10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________________ to ___________________

Commission file number:  001-35245

SRC ENERGY INC.

(Exact name of registrant as specified in its charter)

COLORADO	20-2835920
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1675 Broadway, Suite 2600, Denver, CO	80202
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (720) 616-4300

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock	NYSE AMERICAN

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý  No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No ý

Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý   No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act):  Yes o No ý

The aggregate market value of the voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on June 30, 2017, was approximately $1.0 billion.  Shares of the registrant’s common stock held by each officer and director and each person known to the registrant to own 10% or more of the outstanding voting power of the registrant have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not a determination for other purposes.

As of February 19, 2018, the Registrant had 241,786,159 issued and outstanding shares of common stock.

DOCUMENTS INCORPORATED BY REFERENCE

We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Meeting of Stockholders.

SRC ENERGY INC.

Index

		Page
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	33
Item 2.	Properties	33
Item 3.	Legal Proceeding	34
Item 4.	Mine Safety Disclosures	34
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	37
Item 7.	Management's Discussion and Analysis of Financial Condition and Result of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risks	59
Item 8.	Financial Statements and Supplementary Data	60
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
Item 9A.	Controls and Procedures	60
Item 9B.	Other Information	62
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	62
Item 11.	Executive Compensation	62
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	62
Item 13.	Certain Relationships and Related Transactions and Director Independence	62
Item 14.	Principal Accounting Fees and Services	62
PART IV
Item 15.	Exhibits, Financial Statement Schedules	63
SIGNATURES		F-40
GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS		F-42

PART I

Glossary of Units of Measurements and Industry Terms

Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report.

Cautionary Statement Concerning Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as “believes,” “expects,” “anticipates,” “intends,” “plans,” “estimates,” “should,” “likely,” or similar expressions indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, and future production relative to volume commitments.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Important factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:

• declines in oil and natural gasprices;

• operating hazards that adversely affect our ability to conduct business;

• uncertainties in the estimates of proved reserves;

• the availability and capacity of gathering systems, pipelines, and other midstream infrastructure for our production;

• the effect of seasonal weather conditions and wildlife and plant species restrictions on our operations;

• our ability to fund, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable;

• our ability to obtain adequate financing;

• the effect of local and regional factors on oil and natural gas prices;

• incurrence of ceiling test write-downs;

• our inability to control operations on properties that we do not operate;

• the strength and financial resources of our competitors;

• our ability to successfully identify, execute, and integrate acquisitions, including the GCII Acquisition;

• the effect of federal, state, and local laws and regulations;

• the effects of, including costs to comply with, environmental legislation or regulatory initiatives, including those related to hydraulic fracturing;

• our ability to market our production;

• the effects of local moratoria or bans on our business;

• the effect of environmental liabilities;

• the effect of the adoption and implementation of statutory and regulatory requirements for derivative transactions;

• changes in U.S. tax laws;

• our ability to satisfy our contractual obligations and commitments;

• the amount of our indebtedness and our ability to maintain compliance with debt covenants;

• the effectiveness of our disclosure controls and our internal controls over financial reporting;

• the geographic concentration of our principal properties;

• our ability to protect critical data and technology systems;

• the availability of water for use in our operations; and

• the risks and uncertainties described and referenced in "Risk Factors."

Note Regarding Change in Reserves and Production Volumes

As of January 1, 2017, our natural gas processing agreements with DCP Midstream, L.P. ("DCP Midstream") had been modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods

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prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 with prior periods.

Note Regarding Change in Fiscal Year

In February 2016, the Company changed its fiscal year-end to December 31 from August 31. Certain information in this report is presented as of and for the fiscal years ended August 31, 2015, 2014, and 2013.

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ITEM 1. BUSINESS

Overview

SRC Energy Inc. ("we," "us," "our," "SRC," or the "Company") is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the Denver-Julesburg Basin (“D-J Basin”), which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.

Our drilling and completion activities are focused in the Wattenberg Field, predominantly in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell formation as well as the three benches of the Niobrara formation, all of which are characterized by relatively high liquids content.

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 78% of our proved producing reserves and anticipate operating substantially all of our future net drilling locations.

During the year ended December 31, 2017, we continued to execute our plans for growth through development of our existing oil and gas properties and strategic acquisitions of leasehold and producing properties. Most notably, in December 2017, we closed on the acquisition of certain undeveloped land and non-operated production in the Greeley-Crescent development area in Weld County for $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities. The transaction included approximately 30,200 net acres and approximately 2,500 BOE net daily production from the acquired non-operated properties. The acquired acreage represents a significant increase in the Company’s leasehold and drillable locations in the Greeley-Crescent area.  Combined with SRC’s existing acreage, this results in a consolidated core position of approximately 88,300 net acres.   This contiguous footprint creates further opportunities to drive operational efficiencies with over 1,700 identified gross well locations with predominantly mid- and long-lateral design.

As of December 31, 2017, we are the operator of 572 gross (551 net) producing wells, of which 227 gross (218 net) are Codell or Niobrara horizontal wells. The Company has also participated as a non-operator in 442 gross (99 net) producing wells. In addition, there were 51 gross (47 net) operated wells in various stages of drilling or completion as of December 31, 2017, which excludes 19 gross (16 net) wells for which we have only set surface casings.

For the year ended December 31, 2017, 2016 and 2015, our average net daily production was 34,194 BOED, 11,670 BOED, and 9,548 BOED, respectively. As of December 31, 2017, over 98% of our daily operated production was from horizontal wells.

Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves, and cash flow through development, exploitation, exploration, and acquisitions of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:

• Concentrate on our existing core area in the D-J Basin, where we have significant operating experience.  All of our current wells and our proved undeveloped acreage are located either in or adjacent to the Wattenberg Field, and we seek to acquire developed and undeveloped oil and gas properties in the same area. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.

• Develop and exploit existing oil and gas properties.  Our principal growth strategy has been to develop and exploit our properties to add reserves.  In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells.  There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.

• Use the latest technology to maximize returns and improve hydrocarbon recovery.  Our development objective for individual well optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical

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and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.

• Operate in a safe manner and seek to minimize our impact on surrounding stakeholders. While our scale of operations has increased significantly, we continue to focus on maintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to utilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities.

• Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled.  This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.

• Maintain financial flexibility while focusing on operational cost control.  We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which enhances our financial flexibility. Our high degree of operational control, as well as our focus on operating efficiencies and short return on investment cycle times, is central to our operating strategy.

• Acquire and develop assets near established infrastructure. We have made acquisitions of contiguous acreage and aligned our development plans where technically-capable, financially-stable midstream companies have existing assets and plans for additional investment. We work collaboratively with these companies to proactively identify expansion opportunities that complement our development plans while reducing truck traffic.

Competitive Strengths

We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:

• Core acreage position in the Wattenberg Field. Wells in our core properties in the Wattenberg Field generally exhibit high liquids content, and those properties are generally prospective for Niobrara A, B, and C bench and Codell development. We believe that these factors lead to a high success rate and attractive EURs per acres of leasehold, per unit capital and operating costs, and rates of return. Increased well density within the Codell and Niobrara formations, as well as our acquisition efforts and organic leasing efforts within the core Wattenberg Field, have added to our multi-year drilling inventory. Our core position is situated in an area where there is extensive infrastructure that continues to be expanded.

• Financial flexibility. Our capital structure, along with our high degree of operational control, continues to provide us with significant financial flexibility. Our modest debt level has enabled us to make capital decisions with limited restrictions imposed by debt covenants, lender oversight, and/or mandatory repayment schedules. Additionally, as the operator of substantially all of our anticipated future drilling locations per our December 31, 2017 reserve report, we control the timing and selection of drilling locations as well as completion schedules. This allows us to modify our capital spending program depending on financial resources, leasehold requirements, and market conditions.

• Management experience.  Members of our key management team possess an average of overthirty years of experience in oil and gas exploration and production in multiple resource plays including the Wattenberg Field.

• Balanced oil and natural gas reserves and production.  At December 31, 2017, approximately 72% of total gross revenues were oil and condensate, 16% were natural gas, and 12% were natural gas liquids. We believe that this balanced commodity mix will provide diversification of sources of cash flow.

• Focus on efficiency and cost control. We have continued to demonstrate our ability to drill wells in a cost-efficient and safe way and to successfully integrate acquired assets without incurring significant increases in overhead.

• Safe workplace and reduced impact on surrounding areas. Our employees and contractors are important to us, so we strive to maintain a safety-first approach in our operations. Likewise, we seek to incorporate current technologies to meet regulatory requirements while reducing our impact on the environment and neighboring communities. Toward this effort, modern drilling and completion techniques allow us to concentrate our operations on a reduced number of surface

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locations. As the new locations are developed, we have decreased the overall number of wells by plugging and abandoning vertical wells, allowing us to return those sites to surface owners.

Properties

As of December 31, 2017, our estimated net proved oil and natural gas reserves, as prepared by Ryder Scott Company, L.P. ("Ryder Scott"), an independent reserve engineering firm, were 69.4 MMBbls of oil and condensate, 559.9 Bcf of natural gas, and 64.0 MMBbls of natural gas liquids. As of December 31, 2017, we had approximately 98,600 gross and 88,300 net acres under lease in the Wattenberg Field. We also have non-core leasehold in other areas of Colorado and southwest Nebraska approximating 238,500 gross and 200,500 net acres.

We currently operate over 78% of our proved producing reserves, and substantially all of our drilling and completion expenditures during the year ended December 31, 2017 were focused on the Wattenberg Field. Substantially all of our drilling and completion expenditures for the 2018 calendar year are anticipated to be focused on the Wattenberg Field. A high degree of operational and capital control gives us both operational focus and development flexibility to maximize returns on our leasehold position.

Significant Developments

Acquisitions

In December 2017, the Company completed the purchase of a total of approximately 30,200 net acres in the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement governing the transaction (the "GCII Agreement"). The effective date of this part of the transaction was November 1, 2017. The GCII Agreement also contemplates a second closing at which we will acquire operated producing properties subject to certain regulatory restrictions. The purchase price payable at the second closing will be determined based on the amount of then-current production from the properties conveyed and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.

In September 2017, we completed the second closing contemplated by the May 2016 purchase and sale agreement (the "GC Agreement") pursuant to which we agreed to acquire a total of approximately 33,100 net acres in the Greeley-Crescent area for $505 million (the "GC Acquisition"). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million, composed of cash of $6.3 million and assumed liabilities of $24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations.

In August 2017, we entered into an agreement with a third party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also executed a purchase and sale agreement with a private party for the acquisition of approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.

In March 2017, we acquired developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million, composed of cash and assumed liabilities.

Divestitures

During the year ended December 31, 2017, we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.

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Equity Offering

In November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 5,250,000 shares of common stock on the same terms and conditions. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to40,250,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were$312.2 million. The Company used the proceeds of the offering to pay a portion of the purchase price of the GCII Acquisitionand to repay amounts borrowed under the Revolver.

Revolving Credit Facility

We continue to maintain a borrowing arrangement with our bank syndicate (sometimes referred to as the “Revolver”) to provide us with liquidity that can be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of December 31, 2017, the Revolver provides for maximum borrowings of $500 million, subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including substantially all of our producing wells and developed oil and gas leases, and bears a variable interest rate on borrowings with the effective rate varying with utilization.

In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base.  The borrowing base was increased from $225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018. Due to outstanding letters of credit, approximately $399.5 million of the borrowing base was available to use for future borrowings as of December 31, 2017, subject to our covenant requirements.

2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of its 6.25% Senior Notes (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GCII Acquisition, repay the 2021 Senior Notes, and pay off the outstanding Revolver balance. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

2021 Senior Notes

In December 2017, the Company repurchased all $80 million aggregate principal amount of its 9% Senior Notes (the "2021 Senior Notes"). At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.

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Drilling and Completion Operations

During the periods presented below, we drilled or participated in the drilling of a number of wells that reached productive status in each respective period.  During the year ended December 31, 2017, we turned 109 gross operated wells to sales in ten separate spacing units.  None of the wells are classified as exploratory and 109 of the gross operated wells are classified as development. 

	Year Ended December 31,						Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017			2016
	Gross		Net	Gross		Net	Gross	Net	Gross	Net
Development Wells:
Productive:
Oil	172	*	112	21	**	18	4	4	8	1
Gas	—		—	—		—	—	—	1	—
Nonproductive	—		—	—		—	—	—	—	—
Exploratory Wells:
Productive:
Oil	—		—	6		5	9	9	67	40
Gas	—		—	—		—	—	—	—	—
Nonproductive	—		—	—		—	1	—	—	—

*    Includes 63 gross (11 net) productive wells which we participated in on a non-operated basis.

**    Includes 3 gross (0.42 net) productive wells which we participated in on a non-operated basis.

All of the oil wells in the table above are located in, or adjacent to, the Wattenberg Field of the D-J Basin. As of December 31, 2017, we were the operator of 51 gross (47 net) wells in progress, which excludes 19 gross (16 net) wells for which we have only set surface casings, that were not included in the above well counts.

Production Data

The following table shows our net production of oil and natural gas, average sales prices, and average production costs for the periods presented:

	Year Ended December 31,
	2017		2016		2015
Production:
Oil (MBbls)	5,824		2,257		2,073
Natural Gas (MMcf)	24,834		12,086		8,472
NGLs (MBbls)	2,518		—		—
MBOE	12,481		4,271		3,485
BOED	34,194		11,670		9,548
Average sales price:
Oil ($/Bbl) *	$	44.35	$	34.43	$	40.08
Natural Gas ($/Mcf)	$	2.33	$	2.44	$	2.71
NGLs ($/MBbls)	$	17.10	$	—	$	—
BOE *	$	28.79	$	25.09	$	30.43
Average lease operating expenses ("LOE") per BOE	$	1.56	$	4.67	$	4.61

* Adjusted to include the effect of transportation and gathering expenses.

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Major Customers

We sell our crude oil, natural gas, and NGLs to various purchasers under multiple contractual arrangements. For crude oil, we have several arrangements, ranging from month-to-month to long-term commitments. Notably, in 2014, we secured contracts with oil purchasers who transport oil via pipelines. Under these contracts, we entered into delivery commitments covering a portion of our anticipated future production over the next four to five years. Our natural gas is sold under contracts with two midstream gas gathering and processing companies. With current infrastructure and expansion plans, we believe that gas gathering and processing and oil takeaway capacity will be sufficient to meet our anticipated production growth. See further discussion in Note 16 to our consolidated financial statements. For the year ended December 31, 2017, three of our customers account for more than 10% of our revenues.

Oil and Gas Properties, Wells, Operations, and Acreage

We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

• royalties and other burdens and obligations, expressed or implied, under oil and gas leases;

• overriding royalties and other burdens created by us or our predecessors in title;

• a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farm-out agreements, production sales contracts, and other agreements that may affect the properties or title thereto;

• back-ins and reversionary interests existing as a result of pooling under state orders;

• liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors, and contractual liens under operating agreements;

• pooling, unitization and communitization agreements, declarations, and orders; and

• easements, restrictions, rights-of-way, and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are customary in the industry for properties of the kind that we own.

The following table shows, as of December 31, 2017, by state, our producing wells, developed acreage, and undeveloped acreage:

	Productive Wells		Developed Acreage		Undeveloped Acreage 1
State	Gross	Net	Gross	Net	Gross	Net
Colorado	1,014	650	32,700	26,800	157,800	119,300
Nebraska	—	—	—	—	146,600	142,700
Kansas	—	—	—	—	800	800
Total	1,014	650	32,700	26,800	305,200	262,800

¹    Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of oil and natural gas regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.

    The following table shows, as of December 31, 2017, the status of our gross acreage:

State	Held by Production	Not Held by Production
Colorado	90,900	99,600
Nebraska	—	146,600
Kansas	—	800
Total	90,900	247,000

Leases that are held by production generally remain in force so long as oil or natural gas is produced from the well on

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the particular lease.  Leased acres which are not held by production may require annual rental payments to maintain the lease until the expiration of the lease or the time oil or natural gas is produced from one or more wells drilled on the leased acreage.  At the time oil or natural gas is produced from wells drilled on the leased acreage, the lease is generally considered to be held by production.

The following table shows the calendar years during which our leases not currently held by production will expire unless a productive oil or natural gas well is drilled on the lease or the lease is renewed.

Leased Acres (Gross)	Expiration of Lease
63,200	2018
24,000	2019
13,800	2020
91,400	2021
54,600	After 2021

The overriding royalty interests that we own are not material to our business.

Oil and Natural Gas Reserves

Our estimated proved reserve quantities increased by 143% from December 31, 2016 to December 31, 2017.  At December 31, 2017, we had estimated proved reserves of 69.4 MMBbls of oil and condensate, 559.9 Bcf of natural gas, and 64.0 MMBbls of natural gas liquids. The estimated standardized measure of future net cash flow from our reserves at December 31, 2017 was $1.6 billion and the estimated PV-10 value of our reserves at that date was $1.8 billion. PV-10 is a non-GAAP measure that reflects the present value, discounted at 10%, of estimated future net revenues from our proved reserves. We present a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows in Item 7 under "Non-GAAP Financial Measures." The PV-10 value as of December 31, 2017 increased compared to December 31, 2016 by $1.3 billion. The increase in estimated proved reserve quantities and PV-10 value is primarily due to acquisitions completed during 2017, extensions resulting in new proved undeveloped reserve increases, increased pricing during 2017, and revisions resulting in probable reserves being recognized as proved producing reserves.

Ryder Scott prepared the estimates of our proved reserves, future production, and income attributable to our leasehold interests as of December 31, 2017.  Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years.  The estimates of proved reserves, future production, and income attributable to certain leasehold and royalty interests are based on technical analyses conducted by teams of geoscientists and engineers employed at Ryder Scott.  The office of Ryder Scott that prepared our reserves estimates is registered in the State of Texas (License #F-1580).  Ryder Scott prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses, price differentials, authorizations for expenditure, and geological and geophysical data.

The report of Ryder Scott dated January 26, 2018, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott, as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

Our reserves technical team, which consists of our Reservoir Engineering Manager, VP of Exploration, Chief Operations Officer, and Chief Development Officer, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission.  Our technical team has an average of over thirty years of experience in oil and gas exploration and development.

Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and natural gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices, and with existing technology.  Accordingly, any changes in prices, operating and development costs, regulations, technology, or other factors could significantly increase or decrease estimates of proved reserves.

Estimates of volumes of proved reserves at year end are presented in barrels for oil, Mcf for natural gas, and barrels for NGL at the official temperature and pressure bases of the areas in which the natural gas reserves are located.

The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include decline curve analysis, which incorporate extrapolations of historical production and pressure data

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available through December 31, 2017 in those cases where this data was considered to be definitive.  The data used in this analysis was obtained from public sources and was considered sufficient for calculating producing reserves. The undeveloped reserves were estimated by the analogy method.  The analogy method uses pertinent well data obtained from public sources that was available through December 31, 2017.

Below are estimates of our net proved reserves at December 31, 2017, all of which are located in Colorado:

	Oil (MBbls)	Natural Gas (MMcf)	NGL (MBbl)	MBOE
Proved:
Developed	26,552	219,279	24,251	87,350
Undeveloped	42,844	340,614	39,702	139,315
Total	69,396	559,893	63,953	226,665

The following tabulations present the PV-10 value of our estimated reserves as of December 31, 2017, 2016, and 2015 (in thousands):

	Proved - December 31, 2017
	Developed									Total
	Producing			Non-producing			Undeveloped			Proved
Future cash inflow	$	1,804,029		$	291,678		$	3,397,800		$	5,493,507
Future production costs	(492,270		)	(63,278		)	(735,821		)	(1,291,369		)
Future development costs	(47,562		)	(18,384		)	(982,910		)	(1,048,856		)
Future pre-tax net cash flows	$	1,264,197		$	210,016		$	1,679,069		$	3,153,282
PV-10 (Non-U.S. GAAP)	$	861,685		$	142,996		$	751,603		$	1,756,284

	Proved - December 31, 2016
	Developed								Total
	Producing			Non-producing		Undeveloped			Proved
Future cash inflow	$	414,230		$	—	$	1,766,443		$	2,180,673
Future production costs	(177,138		)	—		(466,955		)	(644,093		)
Future development costs	(29,634		)	—		(554,903		)	(584,537		)
Future pre-tax net cash flows	$	207,458		$	—	$	744,585		$	952,043
PV-10 (Non-U.S. GAAP)	$	154,261		$	—	$	322,087		$	476,348

	Proved - December 31, 2015
	Developed								Total
	Producing			Non-producing		Undeveloped			Proved
Future cash inflow	$	494,858		$	—	$	1,215,752		$	1,710,610
Future production costs	(172,210		)	—		(289,887		)	(462,097		)
Future development costs	(32,700		)	—		(307,749		)	(340,449		)
Future pre-tax net cash flows	$	289,948		$	—	$	618,116		$	908,064
PV-10 (Non-U.S. GAAP)	$	198,056		$	—	$	240,086		$	438,142

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The following table presents the prices used to prepare the reserve estimates, which are based on the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:

	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2017 (Average)	$	46.57	$	2.21	$	16.06
December 31, 2016 (Average)	$	36.07	$	2.44	$	—
December 31, 2015 (Average)	$	41.33	$	2.60	$	—

During the year ended December 31, 2017, the combined effect of our drilling, acquisition, and participation activities and increased commodity prices generated an increase in projected future cash inflow from proved reserves of $3.3 billion and an increase in future pre-tax net cash flow of $2.2 billion from December 31, 2016 to December 31, 2017.  During the same period, our PV-10 from proved reserves increased by $1.3 billion.  During the year ended December 31, 2017, we incurred capital expenditures of approximately $600.0 million related to the acquisition and development of proved reserves.

During the year ended December 31, 2016, the combined effect of our drilling, acquisition, and participation activities partially offset by declining commodity prices generated an increase in projected future cash inflow from proved reserves of $470.1 million and an increase in future pre-tax net cash flow of $44.0 million from December 31, 2015 to December 31, 2016.  During the same period, our PV-10 from proved reserves increased by $38.2 million.  During the year ended December 31, 2016, we incurred capital expenditures of approximately $283.3 million related to the acquisition and development of proved reserves.

Our drilling, acquisition, and participation activities during the four months ended December 31, 2015 and changes in commodity prices resulted in a decrease in projected future cash inflow from proved reserves of $336.0 million from August 31, 2015. Future pre-tax net cash flow decreased $25.2 million from August 31, 2015 to December 31, 2015. During that same period, our PV-10 from proved reserves decreased by $0.1 million.  During the four months ended December 31, 2015, we incurred capital expenditures of approximately $92.5 million related to the acquisition and development of proved reserves.

Our drilling, acquisition, and participation activities, partially offset by declining commodity prices, during the year ended August 31, 2015 generated an increase in projected future cash inflow from proved reserves of $206.6 million compared to August 31, 2014. However, future pre-tax net cash flow decreased $149.6 million from August 31, 2014 to August 31, 2015 as per-unit costs did not decline commensurate with per-unit future cash inflow.  During that same period, our PV-10 from proved reserves decreased by $95.4 million.  During the year ended August 31, 2015, we incurred capital expenditures of approximately $203.2 million related to the acquisition and development of proved reserves.

In general, the volume of production from our oil and gas properties declines as reserves are depleted.  Unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.  Accordingly, volumes generated from our future activities are highly dependent upon our success in acquiring or finding additional reserves, and the costs incurred in doing so.

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Proved Undeveloped Reserves	Net Reserves (MBOE)
Beginning September 1, 2014	19,211
Converted to proved developed	(414	)
Extensions	17,633
Acquisitions	3,780
Divestitures	(1,278	)
Revisions	2,689
Ending August 31, 2015	41,621
Converted to proved developed	(1,869	)
Extensions	17,161
Acquisitions	11,960
Divestitures	(4,360	)
Revisions	(16,224	)
Ending December 31, 2015	48,289
Converted to proved developed	(806	)
Extensions	3,110
Acquisitions	50,530
Divestitures	(6,479	)
Revisions	(19,155	)
Ending December 31, 2016	75,489
Converted to proved developed	(23,781	)
Extensions	46,913
Acquisitions	34,867
Divestitures	(235	)
Revisions	6,062
Ending December 31, 2017	139,315

At December 31, 2017, our proved undeveloped reserves were139,315MBOE. During 2017, the GCII Acquisition, along with other minor acquisitions, led to an increase of34,867MBOE in proved undeveloped reserves.  This increase was partially offset by a decrease of235MBOE as a result of divestitures. In addition to the23,781MBOE of prior year proved undeveloped reserves converted to proved developed reserves, we added46,913MBOEof proved undeveloped reserves which were primarily attributable to extending our development plan by a year due to the passage of time as well as the addition of a third rig for the second and third years of our development plan. Further, due to a better commodity market environment, our increase in expected drilling activity positively affected our proved undeveloped reserves.  Consistent with prior years, we limited our undeveloped locations related to horizontal wells to be drilled within this three-year horizon.

During the year end December 31, 2017, we converted 23,781 MBOE, or 32%, of our proved undeveloped reserves as of December 31, 2016 into proved developed reserves, requiring $185.2 million of drilling and completion capital expenditures. All proved undeveloped reserves as of December 31, 2017 are expected to be converted to proved producing within three years, and within five years of their initial booking. Based on our current drilling plans for the next three years, we expect to allocate more funds to developmental drilling in areas of established production where ongoing and planned midstream infrastructure buildout continues. None of our proved undeveloped reserves as of December 31, 2017 have been in this category for more than five years.

At December 31, 2016, our proved undeveloped reserves were 75,489 MBOE. During 2016, the GC Acquisition, along with other minor acquisitions, led to an increase of 50,530 MBOE in proved undeveloped reserves.  These acquisitions allowed for the creation of spacing units with higher working interests, opportunities to drill longer laterals, and increased focus on our development program in the core Wattenberg area. This increase was partially offset by a decrease of 12,144 MBOE as a result of the GC Acquisition and related changes to our development plan that resulted in the removal of certain legacy PUD locations from the three-year drilling plan. This significant change to our development plan resulted in many of the legacy proved undeveloped locations being removed from the development plan. Consequently, only 806 MBOE, or 2%, of prior year proved undeveloped

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reserves converted to proved developed reserves. During 2016, we also developed 3,217 MBOE of acquired proved undeveloped reserves during the year, and we drilled 5.4 net exploratory wells. Further, due to a better commodity market environment, our increase in expected drilling activity positively affected our proved undeveloped reserves.  While our 2015 reserves estimate assumed no rig initially then an increase to two rigs during the first year, our 2016 reserves estimate assumed two rigs working continually throughout the three-year plan period.

At December 31, 2015, our proved undeveloped reserves were 48,289 MBOE. We drilled 9 net exploratory wells and 4 net development wells during the four months ended December 31, 2015. This generated proved developed reserves from those exploratory wells as well as new proved undeveloped reserves due to direct offset locations. As a result, we recognized an increase in proved undeveloped reserves from extensions of 17,161 MBOE. The 4 net development wells converted 1,869 MBOE during the four months ended December 31, 2015, or 4%, of our proved undeveloped reserves as of August 31, 2015 into proved developed reserves, requiring $17.7 million of drilling and completion capital expenditures. Our proved undeveloped conversion rate for this four-month period is not comparable to the conversion rate for the full-year periods discussed above and below.

At August 31, 2015, our proved undeveloped reserves were 41,621 MBOE. We drilled 40 net exploratory wells and one net development well during the year ended August 31, 2015. This generated proved developed reserves from those exploratory wells, as well as new proved undeveloped reserves due to direct offset locations. In addition, our reserve estimates reflect the positive impact of additional offset operator activities within the Wattenberg Field. As a result, we recognized an increase in proved undeveloped reserves from extensions of 17,633 MBOE. The one net development well converted 414 MBOE during the year ended August 31, 2015, or 2%, of our proved undeveloped reserves as of August 31, 2014 into proved developed reserves, requiring $5.0 million of drilling and completion capital expenditures. Our conversion rate during the fiscal year ended August 31, 2015 was affected by our focus at that time on delineation of our leasehold rather than immediate development. As discussed above, our development activities and conversion rate have increased significantly since that time.

Delivery Commitments

See "Volume Commitments" in Note 16 to our consolidated financial statements included elsewhere in this report.

Competition and Marketing

We are faced with strong competition from many other companies and individuals engaged in the oil and gas business, many of which are very large, well-established energy companies with substantial capabilities and established earnings records.  We may be at a competitive disadvantage in acquiring oil and gas prospects since we must compete with these companies, many of which have greater financial resources and larger technical staffs.  It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business.

Exploration for and production of oil and natural gas are affected by the availability of pipe, casing and other tubular goods, and certain other oil field equipment including drilling rigs and tools.  We depend upon independent contractors to furnish rigs, pressure pumping equipment, and tools to drill and complete our wells.  Higher prices for oil and natural gas may result in competition among operators for drilling and completion equipment, tubular goods, and drilling and completion crews, which may affect our ability to drill, complete, and work over wells in a timely and cost-effective manner.

The market for oil and natural gas is dependent upon a number of factors that are beyond our control and the effects of which are difficult to predict.  These factors include the proximity of wells to, and the capacity of, oil and natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation.  In addition, new legislation may be enacted that would impose price controls or additional excise taxes on oil, natural gas, or both.  Oversupplies of oil and natural gas can be expected to occur from time to time and may result in, among other things, producing wells being shut-in.  Imports of oil and natural gas may adversely affect the market for domestic oil and natural gas.

The market price for oil is significantly affected by policies adopted by the member nations of the Organization of the Petroleum Exporting Countries or OPEC.  Members of OPEC establish production quotas among themselves for petroleum products from time to time with the intent of influencing the global supply of oil and consequently price levels.  We are unable to predict the effect, if any, that OPEC, its members, or other countries will have on the amount of, or the prices received for, oil and natural gas.

Natural gas prices are now largely influenced by competition.  Competitors in this market include producers, natural gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as

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coal.  Changes in government regulations relating to the production, transportation, and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry.

General

Our offices are located at 1675 Broadway Suite 2600, Denver, CO 80202. Our office telephone number is (720) 616-4300, and our fax number is (720) 616-4301. 

Our Greeley offices includes field offices and an equipment yard.

As of December 31, 2017, we had 122 full-time employees.

Available Information

We make available on our website, www.srcenergy.com, under “Investor Relations, SEC Filings,” free of charge, our annual and transition reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”). You may also read or copy any document we file at the SEC's public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington D.C. 20549, or may obtain copies of such documents at the SEC's website at www.sec.gov. Please call the SEC at (800) SEC-0330 for further information on the public reference room.

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Governmental Regulation

Our operations are subject to various federal, state, and local laws and regulations that change from time to time. Many of these regulations are intended to prevent pollution and protect environmental quality, including regulations related to permit requirements for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling, completing and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process, groundwater testing, air emissions, noise, lighting and traffic abatement, and the plugging and abandonment of wells. Other regulations are intended to prevent the waste of oil and natural gas and to protect the rights of owners in a common reservoir. These include regulation of the size of drilling and spacing units or proration units, the number or density of wells that may be drilled in an area, the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose requirements regarding the ratability or fair apportionment of production from fields and individual wells. In addition, our operations are subject to regulations governing the pipeline gathering and transportation of oiland natural gas as well as various federal, state, and local tax laws and regulations.

Failure to comply with applicable laws and regulations can result in substantial penalties. Our competitors in the oil and gas industry are generally subject to regulatory requirements and restrictions similar to those that affect our operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. We are unable to predict the future costs or impact of compliance with applicable laws and regulations.

Regulation of production

Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and gas exploration, production, and related operations.  Most states require drilling permits, drilling and operating bonds, the filing of various reports, and the satisfaction of other requirements relating to the exploration and production of oil and natural gas.  Many states also have statutes or regulations addressing conservation matters including provisions governing the size of drilling and spacing units or proration units, the density of wells, and the unitization or pooling of oil and gas properties. The number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. In addition, certain of the horizontal wells we intend to drill may require pooling of our lease interests with the interests of third parties.  Some states like Colorado allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on the voluntary pooling of lands and leases. In areas with voluntary pooling, it may be more difficult to develop a project if the operator owns less than 100% of the leasehold, or one or more of the leases do not provide the necessary pooling authority. Further, the statutes and regulations of some states limit the rate at which oil and natural gas is produced from properties, prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. This may limit the amount of oil and natural gas that we can produce from our wells and may limit the number of wells or locations at which we can drill.  The federal and state regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability.  Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with these laws.

The Colorado Oil and Gas Conservation Commission (“COGCC”) is the primary regulator of exploration and production of oil and gas resources in the principal area in which we operate.  The COGCC regulates oil and gas operators through rules, policies, written guidance, orders, permits, and inspections. Among other things, the COGCC enforces specifications regarding drilling, development, production, abandonment, enhanced recovery, safety, aesthetics, noise, waste, flowlines, and wildlife.  In recent years, the COGCC has amended its existing regulatory requirements and adopted new requirements with increased frequency. For example, in January 2016, the COGCC approved new rules that require local government consultation and certain best management practices for large-scale oil and natural gas facilities in certain urban mitigation areas. These rules also require operator registration and/or notifications to local governments with respect to future oil and natural gas drilling and production facility locations. The COGCC also approved new rules in 2013, 2014 and 2015.

Regulation of sales and transportation of natural gas

Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978, and Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all “first sales” of natural gas. As a result, our sales of natural gas may be made at market prices, subject to applicable contract provisions. Since 1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters, but we do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers, and marketers with which we compete.

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In August 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. The 2005 EPA directs the FERC and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for “any entity,” including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. FERC rules implementing this provision make it unlawful in connection with the purchase or sale of natural gas or transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme, or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. This anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases, or transportation subject to FERC jurisdiction.

In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our administrative costs.

Gathering is exempt from federal regulation under the NGA, but is subject to various state regulations, which include safety, environmental, and in some circumstances, nondiscriminatory take requirements. FERC has in the past reclassified transportation facilities previously considered to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and conversely, has also reclassified non-jurisdictional gathering facilities as subject to FERC jurisdiction. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

Transportation and safety of natural gas is also subject to other federal and state laws and regulations, including regulation by the Department of Transportation under the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2012. The failure to comply with these rules and regulations can result in substantial penalties.

Our production and gathering facilities are not subject to jurisdiction of the FERC. Our natural gas sales prices, however, continue to be affected by intrastate and interstate gas transportation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive, along with the availability and terms of such transportation. Competition among suppliers has greatly increased in recent years. Our natural gas sales are generally made at the prevailing market price at the time of sale.

Regulation of sales and transportation of oil

Our sales of oil are affected by the availability, terms, and cost of transportation. Interstate transportation of oil by pipeline is regulated by the FERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate transportation of oil, natural gas liquids and refined products (collectively referred to as “petroleum pipelines”) be just and reasonable and non-discriminatory and that such rates and terms and conditions of service are subject to FERC regulation.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions in some jurisdictions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

Insofar as effective, interstate and intrastate rates are equally applicable to all comparable shippers, and accordingly, we do not believe that the regulation of oil transportation rates will affect our operations in any way that is materially different than those of our competitors who are similarly situated.

Regulation of derivatives and reporting of government payments

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was passed by Congress and signed into law in July 2010. The Dodd-Frank Act is designed to provide, among other things, a comprehensive framework for

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the regulation of the over-the-counter derivatives market with the intent to provide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects certain derivative market participants to a variety of capital, margin, and other requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for exemptions from certain of these requirements for commercial end-users.

Environmental Regulations

As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state, and local laws and regulations designed to protect and preserve natural resources and the environment.  Long-term trends in environmental legislation and regulation are generally toward stricter standards, and this trend is likely to continue.  These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling, and other activities on certain lands lying within wilderness and other protected areas; mandate requirements and standards for operations; impose substantial liabilities and remedial obligations for pollution; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification, and renewal by issuing authorities.  Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions, or both.  In March 2015, the COGCC implemented regulatory and statutory amendments that significantly increased the potential penalties for violating the Colorado Oil and Gas Conservation Act or its implementing regulations, orders, or permits.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict and joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites.  Persons responsible for the release or threatened release of hazardous substances under CERCLA may be subject to liability for the costs of cleaning up those substances and for damages to natural resources. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.   Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum-related products.  The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance.  Although RCRA classifies certain oil field wastes as non-hazardous "solid wastes,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. A proposed consent decree filed in December 2016 between the Environmental Protection Agency ("EPA") and certain environmental groups commits the EPA to deciding whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019.

Certain of our operations are subject to the federal Clean Air Act (“CAA”) and similar state and local requirements. The CAA may require certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air-emission-related issues. Greenhouse gas recordkeeping and reporting requirements under the CAA took effect in 2011 and impose increased administrative and control costs. Federal New Source Performance Standards regarding oil and gas operations (“NSPS OOOO”) took effect in 2012, with more subsequent amendments, all of which have likewise added administrative and operational costs. In June 2016, EPA finalized new regulations under the CAA to reduce methane emissions from new and modified sources in the oil and natural gas sector (the “NSPS OOOOa”). These new regulations impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, and additional control requirements for gathering, boosting, and compressor stations. The EPA has proposed a two-year stay of the effective dates of several requirements of NSPS OOOOa. Concurrent with the proposed methane rules, the EPA also finalized a new rule regarding source determinations and permitting requirements for the onshore oil and gas industry under the CAA. Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to oil and natural gas operations that are more stringent than NSPS OOOO and directly regulate methane emissions from affected facilities.

In October 2015, the EPA lowered the national ambient air quality standard (“NAAQS”) for ozone under the CAA from 75 parts per billion to 70 parts per billion. Any resulting expansion of the ozone nonattainment areas in Colorado could cause oil and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements, and increased permitting delays and costs. In addition, the ozone nonattainment status for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area was bumped up by the EPA from “marginal” to “moderate” as a result of the area failing to attain the 2008 ozone NAAQS by the applicable attainment date of July 20, 2015. In 2016, the state of Colorado undertook a

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rulemaking to address the new “moderate” status, culminating in, among others, the incorporation of two existing state-only requirements for oil and natural gas operations into the federally-enforceable State Implementation Plan ("SIP"). During the fall of 2016, EPA also issued final Control Techniques Guidelines ("CTGs") for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-hour Non-Attainment area. In 2017, Colorado adopted new and more stringent air quality control requirements. The Denver Metro/North Front Range NAA is at risk of being reclassified again to “serious” if it does not meet the 2008 NAAQS by 2018 or obtain an extension of the deadline from the EPA. A “serious” classification would trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements becoming applicable to our operations and significant costs and delays in obtaining necessary permits. This process could result in new or more stringent air quality control requirements applicable to our operations.

