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As filed with the Securities and Exchange Commission on January 6, 2017

Registration No. 333-215282

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Extraction Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

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

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:  x

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.

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. The selling stockholders 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 where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED JANUARY 6, 2017

18,798,932 Shares

Extraction Oil & Gas, Inc.

Common Stock

This prospectus relates to the resale or other disposition of up to 18,798,932 shares of the common stock, par value $0.01, of Extraction Oil & Gas, Inc., a Delaware corporation, which may be offered for sale from time to time by the selling stockholders named in this prospectus. The shares of our common stock covered by this prospectus are to be issued by us to the selling stockholders upon conversion of our Series A Convertible Preferred Stock (the “Series A Preferred Stock”), including any shares of Series A Preferred Stock that may be issued pursuant to our option to pay dividends on the Series A Preferred Stock in kind pursuant to the terms of the Certificate of Designations setting forth the terms of the Series A Preferred Stock. We are not selling any shares of our common stock under this prospectus and will not receive any proceeds from the sale of any shares of common stock by the selling stockholders.

Our common stock trades on the NASDAQ Global Select Market under the symbol “XOG.” The last reported sales price of our common stock on January 5, 2017 was $19.90 per share. You are urged to obtain current market quotations for the common stock.

The selling stockholders may from time to time sell, transfer or otherwise dispose of any or all of their shares of common stock in a number of different ways and at varying prices. See “Plan of Distribution” for more information.

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this entire prospectus and any amendments or supplements carefully before you make your investment decision.

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012.

Investing in our common stock involves risks. Please see “Risk Factors” beginning on page 18 of this prospectus.

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.

The date of this prospectus is                   , 2017.

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This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission (the “SEC”) pursuant to which the selling stockholders named herein may, from time to time, offer and sell or otherwise dispose of the shares of our common stock covered by this prospectus. You should not assume that the information contained in this prospectus is accurate on any date subsequent to the date set forth on the front cover of this prospectus or that any information we have incorporated by reference is correct on any date subsequent to the date of the document incorporated by reference, even though this prospectus is delivered or shares of common stock are sold or otherwise disposed of on a later date. It is important for you to read and consider all information contained in this prospectus, including the documents incorporated by reference therein, in making your investment decision. You should also read and consider the information in the documents to which we have referred you under the caption “Where You Can Find Additional Information” in this prospectus.

Neither we nor the selling stockholders have authorized any dealer, salesman or other person to give any information or to make any representation other than those contained or incorporated by reference in this prospectus. You must not rely upon any information or representation not contained or incorporated by reference in this prospectus. This prospectus does not constitute an offer to sell or the solicitation of an offer to buy any of our shares of common stock other than the shares of our common stock covered hereby, nor does this prospectus constitute an offer to sell or the solicitation of an offer to buy any securities in any jurisdiction to any person to whom it is unlawful to make such offer or solicitation in such jurisdiction.

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.”

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

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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.

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, formerly a wholly owned subsidiary of PRL, was 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 the initial public offering of Extraction Oil & Gas, Inc. (the “IPO”), Extraction Oil & Gas Holdings, LLC was merged with and into Extraction Oil & Gas, LLC, with such merger being treated as a reorganization of entities under common control, and Extraction Oil & Gas, LLC converted from a Delaware limited liability company into a Delaware corporation, Extraction Oil & Gas, Inc.

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 selling stockholders 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 or incorporated by reference into 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,” “Information Incorporated by Reference” 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 but prior to the corporate reorganization as described in “—Corporate Reorganization.” 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 owned 100% of the equity interests of Extraction Oil & Gas, LLC. Unless indicated otherwise or the context otherwise requires, references to our net acreage, drilling locations, well count, working interest and our estimated average net daily production as of September 30, 2016 and our proved reserves as of June 30, 2016 in this prospectus are adjusted to give pro forma effect to the transactions described in “—Recent Developments—Bayswater Acquisition—Bayswater Assets.” Unless indicated otherwise or the context otherwise requires, references to the ownership of our common stock following the completion of the IPO are not adjusted to give effect to the conversion of the Series A Preferred Stock as described under “—Recent Developments—Convertible Preferred Securities.”

