection with the closing of this offering into shares of Series A Preferred Stock), but including the holders of restricted units and incentive units, receiving an aggregate number of shares of our common stock based on an implied valuation for us based on the initial public offering price set forth on the cover page of this

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prospectus and the current relative levels of ownership in Holdings, pursuant to the terms of the limited liability company agreement of Holdings, with the allocation of such shares among our existing equity holders to be later determined, pursuant to the terms of the limited liability company agreement of Holdings, by reference to an implied valuation for us based on the 10-day volume weighted average price of our common stock following the closing of this offering. Please see "Corporate Reorganization—Existing Owners Ownership." As a result, as of the effective date of Holdings' merger with and into us, we will begin accounting for the incentive unit awards as equity-classified awards pursuant to ASC Topic 718. This will result in the recognition of $             million of compensation cost equal to the excess of the modified awards' fair value (based on the midpoint of the price range set forth on the cover page of this prospectus) over the amount of cumulative compensation cost recognized prior to that date.

Series A Preferred Stock

        In connection with the consummation of this offering, we will issue      shares of our Series A Preferred Stock to the holders of Holdings' Series B Preferred Units. The Series A Preferred Stock will be entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% (decreased proportionately to the extent such quarterly dividends are paid in cash). Beginning on or after the later of a) 90 days after the closing of this offering and b) the Lock-Up Period End Date, the Series A Preferred Stock will be convertible into shares of our common stock at the election of the holders of the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of        . Beginning on or after the Lock-Up Period End Date, we may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of            , but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, such premium to decrease with time. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at par. See "Description of Capital Stock—Preferred Stock—Series A Preferred."

Public Company Expenses

        General and administrative expenses related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; expenses associated with listing on the NASDAQ; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and director compensation. As a publicly traded company at the closing of this offering, we expect that general and administrative expenses will increase in future periods.

Income Taxes

        Prior to our conversion from a limited liability company into a corporation in connection with this offering, we were not subject to federal or state income taxes. Accordingly, the financial data attributable to us prior to such conversion contain no provision for federal or state income taxes because the tax liability with respect to our taxable income was passed through to our members. At the closing of this offering, we will be taxed as a C corporation under the Internal Revenue Code and subject to federal and state income taxes at a blended statutory rate of approximately 38% of pretax earnings.

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Historical Capital Expenditures and Capital Budget

        For the year ended December 31, 2015 and the six months ended June 30, 2016, our aggregate drilling, completion and leasehold capital expenditures were approximately $398.4 million and $137.8 million, respectively, excluding acquisitions. Our 2016 capital budget is approximately $365 million, substantially all of which we intend to allocate to the Wattenberg Field. We intend to allocate approximately $335 million of our 2016 capital budget to the drilling of 100 gross (90 net) wells and the completion of 92 gross (82 net) wells, approximately $5 million to midstream, and approximately $25 million to leaseholds. Our 2016 capital expenditures budget contemplates that we will drill approximately 77 gross (70 net) wells targeting proved undeveloped locations in 2016. Such wells are associated with 24,083 MBoe of net proved undeveloped reserves. As of August 15, 2016, 40 gross (36 net) of such wells have been spud. Our capital budget excludes any amounts that were or may be paid for potential acquisitions, including the Bayswater Acquisition.

        Our 2017 capital budget is approximately $590 million, substantially all of which we intend to allocate to the Wattenberg Field. We intend to allocate approximately $535 million of our 2017 capital budget to the drilling of 138 gross (102 net) operated wells and the completion of 120 gross (102 net) operated wells, approximately $2 million to midstream, and approximately $53 million to leaseholds. Our 2017 capital expenditures budget contemplates that we will drill approximately 98 gross (74 net) operated wells targeting proved undeveloped locations in 2017. Such wells are associated with 37,967 MBoe of net proved undeveloped reserves. In addition to the operated wells above, our capital budget includes estimated non-operated activity on our acreage consisting of the drilling of 69 gross (18 net) non-operated wells and the completion of 51 gross (15 net) non-operated wells. Our capital budget excludes 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.

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Historical Results of Operations and Operating Expenses

Oil, Natural Gas and NGL Sales Revenues and Operating Expenses.