The federal Clean Water Act (“CWA”) and analogous state laws impose requirements regarding the discharge of pollutants into waters of the U.S. and the state, including spills and leaks of hydrocarbons and produced water. The CWA also requires approval for the construction of facilities in wetlands and other waters of the U.S., and it imposes requirements on storm water run-off. In June 2016, the EPA finalized new CWA pretreatment standards that would prevent onshore unconventional oil and natural gas wells from discharging wastewater pollutants to public treatment facilities. In June 2015, the EPA and the U.S. Army Corps of Engineers adopted a new regulatory definition of “waters of the U.S.,” which governs which waters and wetlands are subject to the CWA. This rule has been stayed pending resolution of ongoing litigation. On January 31, 2018, the EPA signed a final rule delaying the applicability date of the “waters of the U.S.” for several years while the EPA continues to conduct a substantive re-evaluation of the definition of “waters of the U.S.”

The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for threatened or endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. In such areas, we may be prohibited from conducting operations at certain locations or during certain periods, and we may be required to develop plans for avoiding potential adverse effects. In addition, certain species are subject to varying degrees of protection under state laws.

Federal laws including the CWA require certain owners or operators of facilities that store or otherwise handle oil and produced water to prepare and implement spill prevention, control, countermeasure, and response plans addressing the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) subjects owners and operators of facilities to strict and joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities.

In 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic conditions. Based on these findings, the EPA adopted regulations under the CAA that, among other things, established Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. In a subsequent ruling, the U.S. Supreme Court upheld a portion of EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG best available control technology ("BACT") requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, EPA issued a proposed rule to revise its PSD and Title V regulations applicable to GHGs in accordance with these court rulings, including proposing a de minimis level of GHG emissions below which BACT is not required. Depending on what EPA does in a final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the oil and natural gas that we produce.

In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. While Congress has not enacted significant legislation relating to GHG emissions, it may do so in the future and, moreover, several state and regional initiatives have been enacted aimed at monitoring and/or reducing GHG emissions through cap and trade programs.

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The adoption of new laws, regulations, or other requirements limiting or imposing other obligations on GHG emissions from our equipment and operations, and the implementation of requirements that have already been adopted, could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions in other sectors, such as the power sector under EPA’s August 2015 Clean Power Plan, could adversely affect demand for the oil and natural gas that we produce. In March 2017, President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of the Clean Power Plan.  The EPA subsequently published a proposed rule to repeal the Clean Power Plan in October 2017.  A final rule is expected following a comment period.

Further GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris. Pursuant to the agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update its pledge in five yearly intervals starting in 2020. GHG emissions in the earth’s atmosphere have also been shown to produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events, any of which could have an adverse effect on our operations. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement.

Hydraulic Fracturing

We operate primarily in the Wattenberg Field of the D-J Basin where the rock formations are typically tight, and it is a common practice to use hydraulic fracturing to allow for or increase hydrocarbon production.  Hydraulic fracturing involves the process of injecting substances such as water, sand, and additives (some proprietary) under pressure into a targeted subsurface formation to create fractures, thus creating a passageway for the release of oil and gas.  Hydraulic fracturing is a technique that we commonly employ and expect to employ extensively in future wells that we drill and complete.

We outsource all hydraulic fracturing services to service providers with significant experience, and which we deem to be competent and responsible.  Our service providers supply all personnel, equipment, and materials needed to perform each stimulation, including the chemical mixtures that are injected into our wells.  We require our service companies to carry insurance covering various losses and liabilities that could arise in connection with their activities; however, insurance may not be available or adequate to cover losses and liabilities incurred, or may be prohibitively expensive relative to the perceived risk.  In addition to the drilling permit that we are required to obtain and the notice of intent that we provide the appropriate regulatory authorities, our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the relevant geographic location.

In recent years, environmental opposition to hydraulic fracturing has increased, and various governmental and regulatory authorities have adopted or are considering new requirements for this process. To the extent that these requirements increase our costs or restrict our development activities, our business and prospects may be adversely affected.

The EPA has asserted that the Safe Drinking Water Act (“SDWA”) applies to hydraulic fracturing involving diesel fuel, and in February 2014, it issued final guidance on this subject. The guidance defines the term “diesel fuel,” describes the permitting requirements that apply under SDWA for the underground injection of diesel fuel in hydraulic fracturing, and makes recommendations for permit writers. Although the guidance applies only in those states, excluding Colorado, where the EPA directly implements the Underground Injection Control Class II program, it could encourage state regulatory authorities to adopt permitting and other requirements for hydraulic fracturing. In addition, from time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing under the SDWA. If such legislation were enacted, operators engaged in hydraulic fracturing could be required to meet additional federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and provide additional public disclosure of the chemicals used in the fracturing process.

The EPA has also conducted a nationwide study into the effects of hydraulic fracturing on drinking water. In June 2015, the EPA released a draft study report for peer review and comment. The draft report did not find evidence of widespread systemic impacts to drinking water, but did find a relatively small number of site-specific impacts. The EPA noted that these results could indicate that such effects are rare or that other limiting factors exist. In December 2016, EPA released the final report on impacts from hydraulic fracturing activities on drinking water, concluding that hydraulic fracturing activities can impact drinking water resources under some circumstances and identifying some factors that could influence these impacts.

Federal agencies have also adopted or are considering additional regulation of hydraulic fracturing. In March 2016, the U.S. Occupational Safety and Health Administration (“OSHA”) issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances

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Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing. In March 2015, the Bureau of Land Management (“BLM”) issued a new rule regulating hydraulic fracturing activities involving federal and tribal lands and minerals, including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water. The BLM rescinded the rule in December 2017; however, the BLM’s rescission has been challenged by several states in the United States District Court of the District of Northern California.

In November 2016, the BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules became effective in January 2017, but are subject to ongoing litigation. In December 2017, the BLM published a rule to temporarily suspend or delay certain rule requirements until January 2019; that rule is also the subject of litigation in federal court.

In Colorado, the primary regulator is the COGCC, which has adopted regulations regarding chemical disclosure, pressure monitoring, prior agency notice, emission reduction practices, and offset well setbacks with respect to hydraulic fracturing operations. As part of these requirements, operators must report all chemicals used in hydraulically fracturing a well to a publicly searchable registry website developed and maintained by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.

Apart from these ongoing federal and state initiatives, local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered into memoranda of agreement with oil and gas producers to accomplish the same objective. In addition, during the past few years, five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. Local district courts have struck down the ordinances for certain of those Colorado cities, and these decisions were upheld by the Colorado Supreme Court in May 2016. Nevertheless, there is a continued risk that cities will adopt local ordinances that seek to regulate the time, place, and manner of hydraulic fracturing activities, and oil and gas operations generally, within their respective jurisdictions.

During 2014, opponents of hydraulic fracturing also sought statewide ballot initiatives that would have restricted oil and gas development in Colorado by, among other things, significantly increasing the setback between oil and natural gas wells and occupied buildings. These initiatives were withdrawn from the November 2014 ballot in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities.

During 2016, opponents of hydraulic fracturing again advanced various options for ballot initiatives restricting oil and gas development in Colorado. Proponents of two such initiatives attempted to qualify the initiatives to appear on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a minimum distance of 2,500 feet between wells and any occupied structures or "areas of special concern". If implemented, this proposal would have made the vast majority of the surface area of the state ineligible for drilling, including substantially all of our planned future drilling locations. The second proposal would have amended the state constitution to give local governmental authorities the ability to regulate, or to ban, oil and gas exploration, development, and production activities within their boundaries notwithstanding state rules and approvals to the contrary. If implemented, this proposal could have resulted in us becoming subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans on our activities in various jurisdictions. In August 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponents of the proposals had failed to collect enough valid signatures to have the proposals included on the ballot. However, similar proposals may be made in 2018 and in subsequent years. Because a substantial portion of our operations and reserves are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes, or regulatory developments, such developments could materially impact our results of operations, production, and reserves.

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ITEM 1A. RISK FACTORS

Investors should be aware that any purchase of our securities involves risks, including those described below, which could adversely affect the value of our securities. We do not make, nor have we authorized any other person to make, any representation about the future market value of our securities. In addition to the other information contained in this report, the following factors should be considered carefully in evaluating an investment in our securities. Except where the context indicates otherwise, substantially all of the risks described below relating to oil and natural gas and related activities apply to NGLs as well.

Risks Relating to Our Business and the Industry

A decline in oil and natural gas prices may adversely affect our business, financial condition, or results of operations and our ability to meet our financial commitments.

The prices we receive for our oil and natural gas significantly affect many aspects of our business, including our revenue, profitability, access to capital, quantity and present value of proved reserves, and future rate of growth. Oil and natural gas are commodities, and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. In the recent past, benchmark oil prices have fallen from highs of over $100 per Bbl to lows below $30 per Bbl, and natural gas prices have experienced declines of comparable magnitude. Oil and natural gas prices will likely continue to be volatile in the future and will 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 and natural gas;

• prevailing prices on local oil and natural gas price indexes in the areas in which we operate;

• localized supply and demand fundamentals and gathering, processing, and transportation availability;

• the actions, or inaction, of OPEC;

• the price and quantity of imports of foreign oil and natural gas;

• political conditions or hostilities in oil-producing and natural gas-producing regions and related sanctions, including current conflicts in the Middle East and conditions in Africa, South America, and Russia;

• the level of global oil and domestic natural gas exploration and production;

• the level of global oil and domestic natural gas inventories;

• weather conditions and natural disasters;

• domestic and foreign governmental regulations;

• exports from the United States of liquefied natural gas and oil;

• speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

• price and availability of competitors’ supplies of oil and natural gas;

• technological advances affecting energy consumption; and

• the price and availability of alternative fuels.

Sustained periods of reduced oil and natural gas prices and the resultant effect such prices have on our drilling economics and our ability to fund our operations could require us to re-evaluate and postpone or eliminate our development drilling, which would make it more difficult for us to achieve expected levels of production. Lower prices may also reduce the amount of oil and natural gas that we can produce economically and may cause the value of our estimated proved reserves at future reporting dates to decline, which would likely result in a reduction in our proved undeveloped reserves and PV-10 and standardized measure values.

Lower oil and natural gas prices may also reduce our borrowing ability. Our borrowing capacity is based substantially on the value of our oil and natural gas reserves which are, in turn, impacted by prevailing oil and natural gas prices. Our actual borrowings may not exceed our borrowing base, which is currently $400 million.The next semi-annual redetermination of the borrowing base is scheduled to occur in April 2018.If our borrowing base were to decline significantly, we could have to either raise additional capital or adjust our drilling plan. In addition, if the lenders reduce the borrowing base below the then-outstanding balance, we will be required to repay the difference between the outstanding balance and the reduced borrowing base, and we may not have or be able to obtain the funds necessary to do so.

We have historically relied on the availability of additional capital, including proceeds from the sale of equity, debt, and convertible securities, to execute our business strategy. Future acquisitions may require substantial additional capital, the availability of which will depend in significant part on current and expected commodity prices. If we are unable to raise capital on acceptable terms in the future, we may be unable to pursue future acquisition.

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To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. If oil and natural gas prices decline, we will not be able to hedge future production at the same pricing level as our current hedges, and our results of operations and financial condition would be negatively impacted. In addition, hedging arrangements can expose us to risk of financial loss in some circumstances, including when production is less than expected, a counterparty to a hedging contract fails to perform under the contract, or there is a change in the expected differential between the underlying price in the hedging contract and the actual prices received.

Accordingly, any substantial or extended decline in the prices that we receive for our production would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations, and our results of operations.

Operating hazards may adversely affect our ability to conduct business.

Our operations are subject to risks inherent in the oil and gas industry, such as:

• unexpected drilling conditions including loss of well control, loss of drilling fluid circulation, cratering, and explosions;

• uncontrollable flows of oil, natural gas, or well fluids;

• equipment failures, fires, or accidents;

• pollution, releases of hazardous materials, and other environmental risks; and

• shortages in experienced labor or shortages or delays in the delivery of equipment or the performance of services.

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. We do not maintain insurance for all of these risks, nor in amounts that cover all of the losses to which we may be subject, and the insurance that we have may not continue to be available on acceptable terms. Moreover, some risks that we face are not insurable. For example, a leak or other pollution event may occur without our knowledge, making it impossible for us to notify the insurer within the time period required by the policy. Also, we could in some circumstances have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation, and development operations to be curtailed while those activities are being completed.

Our actual production, revenues, and expenditures related to our reserves are likely to differ from those underlying our estimates of proved reserves. We may experience production that is less than estimated, and drilling costs that are greater than estimated, in our reserve report. These differences may be material.

Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

• historical production from the area compared with production from similar producing wells;

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil and natural gas prices; and

• assumptions concerning future operating costs, severance and excise taxes, development costs, and workover and remedial costs.

Because all reserve estimates are based on assumptions that may prove to be incorrect and are to some degree subjective, each of the following items may differ from those assumed in estimating proved reserves:

• the quantities of oil and natural gas that are ultimately recovered;

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• future cash flows from the development of reserves.

Historically, there has been a difference between our actual production and the production estimated in prior reserve reports. We cannot assure you that these differences will not be material in the future.

Approximately 61% of our estimated proved reserves at December 31, 2017 are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our estimates of proved undeveloped reserves

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reflect our plans to make significant capital expenditures to convert those reserves into proved developed reserves, including approximately $982.9 million in estimated capital expenditures during the five years ending December 31, 2022. The estimated development costs may not be accurate, development may not occur as scheduled, and results may not be as estimated. If we choose not to develop proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade to probable or possible any proved undeveloped reserves that are not developed or expected to be developed within this five-year time frame.

You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved reserves at December 31, 2017 is based on twelve-month average prices and costs as of the date of the estimate. These prices and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor we use when calculating standardized measure of discounted cash flows for reporting requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. Each of the foregoing considerations also impacts the PV-10 values of our reserves.

Seasonal weather conditions, wildlife and plant species conservation restrictions, and other constraints could adversely affect our ability to conduct operations.

Our operations could be adversely affected by weather conditions and wildlife and plant species conservation restrictions. In Colorado, certain activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt operations. These constraints and resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operational and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.

Similarly, some of our properties are located in relatively populous areas in the Wattenberg Field, and our operations in those areas may be subject to additional expenses and limitations. For example, we may incur additional expenses in those areas to mitigate visual impacts, noise, and odor issues relating to our operations, and we may find it more difficult to obtain drilling permits and other governmental approvals. In addition, the risk of litigation related to our operations may be higher in those areas. Any of these factors could have a material impact on our operations in the Wattenberg Field and could have a material adverse effect on our business, financial condition, and results of operations.

Furthermore, a critical habitat designation for certain wildlife under the U.S. Endangered Species Act or similar state laws could result in material restrictions to public or private land use and could delay or prohibit land access or development. The listing of particular species as threatened or endangered could have a material adverse effect on our operations in areas where those species are found.

Our future success depends upon our ability to find, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable. Drilling activities may be unsuccessful or may be less successful than anticipated.

In order to maintain or increase our reserves, we must locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to raise the capital necessary to finance our exploration, development, and acquisition activities. Without successful exploration, development, or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would have a material adverse effect on our financial condition.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs, drilling results, and the accuracy of our assumptions and estimates regarding potential well communication issues and other matters affecting the spacing of our wells. Because of these uncertainties, we do not know if the numerous potential drilling locations that we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other potential drilling locations.

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Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient quantities to cover drilling, operating, and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. There can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new 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 proved or unproved property or wells.

Acquisitions we pursue may not achieve their intended results and may result in us assuming unanticipated liabilities. These risks are heightened in the case of the GCII Acquisition due to its size relative to our prior acreage position.

Pursuing acquisitions is an important part of our growth strategy. However, achieving the anticipated benefits of any acquisition is subject to a number of risks and uncertainties. For example, we may discover title defects or adverse environmental or other conditions related to the acquired properties of which we are unaware at the time that we enter into the relevant purchase and sale agreement. Environmental, title, and other problems could reduce the value of the acquired properties to us, and depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We may assume all or substantially all of the liabilities associated with the acquired properties and may be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure that such potential remedies will be adequate for any liabilities that we incur, and such liabilities could be significant. Even though we perform due diligence reviews (including a review of title and other records) of the major properties that we seek to acquire that we believe are generally consistent with industry practices, these reviews are inherently incomplete. It is typically not feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. Moreover, even an in-depth review of records and properties may not necessarily reveal existing or potential liabilities or other problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. The discovery of any material liabilities associated with our acquisitions could materially and adversely affect our business, financial condition, and results of operations. In addition, completing the integration process for any acquisition may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of any acquired operations smoothly or efficiently or that the anticipated benefits of any transaction will be achieved. Further, acquisitions may require additional debt or equity financing, resulting in additional leverage or dilution of ownership.

The success of any acquisition will depend on, among other things, the accuracy of our assessment of the number and quality of the drilling locations associated with the properties to be acquired, future oil and natural gas prices, reserves and production, and future operating costs and various other factors. These assessments are necessarily inexact. Our assessment of certain of these factors will typically be based in part on information provided to us by the seller, including historical production data. Our independent reserve engineers typically will not provide a report regarding the estimated reserves associated with properties to be acquired. The assumptions on which our internal estimates are based may prove to be incorrect in a number of material ways, resulting in our not realizing the expected benefits of the acquisition. As a result, we may not recover the purchase price for the acquisition from the sale of production from the acquired properties or recognize an acceptable return from such sales.

We are subject to all of the foregoing risks with respect to the GCII Acquisition, and these risks are heightened with respect to that acquisition due to the significant amount of acreage acquired relative to our prior acreage position.

We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.

Our ability to execute our long-term operating strategy is highly dependent on our having access to capital when the need arises. Historically, we have addressed our liquidity needs through credit facilities, issuances of equity, debt, and convertible securities, sales of assets, joint ventures, and cash provided by operating activities. We will examine the following alternative sources of capital in light of economic conditions in existence at the relevant time:

• borrowings from banks or other lenders;

• the sale of non-core assets;

• the issuance of debt securities;

• the sale of common stock, preferred stock, or other equity securities;

• joint venture financing; and

• production payments.

The availability of these sources of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our

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credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value, and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises, which would adversely affect our production, cash flows, and capital expenditure plans.

We are dependent on third party pipeline, trucking, and rail systems to transport our production and gathering and processing systems to prepare our production. These systems have limited capacity and, at times, have experienced service disruptions. Curtailments, disruptions, or lack of availability in these systems interfere with our ability to produce and/or market the oil and natural gas we produce and could materially and adversely affect our cash flow and results of operations.

Market conditions or the unavailability of satisfactory oil and gas transportation and processing arrangements may hinder our access to oil and natural gas markets or delay our production. The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of gathering, processing, pipeline, trucking, and rail systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as when pipeline interruptions occur due to scheduled or unscheduled maintenance, accidents, excessive pressure, physical damage to the gathering or transportation system, lack of contracted capacity on such systems, inclement weather, labor or regulatory issues, or other reasons. A portion of our production may be interrupted, or shut in, from time to time as a result of these factors. Curtailments and disruptions in the systems we use may last from a few days to several months or longer. These risks are greater for us than for some of our competitors because our operations are focused on areas where there has been a substantial amount of development activity in recent years and resulting increases in production, and this has increased the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the increased production. For example, the gas gathering systems serving the Wattenberg Field have in recent years experienced high line pressures from time to time, and this has on occasion reduced capacity and caused gas production to be shut in. In addition, we might voluntarily curtail production in response to market conditions. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities, or lack of availability of transport would interfere with our ability to market the oil and natural gas that we produce and could materially and adversely affect our cash flow and results of operations and the expected results of our drilling program.

Oil and natural gas prices may be affected by local and regional factors.

The prices to be received 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 natural gas production and the actual (frequently lower) price that we receive for our production. Our average differential for the year ended December 31, 2017 was $(6.58) per barrel for oil and $(0.67) per Mcf for natural gas. These differentials are difficult to predict and may widen or narrow in the future based on market forces. The unpredictability of future differentials makes it more difficult for us to effectively hedge our production. Our hedging arrangements are generally based on benchmark prices and therefore do not protect us from adverse changes in the differential applicable to our production.

Lower oil and natural gas prices and other adverse market conditions may cause us to record ceiling test write-downs or other impairments, which could negatively impact our results of operations.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If, at the end of any fiscal period, we determine that the net capitalized costs of oil and gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. Once incurred, a ceiling test write-down is not reversible at a later date.

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning-of-the-month average of oil and natural gas prices for the preceding 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values or if estimated future development costs increase.

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The ceiling test calculation as of December 31, 2017 used average realized prices of $46.57 per barrel and $2.21 per Mcf. The oil price used at December 31, 2017 was approximately 29% higher than the December 31, 2016 price of $36.07 per barrel, and the gas price was approximately 9% lower than the December 31, 2016 price of $2.44 Mcf. In addition to our December 31, 2017 ceiling test calculation, we compare our net capitalized costs for oil and gas properties to the ceiling amount at various points during the year. At March 31, 2017, June 30, 2017, September 30, 2017, and December 31, 2017, the ceiling amount exceeded our net capitalized costs for oil and gas properties, and as such, no impairments were necessary. We may experience further ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur further write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. In addition, declining commodity prices or other adverse market conditions, such as declines in the market price of our common stock, could result in goodwill impairments or reductions in proved reserve estimates that would adversely affect our results of operation or financial condition.

We cannot control activities on properties that we do not operate, and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others, therefore, will depend upon a number of factors outside of our control, including the operator’s:

• timing and amount of capital expenditures;

• expertise and diligence in adequately performing operations and complying with applicable agreements, laws, and regulations;

• financial resources;

• inclusion of other participants in drilling wells; and

• use of technology.

As a result of an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected. In addition, our lack of control over non-operated properties makes it more difficult for us to forecast future capital expenditures and production.

We may be unable to satisfy our contractual obligations, including obligations to deliver oil and natural gas from our own production or other sources.

We have entered into agreements that require us to deliver minimum amounts of oil to four counterparties that transport oil via pipelines. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next three years. Since 2016, we have been obligated to deliver a combined volume of 11,157 Bbls of oil per day to three of these counterparties. We also committed to deliver 2,500 Bbls of oil per day to the fourth counterparty for approximately one and a half years beginning in the latter half of 2018. If we are unable to fulfill all of our contractual obligations from our own production or from oil and natural gas that we acquire from third parties, we may be required to pay penalties or damages pursuant to these agreements. We incurred such charges in the amount of $0.7 million during the year ended December 31, 2017.

Furthermore, in collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed during the third quarter of 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of seven years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in mid-2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of seven years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment.

Any future penalties or damages of the types described above could adversely impact our cash flows, profit margins, net income, and reserve values.

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We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on operations.

We operate in the highly competitive areas of oil and gas exploration, development, and production. Factors that affect our ability to compete successfully in the marketplace include:

• the availability of funds for, and information relating to, properties;

• the standards established by us for the minimum projected return on investment; and

• the transportation of natural gas and oil.

Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines, and national and local gas gatherers, many of which possess greater financial and other resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition, and results of operations may be adversely affected.

We may be unable to successfully identify, execute, or effectively integrate future acquisitions, which may negatively affect our results of operations.

Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue to pursue acquisitions in the future. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition, or if the acquisition occurs, effectively integrate the acquired business or properties into our existing business. Negotiations of potential acquisitions and the integration of acquired assets may require a disproportionate amount of management’s attention and our resources. Moreover, our debt agreements contain covenants that may limit our ability to finance an acquisition. Even if we complete additional acquisitions, new assets may not generate revenues comparable to our existing business, the anticipated cost efficiencies or synergies may not be realized, and the assets may not be integrated successfully or operated profitably. Our inability to successfully identify, execute, or effectively integrate future acquisitions may negatively affect our results of operations.

We may incur substantial costs to comply with the various federal, state, and local laws and regulations that affect our oil and natural gas operations, including as a result of the actions of third parties.

We are affected significantly by a substantial number of governmental regulations relating to, among other things, the release or disposal of materials into the environment, health and safety, land use, and other matters. A summary of the principal environmental rules and regulations to which we are currently subject is set forth in “Business and Properties-Governmental Regulation-Environmental Regulations.” Compliance with such laws and regulations often increases our cost of doing business and thereby decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.

The environmental laws and regulations to which we are subject may, among other things:

• require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;

• restrict the types, quantities, and concentrations of substances that can be released into the environment in connection with drilling, hydraulic fracturing, and production activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other "waters of the United States," threatened and endangered species habitat, and other protected areas;

• require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells;

• require us to add procedures and/or staff in order to comply with applicable laws and regulations; and

• impose substantial liabilities for pollution resulting from our operations.

In addition, we could face liability under applicable environmental laws and regulations as a result of the activities of previous owners of our properties or other third parties. For example, over the years, we have owned or leased numerous properties for oil and natural gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA, and state laws, we could be held liable for the removal or remediation of previously released materials or property contamination at such locations, or at third-party locations to which we have sent waste, regardless of our fault, whether we were responsible for the release or whether the operations at the time of the release were lawful.

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Compliance with, or liabilities associated with violations of or remediation obligations under, environmental laws and regulations could have a material adverse effect on our results of operations and financial condition.

New or amended environmental legislation or regulatory initiatives could result in increased costs, additional operating restrictions, or delays or have other adverse effects on us.

The environmental laws and regulations to which we are subject change frequently, often to become more burdensome and/or to increase the risk that we will be subject to significant liabilities. New or amended federal, state, or local laws or implementing regulations or orders imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of resources (especially from shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products. Any such outcome could have a material and adverse impact on our cash flows and results of operations.

For example, in 2014 and 2016, opponents of hydraulic fracturing sought statewide ballot initiatives in Colorado that would have restricted oil and gas development in Colorado and could have had materially adverse impacts on us. One of the proposed initiatives would have made the vast majority of the surface area of the state ineligible for drilling, including substantially all of our planned future drilling locations. Although none of the proposed initiatives were implemented, future initiatives are likely, including in 2018. Similarly, proposals are made from time to time to adopt new, or amend existing, laws and regulations to address hydraulic fracturing or climate change concerns through further regulation of exploration and development activities. The “Business and Properties-Governmental Regulation-Environmental Matters” section of this report includes a discussion of some recent environmental regulatory changes that have affected us. We cannot predict the nature, outcome, or effect on us of future regulatory initiatives, but such initiatives could materially impact our results of operations, production, reserves, and other aspects of our business.

The adoption and implementation of statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital required to conduct these activities.

The Dodd-Frank Act authorizes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. Regulations under the Dodd-Frank Act may, among other things, require us to comply with margin requirements in connection with our derivative activities. If we are required to post cash collateral in connection with some or all of our derivative positions, this would make it difficult or impossible to pursue our current hedging strategy. The regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The regulations may also reduce the number of potential counterparties in the market, which could make hedging more expensive.

If we reduce our use of derivatives as a result of the Dodd-Frank Act and its implementing regulations, our results of operations may be more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our financial position, results of operations, and cash flows. In addition, derivative instruments create a risk of financial loss in some circumstances, including when production is less than the volume covered by the instruments.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.

From time to time, legislative proposals are made that would, if enacted, result in the elimination of the immediate deduction for intangible drilling and development costs, the elimination of the deduction from income for domestic production activities relating to oil and gas exploration and development, the repeal of the percentage depletion allowance for oil and gas properties, and an extension of the amortization period for certain geological and geophysical expenditures. Such changes, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

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Our indebtedness adversely affects our cash flow and may adversely affect our ability to operate our business. Our ability to remain in compliance with debt covenants and make payments on our debt is subject to numerous risks.

As of December 31, 2017, the aggregate amount of our outstanding indebtedness was $550 million. Our indebtedness could have important consequences for investors, including the following:

• the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures, or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;

• the amount of our interest expense may increase because amounts borrowed under our credit facility bear interest at variable rates; if interest rates increase, this could result in higher interest expense; and

• our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, sell assets, borrow more money, or raise equity. We may not be able to refinance our debt, sell assets, borrow more money, or raise equity on terms acceptable to us, if at all.

Any failure to meet our debt obligations could harm our business, financial condition, and results of operations.

Our ability to make payments on and/or to refinance our indebtedness and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a significant extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions, and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness or to fund our other liquidity needs. For example, decreases in oil and natural gas prices in the recent past have adversely affected our ability to generate cash flow from operations and future decreases would have similar effects. If our cash flow and existing capital resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital, or restructure our debt, and any of these actions, if completed, could adversely affect our business and/or the holders of our securities. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, in a timely manner or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.

Our credit facility and the indenture governing our 2025 Senior Notes contain, and future debt agreements may contain, covenants that restrict or limit our ability to:

• pay dividends or distributions on our capital stock or issue preferred stock;

• repurchase, redeem, or retire our capital stock or subordinated debt;

• make certain loans and investments;

• sell assets;

• enter into certain transactions with affiliates;

• create or assume certain liens on our assets;

• enter into sale and leaseback transactions;

• merge or enter into other business combination transactions; or

• engage in certain other corporate activities.

Our credit facility also requires us to satisfy certain financial tests on an ongoing basis. Our ability to comply with these requirements may be affected by events beyond our control, and we cannot assure you that we will satisfy them in the future. In

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addition, these requirements could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the restrictive covenants under our debt agreements. Future debt agreements may have similar, or more restrictive, provisions.

A breach of any of the covenants in our debt agreements could result in a default under the agreement. A default, if not cured or waived, could result in all indebtedness outstanding under the agreement and other debt agreements becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

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

We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations. 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 unpaid costs and liabilities arising from the actions of other working interest owners. In addition, declines in commodity prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, will not be 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 them from our partners. This could materially adversely affect our financial position.

Our disclosure controls and procedures may not prevent or detect potential acts of fraud.

Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, and recorded, processed, summarized, and reported within the time periods specified in applicable SEC rules and forms.

Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our company have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by an unauthorized override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly, because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected.

Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price.

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, we are required to furnish a report by our management in this report regarding the effectiveness of our internal control over financial reporting. The management report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by management. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, investors could lose confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

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Substantially all of our producing properties are located in the D-J Basin in Colorado, making us vulnerable to risks associated with operating in one major geographic area.

Our operations have been focused on the D-J Basin in Colorado, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production, or interruption of transportation and processing services, and any resulting delays or interruptions of production from existing or planned new wells. For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition, or results of operations.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. We sell production to a small number of customers, as is customary in the industry. For the year ended December 31, 2017, we had three major customers, which represented 33%, 24%, and 17%, respectively, of our revenue during the period. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.

Failure to adequately protect critical data and technology systems could materially affect our operations.

Information technology solution failures, network disruptions, and breaches of data security could cause delays or cancellation of transactions, impede processing of transactions and reporting financial results, or cause inadvertent disclosure of non-public information or other problems, any of which could result in disruptions to our operations, liability to third parties, or damage to our reputation. A system failure or data security breach may have a material adverse effect on our financial condition, results of operations, or cash flows.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain or dispose of water at a reasonable cost and in compliance with applicable regulations may have a material adverse effect on our financial condition, results of operations, and cash flows.

Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. Colorado has a relatively arid climate and experiences drought conditions from time to time. If we are unable to obtain water to use in our operations from local sources or dispose of or recycle water used in operations, or if the price of water or water disposal increases significantly, we may be unable to produce oil and natural gas economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could materially and adversely affect our business. The risk of lease expiration typically increases at times when commodity prices are depressed, as the pace of our exploration and development activity tends to slow during such periods. The GCII Acquisition increased these risks for us as a large portion of the acreage we acquired in the transaction is undeveloped.

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We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and 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 oil and gas lease brokers or landmen 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 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.

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 December 31, 2017, we operated 227 gross horizontal producing wells, with an additional 51 horizontal wells waiting on completion, 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. Also, we generally use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. Ultimately, the success of new 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 successful than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, unfavorable commodity prices, or other factors, 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 gas properties, and the value of our undeveloped acreage could decline.

Risks Relating to our Common Stock

We do not intend to pay dividends on our common stock, and our ability to pay dividends on our common stock is restricted.

Since inception, we have not paid any cash dividends on our common stock. Cash dividends are restricted under the terms of our debt agreements, and we presently intend to continue the policy of using retained earnings for expansion of our business. Any future dividends also may be restricted by future agreements.

The price of our stock price has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.

The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events, including, among others:

• changes in production volumes, worldwide demand and prices for oil and natural gas;

• changes in market prices of oil and natural gas;

• changes in securities analysts’ estimates of our financial performance;

• fluctuations in stock market prices and volumes, particularly among securities of energy companies;

• changes in market valuations of similar companies;

• changes in interest rates;

• announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing oil and natural gas resources;

• announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;

• decreases in the amount of capital available to us;

• operating results that fall below market expectations or variations in our quarterly operating results;

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• loss of a relationship with a partner;

• the identification of and severity of environmental events and governmental and other third-party responses to the events; or

• additions or departures of key personnel,

could trigger significant declines in the price of our common stock. External events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and gas exploration and production industries, actual and expected production levels from OPEC members and other oil-producing countries and the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock.

Additional financings may subject our existing stockholders to significant dilution.

To the extent that we raise additional funds or complete acquisitions by issuing equity securities, our stockholders may experience significant dilution. In addition, debt financing, if available, may involve restrictive covenants. We may seek to access the public or private capital markets whenever conditions are favorable, even if we do not have an immediate need for additional capital at that time. Our access to the financial markets and the pricing and terms that we receive in those markets could be adversely impacted by various factors, including changes in general market conditions and commodity prices.

Equity compensation plans will result in future dilution of our common stock.

To the extent options to purchase common stock under our equity incentive plans are exercised, or shares of restricted stock or other equity awards are issued based on satisfaction of vesting requirements, holders of our common stock will experience dilution.

As of December 31, 2017, there were 8,738,146 shares reserved for issuance under our equity compensation plans, of which 1,087,386 restricted shares have been granted and are subject to vesting in the future based on the satisfaction of certain criteria established pursuant to the respective awards, 951,884 performance-vested restricted shares have been granted and are subject to future issuance based on the Company's total shareholder return relative to a selected peer group of companies over the performance period, and 5,636,834 of which are issuable upon the exercise of outstanding options to purchase common stock. Our outstanding options have a weighted average exercise price of $9.38 per share as of December 31, 2017.

Non-U.S. holders of our common stock, in certain situations, could be subject to U.S. federal income tax upon sale, exchange, or disposition of our common stock.

        It is likely that we are, and will remain for the foreseeable future, a U.S. real property holding corporation for U.S. federal income tax purposes because our assets consist primarily of "United States real property interests" as defined in the applicable Treasury regulations. As a result, under the Foreign Investment in Real Property Tax Act ("FIRPTA"), certain non-U.S. investors may be subject to U.S. federal income tax on gain from the disposition of shares of our common stock, in which case they would also be required to file U.S. tax returns with respect to such gain, and may be subject to a withholding tax. In general, whether these FIRPTA provisions apply depends on the amount of our common stock that such non-U.S. investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on an established securities market within the meaning of the applicable Treasury regulations. So long as our common stock continues to be regularly traded on an established securities market, only a non-U.S. investor who has owned, actually or constructively, more than 5% of our common stock at any time during the shorter of (i) the five-year period ending on the date of disposition and (ii) the non-U.S. investor's holding period for its shares may be subject to U.S. federal income tax on the disposition of our common stock under FIRPTA.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.    PROPERTIES

See Item 1 of this report.

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ITEM 3. LEGAL PROCEEDINGS

In July 2016, the Company was informed by the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division ("CDPHE") that it was expanding its review of the Company's facilities in connection with a Compliance Advisory previously issued by the CDPHE and subsequent inspections conducted by the CDPHE. The Compliance Advisory alleged issues at five Company facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. Subsequent tolling agreements between the Company and CDPHE addressed alleged similar storage tank leakage issues at other Company facilities in Colorado. On February 21, 2018, the Company and CDPHE entered into a Compliance Order on Consent resolving the issues related to leakage of volatile organic compounds at certain of the Company’s facilities in Colorado. The terms of the order do not have a material effect on the Company.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the NYSE American under the symbol “SRCI.”

Shown below is the range of high and low sales prices for our common stock as reported by the NYSE American for the past two years. 

Period Ended	High	Low
Three Months Ended March 31, 2016	$9.09	$5.41
Three Months Ended June 30, 2016	$8.41	$5.60
Three Months Ended September 30, 2016	$7.20	$5.88
Three Months Ended December 31, 2016	$9.85	$6.37

Period Ended	High	Low
Three Months Ended March 31, 2017	$9.40	$7.20
Three Months Ended June 30, 2017	$9.07	$6.19
Three Months Ended September 30, 2017	$9.76	$6.61
Three Months Ended December 31, 2017	$10.22	$7.76

As of February 19, 2018, the closing price of our common stock on the NYSE MKT was $8.92.

As of February 19, 2018, we had 241,786,159 outstanding shares of common stock and 80 shareholders of record.

Since inception, we have not paid any cash dividends on common stock.  Cash dividends are restricted under the terms of our debt agreements, and we presently intend to continue the policy of using retained earnings for expansion of our business.

Issuer Purchases of Equity Securities

Period	Total Number of Shares (or Units) Purchased	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs)
October 1, 2017 - October 31, 2017 (1)	2,161	$	9.42	—	—
November 1, 2017 - November 30, 2017 (1)	4,144	$	8.98	—	—
December 1, 2017 - December 31, 2017 (1)	—	$	—	—	—

(1) Pursuant to statutory minimum withholding requirements, certain of our employees and executives exercised their right to "withhold to cover" as a tax payment method for the vesting and exercise of certain shares. These elections were outside of a publicly announced repurchase plan.

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Comparison of Cumulative Return

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2017, with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the companies with a Standard Industrial Code ("SIC") of 1311. The SIC Code 1311 consists of a weighted average composite of publicly traded oil and gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on August 31, 2012 and in the S&P 500 Index and all companies with the SIC Code 1311 on the same date. The results shown in the graph below are not necessarily indicative of future performance.