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 September 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 Wattenberg-focused company with acreage that has (i) low development risk as a result of being within the vicinity of other successful wells drilled by other oil and gas companies, (ii) limited vertical well drainage relative to offset operators in a field with significant historical vertical activity, and (iii) higher oil content than was traditionally targeted when many operators first established their position in the field seeking natural gas production. We believe these characteristics enhance our horizontal production capabilities, recoveries and economic results. Our drilling economics are further enhanced by our ability to drill longer laterals due to our large contiguous acreage position, which our management team built through organic leasing and a series of strategic acquisitions. We operated 96% of our horizontal production for the nine months ended September 30, 2016 and maintain control of a large majority of our drilling inventory. In addition, we proactively seek to secure the necessary midstream and operational infrastructure to keep pace with our production growth.

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As of September 30, 2016, we have drilled 293 gross one-mile equivalent horizontal wells and have completed 245 gross one-mile equivalent horizontal wells. We are currently running an effective three-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 from time to time on a spot basis. 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 three months ended September 30, 2016 was approximately 37,600 BOE/d. The charts below demonstrate the substantial growth in our average net daily production and well count since the second quarter of 2014.

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

(2)         Reflects 28,948 BOE/d attributable to our historically owned properties and approximately 8,600 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 three months ended September 30, 2016.

(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 48% oil, 30% natural gas and 22% NGL.

(4)         Represents the number of years proved reserves would last assuming production continued at the average rate for the three months ended September 30, 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 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. In addition, based on our current permitting activities, we believe that, via additional downspacing in the Niobrara formation, we could have up to approximately 600 additional drilling locations, which are not captured in the inventory numbers below. As of September 30, 2016, we had a drilling

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inventory consisting of 3,929 gross (2,575 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 September 30, 2016.

(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)         Includes 159 drilled but uncompleted one-mile equivalent wells.

(3)         As of September 30, 2016. Approximate net acreage represents only our oil and gas properties in the Wattenberg Field and does not include the approximately 120,000 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.”

(4)         Includes 918 identified drilling locations associated with proved undeveloped reserves as of September 30, 2016, as adjusted for lateral length to present one-mile equivalents (approximately 4,200 feet).

(5)         If converted to 1.5-mile equivalent locations (approximately 6,800 feet), we would have an estimated 2,619 identified gross horizontal drilling locations. If converted to 2.0-mile equivalent locations (approximately 9,400 feet), we would have an estimated 1,965 identified gross horizontal drilling locations.

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

Other Properties

We hold approximately 120,000 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 September 30, 2016, there were de minimis proved reserves associated with this acreage. Average daily production associated with these properties for the quarter ended September 30, 2016 was approximately 663 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 nine months ended September 30, 2016, our aggregate drilling, completion and leasehold capital expenditures were approximately $398.4 million and $203.1 million, respectively, excluding acquisitions. We intend to allocate approximately $335.0 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 $5.0 million to midstream, and approximately $25.0 million to leaseholds. As of September 30, 2016, 69 gross (60 net) of the 100 gross (90 net) budgeted have been drilled, and 55 gross (44 net) of the 92 gross (82 net) wells have been completed. 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 $795-935 million, substantially all of which we intend to allocate to the DJ Basin. We intend to allocate approximately $675-775 million of our 2017 capital budget to the drilling of 185-190 gross operated wells and the completion of 190-195 gross operated wells, approximately $60-80 million to land, midstream and other uses, and approximately $60-80 million to non-operated drilling and completion. We are currently running an effective three-rig program.

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

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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 September 30, 2016, we identified a horizontal drilling inventory of 3,929 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 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 96% of our horizontal production for the nine months ended September 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 transports oil and gas out of the Wattenberg Field to Cushing, Oklahoma. We are committed to meet delivery commitments of 40,000 Bbls/d out of the basin, increasing to 58,000 Bbls/d by November 2018 and through 2026. Upon closing the Bayswater Acquisition, we became subject to two additional long-term crude oil delivery commitments, one for a term of seven years and one for a term of

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five years. We have total delivery commitment obligations of 5,000 Bpd in year one and 3,800 Bpd in year two through seven.

·                  Strategically augment acreage position through opportunistic acquisitions. Since inception, we have consummated six significant acquisitions in the Wattenberg Field, acquiring approximately 76,100 net acres, as of September 30, 2016. We intend to continue to strategically make opportunistic acquisitions as well as pursue additional leasing opportunities to further supplement our oil and natural gas properties, 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 September 30, 2016, after giving effect to the Bayswater Acquisition, the issuance of the Convertible Preferred Securities, the IPO, the Private Placement and our recent increase to the borrowing base of our revolving credit facility, each as described below, we have approximately $1,267.7 million of liquidity, with $792.7 million of cash and cash equivalents and $475.0 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 September 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 September 30, 2016, our horizontal drilling inventory consisted of 3,929 gross (2,575 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 three-rig drilling program, we have a drilling inventory of approximately 14.3 years, prior to considering locations other than those in the Niobrara and Codell formations.