        The following table provides the components of our revenues, operating expenses, other income (expense) and net income (loss) for the periods indicated (in thousands):

 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  2016   2015   2015   2014  
 
  (unaudited)
   
   
 

Revenues:

                         

Oil sales

  $ 84,135   $ 77,464   $ 157,024   $ 75,460  

Natural gas sales

    14,937     10,234     26,019     9,247  

NGL sales

    11,424     5,084     14,707     8,133  

Total Revenues

    110,496     92,782     197,750     92,840  

Operating Expenses:

                         

Lease operating expenses

    25,339     11,312     30,628     5,067  

Production taxes

    10,748     7,924     17,035     9,743  

Exploration expenses

    8,752     4,852     18,636     126  

Depletion, depreciation, amortization, and accretion

    94,638     59,290     146,547     34,042  

Impairment of long lived assets                   

    22,884     9,525     15,778      

Other operating expenses

    891     1,657     2,353      

Acquisition transaction expenses                   

        6,000     6,000      

General and administrative expenses

    15,114     16,870     37,149     19,598  

Total Operating Expenses

    178,366     117,430     274,126     68,576  

Operating Income (Loss):

    (67,870 )   (24,648 )   (76,376 )   24,264  

Other Income (Expense):

                         

Commodity derivative gain (loss)          

    (78,650 )   (8,407 )   79,932     48,008  

Interest expense

    (26,698 )   (23,668 )   (51,030 )   (22,454 )

Other income

    84     13     210     24  

Total Other Income (Expense)

    (105,264 )   (32,062 )   29,112     25,578  

Net Income (Loss)

  $ (173,134 ) $ (56,710 ) $ (47,264 ) $ 49,842  

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        The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:

 
  Six Months Ended
June 30,
  Year Ended
December 31,
 
 
  2016   2015   2015   2014  
 
  (unaudited)
 

Sales (MBoe)(1):

    4,766.1     3,011.1     7,084.0     1,791.5  

Oil sales (MBbls)

    2,518.0     1,777.5     3,945.6     1,022.2  

Natural gas sales (MMcf)

    8,060.7     4,471.9     10,823.0     2,664.1  

NGL sales (MBbls)

    904.6     488.3     1,334.6     325.3  

Sales (BOE/d)(1):

    26,187     16,636     19,408     4,908  

Oil sales (Bbl/d)

    13,835     9,820     10,810     2,801  

Natural gas sales (Mcf/d)

    44,289     24,707     29,652     7,299  

NGL sales (Bbl/d)

    4,971     2,698     3,656     891  

Average sales prices(2):

                         

Oil sales (per Bbl)

  $ 33.41   $ 43.58   $ 39.80   $ 73.82  

Oil sales with derivative settlements (per Bbl)

  $ 41.51   $ 58.06   $ 53.29   $ 77.66  

Natural gas sales (per Mcf)

  $ 1.85   $ 2.29   $ 2.40   $ 3.47  

Natural gas sales with derivative settlements (per Mcf)

  $ 2.77   $ 2.63   $ 2.82   $ 3.49  

NGL sales (per Bbl)

  $ 12.63   $ 10.41   $ 11.02   $ 25.00  

Average price per BOE

  $ 23.18   $ 30.81   $ 27.92   $ 51.82  

Average price per BOE with derivative settlements

  $ 29.02   $ 39.87   $ 36.06   $ 54.04  

Expense per BOE:

                         

Lease operating expenses

  $ 5.32   $ 3.76   $ 4.32   $ 2.83  

Production taxes

  $ 2.26   $ 2.63   $ 2.40   $ 5.44  

Exploration expenses

  $ 1.84   $ 1.61   $ 2.63   $ 0.07  

Depletion, depreciation, amortization, and accretion                   

  $ 19.86   $ 19.69   $ 20.69   $ 19.00  

Impairment of long lived assets

  $ 4.80   $ 3.16   $ 2.23   $  

Other operating expenses

  $ 0.19   $ 0.55   $ 0.33   $  

Acquisition transaction expenses

  $   $ 1.99   $ 0.85   $  

General and administrative expenses

  $ 3.17   $ 5.60   $ 5.24   $ 10.94  

Unit-based compensation

  $ 0.55   $ 1.02   $ 0.84   $ 2.49  

Total operating expenses per BOE

  $ 37.42   $ 39.00   $ 38.69   $ 38.28  

(1)
One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)
Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains or losses on cash settlements for commodity derivatives and premiums paid or received on options that settled during the period.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

        Oil sales revenues.    Crude oil sales revenues increased by $6.7 million to $84.1 million for the six months ended June 30, 2016 as compared to crude oil sales of $77.5 million for the six months ended June 30, 2015. An increase in sales volumes between these periods contributed a $32.3 million positive impact, which was partially offset by a $25.6 million negative impact due to declining crude oil prices.

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