	As of August 31,				As of December 31,
	2012	2013	2014	2015	2015	2016	2017
SRC Energy Inc.	100.00	334.29	480.71	383.57	304.29	318.21	304.64
S&P 500	100.00	118.70	148.67	149.38	155.95	174.60	212.71
SIC Code 1311	100.00	99.32	125.20	71.72	61.21	81.09	88.70

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data presented in this item has been derived from our audited consolidated financial statements that are either included in this report or in reports previously filed with the SEC.  The information in this item should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included in this report.

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31,
	2017			2016						2015		2014			2013
Results of Operations (in thousands):
Revenues	$	362,516		$	107,149		$	34,138		$	124,843	$	104,219		$	46,223
Net income (loss)	142,482			(219,189		)	(122,932		)	18,042		28,853			9,581
Net income (loss) per common share:
Basic	$	0.69		$	(1.26	)	$	(1.14	)	$	0.19	$	0.38		$	0.17
Diluted	$	0.69		$	(1.26	)	$	(1.14	)	$	0.19	$	0.37		$	0.16
Certain Balance Sheet Information (in thousands):
Total Assets	$	2,079,564		$	1,024,113		$	672,616		$	746,449	$	448,542		$	291,236
Working (Deficit) Capital	(42,272		)	(38,056		)	24,992			93,129		(35,338		)	50,608
Long-term Obligations	538,359			75,614			78,000			78,000		37,000			37,000
Total Liabilities	771,130			183,374			166,106			174,052		167,052			88,016
Equity	1,308,434			840,739			506,510			572,397		281,490			203,220
Certain Operating Statistics:
Production:
Oil (MBbls)	5,824			2,257			742			1,970		941			421
Natural Gas (MMcf)	24,834			12,086			3,468			7,344		3,747			2,108
NGLs (MBbls)	2,518			—			—			—		—			—
MBOE	12,481			4,271			1,320			3,194		1,566			773
BOED	34,194			11,670			10,822			8,750		4,290			2,117
Average sales price per BOE 1	$	28.79		$	25.09		$	25.86		$	39.09	$	66.56		$	59.83
LOE per BOE	$	1.56		$	4.67		$	4.41		$	4.70	$	5.10		$	4.42
DD&A2 per BOE	$	9.00		$	10.93		$	14.22		$	20.62	$	21.05		$	17.26

¹ Adjusted to include the effect of transportation and gathering expenses.

² Depletion, Depreciation, & Accretion

As of January 1, 2017, our natural gas processing agreements with DCP Midstream have been modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 with prior periods.

On February 25, 2016, we changed our fiscal year from the period beginning on September 1 and ending on August 31 to the period beginning on January 1 and ending on December 31. As a result, the selected financial data above includes financial information for the transition period from September 1, 2015 through December 31, 2015. This financial information may not be directly comparable to the prior periods as it covers a shorter time frame.

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See Note 19 to the consolidated financial statements included as part of this report for our quarterly financial data. See Note 1 and Note 3 to the consolidated financial statements included as part of this report for information concerning significant accounting policies and acquisitions, respectively.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends on December 31 or August 31 of each year. The following discussion and analysis was prepared to supplement information contained in the accompanying consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of December 31, 2017, and its results of operations for the years ended December 31, 2017, December 31, 2016, and December 31, 2015 (unaudited).  It should be read in conjunction with the “Selected Financial Data” and the accompanying audited consolidated financial statements and related notes thereto contained in this Annual Report on Form 10-K. The unaudited results of operations for the year ended December 31, 2015 was derived from data previously reported in the Company's Transition Report on Form 10-K as filed with the SEC on April 22, 2016.

This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties.  See the “Cautionary Statement Concerning Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.  Forward-looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward-looking statements.  Factors that might cause such differences include, but are not limited to, those discussed in “Risk Factors.”  We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

As of January 1, 2017, our natural gas processing agreements with DCP Midstream were modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 with prior periods.

Overview

SRC Energy Inc. is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the D-J Basin, which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.

Our oil and natural gas activities are focused in the Wattenberg Field, predominantly in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell formation as well as the three benches of the Niobrara formation, which are all characterized by relatively high liquids content.

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 78% of our proved producing reserves, and anticipate operating substantially all of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow. The market prices for oil, natural gas, and NGLs are inherently volatile.  To provide historical perspective, the following table presents the average annual NYMEX prices for oil and natural gas for each of the last five fiscal years.

	Year Ended December 31,						Year Ended August 31,
	2017		2016		2015		2015		2014		2013
Average NYMEX prices					(unaudited)
Oil (per Bbl)	$	50.93	$	43.20	$	48.73	$	60.65	$	100.39	$	94.58
Natural gas (per Mcf)	$	3.00	$	2.52	$	2.58	$	3.12	$	4.38	$	3.55

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For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices) as well as the differential between the Reference Price and the prices realized by us.

	Year Ended December 31,
	2017			2016			2015
Oil (NYMEX WTI)							(unaudited)
Average NYMEX Price	$	50.93		$	43.20		$	48.73
Realized Price *	$	44.35		$	34.43		$	40.08
Differential *	$	(6.58	)	$	(8.77	)	$	(8.65	)
Gas (NYMEX Henry Hub)
Average NYMEX Price	$	3.00		$	2.52		$	2.58
Realized Price	$	2.33		$	2.44		$	2.71
Differential	$	(0.67	)	$	(0.08	)	$	0.13
NGL Realized Price	$	17.10		$	—		$	—

* Adjusted to include the effect of transportation and gathering expenses.

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The differential between the prices received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. With regard to the sale of oil, substantially all of the Company's first quarter 2017 oil production was sold to the counterparties of its firm sales commitments. Beginning in the second quarter of 2017, the Company's oil production exceeded its firm sales commitments, and the surplus oil production was sold at a reduced differential as compared to our committed volumes. Relating to the sale of natural gas, prior to January 1, 2017, the price we received included payment for a percentage of the value attributable to the natural gas liquids produced with the natural gas. Beginning in the first quarter of 2017, natural gas liquids and dry natural gas volumes are disclosed separately, and NGL revenues will replace the premium to dry natural gas prices that the Company historically realized on its wet natural gas sales volumes.

There has been significant volatility in the price of oil and natural gas since mid-2014.  During the year ended December 31, 2017, the NYMEX-WTI oil price ranged from a high of $60.46 per Bbl on December 29, 2017 to a low of $42.48 per Bbl on June 21, 2017, and the NYMEX-Henry Hub natural gas price ranged from a low of $2.56 per MMBtu on February 21, 2017 to a high of $3.42 per MMBtu on May 12, 2017. As reflected in published data, the price for WTI oil settled at $53.75 per Bbl on Friday, December 30, 2016.  Comparably, the price of oil settled at $60.46 per Bbl on Friday, December 29, 2017, an increase of 12% from December 31, 2016. Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil, natural gas, and NGL production.

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and impact the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting.  At December 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, if pricing conditions decline, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.

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Core Operations

The followingtable provides details about our ownership interests with respect to vertical and horizontal producing wells as of December 31, 2017:

Vertical Wells
Operated Wells		Non-Operated Wells		Totals
Gross	Net	Gross	Net	Gross	Net
345	333	164	49	509	382

Horizontal Wells
Operated Wells		Non-Operated Wells		Totals
Gross	Net	Gross	Net	Gross	Net
227	218	278	50	505	268

In addition to the producing wells summarized in the preceding table, as of December 31, 2017, we were the operator of 51 gross (47 net) wells in progress, which excludes19gross (16net) wells for which we have only set surface casings. As of December 31, 2017, we are participating in 35 gross (6 net) non-operated horizontal wells in progress.

As we develop our acreage through horizontal drilling, we have an active program for plugging and abandoning the vast majority of the operated vertical wellbores. During the year ended December 31, 2017, we plugged 159 wells and returned the associated surface acreage to the property owners.

Properties

As of December 31, 2017, our estimated net proved oil and natural gas reserves, as prepared by Ryder Scott, were 69.4 MMBbls of oil and condensate, 559.9 Bcf of natural gas, and 64.0 MMBbls of natural gas liquids. As of December 31, 2017, we had approximately 98,600 gross and 88,300 net acres under lease in the Wattenberg Field. We also have non-core leasehold in other areas of Colorado and southwest Nebraska approximating 238,500 gross and 200,500 net acres.

Production

For the year ended December 31, 2017, our average net daily production increased to 34,194 BOED as compared to 11,670 BOED for the year ended December 31, 2016. By comparison, our production increased from 9,548 BOED for the year ended December 31, 2015 to 11,670 BOED for the year ended December 31, 2016. As of December 31, 2017, approximately98%ofour daily production was from horizontal wells.

Significant Developments

Acquisitions

In December 2017, the Company completed the purchase of a total of approximately 30,200 net acres in the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement governing the transaction (the "GCII Agreement"). The effective date of this part of the transaction was November 1, 2017. The GCII Agreement also contemplates a second closing at which we will acquire operated producing properties subject to certain regulatory restrictions. The purchase price payable at the second closing will be determined based on the amount of then-current production from the properties conveyed and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.

In September 2017, we completed the second closing contemplated by the purchase and sale agreement (the "GC Agreement") relating to our 2016 acquisition of approximately 33,100 net acres in the Greeley-Crescent area for $505 million (the "GC Acquisition"). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired.  The purchase and sale agreement for the GC Acquisition was signed in May 2016 and the first closing was

41

completed in June 2016. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million, composed of cash of $6.3 million and assumed liabilities of $24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations.

In August 2017, we entered into an agreement with another party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also executed a purchase and sale agreement with a private party for the acquisition of approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.

In March 2017, we acquired developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million, composed of cash and assumed liabilities.

Divestitures

During the year ended December 31, 2017, we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.

Equity Offering

In November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 5,250,000 shares of common stock on the same terms and conditions. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to40,250,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were$312.2 million. The Company used the proceeds of the offering to pay a portion of the purchase price of the GCII Acquisitionand to repay amounts borrowed under the Revolver.

Revolving Credit Facility

In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base.  The borrowing base was increased from $225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018. Due to the outstanding principal balance and letters of credit, approximately $399.5 million of the borrowing base was available to use for future borrowings as of December 31, 2017, subject to our covenant requirements.

2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of the 2025 Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GCII Acquisition, repay the 2021 Senior Notes, and pay off the outstanding Revolver balance. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

2021 Senior Notes

In December 2017, the Company repurchased all $80 million aggregate principal amount of its 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.

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Drilling and Completion Operations

Our drilling and completion schedule drives our production forecast and our expected future cash flows. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return. Should commodity prices weaken or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move higher, we may choose to accelerate drilling and completion activities.

During the year ended December 31, 2017, we drilled 115 operated horizontal wells and turned 109 operated horizontal wells to sales. As of December 31, 2017, we are the operatorof51gross (47net) horizontal wells in progress, which excludes19gross (16net) horizontal wells for which we have only set surface casings. For 2018, we expect to drill 117 gross (100 net) operated horizontal wells and complete approximately 116 gross (103 net) operated horizontal wells with mostly mid-length and long laterals targeting the Codell and Niobrara zones.

For the year ended December 31, 2017, we participated in the completion activities on63gross (11net) non-operated horizontal wells. As ofDecember 31, 2017, we are participating in35gross (6net) non-operated horizontal wells in progress.The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements.

Trends and Outlook

Oil traded at $53.75 per Bbl on December 30, 2016, but has since increased approximately 12% as of December 29, 2017 to $60.46. Natural gas traded at $3.72 per Mcf on December 30, 2016, but declined approximately 21% as of December 29, 2017 to $2.95.Although oil prices have increased in the second half of 2017, they continue to be volatile and are out of our control. If oil prices decrease, this could(i) reduce our cash flow which, in turn, could reduce the funds available for exploring and replacing oil and natural gas reserves, (ii) reduce our Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) reduce the number of oil and gas prospects which have reasonable economic returns, (iv) cause us to allow leases to expire based upon the value of potential oil and natural gas reserves in relation to the costs of exploration, (v) result in marginally productive oil and natural gas wells being abandoned as non-commercial, and (vi) cause ceiling test impairments.

Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) the availability and capacity of gathering systems, pipelines, and other midstream infrastructure for our production, (iv) our ability to satisfy our financial and volume commitment obligations, (v) completion of acquisitions of additional properties and reserves, and (vi) competition from other oil and gas companies.

We utilize what we believe to be industry best practices in our effort to achieve optimal hydrocarbon recoveries.  Currently, our practice is to drill 16 to 24 horizontal wells per 640-acre section depending upon specific geologic attributes and existing vertical wellbore development.  Some operators are testing higher density programs, but we believe that it is too early to determine whether the recoveries justify the additional capital cost.

We have been able to reduce drilling and completion costs due to a combination of optimizing well designs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics giving consideration to the current prices of oil and natural gas. We continue to strive to reduce drilling and completion costs going forward, but as commodity prices improve and industry activity increases, we may experience higher service costs, causing well-level rates of return to be lower.

Midstream companies that operate the natural gas processing facilities and gathering pipelines in the Wattenberg Field continue to make significant capital investments to increase the capacity of their systems. From time to time, our production has been adversely impacted by the lack of processing capacity resulting in high natural gas gathering line pressures.

To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream has announced plans for multiple projects including new processing plants, low pressure gathering systems, additional compression, and plant bypass infrastructure. Most notably, in collaboration with DCP Midstream, we and several other producers have agreed to support the expansion of natural gas gathering and processing capacity through agreements that impose baseline and incremental volume commitments, which we are currently exceeding.  The initial plan includes a new 200 MMcf per day processing plant as well as

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the expansion of a related gathering system, both expected to be completed during the third quarter of 2018. Additionally, through the same framework, all of the parties agreed to a development plan to add another 200 MMcf/d plant in mid-2019.

We have extended the use of oil and water gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases or areas to these systems. We believe these gathering lines have several benefits, including a) reduced need to use trucks, thereby reducing truck traffic and noise in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site storage capacity, resulting in lower production location facility costs, and d) generally improved community relations. As these gathering lines are currently being expanded, we have experienced and expect to continue to experience some delays in placing our pads on production.

Oil transportation and takeaway capacity has increased with the expansion of certain interstate pipelines servicing the Wattenberg Field. This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets. We strive to reduce the negative differential that we have historically realized on our oil production depending on transportation commitments, local refinery demand, and our production volumes. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."

As of December 31, 2017, we have identified over 1,700 drilling locations across our acreage position in the core of the Wattenberg Field. For2018, we expect to drill 117 gross operated horizontal wells with mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion program will cost between $480 million and $540 million and will lead to a significant increase in production and associated proved developed producing reserves while allowing us to retain significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions. Initial estimates place full-year 2018 production to average between 48,000 BOED and 52,000 BOED with oil making up 47% - 50% of production.

Other than the foregoing, we do not know of any trends, events, or uncertainties that have had, during the periods covered by this report, or are reasonably expected to have, a material impact on our sales, revenues, expenses, liquidity, or capital resources.

Results of Operations

Material changes of certain items in our consolidated statements of operations included in our consolidated financial statements for the periods presented are discussed below. All references to the year ended December 31, 2015 are unaudited.

For the year ended December 31, 2017 compared to the year endedDecember 31, 2016

For the year ended December 31, 2017, we reported net income of $142.5 million compared to net loss of $219.2 million during the year endedDecember 31, 2016. Net income per basic and diluted share was $0.69 for the year ended December 31, 2017 compared to net loss per share per basic and diluted share of $1.26 for the year endedDecember 31, 2016. Net income per basic share for the year ended December 31, 2017increased by $1.95 primarily due to the ceiling test impairment of $215.2 million incurred during the year ended December 31, 2016 (whereas no ceiling test impairment was recognized during the year ended December 31, 2017) and the 238.3% increase in revenues period over period as described below.

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Oil and Natural Gas Production and Revenues - For the year ended December 31, 2017, we recorded total oil, natural gas, and NGL revenues of $362.5 million compared to $107.1 million for the year endedDecember 31, 2016, an increase of $255.4 million or 238%. The following table summarizes key production and revenue statistics:

	Year Ended December 31,
	2017		2016		Change
Production:
Oil (MBbls)	5,824		2,257		158	%
Natural Gas (MMcf)	24,834		12,086		105	%
NGLs (MBbls) 1	2,518		—		nm
MBOE	12,481		4,271		192	%
BOED	34,194		11,670		193	%
Revenues (in thousands):
Oil	$	261,505	$	77,699	237	%
Natural Gas	57,956		29,450		97	%
NGLs 1	43,055		—		nm
	$	362,516	$	107,149	238	%
Average sales price:
Oil 2	$	44.35	$	34.43	29	%
Natural Gas	$	2.33	$	2.44	(5	)%
NGLs 1	$	17.10	$	—	nm
BOE 2	$	28.79	$	25.09	15	%

¹ For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.

² Adjusted to include the effect of transportation and gathering expenses.

Net oil, natural gas and NGL production for the year ended December 31, 2017 averaged 34,194 BOED, an increase of 193% over average production of 11,670 BOED in the year endedDecember 31, 2016. From December 31, 2016 to December 31, 2017, our well count increased by 140 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted reported production in the current period. The 192% increase in production and the 15% increase in average sales prices resulted in a significant increase in revenues.

LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):

	Year Ended December 31,
	2017		2016
Production costs	$	18,900	$	19,251
Workover	596		698
Total LOE	$	19,496	$	19,949
Per BOE:
Production costs	$	1.51	$	4.51
Workover	0.05		0.16
Total LOE	$	1.56	$	4.67

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells and our overall production volumes and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the year ended December 31, 2017, we experienced decreased production expense compared to the year ended December 31, 2016 primarily due to significantly less expense related to environmental remediation and regulatory compliance projects during 2017 and the continued consolidation of our operations into a more central geographic operating area. Unit operating costs benefited from larger volumes of early production on the 101 net horizontal wells turned to salesduring the

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year ended December 31, 2017.

Transportation and gathering - During 2017, the Company entered into new gathering agreements which resulted in new transportation and gathering charges. Transportation and gathering was $3.2 million, or $0.26 per BOE, for the year ended December 31, 2017, compared to nil for the year ended December 31, 2016. While reported as an expense, the Company analyzes these charges on a net basis within revenue.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $36.3 million, or $2.91 per BOE, for the year ended December 31, 2017, compared to $5.7 million, or $1.34 per BOE, for the year ended December 31, 2016. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 10.0% and 5.3% for the years ended December 31, 2017 and 2016, respectively. During the year ended December 31, 2017, the Company adjusted its estimates for production taxes to reflect significant increases in production. During the year ended December 31, 2016, the Company reduced its estimate for ad valorem taxes, resulting in an approximate $3.6 million reduction to our production taxes.

DD&A - The following table summarizes the components of DD&A:

	Year Ended December 31,
(in thousands)	2017		2016
Depletion of oil and gas properties	$	109,287	$	45,193
Depreciation and accretion	3,022		1,485
Total DD&A	$	112,309	$	46,678
DD&A expense per BOE	$	9.00	$	10.93

For the year ended December 31, 2017, DD&A was $9.00 per BOE compared to $10.93 per BOE for the year endedDecember 31, 2016. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the increase in our total proved reserves and the impairments of our full cost pool that primarily occurred during 2016. These impacts were partially offset by recent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determined the depletion rate.

Full cost ceiling impairment - During the year ended December 31, 2017, we had no impairment as compared to an impairment of $215.2 million for the year endedDecember 31, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See “-Critical Accounting Policies-Oil and Gas Properties, including Ceiling Test.”

General and Administrative ("G&A") - The following table summarizes G&A expenses incurred and capitalized during the periods presented:

	Year Ended December 31,
(in thousands)	2017			2016
G&A costs incurred	$	43,338		$	37,619
Capitalized costs	(10,373		)	(7,074		)
Total G&A	$	32,965		$	30,545
Non-Cash G&A	$	11,225		$	9,491
Cash G&A	21,740			21,054
Total G&A	$	32,965		$	30,545
Non-Cash G&A per BOE	$	0.90		$	2.22
Cash G&A per BOE	1.74			4.93
G&A Expense per BOE	$	2.64		$	7.15

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G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $33.0 million for the year ended December 31, 2017 were 8% higher than G&A for the year ended December 31, 2016. This increase is primarily due to a 27% increase in employee headcount from 96 at December 31, 2016 to 122 at December 31, 2017, which was offset by a reduction in professional fees incurred due to decreased contract services during 2017.

Our G&A expense for the year ended December 31, 2017 includes stock-based compensation of $11.2 million compared to $9.5 million for the year endedDecember 31, 2016.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the year endedDecember 31, 2016 to the year ended December 31, 2017 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivatives - As more fully described in “-Liquidity and Capital Resources-Oil and Gas Commodity Contracts,” we use commodity contracts to help mitigate the risks inherent in the volatility of oil and natural gas prices. For the year ended December 31, 2017, we realized a cash settlement gain of $39.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts. In 2016, we realized a cash settlement gain of $2.4 million.

In addition, for the year ended December 31, 2017, we recorded an unrealized loss of $4.3 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the year endedDecember 31, 2016, we reported an unrealized loss of $10.1 million. Unrealized losses are non-cash items.

Income taxes - We reported income tax benefit of $0.1 million for the year ended December 31, 2017, calculated at an effective tax rate of 0%. In 2016, we reported income tax expense of $0.1 million, calculated at an effective tax rate of 0%. As explained in more detail below, during the year ended December 31, 2017, the effective tax rate was substantially reduced by the recognition of a full valuation allowance on the net deferred tax asset.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of December 31, 2017. During 2016, we reached the same conclusion; therefore, a valuation allowance has been provided as of December 31, 2016.

For the year ended December 31, 2016, compared to the year ended December 31, 2015

For the year ended December 31, 2016, we reported net loss of $219.2 million compared to net loss of $131.7 million during the year ended December 31, 2015. Net loss per basic and diluted share was $1.26 for the year ended December 31, 2016 compared to net loss per share per basic and diluted share of $1.27 for the year ended December 31, 2015. Revenues increased slightly during the year ended December 31, 2016 compared to the year ended December 31, 2015. As of December 31, 2016, we had 631 gross producing wells, compared to 609 gross producing wells as of December 31, 2015. The impact of changing prices on our commodity derivative positions also drove significant differences in our results of operations between the two periods.

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Oil and Natural Gas Production and Revenues - For the year ended December 31, 2016, we recorded total oil, natural gas, and NGL revenues of $107.1 million compared to $106.1 million for the year ended December 31, 2015. The following table summarizes key production and revenue statistics:

	Year Ended December 31,
	2016		2015		Change
Production:
Oil (MBbls)	2,257		2,073		9	%
Natural Gas (MMcf)	12,086		8,472		43	%
MBOE	4,271		3,485		23	%
BOED	11,670		9,548		22	%
Revenues (in thousands):
Oil	$	77,699	$	83,078	(6	)%
Natural Gas	29,450		22,972		28	%
	$	107,149	$	106,050	1	%
Average sales price:
Oil	$	34.43	$	40.08	(14	)%
Natural Gas	2.44		2.71		(10	)%
BOE	$	25.09	$	30.43	(18	)%

Net oil and natural gas production for the year ended December 31, 2016 averaged 11,670 BOED, an increase of 22% over average production of 9,548 BOED in the year ended December 31, 2015. From December 31, 2015 to December 31, 2016, our well count increased by 25 net horizontal wells, growing our reserves and daily production totals. The 18% decline in average sales prices offset the effects of increased production, resulting in relatively flat revenues overall.

LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):

	Year Ended December 31,
	2016		2015
Production costs	$	19,251	$	14,927
Workover	698		1,157
Total LOE	$	19,949	$	16,084
Per BOE:
Production costs	$	4.51	$	4.28
Workover	0.16		0.33
Total LOE	$	4.67	$	4.61

Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in productionand, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of oil and natural gas. During the year ended December 31, 2016, we experienced increased production expense primarily due to operating additional horizontal wells, increased production, and an increase in regulatory compliance projects.

Production taxes - Taxes tend to increase or decrease primarily based on the value of oil and natural gas sold. During the year ended December 31, 2016, production taxes were $5.7 million, or $1.34 per BOE, compared to $9.4 million, or $2.70 per BOE, during the prior year comparable period. As a percent of revenues, taxes were 5.3% and 8.9% for the years ended December 31, 2016 and 2015, respectively. The decrease in 2016 is due to a change in estimate for production taxes based on recent historical experience and additional information received during the period. Based on this analysis, our production tax accrual was reduced, resulting in an approximate $3.6 million reduction to our production taxes.

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DD&A - The following table summarizes the components of DD&A:

	Year Ended December 31,
(in thousands)	2016		2015
Depletion of oil and gas properties	$	45,193	$	61,172
Depreciation and accretion	1,485		899
Total DD&A	$	46,678	$	62,071
DD&A expense per BOE	$	10.93	$	17.81

For the year ended December 31, 2016, depletion of oil and gas properties was $10.93 per BOE compared to $17.81 per BOE for the year ended December 31, 2015. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool, which primarily occurred during the second half of calendar 2015 and the first half of 2016, and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determines the depletion rate.

Full cost ceiling impairment - During the year ended December 31, 2016, we recognized an impairment of $215.2 million as compared to an impairment of $141.2 million for the year ended December 31, 2015, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See “-Critical Accounting Policies-Oil and Gas Properties, including Ceiling Test.”

G&A - The following table summarizes G&A expenses incurred and capitalized during the periods presented:

	Year Ended December 31,
(in thousands)	2016			2015
G&A costs incurred	$	37,619		$	33,618
Capitalized costs	(7,074		)	(2,426		)
Total G&A	$	30,545		$	31,192
Non-Cash G&A	$	9,491		$	14,741
Cash G&A	$	21,054		$	16,451
Total G&A	$	30,545		$	31,192
Non-Cash G&A per BOE	$	2.22		$	4.23
Cash G&A per BOE	$	4.93		$	4.72
G&A Expense per BOE	$	7.15		$	8.95

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. We increased our employee count from 62 at December 31, 2015 to 96 at December 31, 2016, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks. Additionally, during the year ended December 31, 2015, we awarded bonuses, consisting of cash and restricted stock, to management, employees, and directors. Most significantly, bonuses totaling approximately $4.8 million (including restricted stock valued at $4.0 million) were paid to our former co-CEOs, both of whom resigned as of December 31, 2015.

Our G&A expense for the year ended December 31, 2016 includes stock-based compensation of $9.5 million compared to $14.7 million for the year ended December 31, 2015. Stock-based compensation is a non-cash charge that is based on the calculated fair value of stock options, performance stock units, restricted share units, and stock bonus shares that we grant for compensatory purposes. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For performance stock units, the fair value is estimated using the Monte Carlo model. For restricted stock units and stock bonus shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.

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Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the year ended December 31, 2015 to the year ended December 31, 2016 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivative gains (losses) - As more fully described in “-Liquidity and Capital Resources-Oil and Gas Commodity Contracts,” we use commodity contracts to help mitigate the risks inherent in the volatility of oil and natural gas prices. For the year ended December 31, 2016, we realized a cash settlement gain of $2.4 million, net of previously incurred premiums attributable to the settled commodity contracts. In 2015, we realized a cash settlement gain of $28.4 million.

In addition, for the year ended December 31, 2016, we recorded an unrealized loss of $10.1 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the year ended December 31, 2015, we reported an unrealized loss of $17.3 million. Unrealized losses are non-cash items.

Income taxes - We reported income tax expense of $0.1 million for the year ended December 31, 2016, calculated at an effective tax rate of 0%. In 2015, we reported income tax benefit of $14.1 million, calculated at an effective tax rate of 10%. As explained in more detail below, during the year ended December 31, 2016, the effective tax rate was substantially reduced by the recognition of a full valuation allowance on the net deferred tax asset.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of December 31, 2016. During 2015, we reached the same conclusion; therefore, a valuation allowance has been provided as of December 31, 2015.

Liquidity and Capital Resources

Historically, our primary sources of capital have been net cash provided by cash flow from operations, proceeds from the sale of properties, the sale of equity and debt securities, and borrowings under bank credit facilities.  Our primary use of capital has been for the exploration, development, and acquisition of oil and gas properties.  Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us.

We believe that our capital resources, including cash on hand, amounts available under our revolving credit facility, and cash flow from operating activities will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. To the extent actual operating results differ from our anticipated results, available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted.  Our liquidity would also be affected if we increase our capital expenditures or complete one or more additional acquisitions. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.

As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled. This allows us to modify our capital spending as our financial resources allow and market conditions support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity while currently not overly burdening us with restrictive financial covenants and mandatory repayment schedules.

Sources and Uses

Our sources and uses of capital are heavily influenced by the prices that we receive for our production. Oil and gas markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.

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At December 31, 2017, we had cash, cash equivalents, and restricted cash of $48.8 million, $550.0 million outstanding on our 2025 Senior Notes, and no balance outstanding under our revolving credit facility. Our sources and (uses) of funds for the years ended December 31, 2017, 2016, and 2015 are summarized below (in thousands):

	Year Ended December 31,
	2017			2016			2015
Net cash provided by operations	$	291,315		$	48,688		$	103,830
Capital expenditures	(1,133,879		)	(643,266		)	(202,564		)
Net cash provided by other investing activities	93,573			25,350			6,239
Net cash provided by equity financing activities	312,308			542,722			187,444
Net cash provided by (used in) debt financing activities	448,621			(3,159		)	(68,020		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	$	11,938		$	(29,665	)	$	26,929

Net cash provided by operating activities was $291.3 million, $48.7 million, and $103.8 million for the years ended December 31, 2017, 2016, and 2015, respectively. The increase in cash from operating activities from the year ended December 31, 2016 to the year ended December 31, 2017 reflects the increase in realized commodity prices and production.

Net cash provided by other investing activities was $93.6 million, $25.4 million, and $6.2 million for the years ended December 31, 2017, 2016, and 2015, respectively. For the year ended December 31, 2017, we received proceeds from the sale of oil and gas properties and other of $93.6 million. For the year ended December 31, 2016, we received proceeds from the sale of oil and gas properties of $25.4 million.

Net cash provided by equity financing activities was $312.3 million, $542.7 million, and $187.4 million for the years ended December 31, 2017, 2016, and 2015, respectively. Net cash provided by (used in) debt financing activities was $448.6 million, $(3.2) million, and $(68.0) million for the years ended December 31, 2017, 2016, and 2015, respectively. During theyear ended December 31, 2017, we received cash proceeds from borrowing$250 millionunder the Revolver which were primarily used to fund our drilling and completion activities. Additionally, we issued $550 million aggregate principal amount of 2025 Senior Notes in a private placement to qualified institutional buyers. See " - 2025 Senior Notes." The net proceeds from the sale of the 2025 Senior Notes were$538.1 millionafter deductions of $11.9 millionfor expenses and underwriting discounts and commissions. Lastly, we received cash proceeds of approximately$312.2 million(after deduction of underwriting discounts and expenses payable by the Company) from our public offering of 40,250,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $7.76. The proceeds from the private placement and the public offering were used to repay$250 millionof borrowings under the Revolver,fund the GCII Acquisition, and repay the $80 million aggregate principal amount of the 2021 Senior Notes.

Credit Facility

The Revolver has a maturity date of December 15, 2019.  The agreement was most recently amended in September 2017 as a result of the regular semi-annual redetermination of our borrowing base.  The Revolver has a maximum loan commitment of $500 million; however, the maximum amount that we can borrow at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesser of the maximum loan commitment or the borrowing base.  The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the Revolver.  The value of the collateral will generally be derived with reference to the estimated discounted future net cash flows from our proved oil and natural gas reserves. The collateral includes substantially all of our producing wells and developed oil and gas leases.

As a result of the regular semi-annual redetermination of our borrowing base on September 27, 2017, the borrowing base was increased from$225 million to $400 million. As of December 31, 2017, there was no outstanding principal balance and $0.5 millionin letters of credit outstanding, leaving$399.5 millionavailable to us for future borrowings. The next semi-annual redetermination is scheduled forApril 2018. Interest on the Revolver accrues at a variable rate. The interest rate pricing grid contains a graduatedescalation in applicable margin for increased utilization.

The Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than1.0to 1.0.

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2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the principal amount plus an Applicable Premium (as defined in the Indenture) plus accrued and unpaid interest.  On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at the redemption priceequal to a specified percentage of the principal amount of the redeemed notes (104.688% for 2020, 103.125% for 2021, 101.563% for 2022, and 100% for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest.Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 106.25%of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

2021 Senior Notes

In December 2017, the Company repurchased all $80 million aggregate principal amount of its 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.

Capital Expenditures

Capital expenditures for drilling and completion activities totaled $461.8 million, $130.9 million, and $127.8 million for the year ended December 31, 2017, 2016, and 2015, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):

	Year Ended December 31,
	2017		2016		2015
Capital expenditures for drilling and completion activities*	$	461,789	$	130,936	$	127,817
Acquisitions of oil and gas properties and leasehold**	677,643		517,911		105,670
Capitalized interest, capitalized G&A, and other	26,677		18,744		8,221
Accrual basis capital expenditures***	$	1,166,109	$	667,591	$	241,708

* Capital expenditures for drilling and completion activities exclude $34.9 million of expenditures that were accrued during the year ended December 31, 2017; however, the properties associated with these expenditures were subsequently traded, and no cash was required to be remitted to the operator of the activities.

**Acquisitions of oil and gas properties and leasehold reflects the full purchase price of our various acquisitions which includes non-cash additions for liabilities assumed in the transaction such as asset retirement obligations.

***Capital expenditures reported in the consolidated statement of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the capital expenditures.

Excluding the GCII Acquisition, the majority of capital expenditures during the year ended December 31, 2017 were associated with the costs of drilling and completing wells. During the year ended December 31, 2017, we drilled 115 operated horizontal wells and turned 109 operated horizontal wells to sales. As of December 31, 2017, we are the operator of 51 gross (47 net) horizontal wells in progress,which excludes19gross (16net) wells for which we have only set surface casings. All of the wells in progress at December 31, 2017are scheduled to commence production beforeDecember 31, 2018.

For theyear ended December 31, 2017, we participated in 35 gross (6net) non-operated horizontal wells.

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Capital Requirements

Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, development results, and downstream commitments, among other factors. Our primary need for capital will be to fund our anticipated drilling and completion activities and any other acquisitions that we may complete during 2018.

We anticipate that our 2018 drilling and completion capital expenditures for operated wells will cost between $480 million and $540 million for the year. However, should commodity prices and/or economic conditions change, we can reduce or accelerate our drilling and completion activities, which could have a material impact on our anticipated capital requirements.

For the near term, we believe that we have sufficient liquidity to fund ourneeds through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility.  However, should this notmeet all of our long-term needs, we may need to raise additional funds to drill new wells through the sale of our securities, from third parties willing to pay our share of drilling and completing wells, or from other sources.  We may not be successful in raising the capital needed to drill or acquire oil or natural gas wells. We may seek to raise funds in capital markets transactions from time to time if we believe market conditions to be favorable.

Oil and Gas Commodity Contracts

We use derivative contracts to help protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and natural gas production.  At December 31, 2017, we had open positions covering 3.7 million barrels of oil and 5,475 MMcf of natural gas. We do not use derivative instruments for speculative purposes.

Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in our credit facility.

A “put” option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums at the time that we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless, in which case the net premiums paid would be recognized as a loss.

Conversely, a “call” option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create “collars.” We regularly utilize “no premium” (a.k.a. zero cost) collars constructed by selling call options while simultaneously buying put options, in which the premiums paid for the puts is offset by the premiums received for the calls. Collars are consistent with our derivative strategy inasmuch as they establish a known range of prices to be received for the associated volume equivalents, being bound at the upper end by the call’s strike price (the “ceiling”) and at the lower end by the put’s strike price (the “floor”).

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term. Swaps are consistent with our derivative strategy inasmuch as they establish a known future price to be received for the associated equivalent volumes.

During periods of significant price declines, for settled contracts structured as “collars,” we will receive settlement payments from the contracts’ counterparties for the difference between the contracted “floor” price and the average posted price for the contract period. For settled “swaps,” we will receive the difference between the contracted swap price and the average posted price for the contract period, if lower. For settled “put” contracts, we will receive the difference between the put’s strike price and the average posted price for the contract period. If we decide to liquidate an “in-the-money” position prior to settlement date, we will receive the approximate fair value of the contract at that time. These realized gains increase our cash flows for the period in which they are recognized.

Conversely, during periods of significant price increases, upon settlement we would be obligated to pay the counterparties the difference between the contract’s “ceiling” and/or swap price and the average posted price for the contract period. If liquidated

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prior to settlement, we would pay the approximate fair market value to close the position at that time. These realized losses decrease our cash flows for the period in which they are recognized. Losses associated with puts that expire out-of-the-money are simply the original premiums paid for the contracts and are recognized upon expiration.

The fair values of our open, but not yet settled, derivative contracts are estimated by obtaining independent market quotes as well as using industry standard models that consider various assumptions including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. We compare the valuations calculated by us to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate.

The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will also impact our net income in the period recorded.

We do not designate our commodity contracts as accounting hedges.  Accordingly, we use mark-to-market accounting to value the portfolio at the end of each reporting period.  Mark-to-market accounting can create non-cash volatility in our reported earnings during periods of commodity price volatility.  We have experienced such volatility in the past and are likely to experience it in the future.  Mark-to-market accounting treatment results in volatility of our results as unrealized gains and losses from derivatives are reported. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

During the year ended December 31, 2017, we reported an unrealized commodity activity loss of $4.3 million.  Unrealized losses are non-cash items.  We also reported a realized gain of $39.0 thousand, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.

At December 31, 2017, we estimated that the fair value of our various commodity derivative contracts was a net liability of $7.9 million. See Note 8, Commodity Derivative Instruments, for a description of the methods we use to estimate the fair values of commodity derivative instruments.