·                  Significant operational control with low development costs. We operated 96% of our horizontal production for the nine months ended September 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

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utilize cost-effective operating practices, including the selection of drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques. 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 September 30, 2016, after giving effect to the Bayswater Acquisition, the issuance of the Convertible Preferred Securities, the IPO, the Private Placement and our recent increase to the borrowing base of our revolving credit facility, we have approximately $1,267.7 million of liquidity, with $792.7 million of cash and cash equivalents and $475.0 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 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

Initial Public Offering

On October 17, 2016, we completed an initial public offering of 33,333,333 shares of our common stock at a price to the public of $19.00 per share and we became a publicly traded company listed on NASDAQ under the ticker symbol “XOG”. After deducting underwriting discounts and commissions and estimated offering expenses payable by us, we received approximately $683.7 million of aggregate net proceeds from our initial public offering after the underwriters exercised their option on October 24, 2016 to purchase 5,000,000 additional shares in full.

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 approximately $419 million in cash after customary purchase price adjustments (the “Bayswater Acquisition”). Upon completion of the Bayswater Acquisition, we acquired 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 8,600 net BOE/d for the three months ended September 30, 2016. 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

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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 and 30 drilled but uncompleted wells. Upon closing the Bayswater Acquisition, we became subject to two additional long-term crude oil delivery commitments, one for a term of seven years and one for a term of five years. We have total delivery commitment obligations of 5,000 Bpd in year one and 3,800 Bpd in year two through seven.

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 closed the Bayswater Acquisition on October 3, 2016. We funded the purchase price through the issuance of $260.3 million in convertible preferred securities and borrowings under our revolving credit facility.

Option to Acquire Additional Assets from Bayswater

In connection with the consummation of the Bayswater Acquisition, we paid $10.0 million for an option to purchase additional assets from Bayswater (the “Additional Bayswater Assets”) for an additional $190.0 million, for a total purchase price for the Additional Bayswater Assets of $200.0 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 $120.0 million, for a total purchase price for the Additional Bayswater Assets of $130.0 million. The Additional Bayswater Assets include working interests in approximately 9,100 net acres primarily in the Wattenberg Field.

Convertible Preferred Securities

We previously issued to affiliates of Apollo Capital Management (“Apollo”) $75.0 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 were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. In connection with the consummation of the IPO, we used $90.0 million of the net proceeds to redeem the Series A Preferred Units in full, which included a premium of $15.0 million.

In addition, we have issued to, among others, investment funds affiliated with OZ Management LP and Yorktown Partners LLC (“Yorktown”) $185.3 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 were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and we had the ability to pay up to 50% of the quarterly dividend in kind. The Series B Preferred Units were converted in connection with the closing of the IPO into shares of our Series A 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% per year (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 the IPO and (b) the earlier of 120 days after the closing of the IPO and the expiration of the lock-up period contained in the underwriting agreement entered into in connection with the IPO (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 61.9195. Beginning on or after the Lock-Up Period End Date until the three year anniversary of the closing of the IPO, we may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, such premium to decrease with time. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock matures on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference. See “Description of Capital Stock—Preferred Stock—Series A Preferred Stock.”

We refer to the private offering, on July 18, 2016 (the “2016 Notes Offering”) of $550 million principal amount of 7.875% senior secured notes due 2021 (the “2021 Notes” or the “Senior Notes”) and the issuance of the Series A Preferred Units and Series B Preferred Units as the “Financing Transactions.”

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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 $450 million upon the consummation of the Bayswater Acquisition. On December 7, 2016, the borrowing base was increased to $475 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility.”

Private Placement of Common Stock

On December 15, 2016, we issued 25,041,041 shares of common stock, at a price of $18.25 per share, in connection with the Private Placement (the “Private Placement”). The Private Placement resulted in approximately $457.0 million of gross proceeds and approximately $441.8 million of net proceeds (after deducting placement agent commissions and our expenses).