Contractual Commitments

The following table summarizes our contractual obligations as of December 31, 2017 (in thousands):

	Less than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Rig contracts (1)	$	8,527	$	—	$	—	$	—	$	8,527
Volume commitments (2) (3)	23,961		45,796		10,032		—		79,789
Notes payable (4)	34,375		68,750		68,750		653,125		825,000
Capital leases	76		74		63		—		213
Operating leases	840		1,737		1,352		—		3,929
Total	$	67,779	$	116,357	$	80,197	$	653,125	$	917,458

¹  Represents an estimate of the commitment related to the use of two rigs.  Actual amounts will vary as a result of a number of variables, including target formations, measured depth, and other technical details.

²  We have entered into agreements that require us to deliver minimum amounts of oil to certain third parties through 2021. Production can be sourced via third party contract, in-kind agreements, or self-sustained production. We will incur a charge of approximately $5.21 per Bbl if a minimum quantity of oil is not delivered to the pipeline-related counterparties. Amounts reflect the estimated deficiency payments under our pipeline-related commitments assuming no deliveries are made. Potential damages and other charges related to nonperformance under these contracts are not included in the amounts above. See further discussion in Note 16 to our consolidated financial statements.

³  In collaboration with several other producers and DCP Midstream, we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin under two agreements.  For the first agreement, our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date, which is currently expected to be during the third quarter of 2018, for a period of 7 years. For the second agreement, our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date, which is expected to be

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completed in mid-2019, for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. While we expect that our development plan will support the utilization of this capacity, we may be required to pay penalties or damages pursuant to this agreement if we are unable to fulfill our contractual obligation from our own production and if the collective volumes delivered by other producers in the D-J Basin are not in excess of the total commitment. At this time, we are unable to reasonably estimate these amounts, and they have therefore not been reflected in the table above. See further discussion in Note 16 to our consolidated financial statements.

⁴  Includes interest payments related to the issuance of the 2025 Senior Notes. See further discussion in Note 7 to our consolidated financial statements.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on our financial condition, changes in financial condition, revenues or expense, results of operations, liquidity, or capital resources.

Non-GAAP Financial Measures

In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). The following is a summary of the measures we currently report.

Adjusted EBITDA

We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes because it allows us to 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 in the table below from net income (loss) in arriving at adjusted EBITDA. We exclude those items because they 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 EBITDA is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, net income. We believe that adjusted EBITDA is widely used in our industry as a measure of operating performance and may also be used by investors to measure our ability to meet debt covenant requirements. However, our definition of adjusted EBITDA may not be fully comparable to measures with similar titles reported by other companies. We define adjusted EBITDA as net income (loss) adjusted to exclude the impact of the items set forth in the table below (amounts in thousands):

	Year Ended December 31,
	2017			2016			2015
Adjusted EBITDA:
Net income (loss)	$	142,482		$	(219,189	)	$	(131,689	)
Depletion, depreciation, and accretion	112,309			46,678			62,071
Full cost ceiling impairment	—			215,223			141,230
Income tax expense (benefit)	(99		)	106			(14,132		)
Stock-based compensation expense	11,225			9,491			15,162
Mark-to-market of commodity derivative contracts:
Total (gain) loss on commodity derivative contracts	4,226			7,750			(11,037		)
Cash settlements on commodity derivative contracts	942			5,374			29,992
Cash premiums paid for commodity derivative contracts	—			—			(5,073		)
Interest expense, net of interest income	11,479			(192		)	135
Adjusted EBITDA	$	282,564		$	65,241		$	86,659

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PV-10

PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with US GAAP, but rather should be considered in addition to the standardized measure.

PV-10 is derived from the standardized measure, which is the most directly comparable GAAP financial measure. PV-10 is calculated using the same inputs and assumptions as the standardized measure, with the exception that it omits the impact of future income taxes. It is considered to be a pre-tax measurement.

The following table provides a reconciliation of the standardized measure to PV-10:

	As of December 31,									As of August 31, 2015
	2017			2016			2015
Standardized measure of discounted future net cash flows	$	1,600,675		$	434,261		$	390,953		$	365,829
Add: 10 percent annual discount, net of income taxes	1,267,258			427,587			408,939			372,658
Add: future undiscounted income taxes	285,349			90,195			108,172			144,399
Future pre-tax net cash flows	$	3,153,282		$	952,043		$	908,064		$	882,886
Less: 10 percent annual discount, pre-tax	(1,396,998		)	(475,695		)	(469,921		)	(444,605		)
PV-10	$	1,756,284		$	476,348		$	438,143		$	438,281

Critical Accounting Policies

We prepare our consolidated financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the consolidated financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management discusses the development, selection, and disclosure of each of the critical accounting policies.

Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Numerous assumptions are used in the reserve estimation process. Various engineering and geologic criteria are interpreted to derive volumetric estimates, and financial assumptions are made with regard to realized pricing, costs to be incurred to develop and operate the properties, and future tax regimes.

In spite of the imprecise nature of reserves estimates, they are a critical component of our consolidated financial statements. The determination of the depletion component of our DD&A, as well as the ceiling test calculation, is highly dependent on estimates of proved oil and natural gas reserves. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells, and catastrophic events. Lower prices can also make it uneconomical to drill wells or produce from properties with high operating costs.

Oil and Gas Properties, including Ceiling Test: There are two alternative methods of accounting for enterprises involved in the oil and gas industry: the successful efforts method and the full cost method. We use the full cost method of accounting. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of dry holes, abandoned leases, delay rentals, and overhead costs directly related to acquisition, exploration, and development activities) are capitalized into a single full cost pool.

Under the successful efforts method, exploration costs, including the cost of exploratory wells that do not increase proved reserves, the cost of geological and geophysical activities, seismic costs, and lease rentals, are charged to expense as incurred. Depletion of oil and gas properties and the evaluation for impairment are generally calculated on a narrowly defined asset basis compared to an aggregated "pool" basis under the full cost method. The conveyance or abandonment of oil and gas assets generally

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results in recognition of gain or loss. In comparison, the conveyance or abandonment of full cost properties does not generally result in the recognition of gain or loss unless non-recognition of such a gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. Under full cost accounting, recognition of gain or loss is only allowable when the transaction would significantly alter the relationship between capitalized costs and proved reserves.

Our calculation of DD&A expense incorporates all the costs capitalized under full cost accounting plus the estimate of costs to be incurred to develop proved reserves. The sum of historical and future costs is allocated to our estimated quantities of proved oil and natural gas reserves and depleted using the units-of-production method. Changes in commodity prices, as well as associated changes in costs that are affected by commodity prices, can have a significant impact on the estimates used in our calculations.

Companies that use full cost accounting perform a ceiling test each quarter. The full cost ceiling test is the impairment test prescribed by SEC Regulation S-X Rule 4-10. The test compares capitalized costs in the full cost pool less accumulated DD&A and related deferred income taxes to a calculated ceiling amount. The calculated ceiling amount is equal to the sum of the present value of estimated future net revenues, plus the cost of properties not being amortized plus the lower of cost or estimated fair value of unproven properties included in costs being amortized less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves (as defined in the SEC rules) to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance sheet are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. In accordance with SEC Staff Accounting Bulletin Topic 12D, the income tax effect is calculated by using the present value of estimated future net revenue as pre-tax income, deducting the aforementioned tax effects, and applying the statutory tax rate. If the net capitalized costs exceed the ceiling amount, the excess must be charged to expense in recognition of the impairment.

Under the ceiling test, the estimate of future revenues is calculated using a current price (as defined in the SEC rules to include data points over a trailing 12-month period). Thus, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the change on the financial statements over several reporting periods.

During the year ended December 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairments were necessary. A decline in oil and natural gas prices, or an increase in oil and natural gas prices that is insufficient to overcome the impact of price declines in the year-ago periods on the ceiling test calculation, could result in ceiling test impairments in future periods.

Oil, Natural Gas, and NGL Sales: Our proportionate interests in transactions are recorded as revenue when products are delivered to the purchasers. This method can require estimates of volumes, ownership interests, and settlement prices. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. Historically, such differences have not been material. During periods of increased price volatility, it will be more difficult to estimate final settlement prices, and retroactive price adjustments pertaining to prior periods could become significant.

Asset Retirement Obligations ("ARO"): We are subject to legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an ARO requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using our credit-adjusted risk-free rate. Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  This is typically when a well is completed, or an asset is placed in service.  When the ARO is initially recorded, we capitalize the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset.  ARCs related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value (accretion of ARO), while the capitalized cost decreases over the useful life of the asset as depletion expense is recognized.

Commodity Derivative Instruments: Our use of commodity derivative instruments helps us mitigate the cash flow impact of short-term commodity price volatility. We typically enter into contracts covering a portion of our expected oil and natural gas production over 24 months. We record realized gains and losses for contracts that settle during the reporting periods. Contracts

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either settle at their scheduled maturity date or settle prior to their scheduled maturity date as a result of our decision to early liquidate an open position. Realized gains and losses represent cash transactions. Under our commodity derivative strategy, we typically receive cash payments when the posted price for the settlement period is less than the derivative price. Conversely, when the posted price for the settlement period is greater than the derivative price, we typically disburse a cash payment to the counterparty. Thus, realized gains and losses tend to offset increases or decreases in our revenue stream that are caused by changing prices.

In comparison, unrealized gains and losses are related to positions that have not yet settled and do not represent cash transactions. At each reporting date, we estimate the fair value of the open (not settled) commodity contract positions and record a gain or loss based upon the change in fair value since the previous reporting date. The fair values are an approximation of the contracts' values as if we sold them on the reporting date. Since these amounts represent a calculated value for a hypothetical transaction, the actual value realized at the cash settlement date may be significantly different.

A downward trend in commodity prices would generally be expected to result in reduced oil, natural gas, and NGL revenues partially offset realized gains in our hedge transactions. During any reporting period in which commodity prices decline, we expect to report unrealized gains on our open commodity derivative contracts. However, during any period in which the downward trend reverses, we expect to report unrealized losses. Looking forward, we expect current contracts to be settled or liquidated over the next 24 months. We expect to periodically enter into new commodity derivative contracts at then-current prices. Newer commodity derivative contracts at lower prices will reduce the amount of potential price protection provided by the newer contracts.

Business Combinations: The Company accounts for certain transactions under Accounting Standards Codification ("ASC") 805, Business Combinations. For each transaction, the Company reviews the transaction to determine whether it involves an asset or a business. This review requires that we assess various criteria outlined by ASC 805. If the criteria are not met, the transaction is considered an asset acquisition. If the criteria are met, the transaction is considered an acquisition of a business which the Company accounts for using the acquisition method. Under the acquisition method, assets acquired and liabilities assumed are measured at their fair values, which requires the use of significant judgment since some of the acquired assets and liabilities do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (when available), appraisals, comparisons to transactions for similar assets and liabilities, and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Once the fair values of the assets acquired and the liabilities assumed are determined, the excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, the excess, if any, of the fair value of assets acquired and liabilities assumed over the purchase price of the acquired entity is recognized immediately in earnings as a gain from bargain purchase.

Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill. We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and contain considerable management judgments. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.

Income Taxes: Deferred income taxes are recorded for timing differences between items of income or expense reported in the consolidated financial statements and those reported for income tax purposes using the asset/liability method of accounting for income taxes. Deferred income taxes and tax benefits are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and for tax loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. We provide for deferred taxes

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for the estimated future tax effects attributable to temporary differences and carryforwards when realization is more likely than not. If we conclude that it is more likely than not that some portion, or all, of the net deferred tax asset will not be realized, the balance of net deferred tax assets is reduced by a valuation allowance.

We consider many factors in our evaluation of deferred tax assets, including the following sources of taxable income that may be available under the tax law to realize a portion or all of a tax benefit for deductible timing differences and carryforwards:

•Future reversals of existing taxable temporary differences,

•Taxable income in prior carry back years, if permitted,

•Tax planning strategies, and

•Future taxable income exclusive of reversing temporary differences and carryforwards.

Recently Adopted and Issued Accounting Pronouncements

See Note 1, Organization and Summary of Significant Accounting Policies, to the accompanying consolidated financial statements included elsewhere in this report for information regarding recently adopted and issued accounting pronouncements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of natural gas prices, as approximately 72% of our revenue during year ended December 31, 2017 was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a $29.1 million change in revenues for the year ended December 31, 2017, a $0.25 per Mcf change in our realized natural gas price would have resulted in a $6.2 million change in our natural gas revenues, and a $5 per barrel change in our realized NGL price would have resulted in a $12.6 million change in our NGL revenues for the year ended December 31, 2017.

During the year ended December 31, 2017, the price of oil, natural gas, and NGLs increased relative to the year ended 2016.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil, natural gas, and NGL prices include the levels of demand and supply for oil (in global or local markets), the establishment of and compliance with production quotas by oil exporting countries, weather conditions which influence the demand for natural gas, the price and availability of alternative fuels, the strength of the US dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil, natural gas, and NGLs prices with any degree of certainty. Sustained weakness in oil, natural gas, and NGL prices may adversely affect our financial condition and results of operations and may also reduce the amount of oil, natural gas, and NGL reserves that we can produce economically. Any reduction in our oil, natural gas, and NGL reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil, natural gas, and NGL prices can have a favorable impact on our financial condition, results of operations, and capital resources.

We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and natural gas production.  Under the Revolver, we can use derivative contracts to cover up to 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years.  We do not enter into derivative contracts for speculative or trading purposes.  As ofDecember 31, 2017, we had open oil and natural gas derivatives in a netliabilityposition with a fair value of$7.9 million.  A hypothetical upward shift of 10% in the NYMEX forward curve of oil and natural gas prices would decrease the fair value of our position by$9.0 million. A hypothetical downward shift of 10% in the NYMEX forward curve of oil and natural gas prices would increase the fair value of our position by$3.8 million.

Interest Rate Risk - At December 31, 2017, we had no debt outstanding under our revolving credit facility.  Interest on our credit facility accrues at a variable rate, based upon either the Prime Rate or LIBOR plus an applicable margin.  During the year ended December 31, 2017, we incurred interest at an annualized rate of 3.4%.  We are exposed to interest rate risk on the credit facility if the variable reference rates increase.  If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease.  We estimate that if market interest rates increased or decreased by 1% for the year ended December 31, 2017, our interest payments would have changed by approximately $0.6 million.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year, and we have not undertaken any activities to mitigate potential interest rate risk due to restrictions imposed by the Revolver.

Counterparty Risk - As described in "- Commodity Price Risk" above, we enter into commodity derivative agreements

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to mitigate short-term price volatility.  These derivative financial instruments present certain counterparty risks.  We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows.  We do not require collateral or other security to be furnished by counterparties.  We seek to manage the counterparty risk associated with these contracts by limiting transactions to well capitalized, well established, and well-known counterparties that have been approved by our senior officers.  There can be no assurance, however, that our practice effectively mitigates counterparty risk.   

We believe that our exposure to counterparty risk increased slightly during the year ended December 31, 2017 as the amounts due to us from counterparties has increased.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The consolidated financial statements and supplementary data are filed with this Annual Report in a separate section following Part IV, as shown in the index on page F-1 of this Annual Report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report on Form 10-K (the “Evaluation Date”).  Based on such evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the Evaluation Date, our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including Lynn A. Peterson, our Chief Executive Officer, and James P. Henderson, our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017 based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2017.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2017, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which appears herein.

60

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of SRC Energy Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of SRC Energy Inc. and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2017, of the Company and our report dated February 21, 2018, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado 

February 21, 2018

61

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The information responsive to Items 401, 405, 406, and 407 of Regulation S-K to be included in our definitive Proxy Statement for our Annual Meeting of Shareholders, to be filed within 120 days of December 31, 2017, pursuant to Regulation 14A under the Exchange Act (the “2018 Proxy Statement”), is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information responsive to Items 402 and 407 of Regulation S-K to be included in our 2018 Proxy Statement is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information responsive to Items 201(d) and 403 of Regulation S-K to be included in our 2018 Proxy Statement is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

The information responsive to Items 404 and 407 of Regulation S-K to be included in our 2018 Proxy Statement is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information responsive to Items 9(e) of Schedule 14A to be included in our 2018 Proxy Statement is incorporated herein by reference.

62

PART IV

ITEM 15    EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Financial Statements

See page F-1 for a description of the financial statements filed with this report.

Exhibits

Exhibit Number	Exhibit
3.1	Second Amended and Restated Articles of Incorporation of SRC Energy Inc. (the "Company") effective as of June 15, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of the Company filed on June 20, 2017)
3.2	Amended and Restated Bylaws of the Company, effective as of August 18, 2017 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K of the Company filed on August 22, 2017)
4.1	Indenture, dated as of June 14, 2016, among the Company and U.S. Bank National Association as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of the Company filed on June 14, 2016)
4.2	Indenture, dated as of November 29, 2017, among the Company and U.S. Bank National Association as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of the Company filed on November 29, 2017)
10.1	Amended and Restated Credit Agreement, dated as of November 28, 2012 (the “Credit Agreement”), by and among the Company, Community Banks of Colorado, as administrative agent and the lenders party thereto as amended by the First Amendment to Credit Agreement dated as of February 12, 2013 and the Second Amendment to Credit Agreement dated June 28, 2013 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K of the Company filed on October 30, 2014)
10.1.1	Third Amendment to Credit Agreement, dated as of December 20, 2013, by and among the Company, Community Banks of Colorado as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.22 to the Current Report on Form 8-K of the Company filed on December 26, 2013)
10.1.2	Fourth Amendment to Credit Agreement, dated as of June 3, 2014, by and among the Company, Community Banks of Colorado, as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.23 to the Current Report on Form 8-K of the Company filed on June 10, 2014)
10.1.3	Fifth Amendment to Credit Agreement, dated as of December 15, 2014, by and among the Company, SunTrust Bank as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.32 to the Quarterly Report on Form 10-Q of the Company filed on January 9, 2015)
10.1.4	Sixth Amendment to Credit Agreement, dated as of June 2, 2015, by and among the Company, SunTrust Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.35 to the Current Report on Form 8-K of the Company filed on June 8, 2015)
10.1.5	Seventh Amendment to Credit Agreement, dated as of January 28, 2016, by and among the Company, SunTrust Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of the Company filed on February 2, 2016)
10.1.6	Eighth Amendment to Credit Agreement, dated as of May 3, 2016, by and among the Company, SunTrust Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of the Company filed on May 3, 2016)
10.1.7	Ninth Amendment to Credit Agreement, dated as of October 14, 2016, among the Company, SunTrust Bank as Administrative Agent and as an Issuing Bank, and the lenders party thereto (incorporated by reference to Exhibit 99.1 to the Quarterly Report on Form 10-Q of the Company filed on November 3, 2016)
10.1.8	Tenth Amendment to Credit Agreement, dated as of April 28, 2017, among the Company, SunTrust Bank as Administrative Agent and as an Issuing Bank, and the lenders party thereto (incorporated by reference to Exhibit 99.1 to the Quarterly Report on Form 10-Q of the Company filed on May 4, 2017)
10.1.9	Eleventh Amendment to Amended and Restated Credit Agreement, dated as of September 27, 2017, among the Company, SunTrust Bank as Administrative Agent and as an Issuing Bank, and the lenders party thereto (incorporated by reference to Exhibit 99.1 to the Quarterly Report on Form 10-Q of the Company filed on November 1, 2017)
10.2	Commitment Letter, dated as of May 3, 2016, by and among the Company, MTP Energy Master Fund Ltd., and GSO Capital Partners LP (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of the Company filed on May 3, 2016)

63

10.3	Purchase and Sale Agreement dated May 2, 2016 between Noble Energy, Inc., NBL Energy Royalties, Inc., and Noble Energy Wyco, LLC, as Sellers, and the Company, as Buyer (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of the Company filed on May 3, 2016)
10.4	Note Purchase Agreement, dated as of June 14, 2016, among the Company, MTP Energy Master Fund Ltd., and FS Energy and Power Fund (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of the Company filed on June 14, 2016)
10.5	Purchase and Sale Agreement, dated November 7, 2017, by and between the Company and Noble Energy, Inc. and one of its subsidiaries (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of the Company filed on November 8, 2017)
10.6	Note Purchase Agreement, dated November 14, 2017, among the Company and the initial purchasers named therein *
10.7	Registration Rights Agreement, dated November 29, 2017, by and among the Company and the several Initial Purchasers named therein, relating to the 6.250% Senior Notes due 2025 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of the Company filed on November 29, 2017)
10.8	Employment Agreement dated as of May 27, 2015 between the Company and Lynn A. Peterson (incorporated by reference to Exhibit 10.34 to the Current Report on Form 8-K of the Company filed on June 2, 2015) +
10.8.1	First Amendment to Employment Agreement dated as of December 22, 2016 between the Company and Lynn A. Peterson (incorporated by reference to Exhibit 10.5.1 to the Annual Report on Form 10-K of the Company filed on February 23, 2015) +
10.9	Form of Severance Compensation Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 24, 2016) +
10.10	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K of the Company filed on October 16, 2015) +
10.11	2015 Equity Incentive Plan (incorporated by reference to Exhibit 10.18 to the Current Report on Form 8-K of the Company filed on December 17, 2015) +
10.11.1	Form of Performance Share Unit Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 10-Q of the Company filed on August 4, 2016) +
10.11.2	Form of Restricted Share Unit Agreement (incorporated by reference to Exhibit 10.2 to the Current Report on Form 10-Q of the Company filed on August 4, 2016) +
21.1	Subsidiaries of the Company - No significant subsidiaries
23.1	Consent of Deloitte & Touche LLP *
23.2	Consent of EKS&H LLLP *
23.3	Consent of Ryder Scott Company, L.P. *
31.1	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as amended *
31.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as amended *
32.1	Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to 18 USC 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 **
99.1	Report of Ryder Scott Company, L.P. *
101.INS	XBRLInstance Document *
101.SCH	XBRL Taxonomy Extension Schema *
101.CAL	XBRL Taxonomy Extension Calculation Linkbase *
101.DEF	XBRL Taxonomy Extension Definition Linkbase *
101.LAB	XBRL Taxonomy Extension Label Linkbase *
101.PRE	XBRL Taxonomy Extension Presentation Linkbase *

* Filed herewith

** Furnished herewith

+ Management contract or compensatory plan or arrangement

64

SRC ENERGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Index to Consolidated Financial Statements	F-1
Reports of Independent Registered Public Accounting Firms	F-3
Consolidated Balance Sheets	F-4
Consolidated Statements of Operations	F-5
Consolidated Statements of Changes in Shareholders’ Equity	F-6
Consolidated Statements of Cash Flows	F-7
Notes to Consolidated Financial Statements	F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of SRC Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of SRC Energy Inc. and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in shareholders' equity, and cash flows, for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2018, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

February 21, 2018

We have served as the Company's auditor since 2016.

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

SRC Energy Inc.

Denver, Colorado

We have audited the accompanying consolidated balance sheet of SRC Energy Inc. (formerly known as Synergy Resources Corporation) as of December 31, 2015, and the related statements of operations, changes in shareholders’ equity, and cash flows for the four months ended December 31, 2015 and for the year ended August 31, 2015. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of SRC Energy Inc. as of December 31, 2015, and the results of its operations and its cash flows for the four months ended December 31, 2015 and for the year ended August 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ EKS&H LLLP

April 22, 2016

Denver, Colorado

F-3

SRC ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data) 

ASSETS	December 31, 2017			December 31, 2016
Current assets:
Cash and cash equivalents	$	48,772		$	18,615
Accounts receivable:
Oil, natural gas, and NGL sales	86,013			25,728
Trade	18,134			6,805
Commodity derivative assets	—			297
Other current assets	7,116			2,739
Total current assets	160,035			54,184
Property and equipment:
Oil and gas properties, full cost method:
Proved properties, net of accumulated depletion	970,584			424,082
Wells in progress	106,269			81,780
Unproved properties and land, not subject to depletion	793,669			398,547
Oil and gas properties, net	1,870,522			904,409
Other property and equipment, net	6,054			4,327
Total property and equipment, net	1,876,576			908,736
Cash held in escrow and other deposits	—			18,248
Goodwill	40,711			40,711
Other assets	2,242			2,234
Total assets	$	2,079,564		$	1,024,113
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	74,672		$	52,453
Revenue payable	64,111			16,557
Production taxes payable	52,413			17,673
Asset retirement obligations	3,246			2,683
Commodity derivative liabilities	7,865			2,874
Total current liabilities	202,307			92,240
Revolving credit facility	—			—
Notes payable, net of issuance costs	538,186			75,614
Asset retirement obligations	28,376			13,775
Other liabilities	2,261			1,745
Total liabilities	771,130			183,374
Commitments and contingencies (See Note 16)
Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding	—			—
Common stock - $0.001 par value, 300,000,000 shares authorized: 241,365,522 and 200,647,572 shares issued and outstanding as of December 31, 2017 and 2016, respectively	241			201
Additional paid-in capital	1,474,273			1,148,998
Retained deficit	(166,080		)	(308,460		)
Total shareholders' equity	1,308,434			840,739
Total liabilities and shareholders' equity	$	2,079,564		$	1,024,113

The accompanying notes are an integral part of these consolidated financial statements

F-4

SRC ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Oil, natural gas, and NGL revenues	$	362,516		$	107,149		$	34,138		$	124,843
Expenses:
Lease operating expenses	19,496			19,949			5,812			15,017
Transportation and gathering	3,226			—			—			—
Production taxes	36,266			5,732			3,104			11,340
Depreciation, depletion, and accretion	112,309			46,678			18,776			65,869
Full cost ceiling impairment	—			215,223			125,230			16,000
Unused commitment charge	669			597			2,802			—
General and administrative	32,965			30,545			17,875			18,995
Total expenses	204,931			318,724			173,599			127,221
Operating income (loss)	157,585			(211,575		)	(139,461		)	(2,378		)
Other income (expense):
Commodity derivative gain (loss)	(4,226		)	(7,750		)	6,482			32,256
Interest expense, net of amounts capitalized	(11,842		)	—			—			(245		)
Interest income	363			192			40			86
Other income	503			50			—			—
Total other income (expense)	(15,202		)	(7,508		)	6,522			32,097
Income (Loss) before income taxes	142,383			(219,083		)	(132,939		)	29,719
Income tax expense (benefit)	(99		)	106			(10,007		)	11,677
Net income (loss)	$	142,482		$	(219,189	)	$	(122,932	)	$	18,042
Net income (loss) per common share:
Basic	$	0.69		$	(1.26	)	$	(1.14	)	$	0.19
Diluted	$	0.69		$	(1.26	)	$	(1.14	)	$	0.19
Weighted-average shares outstanding:
Basic	206,167,506			173,774,035			107,789,554			94,628,665
Diluted	206,743,551			173,774,035			107,789,554			95,319,269

The accompanying notes are an integral part of these consolidated financial statements

F-5

SRC ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(in thousands, except share data)

	Number of Common Shares	Par Value Common Stock		Additional Paid - In Capital			Accumulated Earnings (Deficit)			Total Shareholders' Equity
Balance, August 31, 2014	77,999,082	$	78	$	265,793		$	15,619		$	281,490
Shares issued in equity offering	18,613,952	19		190,826			—			190,845
Shares issued for acquisition	4,648,136	5		48,429			—			48,434
Shares issued in exchange for mineral assets	995,672	1		11,786			—			11,787
Shares issued for exercise of warrants	2,562,473	2		15,368			—			15,370
Shares issued under stock bonus plan	161,755	—		2,950			—			2,950
Shares issued for exercise of stock options	118,272	—		—			—			—
Stock-based compensation for options	—	—		4,741			—			4,741
Payment of tax withholdings using withheld shares	—	—		(1,262		)	—			(1,262		)
Net income	—	—		—			18,042			18,042
Balance, August 31, 2015	105,099,342	105		538,631			33,661			572,397
Shares issued for acquisition	4,418,413	4		49,835			—			49,839
Shares issued in exchange for mineral assets	37,051	—		426						426
Shares issued under stock bonus and equity incentive plans	422,035	1		7,162			—			7,163
Shares issued for exercise of stock options	56,760	—		—			—			—
Stock-based compensation for options	—	—		2,161			—			2,161
Payment of tax withholdings using withheld shares	—	—		(2,544		)	—			(2,544		)
Net loss	—	—		—			(122,932		)	(122,932		)
Balance, December 31, 2015	110,033,601	110		595,671			(89,271		)	506,510
Shares issued in equity offerings	90,275,000	90		543,321			—			543,411
Shares issued under stock bonus and equity incentive plans	321,101	1		4,231			—			4,232
Shares issued for exercise of stock options	17,870	—		68			—			68
Stock-based compensation for options	—	—		5,417			—			5,417
Stock-based compensation for performance-vested stock units	—	—		1,047			—			1,047
Payment of tax withholdings using withheld shares	—	—		(757		)	—			(757		)
Net loss	—	—		—			(219,189		)	(219,189		)
Balance, December 31, 2016	200,647,572	201		1,148,998			(308,460		)	840,739
Adoption of ASU 2016-09	—	—		102			(102		)	—
Shares issued in equity offering	40,250,000	40		312,131			—			312,171
Shares issued under stock bonus and equity incentive plans	280,284	—		4,976			—			4,976
Shares issued for exercise of stock options	187,666	—		740			—			740
Stock-based compensation for options	—	—		5,076			—			5,076
Stock-based compensation for performance-vested stock units	—	—		2,938			—			2,938
Payment of tax withholdings using withheld shares	—	—		(688		)	—			(688		)
Net income	—	—		—			142,482			142,482
Balance, December 31, 2017	241,365,522	$	241	$	1,474,273		$	(166,080	)	$	1,308,434

The accompanying notes are an integral part of these consolidated financial statements

F-6

SRC ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,						Four Months Ended December 31, 2015				Year Ended August 31, 2015
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	142,482		$	(219,189	)	$	(122,932	)		$	18,042
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and accretion	112,309			46,678			18,776				65,869
Full cost ceiling impairment	—			215,223			125,230				16,000
Settlements of asset retirement obligations	(4,541		)	(228		)	(745		)		—
Loss on extinguishment of debt	11,842			—			—				—
Provision for deferred taxes	—			—			(10,007		)		11,679
Stock-based compensation expense	11,225			9,491			8,431				7,691
Mark-to-market of commodity derivative contracts:
Total (gain) loss on commodity derivative contracts	4,226			7,750			(6,482		)		(32,256		)
Cash settlements on commodity derivative contracts	942			5,374			1,954				31,721
Cash premiums paid for commodity derivative contracts	—			—			(956		)		(4,117		)
Changes in operating assets and liabilities	12,830			(16,411		)	6,803			6,803	10,458
Net cash provided by operating activities	291,315			48,688			20,072				125,087
Cash flows from investing activities:
Acquisitions of oil and gas properties and leaseholds	(661,468		)	(511,173		)	(37,150		)		(82,584		)
Capital expenditures for drilling and completion activities	(450,384		)	(119,571		)	(41,581		)		(186,135		)
Other capital expenditures	(17,841		)	(7,044		)	(5,811		)		(6,375		)
Acquisition of land and other property and equipment	(4,186		)	(5,478		)	(395		)		(714		)
Proceeds from sales of oil and gas properties and other	93,573			25,350			—				6,239
Net cash used in investing activities	(1,040,306		)	(617,916		)	(84,937		)		(269,569		)
Cash flows from financing activities:
Proceeds from the sale of stock	322,000			565,398			—				200,100
Offering costs	(9,745		)	(21,987		)	—				(9,255		)
Proceeds from the employee exercise of stock options	741			68			—				15,370
Payment of employee payroll taxes in connection with shares withheld	(688		)	(757		)	(2,544		)		(1,262		)
Proceeds from revolving credit facility	250,000			55,000			—				186,000
Principal repayments on revolving credit facility	(250,000		)	(133,000		)	—				(145,000		)
Proceeds from issuance of notes payable	550,000			80,000			—				—
Repayment of notes payable	(88,234		)	—			—				—
Financing fees on issuance of notes payable and amendments to revolving credit facility	(13,145		)	(5,159		)	—				(2,316		)
Net cash provided by (used in) financing activities	760,929			539,563			(2,544		)		243,637
Net increase (decrease) in cash, cash equivalents, and restricted cash	11,938			(29,665		)	(67,409		)		99,155
Cash, cash equivalents, and restricted cash at beginning of period	36,834			66,499			133,908				34,753
Cash, cash equivalents, and restricted cash at end of period	$	48,772		$	36,834		$	66,499			$	133,908

Supplemental Cash Flow Information (See Note 17)

The accompanying notes are an integral part of these consolidated financial statements

F-7

SRC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015, and August 31, 2015

1. Organization and Summary of Significant Accounting Policies

Organization:  SRC Energy Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and NGLs, primarily in the D-J Basin of Colorado. On June 15, 2017, our shareholders approved an amendment to the Amended and Restated Articles of Incorporation of the Company to change the name of the Company from Synergy Resources Corporation to SRC Energy Inc. The Company had been using the new name on a "doing business as" basis since March 6, 2017. In addition to using the new name, the Company’s common stock, which is listed and traded on the NYSE American, changed to the new symbol "SRCI."

Basis of Presentation:  The Company operates in one business segment, and all of its operations are located in the United States of America.

At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc. When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

Change of Year-End:  On February 25, 2016, the Company's Board of Directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year.

Use of Estimates:The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates.

Cash and Cash Equivalents:  The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. As of December 31, 2016, the Company had placed $18.2 million in escrow, which was released upon the second closing of the GC Acquisition. Please refer to Note 3, Acquisitions and Divestitures, for further information.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows:

	As of December 31,						As of August 31, 2015
	2017		2016		2015
Cash and cash equivalents	$	48,772	$	18,615	$	66,499	$	133,908
Restricted cash included in cash held in escrow and other deposits	—		18,219		—		—
	$	48,772	$	36,834	$	66,499	$	133,908

F-8

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is the impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties.  The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During theyear ended December 31, 2017, the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company recognized ceiling test impairments of$215.2 million,$125.2 million, and$16.0 million, respectively.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials and are held constant for the productive life of each well.

Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest:The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 10 for additional information.

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information.

Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment, and software), office leasehold improvements, office furniture and equipment, and buildings are stated at historical cost. Expenditures

F-9

for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its other property and equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. 

Accounts Payable and Accrued Expenses: Accounts payable and accrued expenses consist of the following (in thousands):

	As of December 31,
	2017		2016
Trade accounts payable	$	624	$	786
Accrued well costs	56,348		42,779
Accrued G&A	6,017		4,292
Accrued LOE	5,249		3,140
Accrued interest	3,125		320
Accrued other	3,309		1,136
	74,672		52,453

Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received.

Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset.  Asset retirement costs ("ARCs") related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment.

Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under FASB Accounting Standards Codification ("ASC") 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination.  Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31^st. During 2016, we changed the date of our annual goodwill impairment assessment to October 1^st. With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge.

F-10

When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit.  If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge.  The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill.  For purposes of assessing goodwill, the Company only has one reporting unit.

We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.

Oil, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests.  Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the product is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:    The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue (“major customers”) for each of the periods presented are shown in the following table:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31, 2015
	2017	2016
Company A	33%	*	*	*
Company B	24%	20%	15%	11%
Company C	17%	20%	*	*
Company D	*	16%	*	*
Company E	*	13%	*	*
Company F	*	*	57%	65%
Company G	*	*	12%	*

* less than 10%

Based on the current demand for oil and natural gas, the availability of other buyers, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that the loss of our existing customers or individual contract would not have a material adverse effect on us. Our oil and natural gas production is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.

Accounts receivable consist primarily of receivables from oil, natural gas, and NGL sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

F-11

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):

	As of December 31,
	2017	2016
Company A	26%	23%
Company B	23%	*
Company C	16%	*
Company D	11%	43%
Company E	*	10%

* less than 10%

The Company operates exclusively within the United States of America, and except for cash and cash equivalents, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry.

Lease Operating Expenses:  Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities.

Stock-Based Compensation:  The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model.  For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation.  The compensation is recognized over the vesting period of the grant.  See Note 13 for additional information.

Income Tax:  Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions were identified as of any date on or before December 31, 2017.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of December 31, 2017, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 15 for further information.

Financial Instruments: Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative gain (loss) line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 8.

Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for

F-12

additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations.

Recently Adopted Accounting Pronouncements:

In November 2016, the FASB issued Accounting Standards Update ("ASU") 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. We adopted this pronouncement effective October 1, 2017 and have applied it retrospectively. Upon adoption, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2016. This change resulted in a decrease to net cash used in investing activities of $18.2 million. Additionally, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2017. This change resulted in an increase to net cash used in investing activities of $18.2 million. The adoption of this standard did not impact cash flows for the 4-months ended December 31, 2015 nor the year ended August 31, 2015. We have included a tabular reconciliation of cash, cash equivalents, and restricted cash in the discussion of "Cash Held in Escrow" above.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance did not impact the consolidated financial statements.

Recently Issued Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International

F-13

Financial Reporting Standards. The FASB subsequently issued various ASUs, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The Company will adopt these ASUs with an effective date of January 1, 2018, using the modified retrospective method. While we have not yet completed all aspects of the adoption of the standard, based on our current assessment of contracts with customers, we do not believe there will be any impact to the timing of our revenue recognition or our operating income (loss), net income (loss), and cash flows. The Company is in the process of evaluating changes, if any, to accounting policies and internal control procedures along with continuing to assess additional disclosures which may be required upon implementation of these ASUs.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

2. Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):

	As of December 31,
	2017			2016
Oil and gas properties, full cost method:
Costs of proved properties:
Producing and non-producing	$	1,629,789		$	969,239
Less, accumulated depletion and full cost ceiling impairments	(659,205		)	(545,157		)
Subtotal, proved properties, net	970,584			424,082
Costs of wells in progress	106,269			81,780
Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs	786,469			392,561
Land	7,200			5,986
Subtotal, unproved properties and land	793,669			398,547
Costs of other property and equipment:
Other property and equipment	8,134			5,063
Less, accumulated depreciation	(2,080		)	(736		)
Subtotal, other property and equipment, net	6,054			4,327
Total property and equipment, net	$	1,876,576		$	908,736

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At December 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company's ceiling tests resulted in total impairments of $215.2 million, $125.2 million, and $16.0 million, respectively. No impairments were recognized for the comparable 2017 period.

The costs of unproved properties are withheld from the depletion base until such time as the properties are either developed or abandoned. Unproved properties are reviewed on an annual basis, or more frequently if necessary, for impairment and, if impaired, are reclassified to proved properties and included in the depletion base. During the year ended December 31, 2017, these reviews indicated that the estimated fair value of such assets exceeded the carrying values. Therefore, no impairment was necessary as December 31, 2017. However, during the years ended December 31, 2016 and August 31, 2015, the Company recorded impairments of $18.9 million and $15.4 million, respectively, related to the fair value of its unproved properties. No such impairments were recognized during the four months ended December 31, 2015.

F-14

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Capitalized overhead	$	10,293	$	7,074	$	1,091	$	2,049

Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Acquisition of property:
Unproved	$	538,489	$	365,548	$	38,779	$	32,701
Proved	139,154		152,363		51,085		51,400
Exploration costs	—		43,154		23,697		146,892
Development costs	460,875		87,782		17,742		4,957
Other property and equipment, and land	4,397		7,506		395		741
Capitalized interest, capitalized G&A, and other	26,677		18,744		4,415		7,051
Total costs incurred	$	1,169,592	$	675,097	$	136,113	$	243,742

Capitalized Costs Excluded from Depletion:  The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2017 (in thousands):

	Period Incurred
	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31,				Total as of December 31, 2017
	2017		2016				2015		2014 and Prior
Unproved leasehold acquisition costs	$	537,470	$	223,907	$	23,068	$	456	$	1,568	$	786,469
Unproved development costs	26,056		—		—		—		—		26,056
Total unevaluated costs	$	563,526	$	223,907	$	23,068	$	456	$	1,568	$	812,525

There were no individually significant properties or significant development projects included in the Company’s unproved property balance.  The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established.  The majority of these costs are expected to be evaluated and included in the depletion base within three years.

3. Acquisitions and Divestitures

The Company seeks to acquire developed and undeveloped oil and gas properties in the core Wattenberg Field to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons.

December 2017 Acquisition

In November 2017, the Company entered into an agreement ("GCII Agreement") to purchase a total of approximately 30,200 net acres located in an area known as the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $568 million ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement. On December 15, 2017, the Company closed on the portion of the assets comprised of the undeveloped lands and non-operated production. The effective date of this part of the transaction was November 1, 2017, and the purchase price was $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities. The purchase price has preliminarily been allocated as $59.9 million to proved oil and gas

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properties and $509.6 million to unproved oil and gas properties, pending the final closing. The second closing will cover the operated producing properties and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.

The first closing was accounted for as an asset acquisition under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of December 15, 2017.

September 2017 Acquisition

In September 2017, we completed the second closing of the GC Acquisition (as defined in "-June 2016 Acquisition" below). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million, composed of cash of $6.3 million and assumed liabilities of $24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties.

August 2017 Acquisition and Swap

In August 2017, we also entered into an agreement with another party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also acquired approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities. The purchase price for the acquisition has preliminarily been allocated as $6.7 million to proved oil and gas properties and $15.9 million to unproved oil and gas properties, pending the final closing.

March 2017 Acquisition

In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million, composed of cash and assumed liabilities. The purchase price has been allocated as $15.3 million to proved oil and gas properties, $9.4 million to unproved oil and gas properties, and $0.4 million to other assets and land.

Acquisitions in the Second Half of 2016

In August and October 2016, the Company completed four acquisitions of certain assets for a total purchase price of $13.5 million composed of cash, forgiven receivables, and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests and additional interests in developed properties operated by the Company.

June 2016 Acquisition

In May 2016, we entered into a purchase and sale agreement pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million (the "GC Acquisition").

In June 2016, the Company closed on the portion of the assets comprised of undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. As discussed above in "- September 2017 Acquisition" above,we closed on the second part of this transaction covering the operated producing properties in September 2017.

The first closing on June 14, 2016 was for a total purchase price of $486.4 million, net of customary closing adjustments. The purchase price was composed of $485.1 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOED at the time of entering into the GC Agreement.

The first closing was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of

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$0.5 millionrelated to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	June 14, 2016
Consideration given:
Cash	$	485,141
Net liabilities assumed, including asset retirement obligations	1,273
Total consideration given	$	486,414
Allocation of Purchase Price(1)
Proved oil and gas properties	$	132,903
Unproved oil and gas properties	353,511
Total fair value of assets acquired	$	486,414

⁽¹⁾ Oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of11.5%, and assumptions regarding the timing and amount of future development and operating costs.

For theyear ended December 31, 2017, the results of operations of the acquired assets, representing approximately$5.4 millionof revenue and$4.7 millionofoperating income, have been included in the Company's consolidated statements of operations.

The following table presents the unaudited pro forma combined results of operations for the year ended December 31, 2016 as if the first closing had occurred on September 1, 2014.  The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

(in thousands)	Year Ended December 31, 2016
Oil, natural gas, and NGL revenues	$	110,635
Net loss	$	(218,578	)
Net loss per common share
Basic	$	(1.10	)
Diluted	$	(1.10	)

February 2016 Acquisition

In February 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million. The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties. See Note 9 for further details as to the preparation of these significant estimates.

Divestitures

During the year ended December 31, 2017, we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities.

During the year ended December 31, 2016, the Company completed divestitures of approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities. The divested assets had associated production of approximately 200 BOED.

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In accordance with full cost accounting guidelines, the net proceeds from these divestitures were credited to the full cost pool.

4. Depletion, depreciation, and accretion ("DD&A")

DD&A consisted of the following (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Depletion of oil and gas properties	$	109,287	$	45,193	$	18,371	$	65,158
Depreciation and accretion	3,022		1,485		405		711
Total DD&A Expense	$	112,309	$	46,678	$	18,776	$	65,869

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the year ended December 31, 2017, production of 12,481 MBOE represented 5.2% of estimated total proved reverses. For the year ended December 31, 2016, production of 4,271 MBOE represented 4.4% of estimated total proved reserves. For the four months ended December 31, 2015, production of 1,320 MBOE represented 2.0% of estimated total proved reserves.

For the year ended August 31, 2015, production of 3,194 MBOE represented 5.3% of estimated total proved reserves. DD&A expense was $9.00 per BOE and $10.93 per BOE for the years ended December 31, 2017 and 2016, respectively. DD&A expense was $14.22 per BOE and $20.62 per BOE for the four months ended December 31, 2015 and the year ended August 31, 2015, respectively.

5. Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):

	Year Ended December 31,
	2017			2016
Beginning asset retirement obligation	$	16,458		$	13,400
Obligations incurred with development activities	3,398			773
Obligations assumed with acquisitions	24,696			2,230
Accretion expense	1,554			1,046
Obligations discharged with asset retirements and divestitures	(14,332		)	(4,739		)
Revisions in previous estimates	(152		)	3,748
Ending asset retirement obligation	$	31,622		$	16,458
Less, current portion	(3,246		)	(2,683		)
Non-current portion	$	28,376		$	13,775

During the year ended December 31, 2017, the Company decreased its asset retirement obligation by $0.2 million due to a revision to the expected timing of the future cash flows. During the year ended December 31, 2016, the Company increased its asset retirement obligation by $3.7 million due primarily to a revision to its assumption of the average cost to plug and abandon each well.

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6. Revolving Credit Facility

The Company maintains a revolving credit facility (sometimes referred to as the "Revolver") with a bank syndicate with a maturity date of December 15, 2019. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of December 31, 2017, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $400 million. As of December 31, 2017 and 2016, there was no outstanding principal balance. The Company has an outstanding letter of credit of approximately $0.5 million.

In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base.The borrowing base was increased from$225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018.

Interest under the Revolver accrues monthly at a variable rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the years ended December 31, 2017 and 2016, was 3.4%, and 2.6%, respectively.

Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur, or if the bank syndicate or the Company so elects, an unscheduled redetermination could be undertaken.

The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report.

Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than1.0to 1.0. As ofDecember 31, 2017, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

7. Notes Payable

2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of6.6%. The net proceeds were used to fund the GCII Acquisition as discussed further in Note3, repay the 2021 Senior Notes, and pay off the outstanding Revolver balance.

At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the principal amount plus an Applicable Premium (as defined in the Indenture) plus accrued and unpaid interest.  On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption priceequal to a specified percentage of the principal amount of the redeemed notes (104.688% for 2020, 103.125% for 2021,101.563%for 2022, and 100% for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest.Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to35%of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to106.25%of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

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The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

As ofDecember 31, 2017, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

2021 Senior Notes

In June 2016, the Company issued $80 millionaggregate principal amount of 9% Senior Notes due 2021 (the "2021 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal was June 13, 2021. Interest on the 2021 Senior Notes accrued at9%and began accruing on June 14, 2016. Interest was payable on June 15 and December 15 of each year, beginning on December 15, 2016. The 2021 Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the 2021 Senior Notes were $75.2 millionafter deductions of $4.8 millionfor expenses and underwriting discounts and commissions.

In December 2017, the Company repurchased all $80 million aggregate principal amount of the 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.

8. Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.

A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may at times purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase.

A "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where the cost of the put is offset by the proceeds of the call. At settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term.

The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with five counterparties and an exchange. Three of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

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The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses are recorded in the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in it making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.

The Company’s commodity derivative contracts as of December 31, 2017 are summarized below:

Settlement Period	Derivative Instrument	Average Volumes (Bbls per day)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	40.00	$	57.50
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	40.00	$	57.75
Jan 1, 2018 - Dec 31, 2018	Collar	500	$	40.00	$	57.50
Jan 1, 2018 - Dec 31, 2018	Collar	2,500	$	45.00	$	58.00
Jan 1, 2018 - Dec 31, 2018	Collar	2,500	$	45.00	$	64.55
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	44.50	$	65.00
Jan 1, 2018 - Dec 31, 2018	Collar	1,500	$	44.50	$	65.00
Settlement Period	Derivative Instrument	Average Volumes (MMBtu per day)	Floor Price		Ceiling Price
Natural Gas - CIG Rocky Mountain
Jan 1, 2018 - Dec 31, 2018	Collar	10,000	$	2.25	$	2.82
Jan 1, 2018 - Dec 31, 2018	Collar	5,000	$	2.25	$	2.81

Subsequent to December 31, 2017, the Company added the following positions:

Settlement Period	Derivative Instrument	Average Volumes (Bbls per day)	Average Fixed Price
Propane - Mont Belvieu
Feb 1, 2018 - Dec 31, 2018	Swap	1,000	$	0.80

Offsetting of Derivative Assets and Liabilities

As of December 31, 2017 and 2016, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its consolidated balance sheets.

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The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):

		As of December 31, 2017
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	1,960	$	(1,960	)	$	—
Commodity derivative contracts	Non-current assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	9,825	$	(1,960	)	$	7,865
Commodity derivative contracts	Non-current liabilities	$	—	$	—		$	—

		As of December 31, 2016
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	2,045	$	(1,748	)	$	297
Commodity derivative contracts	Non-current assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	4,622	$	(1,748	)	$	2,874
Commodity derivative contracts	Non-current liabilities	$	—	$	—		$	—

The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017			2016
Realized gain (loss) on commodity derivatives	$	39		$	2,355		$	1,577	$	30,466
Unrealized gain (loss) on commodity derivatives	(4,265		)	(10,105		)	4,905		1,790
Total gain (loss)	$	(4,226	)	$	(7,750	)	$	6,482	$	32,256

Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date net of the previously incurred premiums attributable to settled commodity contracts. During the year ended August 31, 2015, the Company liquidated oil derivatives with an average price of $82.79 and covering 372,500 barrels and received cash settlements of approximately $20.5 million. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Monthly settlement	$	1,062		$	4,396		$	2,331		$	11,212
Previously incurred premiums attributable to settled commodity contracts	(1,023		)	(2,041		)	(754		)	(1,255		)
Early liquidation	—			—			—			20,509
Total realized gain (loss)	$	39		$	2,355		$	1,577		$	30,466

Credit Related Contingent Features

As of December 31, 2017, three of the six counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the fourth counterparty, which

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is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fifth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.

9. Fair Value Measurements

ASC 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

• Level 1: Quoted prices available in active markets for identical assets or liabilities;

• Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and

• Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations and asset acquisitions, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its unproved properties using market comparables which are deemed to be a Level 3 input. See Note 2 for additional information.

The acquisition of a group of assets in a business combination transaction and certain asset acquisitions requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired is calculated using a net discounted cash flow approach for the proved producing, proved undeveloped, probable, and possible properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using market comparables.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rate, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Notes 3 and 5 for additional information.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at December 31, 2017
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	—	$	—	$	—
Commodity derivative liability	$	—	$	7,865	$	—	$	7,865

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	Fair Value Measurements at December 31, 2016
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	297	$	—	$	297
Commodity derivative liability	$	—	$	2,874	$	—	$	2,874

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At December 31, 2017, derivative instruments utilized by the Company consist of collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, cash held in escrow, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, cash held in escrow, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the notes payable is estimated to be $564.1 million at December 31, 2017. The Company determined the fair value of its notes payable at December 31, 2017 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes payable as Level 2.

10. Interest Expense

The components of interest expense are (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Revolving credit facility	$	2,004		$	154		$	661		$	2,776
Notes payable	10,036			3,940			—			—
Amortization of debt issuance costs	3,084			1,638			431			853
Debt extinguishment costs	11,842			—			—			—
Less: interest capitalized	(15,124		)	(5,732		)	(1,092		)	(3,384		)
Interest expense, net	$	11,842		$	—		$	—		$	245

F-24

11. Shareholders’ Equity

The Company's classes of stock are summarized as follows:

	As of December 31,
	2017		2016
Preferred stock, shares authorized	10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized	300,000,000		300,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding	241,365,522		200,647,572

Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors.  Since inception, the Company has not issued any preferred shares.

Shares of the Company’s common stock were issued during the years ended December 31, 2017 and 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, as described further below.

Sales of common stock

A summary of the transactions is shown in the following table.  Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions, and expenses of the offering.

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Number of common shares sold	40,250,000		90,275,000		—		18,613,952
Offering price per common share	$	7.76	$	6.02	$	—	$	10.75
Net proceeds (in thousands)	$	312,170	$	543,400	$	—	$	190,845

In November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 5,250,000 shares of common stock on the same terms and conditions. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to40,250,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were$312.2 million. The Company used the proceeds of the Offering to pay a portion of the purchase price of the GCII Acquisition, to repay a portion of the 2021 Senior Notes,and to repay amounts borrowed under the Revolver.

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Common stock issued for acquisition of mineral property interests

During the periods presented, the Company issued shares of common stock in exchange for mineral property interests.  The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Number of common shares issued for mineral property leases	—		—		37,051		995,672
Number of common shares issued for acquisitions	—		—		4,418,413		4,648,136
Total common shares issued	—		—		4,455,464		5,643,808
Average price per common share	$	—	$	—	$	11.28	$	10.67
Aggregate value of shares issues (in thousands)	$	—	$	—	$	50,265	$	60,221

12.    Weighted-Average Shares Outstanding

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31,2015
	2017	2016
Weighted-average shares outstanding - basic	206,167,506	173,774,035	107,789,554	94,628,665
Potentially dilutive common shares from:
Stock options	417,809	—	—	672,493
Restricted stock units and stock bonus shares	158,236	—	—	18,111
Weighted-average shares outstanding - diluted	206,743,551	173,774,035	107,789,554	95,319,269

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31, 2015
	2017	2016
Potentially dilutive common shares from:
Stock options	4,657,834	6,001,500	5,056,000	2,785,500
Performance-vested stock units1	951,884	478,510	—	—
Restricted stock units and stock bonus shares	285,448	890,336	915,867	145,000
Total	5,895,166	7,370,346	5,971,867	2,930,500

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

13. Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant-date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting period").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of December 31, 2017, there were 4,500,000 common shares authorized for

F-26

grant under the 2015 Equity Incentive Plan, of which 110,158 shares were available for future grants. The shares available for future grant exclude 951,884 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards met the criterion to vest at their maximum multiplier.

The amount of stock-based compensation was as follows (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Stock options	$	5,076		$	5,417		$	2,161		$	4,741
Performance-vested stock units	2,938			1,047			—			—
Restricted stock units and stock bonus shares	4,977			4,232			7,162			2,950
Total stock-based compensation	12,991			10,696			9,323			7,691
Less: stock-based compensation capitalized	(1,766		)	(1,205		)	(892		)	(778		)
Total stock-based compensation expense	$	11,225		$	9,491		$	8,431		$	6,913

Stock options

No stock options were granted during the year ended December 31, 2017. During the periods presented, the Company granted the following stock options:

	Year Ended December 31, 2016		Four Months Ended December 31, 2015		Year Ended August 31, 2015
Number of options to purchase common shares	1,067,500		1,142,500		2,377,500
Weighted-average exercise price	$	7.19	$	10.84	$	11.55
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	3 - 5 years		3.7-5 years		3-5 years
Fair Value (in thousands)	$	3,860	$	6,591	$	13,266

The assumptions used in valuing stock options granted during each of the periods presented were as follows:

	Year Ended December 31, 2016		Four Months Ended December 31, 2015		Year Ended August 31, 2015
Expected term	6.4 years		6.5 years		6.5 years
Expected volatility	55	%	53	%	47	%
Risk-free rate	1.25 - 2.00%		1.8 - 2.0%		1.4 - 2.0%
Expected dividend yield	—	%	—	%	—	%

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The following table summarizes activity for stock options for the periods presented:

	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, August 31, 2014	2,167,000		$	5.94	8.0 years	$	16,287
Granted	2,377,500		11.55
Exercised	(258,000	)	3.81			2,103
Forfeited	(110,000	)	4.97
Outstanding, August 31, 2015	4,176,500		9.29		8.6 years	8,187
Granted	1,142,500		10.84
Exercised	(188,000	)	6.56			981
Expired	(60,000	)	11.74
Forfeited	(15,000	)	11.68
Outstanding, December 31, 2015	5,056,000		9.71		8.7 years	4,351
Granted	1,067,500		7.19
Exercised	(20,000	)	3.19			117
Expired	—		—
Forfeited	(102,000	)	10.40
Outstanding, December 31, 2016	6,001,500		9.27		8.0 years	6,515
Granted	—		—
Exercised	(187,666	)	3.95			976
Expired	(41,000	)	11.98
Forfeited	(136,000	)	10.97
Outstanding, December 31, 2017	5,636,834		$	9.38	7.0 years	$	4,806
Outstanding, Exercisable at December 31, 2017	3,203,045		$	9.08	6.5 years	$	3,587

The following table summarizes information about issued and outstanding stock options as of December 31, 2017:

	Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life
Under $5.00	454,000	$	3.45	3.5 years	454,000	$	3.45	3.5 years
$5.00 - $6.99	1,012,000	6.38		6.9 years	558,400	6.45		5.8 years
$7.00 - $10.99	1,548,834	9.36		7.4 years	708,245	9.53		7.0 years
$11.00 - $13.46	2,622,000	11.58		7.4 years	1,482,400	11.59		7.4 years
Total	5,636,834	$	9.38	7.0 years	3,203,045	$	9.08	6.5 years

The estimated unrecognized compensation cost from stock options not vested as of December 31, 2017, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	9,697
Remaining vesting period	2.3 years

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Restricted stock units and stock bonus awards

The Company grants restricted stock units and stock bonus awards to directors, eligible employees, and officers as a part of its equity incentive plan.  Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.

The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented:

	Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, August 31, 2014	293,333		$	10.60
Granted	547,699		11.17
Vested	(208,532	)	11.09
Forfeited	—		—
Not vested, August 31, 2015	632,500		10.93
Granted	919,604		10.08
Vested	(636,237	)	10.13
Forfeited	—		—
Not vested, December 31, 2015	915,867		10.63
Granted	464,533		7.66
Vested	(424,483	)	9.92
Forfeited	(65,581	)	8.99
Not vested, December 31, 2016	890,336		9.55
Granted	681,568		8.29
Vested	(455,772	)	9.21
Forfeited	(28,746	)	9.74
Not vested, December 31, 2017	1,087,386		$	8.89

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2017, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	7,113
Remaining vesting period	2.2 years

Performance-vested stock units

The Company grants performance-vested stock units ("PSUs") to certain executives under its long-term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock

F-29

prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, and the volatilities for each of the Company’s peers.

The assumptions used in valuing the PSUs granted were as follows:

	Year Ended December 31,
	2017		2016
Weighted-average expected term	2.9 years		2.7 years
Weighted-average expected volatility	59	%	58	%
Weighted-average risk-free rate	1.34	%	0.87	%

The fair value of the PSUs granted during the years ended December 31, 2017 and 2016 was $5.1 million and $4.0 million, respectively. As of December 31, 2017, unrecognized compensation for PSUs was $5.0 million and will be amortized through 2019. A summary of the status and activity of PSUs is presented in the following table:

	Number of Units1		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2015	—		$	—
Granted	490,713		8.10
Vested	—		—
Forfeited	(12,203	)	8.22
Not vested, December 31, 2016	478,510		8.09
Granted	473,374		10.79
Vested	—		—
Forfeited	—		—
Not vested, December 31, 2017	951,884		$	9.44

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

14. Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan (the "plan") for eligible employees. Effective January 1, 2017, the Company modified the plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation. The Company contributed approximately $0.7 million for year ended December 31, 2017, $0.4 million for the year ended December 31, 2016, $0.1 million for the four months ended December 31, 2015, and $0.1 million during the year ended August 31, 2015 to the plan.

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15. Income Taxes

The income tax provision is comprised of the following (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Current:
Federal	$	(99	)	$	106		$	—		$	(4	)
State	—			—			—			(111		)
Total current income tax expense (benefit)	(99		)	106			—			(115		)
Deferred:
Federal	48,631			(74,099		)	(45,332		)	10,820
State	4,371			(6,651		)	(4,074		)	972
Total deferred income tax (benefit) expense	53,002			(80,750		)	(49,406		)	11,792
Valuation allowance	(53,002		)	80,750			39,399			—
Income tax expense (benefit)	$	(99	)	$	106		$	(10,007	)	$	11,677

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Federal income tax at statutory rate	$	48,410		$	(74,489	)	$	(45,200	)	$	10,105
State income taxes, net of federal tax	4,371			(6,685		)	(4,062		)	908
Statutory depletion	(159		)	(287		)	(150		)	(451		)
Stock-based compensation	50			383			—			92
Non-deductible compensation	—			—			—			850
Impact of tax reform, net of valuation allowance	(99		)
Valuation allowance	(53,002		)	80,750			39,399			—
Other	330			434			6			173
Income tax expense (benefit)	$	(99	)	$	106		$	(10,007	)	$	11,677
Effective rate expressed as a percentage	—		%	—		%	8		%	39		%

On December 22, 2017, Congress signed Public Law No. 115-97, commonly referred to as the Tax Cut and Jobs Act of 2017 (“TCJA”). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21% beginning in January of 2018, the elimination of the corporate alternative minimum tax (“AMT”), the acceleration of depreciation for US tax purposes, limitations on deductibility of interest expense, the elimination of net operating loss carrybacks, and limitations on the use of future losses.  In accordance with ASC 740, Income Taxes, the impact of a change in tax law is recorded in the period of enactment. Consequently, the Company has recorded a decrease to its net deferred tax assets of $24.0 million with a corresponding net adjustment to the valuation allowance for the year ended December 31, 2017.  The Company also eliminated the $0.1 million deferred tax asset for its AMT credits and recorded a non-current tax receivable with a corresponding benefit to current income taxes. Based on the Company's current interpretation and subject to the release of the related regulations and any future interpretive guidance, the Company believes the effects of the change in tax law incorporated herein are substantially complete. As a result of other changes introduced by the TCJA, starting with compensation paid in 2018, Section 162(m) may limit us from deducting compensation, including performance-based compensation, in excess of $1 million paid to anyone who, starting in 2018, serves as the Chief Executive Officer or Chief Financial Officer, or who is among the three most highly compensated executive officers for any fiscal year. The only exception to this rule is for compensation that is paid pursuant to a binding contract in effect on November 2, 2017 that would have otherwise been deductible under the prior Section 162(m) rules. Accordingly, any compensation

F-31

paid in the future pursuant to new compensation arrangements entered into after November 2, 2017, even if performance-based, will count towards the $1 million fiscal year deduction limit if paid to a covered executive. Additional information that may affect our income tax accounts and disclosures would include further clarification and guidance on how the Internal Revenue Service will implement tax reform, including guidance with respect to 100% bonus depreciation on self-constructed assets and Section 162(m), further clarification and guidance on how state taxing authorities will implement tax reform and the related effect on our state income tax returns, completion of our 2017 tax return filings, and the potential for additional guidance from the SEC or the FASB related to tax reform.

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):

	As of December 31,
	2017			2016
Deferred tax assets (liabilities):
Net operating loss carryforward	$	43,283		$	47,462
Stock-based compensation	5,237			5,576
Basis of oil and gas properties	(5,011		)	62,707
Statutory depletion	2,795			4,028
Unrealized loss on commodity derivative	1,939			1,334
Other	(615		)	(958		)
	47,628			120,149
Valuation allowance on tax assets	(47,628		)	(120,149		)
Deferred tax asset (liability), net	$	—		$	—

In connection with ASU 2016-09, deferred tax assets were increased by $4.5 million related to excess benefit net operating loss carryforwards along with a $4.5 million offsetting increase in the Company's valuation allowance. The impact of the adjustments netted to zero within retained earnings.

At December 31, 2017, the Company has U.S. Federal and state net operating loss carryforward of approximately $175.5 million that could be utilized to offset taxable income of future years. These net operating loss carryforwards will expire in various years beginning in 2025 with substantially all of the carryforwards expiring beginning in 2031.

At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making an assessment as to the future utilization of deferred tax assets. During the year ended December 31, 2017, the Company recognized a full valuation allowance on its net deferred tax assets. This decision was based on the fact that for the preceding three-year period, the Company has reported cumulative net losses. 

The ability of the Company to utilize its NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards.

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The Company underwent an ownership change as defined in Section 382 of the Internal Revenue Code on December 31, 2016, as a result of our issuance of common stock. The amount of our taxable income for tax years ending after our ownership change, which may be offset by NOL carryovers from pre-change years, will be subject to an annual limitation, known as a Section 382 limitation. The Section 382 limitation is based on the value of our stock immediately before the ownership change multiplied by the long-term tax exempt rate in effect at the time of the ownership change, increased by built in gains recognized during the 5-year period beginning on the ownership change date. The identified change of ownership is not anticipated to restrict the Company's ability to utilize its NOLs.

As of December 31, 2017, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. The Company's federal and state tax returns filed since August 31, 2014 and August 31, 2013, respectively, remain subject to examination by tax authorities.

16. Other Commitments and Contingencies

Volume Commitments

The Company entered into firm sales agreements for its oil production with three counterparties during 2014 and entered into an additional firm sales agreement for its oil production in the third quarter 2017. Deliveries under two of the sales agreements commenced during 2015. Deliveries under the third agreement commenced in 2016. Deliveries under the fourth agreement are expected to commence in the fourth quarter of 2018. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described below, are as follows:

Year ending December 31,	Oil (MBbls)
2018	4,485
2019	5,167
2020	4,003
2021	1,672
2022	—
Thereafter	—
Total	15,327

During the years ended December 31, 2017 and 2016, and four months ended December 31, 2015, the Company incurred transportation deficiency charges of $0.7 million, $0.6 million, and $2.8 million, respectively, as we were unable to meet all of the obligations during the period. No such charges were incurred during the year ended August 31, 2015.

In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed during the third quarter of 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in mid-2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. We expect that our development plan will support the utilization of this capacity.

Litigation

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current proceedings are reasonably likely to have a material adverse impact on its business, financial position, results of operations, or cash flows.

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Office Leases

In September 2016, the Company entered into a new 65-month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021.

Rent expense for office leases was $1.1 million for the year ended December 31, 2017, $1.0 million for year ended December 31, 2016, $0.3 million for the four months ended December 31, 2015, and $0.3 million for the year ended August 31, 2015.

Vehicle Leases

In December 2017, the Company entered into a leasing arrangement for its vehicles used in our normal operations. These leases expire after four years and are classified as capital leases. The assets associated with these capital leases are recorded within "Other property and equipment, net."

A schedule of the minimum lease payments under non-cancelable capital and operating leases as of December 31, 2017 follows (in thousands):

Year ending December 31:	Vehicles Leases			Office Leases
2018	$	76		$	840
2019	37			859
2020	37			878
2021	63			875
2022	—			477
Thereafter	—			—
Total minimum lease payments	$	213		$	3,929
Less: Amount representing estimated executory cost	(16		)
Net minimum lease payments	197
Less: Amount representing interest	(24		)
Present value of net minimum lease payments *	$	173

^* Reflected in the balance sheet as current and non-current obligations of $63 thousand and $110 thousand, respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively.

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17. Supplemental Schedule of Information to the Consolidated Statements of Cash Flows

The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
Supplemental cash flow information:	2017			2016
Interest paid	$	9,235		$	3,779		$	683		$	2,817
Income taxes paid	$	—		$	106		$	(150	)	$	202
Non-cash investing and financing activities:
Accrued well costs as of period end	$	56,348		$	42,779		$	31,414		$	33,071
Assets acquired in exchange for common stock	—			—			50,265			60,221
Asset retirement obligations incurred with development activities	3,398			773			1,819			7,051
Asset retirement obligations assumed with acquisitions	24,696			2,230			—			—
Obligations discharged with asset retirements and divestitures	$	(14,332	)	$	(4,739	)	$	—		$	—
Net changes in operating assets and liabilities:
Accounts receivable	$	(72,518	)	$	(13,063	)	$	5,696		$	3,446
Accounts payable and accrued expenses	5,823			2,283			3,954			(2,307		)
Revenue payable	47,345			2,254			(5,441		)	4,557
Production taxes payable	33,311			(7,095		)	3,631			5,121
Other	(1,131		)	(790		)	(1,037		)	(359		)
Changes in operating assets and liabilities	$	12,830		$	(16,411	)	$	6,803		$	10,458

18. Unaudited Oil and Natural Gas Reserves Information

Oil and Natural Gas Reserve Information:  Proved reserves are the estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made).  Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Proved oil and natural gas reserve information as of the period ends presented and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott.  Reserve information for the properties was prepared in accordance with guidelines established by the SEC.

The reserve estimates prepared as of each of the period ends presented were prepared in accordance with applicable SEC rules.  Proved oil and natural gas reserves are calculated based on the prices for oil and natural gas during the twelve-month period before the determination date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can generally be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking.

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The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented:

	Oil (MBbl)		Natural Gas (MMcf)		NGL (MBbl)		MBOE
Balance, August 31, 2014	16,324		95,179		—		32,188
Revision of previous estimates	(1,699	)	(4,889	)	—		(2,513	)
Purchase of reserves in place	4,201		21,957		—		7,860
Extensions, discoveries, and other additions	11,465		73,392		—		23,696
Sale of reserves in place	(629	)	(4,337	)	—		(1,352	)
Production	(1,970	)	(7,344	)	—		(3,194	)
Balance, August 31, 2015	27,692		173,958		—		56,685
Revision of previous estimates	(10,917	)	(38,931	)	—		(17,407	)
Purchase of reserves in place	4,380		58,959		—		14,207
Extensions, discoveries, and other additions	8,263		62,301		—		18,647
Sale of reserves in place	(2,297	)	(14,149	)	—		(4,655	)
Production	(742	)	(3,468	)	—		(1,320	)
Balance, December 31, 2015	26,379		238,670		—		66,157
Revision of previous estimates	(7,788	)	(80,549	)	—		(21,213	)
Purchase of reserves in place	23,141		197,103		—		55,991
Extensions, discoveries, and other additions	1,457		13,018		—		3,627
Sale of reserves in place	(2,900	)	(24,235	)	—		(6,939	)
Production	(2,257	)	(12,086	)	—		(4,271	)
Balance, December 31, 2016	38,032		331,921		—		93,352
Revision of previous estimates	(3,038	)	(66,413	)	28,689		14,581
Purchase of reserves in place	12,150		117,167		13,424		45,103
Extensions, discoveries, and other additions	28,736		206,644		24,358		87,535
Sale of reserves in place	(660	)	(4,592	)	—		(1,425	)
Production	(5,824	)	(24,834	)	(2,518	)	(12,481	)
Balance, December 31, 2017	69,396		559,893		63,953		226,665
Proved developed and undeveloped reserves:
Developed at August 31, 2015	7,393		46,026		—		15,064
Undeveloped at August 31, 2015	20,299		127,932		—		41,621
Balance, August 31, 2015	27,692		173,958		—		56,685
Developed at December 31, 2015	8,410		56,751		—		17,868
Undeveloped at December 31, 2015	17,969		181,919		—		48,289
Balance, December 31, 2015	26,379		238,670		—		66,157
Developed at December 31, 2016	7,435		62,570		—		17,863
Undeveloped at December 31, 2016	30,597		269,351		—		75,489
Balance, December 31, 2016	38,032		331,921		—		93,352
Developed at December 31, 2017	26,552		219,279		24,251		87,350
Undeveloped at December 31, 2017	42,844		340,614		39,702		139,315
Balance, December 31, 2017	69,396		559,893		63,953		226,665

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Notable changes in proved reserves for the year ended December 31, 2017 included:

• Purchases of reserves in place. For the year ended December 31, 2017, purchases of reserves in place of 45,103 MBOE were primarily attributable to the acquisition of proved reserves in the GCII Acquisition. Please see Note 3 for further information.

• Revision of previous estimates. For the year ended December 31, 2017, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 14,581 MBOE primarily as a result of updated pricing as well as shifting from reporting reserves on a 2-stream to a 3-stream basis.

• Extensions and discoveries. For the year ended December 31, 2017, total extensions and discoveries of 87,535 MBOE were primarily attributable to extending our development plan by a year due to the passage of time, the addition of a third rig for the second and third years of our development plan, and the drilling and completion of wells not previously proved.

Notable changes in proved reserves for the year ended December 31, 2016 included:

• Purchases of reserves in place. For the year ended December 31, 2016, purchases of reserves in place of 55,991 MBOE were primarily attributable to the acquisition of proved reserves in the GC Acquisition. Please see Note 3 for further information.

• Revision of previous estimates. For the year ended December 31, 2016, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 21,213 MBOE primarily as a result of the GC Acquisition and related changes to our development plan that resulted in the removal of certain legacy PUD locations from the three-year drilling plan.

• Extensions and discoveries. For the year ended December 31, 2016, total extensions and discoveries of 3,627 MBOE were primarily attributable to successful drilling in the Wattenberg Field. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Notable changes in proved reserves for the four months ended December 31, 2015 included:

• Purchases of reserves in place. For the four months ended December 31, 2015, purchases of reserves in place of 14,207 MBOE were attributable to the acquisition of proved reserves. Please see Note3 for further information.

• Revision of previous estimates. For the four months ended December 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17,407 MBOE. As the Company continued to revise its drilling plans, the development plan was changed to remove undeveloped reserves that were not projected to be drilled in the subsequent three years and reflected the lower development costs anticipated from transitioning to a monobore wellbore design and longer horizontal wells; in addition, we high-graded our inventory of wells to be drilled.

• Extensions and discoveries. For the four months ended December 31, 2015, total extensions and discoveries of 18,647 MBOE were primarily attributable to successful drilling in the Wattenberg Field. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Notable changes in proved reserves for the year ended August 31, 2015 included:

• Purchases of reserves in place. For the year ended August 31, 2015, purchases of reserves in place of 7,860 MBOE were attributable to the acquisition of proved reserves.

• Revision of previous estimates. For the year ended August 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,513 MBOE. As the Company continued to revise its drilling plans toward horizontal drilling, the vertical proved undeveloped and vertical developed non-producing locations were removed from its development plan.

• Extensions and discoveries. For the year ended August 31, 2015, total extensions and discoveries of 23,696 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 67 vertical exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Standardized Measure of Discounted Future Net Cash Flows:  The following discussion relates to the standardized measure of future net cash flows from our proved reserves and changes therein related to estimated proved reserves.  Future oil and natural gas sales have been computed by applying average prices of oil and natural gas as discussed below.  Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the period based on period-end costs.  The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs.  Future income tax expenses were calculated by applying period-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and

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natural gas producing activities.  All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows.  Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves.  Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation.

The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands):

	As of December 31,									As of August 31, 2015
	2017			2016			2015
Future cash inflow	$	5,493,507		$	2,180,673		$	1,710,610		$	2,046,615
Future production costs	(1,291,369		)	(644,093		)	(462,097		)	(653,009		)
Future development costs	(1,048,856		)	(584,537		)	(340,449		)	(510,720		)
Future income tax expense	(285,349		)	(90,195		)	(108,172		)	(144,399		)
Future net cash flows	2,867,933			861,848			799,892			738,487
10% annual discount for estimated timing of cash flows	(1,267,258		)	(427,587		)	(408,939		)	(372,658		)
Standardized measure of discounted future net cash flows	$	1,600,675		$	434,261		$	390,953		$	365,829

There have been significant fluctuations in the posted prices of oil and natural gas during the last three years.  Prices actually received from purchasers of the Company’s oil and natural gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices.

The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:

	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2017 (Average)	$	46.57	$	2.21	$	16.06
December 31, 2016 (Average)	$	36.07	$	2.44	$	—
December 31, 2015 (Average)	$	41.33	$	2.60	$	—
August 31, 2015 (Average)	$	53.27	$	3.28	$	—

The prices for the December 31, 2017 oil and natural gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from January 1, 2017 through December 31, 2017. The December 31, 2017 oil price of $46.57 per barrel (West Texas Intermediate Cushing) was $10.50 higher than the December 31, 2016 oil price of $36.07 per barrel. The December 31, 2017 natural gas price of $2.21 per Mcf (Henry Hub) was $0.23 lower than the December 31, 2016 price of $2.44 per Mcf.