Recent Acquisitions

We recently closed on two separate transactions from unrelated sellers to acquire approximately 16,800 net acres in the DJ Basin for aggregate cash consideration of approximately $177 million. The acquisitions include de minimis oil and gas production and approximately 425 net 1-mile equivalent drilling locations. Net proceeds from the Private Placement were used, in part, to replenish cash used to pay the cash consideration of the acquisitions.

Corporate Reorganization

In connection with the IPO:

·                  Extraction Oil & Gas, LLC was converted from a Delaware limited liability company into a Delaware corporation;

·                  We redeemed the Series A Preferred Units in full with a portion of the net proceeds from the IPO; and

·                  Holdings merged with and into us, and we were the surviving entity to such merger, with the equity holders in Holdings, other than the holders of the Series B Preferred Units (which were converted in connection with the closing of the IPO into shares of Series A Preferred Stock), but including the holders of restricted units and incentive units, receiving 108,460,231 shares of our common stock, with the allocation of such shares among our existing equity holders 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 the IPO.

As part of Holdings’ merger with and into us, Holdings’ other subsidiaries became our direct or indirect subsidiaries.

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The following diagram indicates our simplified ownership structure:

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

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. 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

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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 converted into a Delaware corporation in connection with the IPO. 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, 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. After accounting for the Private Placement,Yorktown currently owns an approximate 29% equity interest in us and a 26% equity interest in us assuming all of the shares of Series A Preferred Stock are converted into shares of our common stock including any shares of Series A Preferred Stock that may be issued pursuant to our option to pay dividends on the Series A Preferred Stock in kind pursuant to the terms of the Certificate of Designations setting forth the terms of the Series A Preferred Stock. 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 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

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·                  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 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

(1)  The number of outstanding shares as of December 19, 2016 includes the 18,798,932 shares of common stock issuable upon the conversion of our Series A Preferred Stock including any shares of Series A Preferred Stock that may be issued pursuant to our option to pay dividends on the Series A Preferred Stock in kind pursuant to the terms of the Certificate of Designations setting forth the terms of the Series A Preferred Stock, and excludes (i) 4,500,000 shares of common stock issuable upon exercise of options currently outstanding, of which none are currently are exercisable and (ii) an aggregate of approximately 9,998,132 shares of common stock reserved and available for future issuance under our long-term incentive plan (our “LTIP”).

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The summary historical financial data as of and for the nine months ended September 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 nine months ended September 30, 2016 and 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—Recent Developments,” (iii) the transactions described under “—Corporate Reorganization,” (iv) the IPO and the application of the net proceeds from the IPO, and (v) the Private Placement, as if each such transaction had been completed as of January 1, 2015. The pro forma balance sheet data of our Predecessor as of September 30, 2016 have been prepared to give pro forma effect to (i) the Bayswater Acquisition, (ii) the transactions described under “—Corporate Reorganization”, (iii) the IPO and the application of the net proceeds from the IPO, and (iv) the Private Placement, as if each such transaction had been completed on September 30, 2016. 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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(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.”

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.

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

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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.

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

(1)         If we had been subject to entity-level U.S. federal and state income taxes, the pro forma, undiscounted, income tax expense at June 30, 2016 would have been $166.7 million ($81.5 million on a discounted basis) and the Standardized Measure would have been $604.5 million. If we had been subject to entity-level U.S. federal and state income taxes, the pro forma, undiscounted, income tax expense at December 31, 2015 would have been $453.9 million ($220.5 million on a discounted basis) and the Standardized Measure would have been $615.4 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.

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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.

(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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(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 and the documents we have incorporated by reference into 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 materially and you could 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 September 30, 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:

·                  worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGL;

·                  the price and quantity of foreign imports;

·                  political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

·                  the level of global exploration and production;

·                  the level of global inventories;

·                  prevailing prices on local price indices in the areas in which we operate;

·                  the proximity, capacity, cost and availability of gathering and transportation facilities;

·                  localized and global supply and demand fundamentals and transportation availability;

·                  weather conditions;

·                  technological advances affecting energy consumption;

·                  the price and availability of alternative fuels; and

·                  domestic, local and foreign governmental regulation and taxes.

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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 inventories and lower global demand.

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 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.