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Changes in the Standardized Measure of Discounted Future Net Cash Flows:  The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Standardized measure, beginning of period	$	434,261		$	390,953		$	365,829		$	402,699
Sale and transfers, net of production costs	(306,754		)	(81,468		)	(25,222		)	(98,486		)
Net changes in prices and production costs	135,525			(64,387		)	(81,968		)	(233,051		)
Extensions, discoveries, and improved recovery	811,564			18,795			116,343			173,918
Changes in estimated future development costs	(25,969		)	(6,016		)	(7,195		)	10,002
Previously estimated development costs incurred during the period	170,296			62,502			5,923			4,957
Revision of quantity estimates	165,267			(110,306		)	(36,820		)	(38,340		)
Accretion of discount	47,635			44,703			14,610			57,629
Net change in income taxes	(113,523		)	5,104			25,263			58,547
Divestitures of reserves	(7,157		)	(26,839		)	(43,754		)	(19,234		)
Purchase of reserves in place	260,999			228,855			77,024			56,795
Changes in timing and other	28,531			(27,635		)	(19,080		)	(9,607		)
Standardized measure, end of period	$	1,600,675		$	434,261		$	390,953		$	365,829

19. Unaudited Financial Data

The Company’s unaudited quarterly financial information is as follows (in thousands, except share data):

	Year Ended December 31, 2017
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Revenues	$	43,790	$	75,036	$	103,593		$	140,097
Expenses	27,536		48,514		57,461			71,420
Operating income	16,254		26,522		46,132			68,677
Other income (expense)	3,626		1,414		(2,284		)	(17,958		)
Income before income taxes	19,880		27,936		43,848			50,719
Income tax benefit	—		—		—			(99		)
Net income	$	19,880	$	27,936	$	43,848		$	50,818
Net income per common share: (1)
Basic	$	0.10	$	0.14	$	0.22		$	0.23
Diluted (2)	$	0.10	$	0.14	$	0.22		$	0.23
Weighted-average shares outstanding:
Basic	200,707,891		200,831,063		200,881,447			222,072,930
Diluted	201,309,251		201,224,172		201,460,915			222,917,611

F-39

	Year Ended December 31, 2016
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	18,273		$	23,947		$	26,234		$	38,695
Expenses	71,356			172,157			45,887			29,324
Operating income (loss)	(53,083		)	(148,210		)	(19,653		)	9,371
Other income (expense)	1,682			(5,537		)	417			(4,070		)
Income (loss) before income taxes	(51,401		)	(153,747		)	(19,236		)	5,301
Income tax expense	—			101			5			—
Net income (loss)	$	(51,401	)	$	(153,848	)	$	(19,241	)	$	5,301
Net income (loss) per common share: (1)
Basic	$	(0.42	)	$	(0.89	)	$	(0.10	)	$	0.03
Diluted (2)	$	(0.42	)	$	(0.89	)	$	(0.10	)	$	0.03
Weighted-average shares outstanding:
Basic	121,392,736			172,013,551			200,515,555			200,585,800
Diluted	121,392,736			172,013,551			200,515,555			201,254,678

¹  The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

²  Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 21st day of February 2018.

SRC Energy Inc.

/s/ Lynn A. Peterson

Lynn A. Peterson, Principal Executive Officer

/s/ James P. Henderson

James P. Henderson, Principal Financial Officer

/s/ Jared C. Grenzenbach

Jared C. Grenzenbach, Principal Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of l934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

F-40

Signature	Title	Date
/s/ Lynn A. Peterson	President, Chief Executive Officer, and Director	February 21, 2018
Lynn A. Peterson	(Principal Executive Officer)
/s/ Jack N. Aydin	Director	February 21, 2018
Jack N. Aydin
/s/ Daniel E. Kelly	Director	February 21, 2018
Daniel E. Kelly
/s/ Paul Korus	Director	February 21, 2018
Paul Korus
/s/ Raymond E. McElhaney	Director	February 21, 2018
Raymond E. McElhaney
/s/ Jennifer S. Zucker	Director	February 21, 2018
Jennifer S. Zucker

GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS

Units of Measurement

The following presents a list of units of measurement used throughout the document:

Bbl - One stock tank barrel of oil or 42 U.S. gallons liquid volume of NGLs.

Bcf - One billion cubic feet of natural gas volume.

BOE - One barrel of oil equivalent, which combines Bbls of oil, Mcf of natural gas by converting each six Mcf of natural gas to one Bbl of oil, and Bbls of NGLs.

BOED - BOE per day.

Btu - British thermal unit.

MBOE - One thousand BOE.

MMBbls - One million barrels of oil.

Mcf - One thousand cubic feet of natural gas volume.

MMBtu - One million British thermal units.

MMcf - One million cubic feet of natural gas volume.

MMcf/d - MMcf per day.

Glossary of Industry Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report:

Completion - Refers to the work performed and the installation of permanent equipment for the production of oil and natural gas from a recently drilled well.

Developed acreage - Acreage assignable to productive wells.

Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differentials - The difference between the oil and natural gas index spot price and the corresponding cash spot price in a specified location.

Dry gas - Natural gas is considered dry when its composition is over 90% pure methane.

Dry well or dry hole- A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or natural gas well.

EURs - Estimated ultimate recovery.

Exploratory well- A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest.

Gross acres or wells - Refers to the total acres or wells in which we have a working interest.

Henry Hub - Henry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts traded on the NYMEX.

Horizontal drilling- A drilling technique that permits the operator to drill a horizontal wellbore from the bottom of a vertical section of a well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling

F-42

techniques allow and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

Horizontal well- A well that has been drilled using the horizontal drilling technique. The term "horizontal wells" include wells where the productive length of the wellbore is drilled more or less horizontal to the earth's surface, to intersect the target formation on a parallel basis.

Hydraulically fracture or Hydraulic fracturing - a procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability, thereby allowing the release of trapped hydrocarbons.

Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions, and production operations among working interest partners.

Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from "wet" natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other condensates.

Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest.

Net revenue interest - Refers to all working interests less all royalties.

Net production- Oil and natural gas production that we own less royalties and production due to others.

Non-operated - A project in which another entity has responsibility over the daily operation of the project.

NYMEX- New York Mercantile Exchange.

OPEC - the Organization of Petroleum Exporting Countries.

Operator - The individual or company responsible for the exploration, development, and/or production of an oil or natural gas well or lease.

Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest.

Possible reserves - This term is defined in SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates.

Present value of future net revenues or PV-10 - PV-10 is a Non-GAAP financial measure calculated before the imposition of corporate income taxes. It is derived from the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves prepared in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.  The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on specified economic conditions.  The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas during the relevant period. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on current cost levels.  No deduction is made for the depletion of historical costs or for indirect costs, such as general corporate overhead.  Present values are computed by discounting future net revenues by 10% per year.

Probable reserves - This term is defined in SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

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Productive well - A well that is not a dry well or dry hole, as defined above, and includes wells that are mechanically capable of production.

Proved developed non-producing reservesor PDNPs - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves or PDPs- Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves.

Proved reserves - This term means "proved oil and natural gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of oil and condensate, natural gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved undeveloped reserves or PUDs- Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Recomplete or Recompletion - The modification of an existing well for the purpose of producing oil and natural gas from a different producing formation.

Reserves - Estimated remaining quantities of oil, natural gas, and NGLs or related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil, natural gas, and NGLs or related substances to market, and all permits and financing required to implement the project.

Royalty - An interest in an oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Section - A square tract of land one mile by one mile, containing 640 acres.

Spud - To begin drilling; the act of beginning a hole.

Standardized measure of discounted future net cash flows or standardized measure- Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense.

Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

Vertical well - Directional wells that are drilled at an angle toward a target area where the productive length of the wellbore intersects the target formation on a perpendicular basis.

Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate, and oil.

Working interest - An interest in an oil and gas lease that gives the owner of the interest the right to drill and produce oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations.

F-44

Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production.

WTI - West Texas Intermediate. A specific grade of oil used as a benchmark in oil pricing. It is the underlying commodity of NYMEX's oil futures contracts.

F-45

EX-10.6

Exhibit 10.6

$550,000,000

SRC Energy Inc.

6.250% Senior Notes due 2025

Purchase Agreement

November 14, 2017

J.P. Morgan Securities LLC
Credit Suisse Securities (USA) LLC

As Representatives of the

several Initial Purchasers listed

in Schedule 1 hereto

c/o J.P. Morgan Securities LLC

383 Madison Avenue

New York, New York 10179

c/o Credit Suisse Securities (USA) LLC

Eleven Madison Avenue
New York, New York 10010-3629

Ladies and Gentlemen:

SRC Energy Inc., a Colorado corporation (the “Company”), proposes to issue and sell to the several initial purchasers listed in Schedule 1 hereto (the “Initial Purchasers”), for whom you are acting as representatives (the “Representatives”), $550,000,000 principal amount of its 6.250% Senior Notes due 2025 (the “Securities”). The Securities will be issued pursuant to an Indenture to be dated as of November 29, 2017 (the "Indenture"), among the Company and U.S. Bank National Association, as trustee (the “Trustee”).

The Company hereby confirms its agreement with the several Initial Purchasers concerning the purchase and resale of the Securities, as follows:

1. Offering Memorandum and Transaction Information.

The Securities will be sold to the Initial Purchasers without being registered under the Securities Act of 1933, as amended (the “Securities Act”), in reliance upon an

exemption therefrom. The Company has prepared a preliminary offering memorandum dated November 8, 2017 (the “Preliminary Offering Memorandum”) and will prepare an offering memorandum dated the date hereof (the “Offering Memorandum”) setting forth information concerning the Company and the Securities. Copies of the Preliminary Offering Memorandum have been, and copies of the Offering Memorandum will be, delivered by the Company to the Initial Purchasers pursuant to the terms of this purchase agreement (the “Agreement”). The Company hereby confirms that it has authorized the use of the Preliminary Offering Memorandum, the other Time of Sale Information (as defined below) and the Offering Memorandum in connection with the offering and resale of the Securities by the Initial Purchasers in the manner contemplated by this Agreement. References herein to the Preliminary Offering Memorandum, the Time of Sale Information and the Offering Memorandum shall be deemed to refer to and include any document incorporated by reference therein and any reference to “amend,” “amendment” or “supplement” with respect to the Preliminary Offering Memorandum or the Offering Memorandum shall be deemed to refer to and include any documents filed after such date and incorporated by reference therein.

At or prior to the time when sales of the Securities were first made (the “Time of Sale”), the Company had prepared the following information (collectively, the “Time of Sale Information”): the Preliminary Offering Memorandum, as supplemented and amended by the written communications listed on Annex A hereto.

The Company intends to use the proceeds of the offering of the Securities to finance the Acquisition, to pay related fees and expenses, to redeem or repurchase its existing 9% senior notes due 2021 and other general corporate purposes, which may include repayment of amounts borrowed under the Credit Agreement (as defined below) (the“Transactions”).

The Company has entered into a Purchase and Sale Agreement (the “Acquisition Agreement”) dated as of November 7, 2017 with Noble Energy, Inc. and one of its subsidiaries (collectively, the “Seller”) to purchase certain assets of the Seller, as described in the Time of Sale Information. The term “Acquisition” as used herein shall refer to the transactions contemplated by the Acquisition Agreement.

Concurrently with the offering of the Securities, the Company is conducting an offering of its common stock (as it may be increased or decreased, the “Common Stock Offering”), the proceeds of which, together with the proceeds of the offering of the Securities, will be used to finance the Acquisition.

Holders of the Securities (including the Initial Purchasers and their direct and indirect transferees) will be entitled to the benefits of a Registration Rights Agreement, to be dated the Closing Date (as defined below) and substantially in the form attached hereto as Exhibit A (the “Registration Rights Agreement”), pursuant to which the Company will agree to file one or more registration statements with the Securities and Exchange Commission (the “Commission”) providing for the registration under the Securities Act of the Securities or the Exchange Securities referred to (and as defined) in the Registration Rights Agreement.

2.    Purchase and Resale of the Securities.

(a)    The Company agrees to issue and sell the Securities to the several Initial Purchasers as provided in this Agreement, and each Initial Purchaser, on the basis of the representations, warranties and agreements set forth herein and subject to the conditions set forth herein, agrees, severally and not jointly, to purchase from the Company the respective principal amount of Securities set forth opposite such Initial Purchaser’s name in Schedule 1 hereto at a price equal to 98% of the principal amount thereof plus accrued interest, if any, from November 29, 2017 to the Closing Date. The Company will not be obligated to deliver any of the Securities except upon payment for all the Securities to be purchased as provided herein.

(b)    The Company understands that the Initial Purchasers intend to offer the Securities for resale on the terms set forth in the Time of Sale Information. Each Initial Purchaser, severally and not jointly, represents, warrants and agrees that:

(i)    it is a qualified institutional buyer within the meaning of Rule 144A under the Securities Act (a “QIB”) and an accredited investor within the meaning of Rule 501(a) of Regulation D under the Securities Act (“Regulation D”);

(ii)    it has not solicited offers for, or offered or sold, and will not solicit offers for, or offer or sell, the Securities by means of any form of general solicitation or general advertising within the meaning of Rule 502(c) of Regulation D or in any manner involving a public offering within the meaning of Section 4(a)(2) of the Securities Act; and

(iii)    it has not solicited offers for, or offered or sold, and will not solicit offers for, or offer or sell, the Securities as part of their initial offering except:

(A)    to persons whom it reasonably believes to be QIBs in transactions pursuant to Rule 144A under the Securities Act (“Rule 144A”) and in connection with each such sale, it has taken or will take reasonable steps to ensure that the purchaser of the Securities is aware that such sale is being made in reliance on Rule 144A; or

(B)    in accordance with the restrictions set forth in Annex C hereto.

(c)    Each Initial Purchaser acknowledges and agrees that the Company and, for purposes of the “no registration” opinions to be delivered to the Initial Purchasers pursuant to Sections 6(f) and 6(h), counsel for the Company and counsel for the Initial Purchasers, respectively, may rely upon the accuracy of the representations and warranties of the Initial Purchasers, and compliance by the Initial Purchasers with their agreements, contained in paragraph (b) above (including Annex C hereto), and each Initial Purchaser hereby consents to such reliance.

(d)    The Company acknowledges and agrees that the Initial Purchasers may offer and sell Securities to or through any affiliate of an Initial Purchaser and that any such affiliate may offer and sell Securities purchased by it to or through any Initial Purchaser; provided, however, that any such affiliate shall be subject to the same obligations as its affiliated Initial Purchaser hereunder, and that such Initial Purchaser shall be liable for any breach of those obligations by such affiliate.

(e)    Payment for and delivery of the Securities will be made at the offices of Davis Polk & Wardwell LLP at 10:00 A.M., New York City time, on November 29, 2017, or at such other time or place on the same or such other date, not later than the fifth business day thereafter, as the Representatives and the Company may agree upon in writing. The time and date of such payment and delivery is referred to herein as the “Closing Date.”

(f)    Payment for the Securities shall be made by wire transfer in immediately available funds to the account(s) specified by the Company to the Representatives against delivery to the nominee of The Depository Trust Company (“DTC”), for the account of the Initial Purchasers, of one or more global notes representing the Securities (collectively, the “Global Note”), with any transfer taxes payable in connection with the sale of the Securities duly paid by the Company. The Global Note will be made available for inspection by the Representatives not later than 1:00 P.M., New York City time, on the business day prior to the Closing Date.

(g)    The Company acknowledges and agrees that each Representative and Initial Purchaser is acting solely in the capacity of an arm’s length contractual counterparty to the Company with respect to the offering of Securities contemplated hereby (including in connection with determining the terms of the offering) and not as a financial advisor or a fiduciary to, or an agent of, the Company or any other person. Additionally, neither the Representatives nor any other Initial Purchaser is advising the Company or any other person as to any legal, tax, investment, accounting or regulatory matters in any jurisdiction. The Company shall consult with its own advisors concerning such matters and shall be responsible for making its own independent investigation and appraisal of the transactions contemplated hereby, and the Representatives and the Initial Purchasers shall have no responsibility or liability to the Company with respect thereto. Any review by the Representatives or any Initial Purchaser of the Company, and the transactions contemplated hereby or other matters relating to such transactions will be performed solely for the benefit of the Representatives or such Initial Purchaser, as the case may be, and shall not be on behalf of the Company or any other person.

3.    Representations and Warranties of the Company. The Company represents and warrants to each Initial Purchaser that:

(a)Preliminary Offering Memorandum, Time of Sale Information and Offering Memorandum. The Preliminary Offering Memorandum, as of its date, did not, the Time of Sale Information, at the Time of Sale, did not, and at the Closing Date, will not, and the Offering Memorandum, in the form first used by the Initial Purchasers to confirm sales of the Securities and as of the Closing Date, will not, contain any untrue statement of a

material fact or omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that the Company makes no representation or warranty with respect to any statements or omissions made in reliance upon and in conformity with information relating to any Initial Purchaser furnished to the Company in writing by such Initial Purchaser through the Representatives expressly for use in the Time of Sale Information or the Offering Memorandum.

(b)Additional Written Communications. The Company (including its agents and representatives, other than the Initial Purchasers in their capacity as such) has not prepared, made, used, authorized, approved or referred to and will not make, use, authorize, approve or refer to any written communication that constitutes an offer to sell or solicitation of an offer to buy the Securities (each such communication by the Company or its agents and representatives (other than a communication referred to in clauses (i) and (ii) below) an “Issuer Written Communication”) other than (i) the Preliminary Offering Memorandum, (ii) the Offering Memorandum, (iii) the documents listed on Annex A hereto, including a term sheet substantially in the form of Annex B hereto, which constitute part of the Time of Sale Information, and (iv) any electronic road show or other written communications, in each case used in accordance with Section 4(c). Each such Issuer Written Communication, when taken together with the Time of Sale Information at the Time of Sale, did not, and at the Closing Date will not, contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that the Company makes no representation or warranty with respect to any statements or omissions made in each such Issuer Written Communication in reliance upon and in conformity with information relating to any Initial Purchaser furnished to the Company in writing by such Initial Purchaser through the Representatives expressly for use in any Issuer Written Communication.

(c)Incorporated Documents. The documents incorporated by reference in each of the Time of Sale Information and the Offering Memorandum, when they were filed with the Commission, conformed or will conform, as the case may be, in all material respects to the requirements of the Exchange Act, and the rules and regulations of the Commission thereunder, and did not and will not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.

(d)Good Standing of the Company. The Company has been duly incorporated and is validly existing as a corporation in good standing under the laws of the State of Colorado and has the requisite corporate power and authority to own, lease and operate its properties and to conduct its business as described in the Time of Sale Information and the Offering Memorandum, and to enter into and perform its obligations under this Agreement. The Company is duly qualified to do business as a foreign corporation and is in good standing in each other jurisdiction in which such qualification is required, except for each jurisdiction where the failure to so qualify or to be in good standing would not

reasonably be expected to have a material adverse effect on the business, properties, management, condition (financial or otherwise), stockholders’ equity, results of operations or prospects of the Company or its Subsidiaries (as defined below), taken as a whole, or on the performance by the Company of its obligations under this Agreement (a “Material Adverse Effect”)

(e)Subsidiaries. The Company does not own or control, directly or indirectly, any corporation, association or other entity and has no subsidiaries other than those set forth on Schedule 2 hereto (each a “Subsidiary” and, collectively the “Subsidiaries”).Each Subsidiary has been duly formed and is existing and in good standing under the laws of the jurisdiction of its formation, with organizational power and authority to own its properties and conduct its business as described in the Time of Sale Information; and each Subsidiary of the Company is duly qualified to do business as a foreign corporation in good standing in all other jurisdictions in which its ownership or lease of property or the conduct of its business requires such qualification except for each jurisdiction where the failure to so qualify or to be in good standing would not reasonably be expected to have a Material Adverse Effect; all of the issued and outstanding ownership interests of each Subsidiary of the Company has been duly authorized and validly issued and is fully paid and nonassessable; and the ownership interests of each Subsidiary owned by the Company, directly or through Subsidiaries, is owned free from liens, encumbrances and defects other than liens under the Credit Agreement.

(f)Capitalization. The authorized capital stock of the Company and the issued and outstanding capital stock of the Company are as set forth in each of the Time of Sale Information and the Offering Memorandum (as of the date shown therein). The shares of issued and outstanding capital stock of the Company have been duly authorized and validly issued and are fully paid and non-assessable and none of the outstanding shares of capital stock of the Company were issued in violation of preemptive or similar rights of any security holder of the Company granted under the Company’s articles of incorporation, the Colorado Business Corporation Act or any agreement or other instrument to which the Company is a party or by which it is bound. The capital stock of the Company conforms in all material respects to the description contained in each of the Time of Sale Information and the Offering Memorandum, and such description conforms in all material respects to the rights set forth in the instruments defining the same. The description of the Company Stock Plans (as defined below) and the awards granted thereunder contained or incorporated by reference in each of the Time of Sale Information and the Offering Memorandum accurately and fairly present in all material respects the information required to be shown with respect to such plans and awards.

(g)Stock Options. With respect to the stock options (the “Stock Options”) granted pursuant to the stock based compensation plans of the Company (the “Company Stock Plans”), (i) each Stock Option intended to qualify as an “incentive stock option” under Section 422 of the Code so qualifies, (ii) each grant of a Stock Option was duly authorized no later than the date on which the grant of such Stock Option was by its terms to be effective (the “Grant Date”) by all necessary corporate action, including, as applicable, approval by the board of directors of the Company (or a duly constituted and

authorized committee thereof) and any required stockholder approval by the necessary number of votes or written consents, and the award agreement governing such grant (if any) was duly executed and delivered by each party thereto, (iii) each such grant was made in accordance with the terms of the Company Stock Plans, the Exchange Act and all other applicable laws and regulatory rules or requirements, including the rules of the NYSE American, LLC (the “NYSE”) and any other exchange on which Company securities are traded in each case in all material respects, and (iv) each such grant was properly accounted for in all material respects in accordance with generally accepted accounting principles in the United States of America (“GAAP”) in the financial statements (including the related notes) of the Company and its Subsidiaries and disclosed in the Company’s filings with the Commission in accordance with the Exchange Act and all other applicable laws. Except as disclosed in the Time of Sale Information and the Offering Memorandum and for any awards made under the Company Stock Plans following the date of the most recent financial statements included or incorporated by reference in the Time of Sale Information and the Offering Memorandum and not required to be so disclosed, there are no outstanding (i) securities or obligations of the Company convertible into or exchangeable for any equity interests of the Company, (ii) warrants, rights or options to subscribe for or purchase from the Company any equity interests or any such convertible or exchangeable securities or obligations, or (iii) obligations of the Company to issue any equity interests, any such convertible or exchangeable securities or obligations, or any such warrants, rights or options.

(h)No Finder’s Fee. Except as disclosed in the Time of Sale Information and the Offering Memorandum, the Company is not a party to any contract, agreement or understanding with any person (other than this Agreement) that would give rise to a valid claim against the Company or any Initial Purchaser for a brokerage commission, finder’s fee or like payment in connection with the offering and sale of the Securities.

(i)Reserved.

(j)Title to Real and Personal Property. Except as otherwise set forth in the Time of Sale Information and the Offering Memorandum or such as in the aggregate does not now cause or will in the future cause a Material Adverse Effect, the Company and its Subsidiaries have title to their respective properties as follows: (i) with respect to oil and gas properties underlying the Company’s estimates of its and its Subsidiaries net proved oil and natural gas reserves contained in the Time of Sale Information and the Offering Memorandum, such title is legal, good and defensible title in conformity with customary industry standards, free and clear of all liens, security interests, pledges, charges, encumbrances, mortgages and restrictions, except for liens, security interests, pledges, charges, encumbrances, mortgages and restrictions under operating agreements, unitization and pooling agreements, production sales contracts, farmout agreements and other oil and gas exploration participation and production agreements, in each case that secure payment of amounts not yet due and payable or other unmatured obligations and are of a scope and nature customary for the oil and gas industry or arise in connection with drilling and production operations, and (ii) with respect to real and personal property other than that appurtenant to oil and gas interests, such title is free and clear of all

material liens, security interests, pledges, charges, encumbrances, mortgages and restrictions, except, in the case of clauses (i) or (ii), for any such liens, security interests, pledges, charges and encumberances granted pursuant to the Amended and Restated Credit Agreement, dated as of November 28, 2012 (the “Credit Agreement”), by and among the Company, Suntrust Bank, as administrative agent and the lenders party thereto, as amended. No real property owned, leased, licensed, or used by the Company or any of its Subsidiaries lies in an area that is, or to the knowledge of the Company will be, subject to restrictions that would prohibit the continued effective ownership, leasing, licensing, exploration, development or production or use of such real property in the business of the Company or any of its Subsidiaries as presently conducted or as the Time of Sale Information and the Offering Memorandum indicates the Company contemplates conducting, except as may be properly described in the Time of Sale Information and the Offering Memorandum or such as in the aggregate would not reasonably be expected to result in a Material Adverse Effect.

(k)Absence of Defaults and Conflicts Resulting from Transaction. The execution, delivery and performance by the Company of this Agreement, the Securities, the Indenture, the Exchange Securities and the Registration Rights Agreement (collectively, the “Transaction Documents”) and compliance by the Company with the terms thereof and the consummation of the transactions contemplated by the Transaction Documents will not (i) conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, or result in the creation or imposition of any lien, charge or encumbrance upon any property or assets of the Company or any of its Subsidiaries pursuant to, any indenture, mortgage, deed of trust, loan agreement or other agreement or instrument to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound or to which any of the property or assets of the Company or any of its Subsidiaries is subject, (ii) result in any violation of the provisions of the charter or bylaws or similar organizational documents of the Company or (iii) result in the violation of any law or statute or any judgment, order, rule or regulation of any court or arbitrator or governmental or regulatory authority, except, in the case of clauses (i) and (iii) above, for any such conflict, breach, violation or default that would not, individually or in the aggregate, have a Material Adverse Effect.

(l)Absence of Existing Defaults and Conflicts. Neither the Company nor any of its Subsidiaries is (i) in violation of its articles or bylaws or similar organizational documents, (ii) in default, and no event has occurred that, with notice or lapse of time or both, would constitute such a default, in the due performance or observance of any term, covenant or condition contained in any indenture, mortgage, deed of trust, loan agreement or other agreement or instrument to which any of them is a party or by which any of them is bound or to which any of the property or assets of the Company or any of its Subsidiaries is subject, or (iii) in violation of any law or statute or any judgment, order, rule or regulation of any court or arbitrator or governmental or regulatory authority, except, in the case of clauses (ii) and (iii) above, for any such default or violation that would not, individually or in the aggregate, have a Material Adverse Effect.

(m)Authorization of Agreement. The Company has full corporate right, power and authority to execute and deliver this Agreement and to perform its obligations hereunder, and all action required to be taken for the due and proper authorization, execution and delivery by it of this Agreement and the consummation by it of the transactions contemplated hereby has been duly and validly taken.

(n)Valid Execution and Delivery of Agreement. This Agreement has been duly authorized, executed and delivered by the Company.

(o)Possession of Licenses and Permits. The Company and its Subsidiaries possess such permits, licenses, certificates, approvals, consents and other authorizations (collectively, “Governmental Licenses”) issued by appropriate federal, state, local or foreign regulatory bodies necessary for the ownership of its respective assets and to conduct the business as now operated by it, except where the failure to have obtained the same would not have a Material Adverse Effect. The Company and its Subsidiaries are in compliance with the terms and conditions of all such Governmental Licenses, except where the failure to so comply would not singly or in the aggregate have a Material Adverse Effect. All of the Governmental Licenses are valid and in full force and effect, except where the invalidity or the failure to be in full force and effect would not singly or in the aggregate have a Material Adverse Effect. The Company has not received any notice of proceedings relating to the revocation or modification of any such Governmental Licenses that, singly or in the aggregate, if the subject of an unfavorable decision, ruling or finding, would result in a Material Adverse Effect.

(p)Absence of Labor Dispute. No labor dispute with the employees of the Company or any of its Subsidiaries exists or, to the knowledge of the Company, is imminent, and the Company is not aware of any existing or imminent labor disturbance by the employees of any of its principal operators, contractors, suppliers or customers, except as would not have a Material Adverse Effect. The Company is not aware that any key employee or significant group of employees of the Company or any of its Subsidiaries plans to terminate employment with the Company or such Subsidiary, as relevant.

(q)Possession of Intellectual Property. The Company and its Subsidiaries own or possess, or can acquire on reasonable terms, adequate patents, patent rights, licenses, inventions, copyrights, know how (including trade secrets and other unpatented and/or unpatentable proprietary or confidential information, systems or procedures), trademarks, service marks, trade names or other intellectual property (collectively, “Intellectual Property”) necessary to carry on the business as now operated by it, except where the failure to own or possess, or have the ability to acquire on reasonable terms, such Intellectual Property would not, singly or in the aggregate, have a Material Adverse Effect. Neither the Company nor any of its Subsidiaries has received any notice, and is not otherwise aware, of any infringement of or conflict with asserted rights of others with respect to any Intellectual Property or of any facts or circumstances that would render any Intellectual Property invalid or inadequate to protect the interest of the Company or any of its Subsidiaries therein, and which infringement or conflict, if determined adversely

to the Company or its Subsidiaries, singly or in the aggregate, would have a Material Adverse Effect.

(r)Environmental Laws. There has been no storage, disposal, generation, manufacture, refinement, transportation, handling or treatment of hazardous substances or hazardous wastes at, upon, to, through or from any of the property now or previously owned, leased or operated by the Company, any of its Subsidiaries or any of their respective predecessors in interest, except that would not, individually or in the aggregate, have a Material Adverse Effect. There has been no spill, discharge, leak, emission, injection, escape, dumping or release of any kind onto any property now or previously owned, leased or operated by the Company or any of its Subsidiaries or into the environment surrounding such property of any hazardous substances or hazardous wastes, except for any such spill, discharge, leak, emission, injection, escape, dumping or release that would not, singularly or in the aggregate with all such spills, discharges, leaks, emissions, injections, escapes, dumpings and releases, result in a Material Adverse Effect; and the terms “hazardous substances,” and “hazardous wastes” shall be construed broadly to include such terms and similar terms, all of which shall have the meanings specified in any applicable local, state and federal laws or regulations with respect to environmental protection. Neither the Company nor any of its Subsidiaries has been named as a “potentially responsible party” under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended. Neither the Company nor any of its Subsidiaries is in violation of any statute, applicable law (including common law), ordinance, rule, regulation, decision or order of any governmental agency or body or any court, domestic or foreign, relating to the use, disposal or release of hazardous or toxic substances or relating to the protection or restoration of the environment or human exposure to hazardous or toxic substances (collectively, “environmental laws”), owns, leases or operates any real property contaminated with any substance that is subject to any environmental laws, is liable for any off-site disposal or contamination pursuant to environmental laws, or is subject to any claim relating to any environmental laws, which violation, contamination, liability or claim would, individually or in the aggregate, have a Material Adverse Effect; and the Company is not aware of any pending investigation which might lead to such a liability or claim.

(s)Insurance. Except as otherwise set forth in the Time of Sale Information and the Offering Memorandum, the Company, its Subsidiaries and their respective properties are insured by insurers or are self-insured against such losses and risks and in such amounts as the Company believes are adequate for the conduct of its business and as the Company believes are customary for the business in which it is engaged in all material respects; all such policies of insurance insuring the Company, its Subsidiaries and their respective properties are in full force and effect, and the Company has no reason to believe that it will not be able to renew its existing insurance coverage as and when such coverage expires or to obtain similar coverage from similar insurers as may be necessary to continue its business. Except as otherwise set forth in the Time of Sale Information and the Offering Memorandum, there are no material claims by the Company or any of its Subsidiaries under any such policy or instrument as to which any insurance company is denying liability or defending under a reservation of rights clause.

(t)Accurate Disclosure. The statements in the Time of Sale Information and the Offering Memorandum under the headings “Description of notes” and “Material United States federal income tax considerations,” insofar as such statements summarize legal matters, agreements, documents or proceedings discussed therein, are accurate and fair summaries of such legal matters, agreements, documents or proceedings and present the information required to be shown.

(u)Absence of Manipulation. Neither the Company nor any of its Subsidiaries has taken, directly or indirectly, any action designed to or that has constituted or could reasonably be expected to cause or result in any stabilization or manipulation of the price of any security of the Company or any of its Subsidiaries to facilitate the sale or resale of the Securities.

(v)Forward-Looking Statements. No forward-looking statement (within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act) contained in the Time of Sale Information and the Offering Memorandum has been made or reaffirmed without a reasonable basis or has been disclosed other than in good faith.

(w)Statistical and Market-Related Data. Nothing has come to the attention of the Company that has caused the Company to believe that the statistical and market-related data included or incorporated by reference in the Time of Sale Information and the Offering Memorandum is not based on or derived from sources that are reliable and accurate in all material respects.

(x)Independent Accountants. Deloitte & Touche LLP and EKS&H LLP, who have each certified certain financial statements of the Company and its Subsidiaries are each an independent registered public accounting firm with respect to the Company and its Subsidiaries within the applicable rules and regulations adopted by the Commission and the Public Company Accounting Oversight Board (United States) and as required by the Securities Act.

(y)Internal Controls. The Company and its Subsidiaries have established and maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that (i) are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its principal executive officer and its principal financial officer or persons performing similar functions; (ii) have been evaluated for effectiveness as of a date within 90 days prior to the earlier of the date that the Company filed its most recent annual or quarterly report with the Commission and the date of the Time of Sale Information; (iii) are effective in all material respects to perform the functions for which they were established. The Company and its Subsidiaries also maintain systems of “internal control over financial reporting” (as defined in Rule 13a-15(f) of the Exchange Act) that comply with the requirements of the Exchange Act and have been designed by, or under the supervision of, their respective principal executive and principal financial officers, or persons performing similar functions, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external

purposes in accordance with GAAP; and (v) the interactive data in eXtensible Business Reporting Language incorporated by reference in the Time of Sale Information and the Offering Memorandum fairly presents in all material respects the information called for and are prepared in all material respects in accordance with the Commission’s rules and guidelines applicable thereto. There has been no (i) significant deficiency or material weakness in the Company’s design or operation of internal controls over financial reporting required to be disclosed that was not so disclosed or (ii) fraud, whether or not material, that involves executive officers or other employees who have a significant role in the Company’s internal controls over financial reporting. The Company and its Subsidiaries maintain systems of internal accounting controls sufficient to provide reasonable assurance that (i) transactions are executed in accordance with management’s general or specific authorizations; (ii) transactions are recorded as necessary to permit preparation of financial statements in conformity with GAAP and to maintain asset accountability; (iii) access to assets is permitted only in accordance with management’s general or specific authorization; and (iv) the recorded accountability for assets is compared with the existing assets at reasonable intervals and appropriate action is taken with respect to any differences. There has been no change in any of the Company’s or any of its Subsidiaries’ internal controls over financial reporting that has occurred during its most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. The interactive data in eXtensible Business Reporting Language included or incorporated by reference in the Offering Memorandum fairly presents the information called for in all material respects and has been prepared in all material respects in accordance with the Commission’s rules and guidelines applicable thereto.

(z)Acquisition. The Acquisition Agreement has been duly authorized, executed and delivered by, and is a valid and binding agreement of the Company, enforceable in accordance with its terms, and, to the knowledge of the Company, the Acquisition Agreement has been duly authorized, executed and delivered by, and is a valid and binding agreement of the Seller and the other parties thereto, enforceable in accordance with its terms, in each case except as enforcement thereof may be subject to or limited by bankruptcy, insolvency or other similar laws relating to or affecting creditors’ rights generally or by general equitable principles. Assuming the completion of the transactions contemplated by this Agreement, the Company expects that the Acquisition will be consummated in all material respects on the terms and by the date and as contemplated by the Acquisition Agreement and the description thereof set forth in the Time of Sale Information and the Offering Memorandum.

(aa)Sarbanes-Oxley Act. The Company, its Subsidiaries and each of their respective directors and officers are in compliance, in all material respects, with all provisions now applicable to it of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations promulgated in connection therewith (the “Sarbanes Oxley Act”), including Section 402 related to loans and Sections 302 and 906 related to certifications and all rules and regulations promulgated thereunder or implementing the provisions thereof.

(ab)Legal Proceedings. There are no pending actions, suits, proceedings, inquiries or investigations before or brought by any court or governmental agency or body, domestic or foreign, or, to the knowledge of the Company, threatened, against or affecting the Company, its Subsidiaries or any of their respective properties, which are required to be disclosed in the Time of Sale Information and the Offering Memorandum and are not so disclosed, or that would reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect.

(ac)Financial Statements; Change in Fiscal Year. The financial statements included or incorporated by reference in the Time of Sale Information and the Offering Memorandum present fairly the financial position of the Company and its Subsidiaries as of the dates shown and their results of operations and cash flows for the periods shown, and such financial statements have been prepared in conformity with GAAP; and the assumptions used in preparing the pro forma financial statements incorporated by reference in the Time of Sale Information and the Offering Memorandum provide a reasonable basis for presenting the significant effects directly attributable to the transactions or events described therein, the related pro forma adjustments give appropriate effect to those assumptions, and the pro forma columns therein reflect the proper application of those adjustments to the corresponding historical financial statement amounts. The statements in the Registration Statement, the General Disclosure Package and the Final Prospectus regarding the Company’s change in its fiscal and tax year-end to December 31 from August 31 are true and correct in all material respects.

(ad)No Material Adverse Change in Business. Since the date of the most recent audited financial statements of the Company and its Subsidiaries included or incorporated by reference in the Time of Sale Information and the Offering Memorandum, and except in each case as otherwise disclosed in the Time of Sale Information and the Offering Memorandum, (i) there has not been any change in the capital stock (other than the issuance or reacquisition of shares of common stock of the Company in the ordinary course of business pursuant to Company Stock Plans that are described in the Time of Sale Information and the Offering Memorandum) or awards thereunder, short-term debt or long-term debt of the Company (other than borrowings or repayments under the Credit Agreement in the ordinary course of business and consistent with past practice), or any dividend or distribution of any kind declared, set aside for payment, paid or made by the Company or any of its Subsidiaries on any class of capital stock (other than dividends or distributions deemed to occur upon the exercise or exchange of awards under Company Stock Plans that are described in the Time of Sale Information and the Offering Memorandum, or which represent a portion of the exercise or exchange price thereof, or made in lieu of withholding taxes in connection with any such exercise or exchange), (ii) there has not been any material adverse change, nor any development or event involving a prospective material adverse change, in or affecting the business, properties, management, condition (financial or otherwise), stockholders’ equity, results of operations or prospects of the Company and its Subsidiaries, taken as a whole, (iii) neither the Company nor any of its Subsidiaries has entered into any transaction or agreement (whether or not in the ordinary course of business) that is material to the Company or

incurred any liability or obligation, direct or contingent, that is material to the Company, and (iv) neither the Company nor any of its Subsidiaries has sustained any loss or interference with its business that is material to the Company and that is either from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor disturbance or dispute or any action, order or decree of any court or arbitrator or governmental or regulatory authority.

(ae)Investment Company Act. Neither the Company or any of its Subsidiaries is and, immediately after giving effect to the offering and sale of the Securities and the application of the proceeds thereof as described in the Time of Sale Information and the Offering Memorandum, will not be, required to register as an “investment company” within the meaning of the Investment Company Act of 1940, as amended, and the rules and regulations of the Commission thereunder.

(af)Ratings. No “nationally recognized statistical rating organization” as such term is defined in Section 3(a)(62) of the Exchange Act (i) has imposed (or has informed the Company that it is considering imposing) any condition (financial or otherwise) on the Company’s retaining any rating assigned to the Company or any securities of the Company or (ii) has indicated to the Company that it is considering any of the actions described in Section 6(b) hereof.

(ag)Taxes. The Company has filed on a timely basis all foreign, federal, state and local tax returns that are required to be filed or has requested extensions thereof (except in any case in which the failure to so file would not result in a Material Adverse Effect) and has paid all taxes required to be paid by it and any other assessment, fine or penalty levied against it to the extent due and payable, except for any such assessment, fine or penalty that is currently being contested in good faith or would not result in a Material Adverse Effect.

(ah)No Unlawful Payments. Neither the Company, its Subsidiaries nor, to the knowledge of the Company, any director, officer, agent, employee or other person associated with or acting on behalf of the Company or any of its Subsidiaries has (i) used any corporate funds for any unlawful contribution, gift, entertainment or other unlawful expense relating to political activity; (ii) made any direct or indirect unlawful payment to any foreign or domestic government official or employee from corporate funds; (iii) violated or is in violation of any provision of the Foreign Corrupt Practices Act of 1977 or any other applicable antibribery or anticorruption law; or (iv) made any bribe, rebate, payoff, influence payment, kickback or other unlawful payment. The Company and its Subsidiaries have instituted, maintained and enforced, and will continue to maintain and enforce policies and procedures designed to promote and ensure compliance with all applicable antibribery and anticorruption laws.

(ai)Compliance with Anti-Money Laundering Laws. The operations of the Company and its Subsidiaries are and have been conducted at all times in material compliance with applicable financial recordkeeping and reporting requirements, including those of the Currency and Foreign Transactions Reporting Act of 1970, as amended, the applicable money laundering statutes of all jurisdictions where the Company or any of its

Subsidiaries conducts business, the rules and regulations thereunder and any related or similar rules, regulations or guidelines issued, administered or enforced by any governmental agency (collectively, the “Anti-Money Laundering Laws”) and no action, suit or proceeding by or before any court or governmental agency, authority or body or any arbitrator involving the Company or any of its Subsidiaries with respect to the Anti-Money Laundering Laws is pending or, to the knowledge of the Company, threatened.

(aj)No Conflicts with Sanctions Laws. Neither the Company, its Subsidiaries nor any of their respective directors or officers, nor, to the knowledge of the Company, any of their respective employees, agents, affiliates or other persons associated with or acting on behalf of the Company is currently the subject or the target of any sanctions administered or enforced by the U.S. government (including, without limitation, the Office of Foreign Assets Control of the U.S. Department of the Treasury or the U.S. Department of State and including, without limitation, the designation as a “specially designated national” or “blocked person”), the United Nations Security Council, the European Union, Her Majesty’s Treasury or other relevant sanctions authority (collectively, “Sanctions”), nor is the Company or any of its Subsidiaries located, organized or resident in a country or territory that is the subject or target of Sanctions, including, without limitation, Crimea, Cuba, Iran, North Korea and Syria (each, a “Sanctioned Country”); and the Company will not directly or indirectly use the proceeds of the offering of the Securities hereunder, or lend, contribute or otherwise make available such proceeds to any subsidiary, joint venture partner or other person or entity in order (i) to fund or facilitate any activities of or business with any person that, at the time of such funding or facilitation, is the subject or target of Sanctions, (ii) to fund or facilitate any activities of or business in any Sanctioned Country or (iii) take any other action that will result in a violation by any person (including any person participating in the transaction, whether as underwriter, advisor, investor or otherwise) of Sanctions.

(ak)Compliance with ERISA. Except as would not reasonably be expected to result in a Material Adverse Effect: the minimum funding standard under Section 302 of the Employee Retirement Income Security Act of 1974, as amended, and the regulations and published interpretations thereunder (“ERISA”), have been satisfied by each “pension plan” (as defined in Section 3(2) of ERISA) that has been established or maintained by the Company or any of its Subsidiaries, and the trust forming part of each such plan that is intended to be qualified under Section 401 of the Internal Revenue Code of 1986, as amended (the “Code”), is so qualified; the Company or any of its Subsidiaries, as relevant, has fulfilled its obligations, if any, under Section 515 of ERISA; neither the Company nor any of its Subsidiaries maintains or is required to contribute to a “welfare plan” (as defined in Section 3(1) of ERISA), that provides retiree or other post-employment welfare benefits or insurance coverage (other than “continuation coverage” (as defined in Section 602 of ERISA)); each pension plan and welfare plan established or maintained by the Company or any of its Subsidiaries is in compliance with the currently applicable provisions of ERISA, except where the failure to comply would not result in a Material Adverse Effect; and the Company and its Subsidiaries have not incurred or could not reasonably be expected to incur any withdrawal liability under

Section 4201 of ERISA, any liability under Sections 4062, 4063 or 4064 of ERISA, or any other liability under Title IV of ERISA.

(al)Solvency. On and immediately after the Closing Date, the Company and each of its Subsidiaries (after giving effect to the issuance and sale of the Securities and the other transactions related thereto as described in each of the Time of Sale Information and the Offering Memorandum) will be Solvent. As used in this paragraph, the term “Solvent” means, with respect to a particular date and entity, that on such date (i) the fair value (and present fair saleable value) of the assets of such entity is not less than the total amount required to pay the probable liability of such entity on its total existing debts and liabilities (including contingent liabilities) as they become absolute and matured; (ii) such entity is able to realize upon its assets and pay its debts and other liabilities, contingent obligations and commitments as they mature and become due in the normal course of business; (iii) assuming consummation of the issuance and sale of the Securities as contemplated by this Agreement, the Time of Sale Information and the Offering Memorandum, such entity does not have, intend to incur or believe that it will incur debts or liabilities beyond its ability to pay as such debts and liabilities mature; (iv) such entity is not engaged in any business or transaction, and does not propose to engage in any business or transaction, for which its property would constitute unreasonably small capital; and (v) such entity is not a defendant in any civil action that is reasonably likely to result in a judgment that such entity is or would become unable to satisfy.

(am)No Restrictions on Subsidiaries. No Subsidiary is currently prohibited, directly or indirectly, under any agreement or other instrument to which it is a party or is subject, from paying any dividends to the Company, from making any other distribution on such Subsidiary’s capital stock, from repaying to the Company any loans or advances to such Subsidiary from the Company or from transferring any of such Subsidiary’s properties or assets to the Company or any other Subsidiary of the Company.

(an)Independent Petroleum Engineers. Ryder Scott Company, L.P. (“Ryder Scott”), which has certified the reserve information of the Company and its Subsidiaries, has represented to the Company that it is, and to the knowledge of the Company is, an independent petroleum engineering firm in accordance with guidelines established by the Commission.

(ao)Reserve Report Data. The oil and gas reserve estimates of the Company included or incorporated by reference in the Time of Sale Information and the Offering Memorandum have been prepared or audited by independent reserve engineers in accordance with Commission guidelines applied on a consistent basis throughout the periods involved, and the Company has no reason to believe that such estimates do not fairly reflect the oil and gas reserves of the Company and its Subsidiaries as of the dates indicated. Other than production of the reserves in the ordinary course of business, intervening product price fluctuations and as described in the Time of Sale Information and the Offering Memorandum, the Company is not aware of any facts or circumstances that would have a Material Adverse Effect on the reserves or the present value of future

net cash flows therefrom as described in the Time of Sale Information and the Offering Memorandum.

(ap)Due Authorization. The Company has full corporate right, power and authority to execute and deliver Transaction Documents and to perform its obligations hereunder and thereunder; and all action required to be taken for the due and proper authorization, execution and delivery of each of the Transaction Documents and the consummation of the transactions contemplated thereby has been duly and validly taken.

(aq)The Indenture. The Indenture has been duly authorized by the Company and on the Closing Date will be duly executed and delivered by the Company and, when duly executed and delivered in accordance with its terms by each of the parties thereto, will constitute a valid and legally binding agreement of the Company enforceable against the Company in accordance with its terms, except as enforceability may be limited by applicable bankruptcy, insolvency or similar laws affecting the enforcement of creditors’ rights generally or by equitable principles relating to enforceability (collectively, the “Enforceability Exceptions”); and the Indenture will conform in all material respects to the applicable requirements of the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

(ar)The Securities. The Securities have been duly authorized by the Company and, when duly executed, authenticated, issued and delivered as provided in the Indenture and paid for as provided herein, will be duly and validly issued and outstanding and will constitute valid and legally binding obligations of the Company enforceable against the Company in accordance with their terms, subject to the Enforceability Exceptions, and will be entitled to the benefits of the Indenture.

(as)The Exchange Securities. On the Closing Date, the Exchange Securities will have been duly authorized by the Company and, when duly executed, authenticated, issued and delivered as contemplated by the Registration Rights Agreement, will be duly and validly issued and outstanding and will constitute valid and legally binding obligations of the Company, as issuer, enforceable against the Company in accordance with their terms, subject to the Enforceability Exceptions, and will be entitled to the benefits of the Indenture.

(at)Purchase and Registration Rights Agreements. The Registration Rights Agreement has been duly authorized by the Company and on the Closing Date will be duly executed and delivered by the Company and, when duly executed and delivered in accordance with its terms by each of the parties thereto, will constitute a valid and legally binding agreement of the Company enforceable against the Company in accordance with its terms, subject to the Enforceability Exceptions, and except that rights to indemnity and contribution thereunder may be limited by applicable law and public policy.

(au)Descriptions of the Transaction Documents. Each Transaction Document conforms in all material respects to the description thereof contained in each of the Time of Sale Information and the Offering Memorandum.

(av)No Consents Required. No consent, approval, authorization, order, registration or qualification of or with any court or arbitrator or governmental or regulatory authority is required for the execution, delivery and performance by the Company of each of the Transaction Documents to which each is a party, the issuance and sale of the Securities, the issuance of the Exchange Securities and compliance by the Company with the terms thereof and the consummation of the transactions contemplated by the Transaction Documents, except for such consents, approvals, authorizations, orders and registrations or qualifications as may be required (i) under applicable state securities laws in connection with the purchase and resale of the Securities by the Initial Purchasers and (ii) with respect to the Exchange Securities under the Securities Act, the Trust Indenture Act and applicable state securities laws as contemplated by the Registration Rights Agreement.

(aw)Senior Indebtedness. The Securities constitute “senior indebtedness” as such term is defined in any indenture or agreement governing any outstanding subordinated indebtedness of the Company.

(ax)Rule 144A Eligibility. On the Closing Date, the Securities will not be of the same class as securities listed on a national securities exchange registered under Section 6 of the Exchange Act or quoted in an automated inter-dealer quotation system; and each of the Preliminary Offering Memorandum and the Offering Memorandum, as of its respective date, contains or will contain all the information that, if requested by a prospective purchaser of the Securities, would be required to be provided to such prospective purchaser pursuant to Rule 144A(d)(4) under the Securities Act.

(ay)No Integration. Neither the Company nor any of its affiliates (as defined in Rule 501(b) of Regulation D) has, directly or through any agent, sold, offered for sale, solicited offers to buy or otherwise negotiated in respect of, any security (as defined in the Securities Act), that is or will be integrated with the sale of the Securities in a manner that would require registration of the Securities under the Securities Act.

(az)No General Solicitation or Directed Selling Efforts. None of the Company or any of its affiliates or any other person acting on its or their behalf (other than the Initial Purchasers, as to which no representation is made) has (i) solicited offers for, or offered or sold, the Securities by means of any form of general solicitation or general advertising within the meaning of Rule 502(c) of Regulation D or in any manner involving a public offering within the meaning of Section 4(a)(2) of the Securities Act or (ii) engaged in any directed selling efforts within the meaning of Regulation S under the Securities Act (“Regulation S”), and all such persons have complied with the offering restrictions requirement of Regulation S.

(ba)Securities Law Exemptions. Assuming the accuracy of the representations and warranties of the Initial Purchasers contained in Section 1(b) (including Annex C hereto) and their compliance with their agreements set forth therein, it is not necessary, in connection with the issuance and sale of the Securities to the Initial Purchasers and the offer, resale and delivery of the Securities by the Initial Purchasers in the manner contemplated by this Agreement, the Time of Sale Information and the Offering

Memorandum, to register the Securities under the Securities Act or to qualify the Indenture under the Trust Indenture Act.

4.    Further Agreements of the Company. The Company covenants and agrees with each Initial Purchaser that:

(a)Delivery of Copies. The Company will deliver, without charge, to the Initial Purchasers as many copies of the Preliminary Offering Memorandum, any other Time of Sale Information, any Issuer Written Communication and the Offering Memorandum (including all amendments and supplements thereto) as the Representatives may reasonably request.

(b)Offering Memorandum, Amendments or Supplements. Before finalizing the Offering Memorandum or making or distributing any amendment or supplement to any of the Time of Sale Information or the Offering Memorandum or filing with the Commission any document that will be incorporated by reference therein, the Company will furnish to the Representatives and counsel for the Initial Purchasers a copy of the proposed Offering Memorandum or such amendment or supplement or document to be incorporated by reference therein for review, and will not distribute any such proposed Offering Memorandum, amendment or supplement or file any such document with the Commission to which the Representatives reasonably object.

(c)Additional Written Communications. Before making, using, authorizing, approving or referring to any Issuer Written Communication, the Company will furnish to the Representatives and counsel for the Initial Purchasers a copy of such written communication for review and will not make, use, authorize, approve or refer to any such written communication to which the Representatives reasonably object.

(d)Notice to the Representatives. The Company will advise the Representatives promptly, and confirm such advice in writing, (i) of the issuance by any governmental or regulatory authority of any order preventing or suspending the use of any of the Time of Sale Information, any Issuer Written Communication or the Offering Memorandum or the initiation or threatening of any proceeding for that purpose; (ii) of the occurrence of any event at any time prior to the completion of the initial offering of the Securities as a result of which any of the Time of Sale Information, any Issuer Written Communication or the Offering Memorandum as then amended or supplemented would include any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances existing when such Time of Sale Information, Issuer Written Communication or the Offering Memorandum is delivered to a purchaser, not misleading; and (iii) of the receipt by the Company of any notice with respect to any suspension of the qualification of the Securities for offer and sale in any jurisdiction or the initiation or threatening of any proceeding for such purpose; and the Company will use its reasonable best efforts to prevent the issuance of any such order preventing or suspending the use of any of the Time of Sale Information, any Issuer Written Communication or the Offering

Memorandum or suspending any such qualification of the Securities and, if any such order is issued, will obtain as soon as possible the withdrawal thereof.

(e)Time of Sale Information. If at any time prior to the Closing Date (i) any event shall occur or condition shall exist as a result of which any of the Time of Sale Information as then amended or supplemented would include any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading or (ii) it is necessary to amend or supplement the Time of Sale Information to comply with law, the Company will immediately notify the Initial Purchasers thereof and forthwith prepare and, subject to paragraph (b) above, furnish to the Initial Purchasers such amendments or supplements to the Time of Sale Information (or any document to be filed with the Commission and incorporated by reference therein) as may be necessary so that the statements in any of the Time of Sale Information as so amended or supplemented (including such documents to be incorporated by reference therein) will not, in the light of the circumstances under which they were made, be misleading or so that any of the Time of Sale Information will comply with law.

(f)Ongoing Compliance. If at any time prior to the completion of the initial offering of the Securities (i) any event shall occur or condition shall exist as a result of which the Offering Memorandum as then amended or supplemented would include any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances existing when the Offering Memorandum is delivered to a purchaser, not misleading or (ii) it is necessary to amend or supplement the Offering Memorandum to comply with law, the Company will immediately notify the Initial Purchasers thereof and forthwith prepare and, subject to paragraph (b) above, furnish to the Initial Purchasers such amendments or supplements to the Offering Memorandum (or any document to be filed with the Commission and incorporated by reference therein) as may be necessary so that the statements in the Offering Memorandum as so amended or supplemented (including such document to be incorporated by reference therein) will not, in the light of the circumstances existing when the Offering Memorandum is delivered to a purchaser, be misleading or so that the Offering Memorandum will comply with law.

(g)Blue Sky Compliance. The Company will qualify the Securities for offer and sale under the securities or Blue Sky laws of such jurisdictions as the Representatives shall reasonably request and will continue such qualifications in effect so long as reasonably required for the offering and resale of the Securities; provided that the Company shall not be required to (i) qualify as a foreign corporation or other entity or as a dealer in securities in any such jurisdiction where it would not otherwise be required to so qualify, (ii) file any general consent to service of process in any such jurisdiction or (iii) subject itself to taxation in any such jurisdiction if it is not otherwise so subject.

(h)Clear Market. During the period from the date hereof through and including the date that is 60 days after the date hereof, the Company will not, without the prior written consent of the Representatives, offer, sell, contract to sell or otherwise dispose of

any debt securities issued or guaranteed by the Company and having a tenor of more than one year.    

(i)Use of Proceeds. The Company will apply the net proceeds from the sale of the Securities as described in each of the Time of Sale Information and the Offering Memorandum under the heading “Use of proceeds.”

(j)Supplying Information. While the Securities remain outstanding and are “restricted securities” within the meaning of Rule 144(a)(3) under the Securities Act, the Company will, during any period in which the Company is not subject to and in compliance with Section 13 or 15(d) of the Exchange Act, furnish to holders of the Securities and prospective purchasers of the Securities designated by such holders, upon the request of such holders or such prospective purchasers, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

(k)DTC. The Company will assist the Initial Purchasers in arranging for the Securities to be eligible for clearance and settlement through DTC.

(l)No Resales by the Company. The Company will not, and will not permit any of its affiliates (as defined in Rule 144 under the Securities Act) to, resell any of the Securities that have been acquired by any of them, except for Securities purchased by the Company or any of its affiliates and resold in a transaction registered under the Securities Act.

(m)No Integration. Neither the Company nor any of its affiliates (as defined in Rule 501(b) of Regulation D) will, directly or through any agent, sell, offer for sale, solicit offers to buy or otherwise negotiate in respect of, any security (as defined in the Securities Act), that is or will be integrated with the sale of the Securities in a manner that would require registration of the Securities under the Securities Act.

(n)No General Solicitation or Directed Selling Efforts. None of the Company or any of its affiliates or any other person acting on its or their behalf (other than the Initial Purchasers, as to which no covenant is given) will (i) solicit offers for, or offer or sell, the Securities by means of any form of general solicitation or general advertising within the meaning of Rule 502(c) of Regulation D or in any manner involving a public offering within the meaning of Section 4(a)(2) of the Securities Act or (ii) engage in any directed selling efforts within the meaning of Regulation S, and all such persons will comply with the offering restrictions requirement of Regulation S.

(o)No Stabilization. The Company will not take, directly or indirectly, any action designed to or that could reasonably be expected to cause or result in any stabilization or manipulation of the price of the Securities.

5.    Certain Agreements of the Initial Purchasers.    Each Initial Purchaser hereby represents and agrees that it has not and will not use, authorize use of, refer to, or participate in the planning for use of, any written communication that constitutes an offer to sell or the solicitation of an offer to buy the Securities other than (i) the

Preliminary Offering Memorandum and the Offering Memorandum, (ii) any written communication that contains either (a) no “issuer information” (as defined in Rule 433(h)(2) under the Securities Act) or (b) “issuer information” that was included (including through incorporation by reference) in the Time of Sale Information or the Offering Memorandum, (iii) any written communication listed on Annex A or prepared pursuant to Section 4(c) (including any electronic road show) above, (iv) any written communication prepared by such Initial Purchaser and approved by the Company and the Representatives in advance in writing or (v) any written communication relating to or that contains the terms of the Securities and/or other information that was included (including through incorporation by reference) in the Time of Sale Information or the Offering Memorandum.

6.    Conditions of Initial Purchasers’ Obligations. The obligation of each Initial Purchaser to purchase Securities on the Closing Date as provided herein is subject to the performance by the Company covenants and other obligations hereunder and to the following additional conditions:

(a)Representations and Warranties. The representations and warranties of the Company contained herein shall be true and correct on the date hereof and on and as of the Closing Date; and the statements of the Company and its officers made in any certificates delivered pursuant to this Agreement shall be true and correct on and as of the Closing Date.

(b)No Downgrade. Subsequent to the earlier of (A) the Time of Sale and (B) the execution and delivery of this Agreement, (i) no downgrading shall have occurred in the rating accorded the Securities or any other debt securities or preferred stock issued or guaranteed by the Company or any of its Subsidiaries by any “nationally recognized statistical rating organization,” as such term is defined under Section 3(a)(62) under the Exchange Act and (ii) no such organization shall have publicly announced that it has under surveillance or review, or has changed its outlook with respect to, its rating of the Securities or of any other debt securities or preferred stock issued or guaranteed by the Company or any of its Subsidiaries (other than an announcement with positive implications of a possible upgrading).

(c)No Material Adverse Change. Subsequent to the execution and delivery of this Agreement, there shall not have occurred (i) any change, or any development or event involving a prospective change, in or affecting the business, properties, management, condition (financial or otherwise), stockholders’ equity, results of operations, or prospects of the Company or any of its Subsidiaries, taken as a whole, which, in the judgment of the Representatives, is material and adverse and makes it impractical or inadvisable to market the Securities; (ii) any downgrading in the rating of any debt securities or preferred stock of the Company or any of its Subsidiaries by any “nationally recognized statistical rating organization” (as defined in Section 3(a)(62) of the Exchange Act), or any public announcement that any such organization has under surveillance or review its rating of any debt securities or preferred stock of the Company or any of its Subsidiaries (other than an announcement with positive implications of a

possible upgrading, and no implication of a possible downgrading, of such rating)or any announcement that the Company or any of its Subsidiaries has been placed on negative outlook; (iii)  any change in U.S. or international financial, political or economic conditions or currency exchange rates or exchange controls the effect of which is such as to make it, in the judgment of the Representatives, impractical to market or to enforce contracts for the sale of the Securities, whether in the primary market or in respect of dealings in the secondary market; (iv) any suspension or material limitation of trading in securities generally on the New York Stock Exchange, or any setting of minimum or maximum prices for trading on such exchange; (v) or any suspension of trading of any securities of the Company or any of its Subsidiaries on any exchange or in the over-the-counter market; (vi) any banking moratorium declared by any U.S. federal or New York authorities; (vii) any major disruption of settlements of securities, payment, or clearance services in the United States or any other country where such securities are listed or (viii) any attack on, outbreak or escalation of hostilities or act of terrorism involving the United States, any declaration of war by Congress or any other national or international calamity or emergency if, in the judgment of the Representatives, the effect of any such attack, outbreak, escalation, act, declaration, calamity or emergency is such as to make it impractical or inadvisable to market the Securities or to enforce contracts for the sale of the Securities.

(d)Officer’s Certificate. The Representatives shall have received a certificate, dated such Closing Date, of an executive officer of the Company and a principal financial or accounting officer of the Company in which such officers shall state that: the representations and warranties of the Company in this Agreement are true and correct; the Company has complied with all agreements and satisfied all conditions on its part to be performed or satisfied hereunder at or prior to such Closing Date and, subsequent to the date of the most recent financial statements included or incorporated by reference in the Time of Sale Information and the Offering Memorandum, there has been no material adverse change, nor any development or event involving a prospective material adverse change, in or affecting the business, properties, management, condition (financial or otherwise), stockholders’ equity, results of operations, or prospects of the Company or any of its Subsidiaries, taken as a whole, except as set forth in the Time of Sale Information and the Offering Memorandum or as described in such certificate.

(e)Comfort Letters. (i) The Representatives shall have received letters, dated, respectively, the date hereof and the Closing Date and addressed to the Initial Purchasers, of each of Deloitte & Touche LLP and EKS&H LLP in form and substance satisfactory to the Initial Purchasers, in each case confirming that they are a registered public accounting firm and independent public accountants within the meaning of the Sarbanes-Oxley Act, the Exchange Act, the rules and regulations of the Commission, the auditing principles, rules, standards and practices applicable to auditors of “issuers” (as defined in the Sarbanes-Oxley Act) promulgated or approved by the Public Company Accounting Oversight Board and the rules of the NYSE and containing statements and information of the type customarily included in accountants’ “comfort letters” with respect to the financial statements of the Company and its Subsidiaries and certain financial information included or incorporated by reference in the Time of Sale Information and

Offering Memorandum (except that, in any letter dated the Closing Date, the specified date referred to in such letters hereto shall be a date no more than three days prior to such Closing Date).

(f)Reserve Report Confirmation Letter. The Representatives shall have received letters, dated, respectively, the date hereof and each Closing Date and addressed to the Initial Purchasers, of Ryder Scott Company, L.P., in form and substance satisfactory to the Initial Purchasers, containing statements and information with respect to the estimated oil and gas reserves of the Company and its Subsidiaries.

(g)Opinion and 10b-5 Statement of Counsel for the Company. Davis Graham & Stubbs LLP, counsel for the Company, shall have furnished to the Representatives, at the request of the Company, their written opinion and 10b-5 statement, dated the Closing Date and addressed to the Initial Purchasers, in form and substance reasonably satisfactory to the Representatives, to the effect set forth in Annex D hereto.

(h)Opinion and 10b-5 Statement of Counsel for the Initial Purchasers. The Representatives shall have received on and as of the Closing Date an opinion and 10b-5 statement, addressed to the Initial Purchasers, of Davis Polk & Wardwell LLP, counsel for the Initial Purchasers, with respect to such matters as the Representatives may reasonably request, and such counsel shall have received such documents and information as they may reasonably request to enable them to pass upon such matters.

(i)No Legal Impediment to Issuance. No action shall have been taken and no statute, rule, regulation or order shall have been enacted, adopted or issued by any federal, state or foreign governmental or regulatory authority that would, as of the Closing Date, prevent the issuance or sale of the Securities; and no injunction or order of any federal, state or foreign court shall have been issued that would, as of the Closing Date, prevent the issuance or sale of the Securities.

(j)Good Standing. The Representatives shall have received on and as of the Closing Date satisfactory evidence of the good standing of the Company and its Subsidiaries in their respective jurisdictions of organization and their good standing in such other jurisdictions as the Representatives may reasonably request, in each case in writing or any standard form of telecommunication from the appropriate governmental authorities of such jurisdictions.

(k)Registration Rights Agreement. The Initial Purchasers shall have received a counterpart of the Registration Rights Agreement that shall have been executed and delivered by a duly authorized officer of the Company.

(l)DTC. The Securities shall be eligible for clearance and settlement through DTC.

(m)Indenture and Securities. The Indenture shall have been duly executed and delivered by a duly authorized officer of the Company and the Trustee, and the Securities

shall have been duly executed and delivered by a duly authorized officer of the Company and duly authenticated by the Trustee.

(n)Common Stock Offering. The Common Stock Offering shall have been consummated.

(o)Additional Documents. On or prior to the Closing Date, the Company shall have furnished to the Representatives such further certificates and documents as the Representatives may reasonably request.

All opinions, letters, certificates and evidence mentioned above or elsewhere in this Agreement shall be deemed to be in compliance with the provisions hereof only if they are in form and substance reasonably satisfactory to counsel for the Initial Purchasers.

7.    Indemnification and Contribution.

(a)Indemnification of the Initial Purchasers. The Company agrees to indemnify and hold harmless each Initial Purchaser, its affiliates, directors and officers and each person, if any, who controls such Initial Purchaser within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act, from and against any and all losses, claims, damages and liabilities (including, without limitation, legal fees and other expenses reasonably incurred in connection with any suit, action or proceeding or any claim asserted, as such fees and expenses are incurred), joint or several, that arise out of, or are based upon, any untrue statement or alleged untrue statement of a material fact contained in the Preliminary Offering Memorandum, any of the other Time of Sale Information, any Issuer Written Communication or the Offering Memorandum (or any amendment or supplement thereto) or any omission or alleged omission to state therein a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, in each case except insofar as such losses, claims, damages or liabilities arise out of, or are based upon, any untrue statement or omission or alleged untrue statement or omission made in reliance upon and in conformity with any information relating to any Initial Purchaser furnished to the Company in writing by such Initial Purchaser through the Representatives expressly for use therein.

(b)Indemnification of the Company. Each Initial Purchaser agrees, severally and not jointly, to indemnify and hold harmless the Company and its directors and officers and each person, if any, who controls the Company within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act to the same extent as the indemnity set forth in paragraph (a) above, but only with respect to any losses, claims, damages or liabilities that arise out of, or are based upon, any untrue statement or omission or alleged untrue statement or omission made in reliance upon and in conformity with any information relating to such Initial Purchaser furnished to the Company in writing by such Initial Purchaser through the Representatives expressly for use in the Preliminary Offering Memorandum, any of the other Time of Sale Information, any Issuer Written Communication or the Offering Memorandum (or any amendment or supplement thereto),

it being understood and agreed that the only such information consists of the following paragraphs in the Preliminary Offering Memorandum and the Offering Memorandum: the second paragraph and the ninth paragraph under the caption “Plan of distribution.”

(c)Notice and Procedures. If any suit, action, proceeding (including any governmental or regulatory investigation), claim or demand shall be brought or asserted against any person in respect of which indemnification may be sought pursuant to either paragraph (a) or (b) above, such person (the “Indemnified Person”) shall promptly notify the person against whom such indemnification may be sought (the “Indemnifying Person”) in writing; provided that the failure to notify the Indemnifying Person shall not relieve it from any liability that it may have under paragraph (a) or (b) above except to the extent that it has been materially prejudiced (through the forfeiture of substantive rights or defenses) by such failure; and provided, further, that the failure to notify the Indemnifying Person shall not relieve it from any liability that it may have to an Indemnified Person otherwise than under paragraph (a) or (b) above. If any such proceeding shall be brought or asserted against an Indemnified Person and it shall have notified the Indemnifying Person thereof, the Indemnifying Person shall retain counsel reasonably satisfactory to the Indemnified Person (who shall not, without the consent of the Indemnified Person, be counsel to the Indemnifying Person) to represent the Indemnified Person and any others entitled to indemnification pursuant to this Section 7 that the Indemnifying Person may designate in such proceeding and shall pay the fees and expenses of such proceeding and shall pay the fees and expenses of such counsel related to such proceeding, as incurred. In any such proceeding, any Indemnified Person shall have the right to retain its own counsel, but the fees and expenses of such counsel shall be at the expense of such Indemnified Person unless (i) the Indemnifying Person and the Indemnified Person shall have mutually agreed to the contrary; (ii) the Indemnifying Person has failed within a reasonable time to retain counsel reasonably satisfactory to the Indemnified Person; (iii) the Indemnified Person shall have reasonably concluded that there may be legal defenses available to it that are different from or in addition to those available to the Indemnifying Person; or (iv) the named parties in any such proceeding (including any impleaded parties) include both the Indemnifying Person and the Indemnified Person and representation of both parties by the same counsel would be inappropriate due to actual or potential differing interests between them. It is understood and agreed that the Indemnifying Person shall not, in connection with any proceeding or related proceeding in the same jurisdiction, be liable for the fees and expenses of more than one separate firm (in addition to any local counsel) for all Indemnified Persons, and that all such fees and expenses shall be paid or reimbursed as they are incurred. Any such separate firm for any Initial Purchaser, its affiliates, directors and officers and any control persons of such Initial Purchaser shall be designated in writing by the Representatives and any such separate firm for the Company, its directors and officers and any control persons of the Company shall be designated in writing by the Company. The Indemnifying Person shall not be liable for any settlement of any proceeding effected without its written consent, but if settled with such consent or if there be a final judgment for the plaintiff, the Indemnifying Person agrees to indemnify each Indemnified Person from and against any loss or liability by reason of such settlement or judgment. No Indemnifying Person shall, without the written consent of the Indemnified Person, effect any settlement of any pending or

threatened proceeding in respect of which any Indemnified Person is or could have been a party and indemnification could have been sought hereunder by such Indemnified Person, unless such settlement (x) includes an unconditional release of such Indemnified Person from all liability on claims that are the subject matter of such proceeding and (y) does not include any statement as to or any admission of fault, culpability or a failure to act by or on behalf of any Indemnified Person.

(d)Contribution. If the indemnification provided for in paragraph (a) or (b) above is unavailable to an Indemnified Person or insufficient in respect of any losses, claims, damages or liabilities referred to therein, then each Indemnifying Person under such paragraph, in lieu of indemnifying such Indemnified Person thereunder, shall contribute to the amount paid or payable by such Indemnified Person as a result of such losses, claims, damages or liabilities (i) in such proportion as is appropriate to reflect the relative benefits received by the Company on the one hand and the Initial Purchasers on the other from the offering of the Securities or (ii) if the allocation provided by clause (i) is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) but also the relative fault of the Company on the one hand and the Initial Purchasers on the other in connection with the statements or omissions that resulted in such losses, claims, damages or liabilities, as well as any other relevant equitable considerations. The relative benefits received by the Company on the one hand and the Initial Purchasers on the other shall be deemed to be in the same respective proportions as the net proceeds (before deducting expenses) received by the Company from the sale of the Securities and the total discounts and commissions received by the Initial Purchasers in connection therewith, as provided in this Agreement, bear to the aggregate offering price of the Securities. The relative fault of the Company on the one hand and the Initial Purchasers on the other shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Company or by the Initial Purchasers and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission.

(e)Limitation on Liability. The Company and the Initial Purchasers agree that it would not be just and equitable if contribution pursuant to this Section 7 were determined by pro rata allocation (even if the Initial Purchasers were treated as one entity for such purpose) or by any other method of allocation that does not take account of the equitable considerations referred to in paragraph (d) above. The amount paid or payable by an Indemnified Person as a result of the losses, claims, damages and liabilities referred to in paragraph (d) above shall be deemed to include, subject to the limitations set forth above, any legal or other expenses reasonably incurred by such Indemnified Person in connection with any such action or claim. Notwithstanding the provisions of this Section 7, in no event shall an Initial Purchaser be required to contribute any amount in excess of the amount by which the total discounts and commissions received by such Initial Purchaser with respect to the offering of the Securities exceeds the amount of any damages that such Initial Purchaser has otherwise been required to pay by reason of such untrue or alleged untrue statement or omission or alleged omission. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the

Securities Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The Initial Purchasers’ obligations to contribute pursuant to this Section 7 are several in proportion to their respective purchase obligations hereunder and not joint.

(f)Non-Exclusive Remedies. The remedies provided for in this Section 7 are not exclusive and shall not limit any rights or remedies that may otherwise be available to any Indemnified Person at law or in equity.

8.    Effectiveness of Agreement. This Agreement shall become effective as of the date first written above.

9.    Termination. This Agreement may be terminated in the absolute discretion of the Representatives, by notice to the Company, if after the execution and delivery of this Agreement and on or prior to the Closing Date (i) trading generally shall have been suspended or materially limited on the New York Stock Exchange or the over-the-counter market; (ii) trading of any securities issued or guaranteed by the Company shall have been suspended on any exchange or in any over-the-counter market; (iii) a general moratorium on commercial banking activities shall have been declared by federal or New York State authorities; or (iv) there shall have occurred any outbreak or escalation of hostilities or any change in financial markets or any calamity or crisis, either within or outside the United States, that, in the judgment of the Representatives, is material and adverse and makes it impracticable or inadvisable to proceed with the offering, sale or delivery of the Securities on the terms and in the manner contemplated by this Agreement, the Time of Sale Information and the Offering Memorandum.

10.    Defaulting Initial Purchaser.

(a)If, on the Closing Date, any Initial Purchaser defaults on its obligation to purchase the Securities that it has agreed to purchase hereunder, the non-defaulting Initial Purchasers may in their discretion arrange for the purchase of such Securities by other persons satisfactory to the Company on the terms contained in this Agreement. If, within 36 hours after any such default by any Initial Purchaser, the non-defaulting Initial Purchasers do not arrange for the purchase of such Securities, then the Company shall be entitled to a further period of 36 hours within which to procure other persons satisfactory to the non-defaulting Initial Purchasers to purchase such Securities on such terms. If other persons become obligated or agree to purchase the Securities of a defaulting Initial Purchaser, either the non‑defaulting Initial Purchasers or the Company may postpone the Closing Date for up to five full business days in order to effect any changes that in the opinion of counsel for the Company or counsel for the Initial Purchasers may be necessary in the Time of Sale Information, the Offering Memorandum or in any other document or arrangement, and the Company agrees to promptly prepare any amendment or supplement to the Time of Sale Information or the Offering Memorandum that effects any such changes. As used in this Agreement, the term “Initial Purchaser” includes, for all purposes of this Agreement unless the context otherwise requires, any person not listed in

(b) hereto that, pursuant to this Section 10, purchases Securities that a defaulting Initial Purchaser agreed but failed to purchase.

(c)If, after giving effect to any arrangements for the purchase of the Securities of a defaulting Initial Purchaser or Initial Purchasers by the non-defaulting Initial Purchasers and the Company as provided in paragraph (a) above, the aggregate principal amount of such Securities that remains unpurchased does not exceed one-eleventh of the aggregate principal amount of all the Securities, then the Company shall have the right to require each non-defaulting Initial Purchaser to purchase the principal amount of Securities that such Initial Purchaser agreed to purchase hereunder plus such Initial Purchaser’s prorata share (based on the principal amount of Securities that such Initial Purchaser agreed to purchase hereunder) of the Securities of such defaulting Initial Purchaser or Initial Purchasers for which such arrangements have not been made.