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Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of oil and natural gas reserves. We expect to fund our 2017 capital expenditures with the proceeds of the IPO, the Private Placement, 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:

·                  our proved reserves;

·                  the level of hydrocarbons we are able to produce from existing wells;

·                  the prices at which our production is sold;

·                  the availability of takeaway capacity;

·                  our ability to acquire, locate and produce new reserves; and

·                  our ability to borrow under our revolving credit facility.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

·                  delays imposed by or resulting from compliance with environmental and other regulatory requirements including limitations on or resulting from wastewater discharge and disposal, subsurface injections, greenhouse gas emissions and hydraulic fracturing;

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·                  pressure or irregularities in geological formations;

·                  shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

·                  equipment failures or accidents;

·                  lack of available gathering facilities or delays in construction of gathering facilities;

·                  lack of available capacity on interconnecting transmission pipelines;

·                  adverse weather conditions, such as blizzards, tornados and ice storms;

·                  issues related to compliance with environmental and other governmental regulations;

·                  environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

·                  declines in oil, natural gas and NGL prices;

·                  limited availability of financing at acceptable terms;

·                  title problems or legal disputes regarding leasehold rights; and

·                  limitations in the market for oil, natural gas and NGL.

Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

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

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our debt arrangements contain a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

·                  incur additional indebtedness;

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·                  sell assets;

·                  make loans to others;

·                  make certain acquisitions and investments;

·                  enter into mergers, consolidations or other transactions resulting in the transfer of all or substantially all of our assets;

·                  make certain payments, including paying dividends or distributions in respect of our equity;

·                  hedge future production or interest rates;

·                  redeem and prepay other debt;

·                  holding cash balances in excess of certain thresholds while carrying a balance of our revolving credit facility;

·                  incur liens; and

·                  engage in certain other transactions without the prior consent of the lenders.

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 September 30, 2016, our borrowing base was $350.0 million. On September 14, 2016, we entered into an amendment to our revolving credit facility that, among other things, increased the borrowing base to $450 million upon the consummation of the Bayswater Acquisition. The Bayswater Acquisition closed on October 3, 2016, which triggered the borrowing base increase. On December 7, 2016, our borrowing base was increased to $475 million.

A breach of any covenant in our revolving credit facility will result in a default under the revolving credit facility after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. In addition, our obligations under our revolving credit facility are secured by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 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

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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:

·                  production is less than the volume covered by the derivative instruments;

·                  the counterparty to the derivative instrument defaults on its contractual obligations;

·                  there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

·                  there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGL, which could also have an adverse effect on our financial condition.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of

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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 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 September 30, 2016, we have drilled 293 gross one-mile equivalent horizontal wells and have

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completed 245 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 53% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

As of September 30, 2016, approximately 53% 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 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

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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 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. Upon closing the Bayswater Acquisition, we became subject to two additional long-term crude oil delivery commitments, one for a term of seven years and one for a term of five years. We have total delivery commitment obligations of 5,000 Bpd in year one and 3,800 Bpd in year two through seven. 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

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transportation and processing capacity. As of September 30, 2016, the aggregate amount of estimated payments over the ten-year term of these agreements was $952.9 million. If we have insufficient production to meet the minimum volumes under this agreement or any other firm commitment agreement we may enter into, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results or operations.

The prices we receive for our production may be affected by local and regional factors.

The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process, and transport, our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.

Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.

Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as winter storms, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

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.

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.

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Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecast, as well as access to liquidity sources, such as the capital markets, our revolving credit facility and derivative contracts. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.

As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, 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.

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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.

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.

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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:

·                  injury or loss of life;

·                  damage to and destruction of property, natural resources and equipment;

·                  pollution and other environmental damage;

·                  regulatory investigations and penalties;

·                  suspension of our operations; and

·                  repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and 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.

Properties that we decide to drill may not yield oil, natural gas or NGL in commercially viable quantities.

Properties that we decide to drill that do not yield oil, natural gas or NGL in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

·                  unexpected drilling conditions;

·                  title problems;

·                  pressure or lost circulation in formations;

·                  equipment failure or accidents;

·                  adverse weather conditions;

·                  compliance with environmental and other governmental or contractual requirements; and

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·                  increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of oil and gas properties or businesses that complement or expand our current business. The successful acquisition of oil and gas properties requires an assessment of several factors, including:

·                  recoverable reserves;

·                  future oil, natural gas and NGL prices and their applicable differentials;

·                  operating costs; and

·                  potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our debt arrangements will impose certain limitations on our ability to enter into mergers or combination transactions. Our debt arrangements will also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

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.

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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 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, in October 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.

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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 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.