(d)If, after giving effect to any arrangements for the purchase of the Securities of a defaulting Initial Purchaser or Initial Purchasers by the non-defaulting Initial Purchasers and the Company as provided in paragraph (a) above, the aggregate principal amount of such Securities that remains unpurchased exceeds one-eleventh of the aggregate principal amount of all the Securities, or if the Company shall not exercise the right described in paragraph (b) above, then this Agreement shall terminate without liability on the part of the non-defaulting Initial Purchasers. Any termination of this Agreement pursuant to this Section 10 shall be without liability on the part of the Company, except that the Company will continue to be liable for the payment of expenses as set forth in Section 11 hereof, and if the purchase of the Securities by the Initial Purchasers is not consummated for any reason, the respective obligations of the Company and the Initial Purchasers pursuant to Section 7 hereof shall remain in effect.

(e)Nothing contained herein shall relieve a defaulting Initial Purchaser of any liability it may have to the Company or any non-defaulting Initial Purchaser for damages caused by its default.

11.    Payment of Expenses.

(a)Whether or not the transactions contemplated by this Agreement are consummated or this Agreement is terminated, the Company agrees to pay or cause to be paid all costs and expenses incident to the performance of its obligations hereunder, including without limitation, (i) the costs incident to the authorization, issuance, sale, preparation and delivery of the Securities and any taxes payable in that connection; (ii) the costs incident to the preparation and printing of the Preliminary Offering Memorandum, any other Time of Sale Information, any Issuer Written Communication and the Offering Memorandum (including any amendment or supplement thereto) and the distribution thereof; (iii) the costs of reproducing and distributing each of the Transaction Documents; (iv) the fees and expenses of the Company's counsel and independent accountants; (v) the fees and expenses incurred in connection with the registration or qualification and determination of eligibility for investment of the Securities under the laws of such jurisdictions as the Representatives may reasonably designate and the preparation, printing and distribution of a Blue Sky Memorandum (including the related

fees and expenses of counsel for the Initial Purchasers); (vi) any fees charged by rating agencies for rating the Securities; (vii) the fees and expenses of the Trustee and any paying agent (including related fees and expenses of any counsel to such parties); (viii) all expenses and application fees incurred in connection with the approval of the Securities for book-entry transfer by DTC; and (ix) all expenses incurred by the Company in connection with any “road show” presentation to potential investors.

(b)If (i) this Agreement is terminated pursuant to Section 9, (ii) the Company for any reason fails to tender the Securities for delivery to the Initial Purchasers, (iii) the Initial Purchasers decline to purchase the Securities for any reason permitted under this Agreement or (iv) the purchase of the Securities by the Initial Purchasers is not consummated for any other reason (other than a breach of this Agreement by the Initial Purchasers), the Company agrees to reimburse the Initial Purchasers for all documented out-of-pocket costs and expenses (including the fees and expenses of their counsel) reasonably incurred by the Initial Purchasers in connection with this Agreement and the offering contemplated hereby.

12.    Persons Entitled to Benefit of Agreement. This Agreement shall inure to the benefit of and be binding upon the parties hereto and their respective successors and the officers and directors and any controlling persons referred to herein, and the affiliates of each Initial Purchaser referred to in Section 7 hereof. Nothing in this Agreement is intended or shall be construed to give any other person any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision contained herein. No purchaser of Securities from any Initial Purchaser shall be deemed to be a successor merely by reason of such purchase.

13.    Survival of Certain Representations and Obligations. The respective indemnities, agreements, representations, warranties and other statements of the Company or its officers and of the several Initial Purchasers set forth in or made pursuant to this Agreement will remain in full force and effect, regardless of any investigation, or statement as to the results thereof, made by or on behalf of any Initial Purchaser, Indemnified Party, the Company or any controlling person, and will survive delivery of and payment for the Securities. If any Securities have been purchased hereunder, the representations and warranties in Section 3 and all obligations under Section 4 shall also remain in effect.

14.    Certain Defined Terms. For purposes of this Agreement, (a) except where otherwise expressly provided, the term “affiliate” has the meaning set forth in Rule 405 under the Securities Act; (b) the term “business day” means any day other than a day on which banks are permitted or required to be closed in New York City; (c) the term “Exchange Act” collectively means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Commission thereunder; and (d) the term “written communication” has the meaning set forth in Rule 405 under the Securities Act.

15.    Compliance with USA Patriot Act. In accordance with the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)), the Initial Purchasers are required to obtain, verify and record information that identifies

their respective clients, including the Company, which information may include the name and address of their respective clients, as well as other information that will allow the Initial Purchasers to properly identify their respective clients.

16.    Miscellaneous.

(a)Authority of the Representatives. Any action by the Initial Purchasers hereunder may be taken by J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC on behalf of the Initial Purchasers, and any such action taken by J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC shall be binding upon the Initial Purchasers.

(b)Notices. All notices and other communications hereunder shall be in writing and shall be deemed to have been duly given if mailed or transmitted and confirmed by any standard form of telecommunication. Notices to the Initial Purchasers shall be given to the Representatives c/o J.P. Morgan Securities LLC, 383 Madison Avenue, New York, New York 10179; Attention: High Yield Syndicate Desk and Credit Suisse Securities (USA) LLC, Eleven Madison Avenue, New York, New York 10010-3629, Attention: High Yield Capital Markets. Notices to the Company shall be given to it at SRC Energy Inc., 1675 Broadway, Suite 2600, Denver, Colorado 80202, Attention: Cathleen M. Osborn.

(c)Governing Law. This Agreement and any claim, controversy or dispute arising under or related to this Agreement shall be governed by and construed in accordance with the laws of the State of New York.

(d)Submission to Jurisdiction. The Company hereby submits to the exclusive jurisdiction of the U.S. federal and New York state courts in the Borough of Manhattan in The City of New York in any suit or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby. The Company waives any objection which it may now or hereafter have to the laying of venue of any such suit or proceeding in such courts. The Company agrees that final judgment in any such suit, action or proceeding brought in such court shall be conclusive and binding upon the Company and may be enforced in any court to the jurisdiction of which Company is subject by a suit upon such judgment.

(e)Waiver of Jury Trial. Each of the parties hereto hereby waives any right to trial by jury in any suit or proceeding arising out of or relating to this Agreement.

(f)Counterparts. This Agreement may be signed in counterparts (which may include counterparts delivered by any standard form of telecommunication), each of which shall be an original and all of which together shall constitute one and the same instrument.

(g)Amendments or Waivers. No amendment or waiver of any provision of this Agreement, nor any consent or approval to any departure therefrom, shall in any event be effective unless the same shall be in writing and signed by the parties hereto.

(h)Headings. The headings herein are included for convenience of reference only and are not intended to be part of, or to affect the meaning or interpretation of, this Agreement.

If the foregoing is in accordance with your understanding, please indicate your acceptance of this Agreement by signing in the space provided below.

Very truly yours,

SRC ENERGY INC.
By:	/s/ Lynn A. Peterson
	Name:	Lynn A. Peterson
	Title:	CEO and President

Accepted: As of the date first written above

J.P. MORGAN SECURITIES LLC
By:	/s/ Carly Roddy
	Name:	Carly Roddy
	Title:	Vice President

CREDIT SUISSE SECURITIES (USA) LLC
By:	/s/ Ricardo Concha
	Name:	Ricardo Concha
	Title:	Director

For themselves and on behalf of the

several Initial Purchasers listed

in Schedule 1 hereto.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-191684 and 333- 208589 on Form S-8 and Registration Statement No. 333-206876 on Form S-3 of our reports dated February 21, 2018, relating to the consolidated financial statements of SRC Energy Inc. and subsidiaries, and the effectiveness of SRC Energy Inc. and subsidiaries’ internal control over financial reporting, appearing in the Annual Report on Form 10-K of SRC Energy Inc. for the year ended December 31, 2017.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

February 21, 2018

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in SRC Energy Inc.’s (formerly known as Synergy Resources Corporation) Registration Statements on Form S-3 (File Nos. 333-186726, 333-188364, 333-201732, and 333-206876) and on Form S-8 (File Nos. 333-191684 and 333-208589) of our report dated April 22, 2016, relating to the consolidated financial statements which appear in this Annual Report on Form 10-K.

/s/ EKS&H LLLP

February 21, 2018

Denver, Colorado

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

The Board of Directors

SRC Energy Inc.

Denver, Colorado

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (File No. 333-206876) and on Form S-8 (File Nos. 333-191684 and 333-208589) of SRC Energy Inc. and subsidiaries (the “Company”) of our report relating to the Company’s proven oil and gas reserves which was filed as Exhibit 99.1 to the Company’s Annual Report on Form 10-K for the year endedDecember 31, 2017 (the “10-K), and information derived from our report included in the 10-K.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P

TBPE Firm Registration No. F-1580

Denver, Colorado

February 21, 2018

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 15 U.S.C. SECTION 7241, AS

ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Lynn A. Peterson, certify that:

1. I have reviewed this annual report on Form 10-K of SRC Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 21, 2018

/s/ Lynn A. Peterson

Lynn A. Peterson,

Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 15 U.S.C. SECTION 7241, AS

ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James P. Henderson, certify that:

1. I have reviewed this annual report on Form 10-K of SRC Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 21, 2018

/s/ James P. Henderson

James P. Henderson,

Principal Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATIONS OF

PRINCIPAL EXECUTIVE AND FINANCIAL OFFICERS

PURSUANT TO 18 U.S.C. SECTION 1350,AS

ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of SRC Energy Inc., (the "Company") on Form 10-K for the year ended December 31, 2017 as filed with the Securities Exchange Commission on the date hereof (the "Report") Lynn A. Peterson, Principal Executive Officer of the Company, and James P. Henderson, the Principal Financial Officer of the Company, certify pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 21, 2018	By:	/s/ Lynn A. Peterson
			Lynn A. Peterson, Principal Executive Officer

Date:	February 21, 2018	By:	/s/ James P. Henderson
			James P. Henderson, Principal Financial Officer

This certification is furnished with this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and will not, except to the extent required by such Act, be deemed filed by the Registrant for purposes of Section 18 of the Exchange Act. This certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that the Registrant specifically incorporates it by reference.

EX-99.1

January 26, 2018

SRC Energy Inc.

1675 Broadway Suite 2600

Denver, Colorado 80202

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of SRC Energy Inc. (SRC) as of December 31, 2017. The subject properties are located in the states of Colorado and Wyoming. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 26, 2018 and presented herein, was prepared for public disclosure by SRC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of SRC as of December 31, 2017.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2017 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SRC Energy Inc.

January 26, 2018

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SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
SRC ENERGY INC.
	As of December 31, 2017
		Proved
		Developed						Total
		Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate - Mbbl		22,687		3,865		42,844		69,396
Gas - MMcf		21,047		3,204		39,702		63,953
		191,511		27,768		340,614		559,893
Income Data($M)
Future Gross Revenue		$	1,782,712	$	286,643	$	3,328,680	$	5,398,035
Deductions		518,516		76,626		1,649,609		2,244,751
Future Net Income (FNI)		$	1,264,196	$	210,017	$	1,679,071	$	3,153,284
Discounted FNI @ 10%		$	861,685	$	142,996	$	751,603	$	1,756,284

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of SRC. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, development costs, and certain abandonment costs. The “Other Deductions” in the cash flow projections consist of variable operating costs. The proved developed non-producing category includes abandonment costs associated with certain shut-in wells, as well as reserves and income associated with certain shut-in wells. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 78 percent and gas reserves account for the remaining 22 percent of total future gross revenue from proved reserves.

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January 26, 2018

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The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of December 31, 2017
Discount Rate		Total
Percent		Proved
12		$1,603,587
15		$1,415,035
20		$1,177,509
25		$1,004,011

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At SRC’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically

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January 26, 2018

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producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

SRC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which SRC owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is

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identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or analogy. One hundred percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include decline curve analysis which utilized extrapolations of historical production and pressure data available through December 2017 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by SRC and were considered sufficient for the purpose thereof.

One hundred percent of the proved developed non-producing and undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were considered sufficient for the purpose thereof

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

SRC has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished

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by SRC with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, ad valorem and production taxes, development costs, development plans, abandonment costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by SRC. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Analogy wells were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by SRC. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations,

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exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

SRC furnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by SRC. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by SRC to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$51.34/bbl	$46.57/bbl
United States	NGLs	WTI Cushing	$51.34/bbl	$16.06/bbl
	Gas	Henry Hub	$2.98/MMBTU	$2.21/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by SRC and are based on the operating expense reports of SRC and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs do not include corporate general administrative costs that are not allocated directly to the leases and wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished

SRC Energy Inc.

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to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by SRC. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by SRC and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment was included for all properties. The estimates of the net abandonment costs furnished by SRC were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with SRC’s plans to develop these reserves as of December 31, 2017. The implementation of SRC’s development plans as presented to us and incorporated herein is subject to the approval process adopted by SRC’s management. As the result of our inquiries during the course of preparing this report, SRC has informed us that the development activities included herein have been subjected to and received the internal approvals required by SRC’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to SRC. Additionally, SRC has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by SRC were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified

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January 26, 2018

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professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to SRC. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by SRC.

SRCmakes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act.  Furthermore, SRC has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference.  We have consented to the incorporation by reference in the registration statements on Forms S-3 and S-8 of SRC, of the references to our name, as well as to the references to our third party report for SRC, which appears in the December 31, 2017 annual report on Form 10-K of SRC.  Our written consent for such use is included as a separate exhibit to the filings made with the SEC by SRC.

We have provided SRC with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by SRC and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

SRC Energy Inc.

January 26, 2018

Page 9

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580
	/s/ James L. Baird
	James L. Baird, P.E.
	Colorado License No. 41521
[Seal]	Managing Senior Vice President
	/s/ Richard J. Marshall
	Richard J. Marshall, P.E.
	Colorado License No. 23260
	Vice President [Seal]

JLB-RJM (FWZ)/pl

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Mr. Marshall, an employee of Ryder Scott Company L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Mr. Marshall served in a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding Mr. Marshall’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Marshall earned a B.S. in Geology from the University of Missouri in 1974 and a M.S. in Geological Engineering from the University of Missouri at Rolla in 1976. Mr. Marshall is a registered Professional Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers, Wyoming Geological Association, Rocky Mountain Association of Geologists and the Society of Petroleum Evaluation Engineers.

Based on Mr. Marshall’s educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 19, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	SRC Energy Inc.
Entity Central Index Key	0001413507
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		241,786,159
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1.0

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 48,772	$ 18,615
Accounts receivable:
Oil, natural gas, and NGL sales	86,013	25,728
Trade	18,134	6,805
Commodity derivative assets	0	297
Other current assets	7,116	2,739
Total current assets	160,035	54,184
Property and equipment:
Proved properties, net of accumulated depletion	970,584	424,082
Wells in progress	106,269	81,780
Unproved properties and land, not subject to depletion	793,669	398,547
Oil and gas properties, net	1,870,522	904,409
Other property and equipment, net	6,054	4,327
Total property and equipment, net	1,876,576	908,736
Cash held in escrow and other deposits	0	18,248
Goodwill	40,711	40,711
Other assets	2,242	2,234
Total assets	2,079,564	1,024,113
Current liabilities:
Accounts payable and accrued expenses	74,672	52,453
Revenue payable	64,111	16,557
Production taxes payable	52,413	17,673
Asset retirement obligations	3,246	2,683
Commodity derivative liabilities	7,865	2,874
Total current liabilities	202,307	92,240
Revolving credit facility	0	0
Notes payable, net of issuance costs	538,186	75,614
Asset retirement obligations	28,376	13,775
Other liabilities	2,261	1,745
Total liabilities	771,130	183,374
Commitments and contingencies (See Note16)
Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding	0	0
Common stock - $0.001 par value, 300,000,000 shares authorized: 241,365,522 and 200,647,572 shares issued and outstanding as of December 31, 2017 and 2016, respectively	241	201
Additional paid-in capital	1,474,273	1,148,998
Retained deficit	(166,080)	(308,460)
Total shareholders' equity	1,308,434	840,739
Total liabilities and shareholders' equity	$ 2,079,564	$ 1,024,113

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred stock, par value per share (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding		0
Common stock, par value per share (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	241,365,522	200,647,572
Common stock, shares outstanding	241,365,522	200,647,572

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Income Statement [Abstract]
Oil, natural gas, and NGL revenues	$ 34,138	$ 362,516	$ 107,149	$ 124,843
Expenses:
Lease operating expenses	5,812	19,496	19,949	15,017
Transportation and gathering	0	3,226	0	0
Production taxes	3,104	36,266	5,732	11,340
Depreciation, depletion, and accretion	18,776	112,309	46,678	65,869
Full cost ceiling impairment	125,230	0	215,223	16,000
Unused commitment charge	2,802	669	597	0
General and administrative	17,875	32,965	30,545	18,995
Total expenses	173,599	204,931	318,724	127,221
Operating income (loss)	(139,461)	157,585	(211,575)	(2,378)
Other income (expense):
Commodity derivative gain (loss)	6,482	(4,226)	(7,750)	32,256
Interest expense, net of amounts capitalized	0	(11,842)	0	(245)
Interest income	40	363	192	86
Other income	0	503	50	0
Total other income (expense)	6,522	(15,202)	(7,508)	32,097
Income (Loss) before income taxes	(132,939)	142,383	(219,083)	29,719
Income tax expense (benefit)	(10,007)	(99)	106	11,677
Net income (loss)	$ (122,932)	$ 142,482	$ (219,189)	$ 18,042
Net income (loss) per common share:
Basic (in dollars per share)	$ (1.14)	$ 0.69	$ (1.26)	$ 0.19
Diluted (in dollars per share)	$ (1.14)	$ 0.69	$ (1.26)	$ 0.19
Weighted-average shares outstanding:
Basic (in shares)	107,789,554	206,167,506	173,774,035	94,628,665
Diluted (in shares)	107,789,554	206,743,551	173,774,035	95,319,269

XML

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid - In Capital	Accumulated Earnings (Deficit)
Balance at Aug. 31, 2014	$ 281,490	$ 78	$ 265,793	$ 15,619
Balance, shares at Aug. 31, 2014		77,999,082
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued in equity offering	$ 190,845	$ 19	190,826
Shares issued in equity offering, shares	18,613,952	18,613,952
Shares issued for acquisition	$ 48,434	$ 5	48,429
Shares issued for acquisition, shares	4,648,136	4,648,136
Shares issued in exchange for mineral assets	$ 11,787	$ 1	11,786
Shares issued in exchange for mineral assets, shares	995,672	995,672
Shares issued for exercise of warrants	$ 15,370	$ 2	15,368
Shares issued for exercise of warrants, shares		2,562,473
Shares issued under stock bonus and equity incentive plans	2,950		2,950
Shares issued under stock bonus and equity incentive plans, shares		161,755
Shares issued for exercise of stock options	$ 0
Shares issued for exercise of stock options, shares	258,000	118,272
Stock-based compensation for options	$ 4,741		4,741
Stock based compensation for options, shares		0
Payment of tax withholdings using withheld shares	(1,262)		(1,262)
Net income (loss)	18,042			18,042
Balance at Aug. 31, 2015	$ 572,397	$ 105	538,631	33,661
Balance, shares at Aug. 31, 2015		105,099,342
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued in equity offering, shares	0
Shares issued for acquisition	$ 49,839	$ 4	49,835
Shares issued for acquisition, shares	4,418,413.000	4,418,413
Shares issued in exchange for mineral assets	$ 426	$ 0	426
Shares issued in exchange for mineral assets, shares	37,051.000	37,051
Shares issued under stock bonus and equity incentive plans	$ 7,163	$ 1	7,162
Shares issued under stock bonus and equity incentive plans, shares		422,035
Shares issued for exercise of stock options	$ 0
Shares issued for exercise of stock options, shares	188,000	56,760
Stock-based compensation for options	$ 2,161		2,161
Stock based compensation for options, shares		0
Payment of tax withholdings using withheld shares	(2,544)		(2,544)
Net income (loss)	(122,932)			(122,932)
Balance at Dec. 31, 2015	506,510	$ 110	595,671	(89,271)
Balance, shares at Dec. 31, 2015		110,033,601
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued in equity offering	$ 543,411	$ 90	543,321
Shares issued in equity offering, shares	90,275,000	90,275,000
Shares issued for acquisition, shares	0
Shares issued in exchange for mineral assets, shares	0
Shares issued under stock bonus and equity incentive plans	$ 4,232	$ 1	4,231
Shares issued under stock bonus and equity incentive plans, shares		321,101
Shares issued for exercise of stock options	$ 68	$ 0	68
Shares issued for exercise of stock options, shares	20,000	17,870
Stock-based compensation for options	$ 5,417		5,417
Stock-based compensation for performance-vested stock units	1,047		1,047
Payment of tax withholdings using withheld shares	(757)		(757)
Net income (loss)	(219,189)			(219,189)
Balance at Dec. 31, 2016	$ 840,739	$ 201	1,148,998	(308,460)
Balance, shares at Dec. 31, 2016	200,647,572	200,647,572
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued in equity offering	$ 312,171	$ 40	312,131
Shares issued in equity offering, shares	40,250,000	40,250,000
Shares issued for acquisition, shares	0
Shares issued in exchange for mineral assets, shares	0
Shares issued under stock bonus and equity incentive plans	$ 4,976	$ 0	4,976
Shares issued under stock bonus and equity incentive plans, shares		280,284
Shares issued for exercise of stock options	$ 740	$ 0	740
Shares issued for exercise of stock options, shares	187,666	187,666
Stock-based compensation for options	$ 5,076		5,076
Stock-based compensation for performance-vested stock units	2,938		2,938
Payment of tax withholdings using withheld shares	(688)		(688)
Net income (loss)	142,482			142,482
Balance at Dec. 31, 2017	$ 1,308,434	$ 241	1,474,273	(166,080)
Balance, shares at Dec. 31, 2017	241,365,522	241,365,522
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Adoption of ASU 2016-09			$ 102	$ (102)

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ (122,932)	$ 142,482	$ (219,189)	$ 18,042
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and accretion	18,776	112,309	46,678	65,869
Full cost ceiling impairment	125,230	0	215,223	16,000
Settlements of asset retirement obligations	(745)	(4,541)	(228)	0
Loss on extinguishment of debt	0	11,842	0	0
Provision for deferred taxes	(10,007)	0	0	11,679
Stock-based compensation expense	8,431	11,225	9,491	7,691
Total (gain) loss on commodity derivative contracts	(6,482)	4,226	7,750	(32,256)
Cash settlements on commodity derivative contracts	1,954	942	5,374	31,721
Cash premiums paid for commodity derivative contracts	(956)	0	0	(4,117)
Changes in operating assets and liabilities	6,803	12,830	(16,411)	10,458
Net cash provided by operating activities	20,072	291,315	48,688	125,087
Cash flows from investing activities:
Acquisitions of oil and gas properties and leaseholds	(37,150)	(661,468)	(511,173)	(82,584)
Capital expenditures for drilling and completion activities	(41,581)	(450,384)	(119,571)	(186,135)
Other capital expenditures	(5,811)	(17,841)	(7,044)	(6,375)
Acquisition of land and other property and equipment	(395)	(4,186)	(5,478)	(714)
Proceeds from sales of oil and gas properties and other	0	93,573	25,350	6,239
Net cash used in investing activities	(84,937)	(1,040,306)	(617,916)	(269,569)
Cash flows from financing activities:
Proceeds from the sale of stock	0	322,000	565,398	200,100
Offering costs	0	(9,745)	(21,987)	(9,255)
Proceeds from the employee exercise of stock options	0	741	68	15,370
Payment of employee payroll taxes in connection with shares withheld	(2,544)	(688)	(757)	(1,262)
Proceeds from revolving credit facility	0	250,000	55,000	186,000
Principal repayments on revolving credit facility	0	(250,000)	(133,000)	(145,000)
Proceeds from issuance of notes payable	0	550,000	80,000	0
Repayment of notes payable	0	(88,234)	0	0
Financing fees on issuance of notes payable and amendments to revolving credit facility	0	(13,145)	(5,159)	(2,316)
Net cash provided by (used in) financing activities	(2,544)	760,929	539,563	243,637
Net increase (decrease) in cash, cash equivalents, and restricted cash	(67,409)	11,938	(29,665)	99,155
Cash, cash equivalents, and restricted cash at beginning of period	133,908	36,834	66,499	34,753
Cash, cash equivalents, and restricted cash at end of period	$ 66,499	$ 48,772	$ 36,834	$ 133,908

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Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Summary of Significant Accounting Policies

Organization and Summary of Significant Accounting Policies

Organization:  SRC Energy Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and NGLs, primarily in the D-J Basin of Colorado. On June 15, 2017, our shareholders approved an amendment to the Amended and Restated Articles of Incorporation of the Company to change the name of the Company from Synergy Resources Corporation to SRC Energy Inc. The Company had been using the new name on a "doing business as" basis since March 6, 2017. In addition to using the new name, the Company’s common stock, which is listed and traded on the NYSE American, changed to the new symbol "SRCI."

Basis of Presentation:  The Company operates in one business segment, and all of its operations are located in the United States of America.

At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc. When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

Change of Year-End:  On February 25, 2016, the Company's Board of Directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year.

Use of Estimates:The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates.

Cash and Cash Equivalents:  The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. As of December 31, 2016, the Company had placed $18.2 million in escrow, which was released upon the second closing of the GC Acquisition. Please refer to Note 3, Acquisitions and Divestitures, for further information.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows:

	As of December 31,						As of August 31, 2015
	2017		2016		2015
Cash and cash equivalents	$	48,772	$	18,615	$	66,499	$	133,908
Restricted cash included in cash held in escrow and other deposits	—		18,219		—		—
	$	48,772	$	36,834	$	66,499	$	133,908

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is the impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties.  The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During theyear ended December 31, 2017, the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company recognized ceiling test impairments of$215.2 million,$125.2 million, and$16.0 million, respectively.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials and are held constant for the productive life of each well.

Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest:The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 10 for additional information.

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information.

Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment, and software), office leasehold improvements, office furniture and equipment, and buildings are stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its other property and equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. 

Accounts Payable and Accrued Expenses: Accounts payable and accrued expenses consist of the following (in thousands):

	As of December 31,
	2017		2016
Trade accounts payable	$	624	$	786
Accrued well costs	56,348		42,779
Accrued G&A	6,017		4,292
Accrued LOE	5,249		3,140
Accrued interest	3,125		320
Accrued other	3,309		1,136
	74,672		52,453

Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received.

Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset.  Asset retirement costs ("ARCs") related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment.

Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under FASB Accounting Standards Codification ("ASC") 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination.  Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31^st. During 2016, we changed the date of our annual goodwill impairment assessment to October 1^st. With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge.

When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit.  If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge.  The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill.  For purposes of assessing goodwill, the Company only has one reporting unit.

We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.

Oil, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests.  Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the product is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:    The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue (“major customers”) for each of the periods presented are shown in the following table:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31, 2015
	2017	2016
Company A	33%	*	*	*
Company B	24%	20%	15%	11%
Company C	17%	20%	*	*
Company D	*	16%	*	*
Company E	*	13%	*	*
Company F	*	*	57%	65%
Company G	*	*	12%	*

* less than 10%

Based on the current demand for oil and natural gas, the availability of other buyers, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that the loss of our existing customers or individual contract would not have a material adverse effect on us. Our oil and natural gas production is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.

Accounts receivable consist primarily of receivables from oil, natural gas, and NGL sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):

	As of December 31,
	2017	2016
Company A	26%	23%
Company B	23%	*
Company C	16%	*
Company D	11%	43%
Company E	*	10%

* less than 10%

The Company operates exclusively within the United States of America, and except for cash and cash equivalents, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry.

Lease Operating Expenses:  Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities.

Stock-Based Compensation:  The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model.  For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation.  The compensation is recognized over the vesting period of the grant.  See Note 13 for additional information.

Income Tax:  Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions were identified as of any date on or before December 31, 2017.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of December 31, 2017, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 15 for further information.

Financial Instruments: Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative gain (loss) line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 8.

Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations.

Recently Adopted Accounting Pronouncements:

In November 2016, the FASB issued Accounting Standards Update ("ASU") 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. We adopted this pronouncement effective October 1, 2017 and have applied it retrospectively. Upon adoption, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2016. This change resulted in a decrease to net cash used in investing activities of $18.2 million. Additionally, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2017. This change resulted in an increase to net cash used in investing activities of $18.2 million. The adoption of this standard did not impact cash flows for the 4-months ended December 31, 2015 nor the year ended August 31, 2015. We have included a tabular reconciliation of cash, cash equivalents, and restricted cash in the discussion of "Cash Held in Escrow" above.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance did not impact the consolidated financial statements.

Recently Issued Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued various ASUs, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The Company will adopt these ASUs with an effective date of January 1, 2018, using the modified retrospective method. While we have not yet completed all aspects of the adoption of the standard, based on our current assessment of contracts with customers, we do not believe there will be any impact to the timing of our revenue recognition or our operating income (loss), net income (loss), and cash flows. The Company is in the process of evaluating changes, if any, to accounting policies and internal control procedures along with continuing to assess additional disclosures which may be required upon implementation of these ASUs.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

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Property and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):

	As of December 31,
	2017			2016
Oil and gas properties, full cost method:
Costs of proved properties:
Producing and non-producing	$	1,629,789		$	969,239
Less, accumulated depletion and full cost ceiling impairments	(659,205		)	(545,157		)
Subtotal, proved properties, net	970,584			424,082
Costs of wells in progress	106,269			81,780
Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs	786,469			392,561
Land	7,200			5,986
Subtotal, unproved properties and land	793,669			398,547
Costs of other property and equipment:
Other property and equipment	8,134			5,063
Less, accumulated depreciation	(2,080		)	(736		)
Subtotal, other property and equipment, net	6,054			4,327
Total property and equipment, net	$	1,876,576		$	908,736

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At December 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company's ceiling tests resulted in total impairments of $215.2 million, $125.2 million, and $16.0 million, respectively. No impairments were recognized for the comparable 2017 period.

The costs of unproved properties are withheld from the depletion base until such time as the properties are either developed or abandoned. Unproved properties are reviewed on an annual basis, or more frequently if necessary, for impairment and, if impaired, are reclassified to proved properties and included in the depletion base. During the year ended December 31, 2017, these reviews indicated that the estimated fair value of such assets exceeded the carrying values. Therefore, no impairment was necessary as December 31, 2017. However, during the years ended December 31, 2016 and August 31, 2015, the Company recorded impairments of $18.9 million and $15.4 million, respectively, related to the fair value of its unproved properties. No such impairments were recognized during the four months ended December 31, 2015.

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Capitalized overhead	$	10,293	$	7,074	$	1,091	$	2,049

Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Acquisition of property:
Unproved	$	538,489	$	365,548	$	38,779	$	32,701
Proved	139,154		152,363		51,085		51,400
Exploration costs	—		43,154		23,697		146,892
Development costs	460,875		87,782		17,742		4,957
Other property and equipment, and land	4,397		7,506		395		741
Capitalized interest, capitalized G&A, and other	26,677		18,744		4,415		7,051
Total costs incurred	$	1,169,592	$	675,097	$	136,113	$	243,742

Capitalized Costs Excluded from Depletion:  The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2017 (in thousands):

	Period Incurred
	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31,				Total as of December 31, 2017
	2017		2016				2015		2014 and Prior
Unproved leasehold acquisition costs	$	537,470	$	223,907	$	23,068	$	456	$	1,568	$	786,469
Unproved development costs	26,056		—		—		—		—		26,056
Total unevaluated costs	$	563,526	$	223,907	$	23,068	$	456	$	1,568	$	812,525

There were no individually significant properties or significant development projects included in the Company’s unproved property balance.  The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established.  The majority of these costs are expected to be evaluated and included in the depletion base within three years.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

The Company seeks to acquire developed and undeveloped oil and gas properties in the core Wattenberg Field to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons.

December 2017 Acquisition

In November 2017, the Company entered into an agreement ("GCII Agreement") to purchase a total of approximately 30,200 net acres located in an area known as the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $568 million ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement. On December 15, 2017, the Company closed on the portion of the assets comprised of the undeveloped lands and non-operated production. The effective date of this part of the transaction was November 1, 2017, and the purchase price was $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities. The purchase price has preliminarily been allocated as $59.9 million to proved oil and gas properties and $509.6 million to unproved oil and gas properties, pending the final closing. The second closing will cover the operated producing properties and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.

The first closing was accounted for as an asset acquisition under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of December 15, 2017.

September 2017 Acquisition

In September 2017, we completed the second closing of the GC Acquisition (as defined in "-June 2016 Acquisition" below). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million, composed of cash of $6.3 million and assumed liabilities of $24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties.

August 2017 Acquisition and Swap

In August 2017, we also entered into an agreement with another party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also acquired approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities. The purchase price for the acquisition has preliminarily been allocated as $6.7 million to proved oil and gas properties and $15.9 million to unproved oil and gas properties, pending the final closing.

March 2017 Acquisition

In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million, composed of cash and assumed liabilities. The purchase price has been allocated as $15.3 million to proved oil and gas properties, $9.4 million to unproved oil and gas properties, and $0.4 million to other assets and land.

Acquisitions in the Second Half of 2016

In August and October 2016, the Company completed four acquisitions of certain assets for a total purchase price of $13.5 million composed of cash, forgiven receivables, and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests and additional interests in developed properties operated by the Company.

June 2016 Acquisition

In May 2016, we entered into a purchase and sale agreement pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million (the "GC Acquisition").

In June 2016, the Company closed on the portion of the assets comprised of undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. As discussed above in "- September 2017 Acquisition" above,we closed on the second part of this transaction covering the operated producing properties in September 2017.

The first closing on June 14, 2016 was for a total purchase price of $486.4 million, net of customary closing adjustments. The purchase price was composed of $485.1 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOED at the time of entering into the GC Agreement.

The first closing was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of $0.5 millionrelated to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	June 14, 2016
Consideration given:
Cash	$	485,141
Net liabilities assumed, including asset retirement obligations	1,273
Total consideration given	$	486,414
Allocation of Purchase Price(1)
Proved oil and gas properties	$	132,903
Unproved oil and gas properties	353,511
Total fair value of assets acquired	$	486,414

⁽¹⁾ Oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of11.5%, and assumptions regarding the timing and amount of future development and operating costs.

For theyear ended December 31, 2017, the results of operations of the acquired assets, representing approximately$5.4 millionof revenue and$4.7 millionofoperating income, have been included in the Company's consolidated statements of operations.

The following table presents the unaudited pro forma combined results of operations for the year ended December 31, 2016 as if the first closing had occurred on September 1, 2014.  The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

(in thousands)	Year Ended December 31, 2016
Oil, natural gas, and NGL revenues	$	110,635
Net loss	$	(218,578	)
Net loss per common share
Basic	$	(1.10	)
Diluted	$	(1.10	)

February 2016 Acquisition

In February 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million. The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties. See Note 9 for further details as to the preparation of these significant estimates.

Divestitures

During the year ended December 31, 2017, we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities.

During the year ended December 31, 2016, the Company completed divestitures of approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities. The divested assets had associated production of approximately 200 BOED.

In accordance with full cost accounting guidelines, the net proceeds from these divestitures were credited to the full cost pool.

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Depletion, depreciation and accretion ("DD&A")

12 Months Ended

Dec. 31, 2017

Other Costs and Disclosures [Abstract]

Depletion, depreciation and accretion (DD&A)

Depletion, depreciation, and accretion ("DD&A")

DD&A consisted of the following (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Depletion of oil and gas properties	$	109,287	$	45,193	$	18,371	$	65,158
Depreciation and accretion	3,022		1,485		405		711
Total DD&A Expense	$	112,309	$	46,678	$	18,776	$	65,869

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the year ended December 31, 2017, production of 12,481 MBOE represented 5.2% of estimated total proved reverses. For the year ended December 31, 2016, production of 4,271 MBOE represented 4.4% of estimated total proved reserves. For the four months ended December 31, 2015, production of 1,320 MBOE represented 2.0% of estimated total proved reserves.

For the year ended August 31, 2015, production of 3,194 MBOE represented 5.3% of estimated total proved reserves. DD&A expense was $9.00 per BOE and $10.93 per BOE for the years ended December 31, 2017 and 2016, respectively. DD&A expense was $14.22 per BOE and $20.62 per BOE for the four months ended December 31, 2015 and the year ended August 31, 2015, respectively.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):

	Year Ended December 31,
	2017			2016
Beginning asset retirement obligation	$	16,458		$	13,400
Obligations incurred with development activities	3,398			773
Obligations assumed with acquisitions	24,696			2,230
Accretion expense	1,554			1,046
Obligations discharged with asset retirements and divestitures	(14,332		)	(4,739		)
Revisions in previous estimates	(152		)	3,748
Ending asset retirement obligation	$	31,622		$	16,458
Less, current portion	(3,246		)	(2,683		)
Non-current portion	$	28,376		$	13,775

During the year ended December 31, 2017, the Company decreased its asset retirement obligation by $0.2 million due to a revision to the expected timing of the future cash flows. During the year ended December 31, 2016, the Company increased its asset retirement obligation by $3.7 million due primarily to a revision to its assumption of the average cost to plug and abandon each well.

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Revolving Credit Facility

12 Months Ended

Dec. 31, 2017

Line of Credit Facility [Abstract]

Revolving Credit Facility

Revolving Credit Facility

The Company maintains a revolving credit facility (sometimes referred to as the "Revolver") with a bank syndicate with a maturity date of December 15, 2019. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of December 31, 2017, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $400 million. As of December 31, 2017 and 2016, there was no outstanding principal balance. The Company has an outstanding letter of credit of approximately $0.5 million.

In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base.The borrowing base was increased from$225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018.

Interest under the Revolver accrues monthly at a variable rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the years ended December 31, 2017 and 2016, was 3.4%, and 2.6%, respectively.

Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur, or if the bank syndicate or the Company so elects, an unscheduled redetermination could be undertaken.

The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report.

Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than1.0to 1.0. As ofDecember 31, 2017, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

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Notes Payable

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Notes Payable

Notes Payable

2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of6.6%. The net proceeds were used to fund the GCII Acquisition as discussed further in Note3, repay the 2021 Senior Notes, and pay off the outstanding Revolver balance.

At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the principal amount plus an Applicable Premium (as defined in the Indenture) plus accrued and unpaid interest.  On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption priceequal to a specified percentage of the principal amount of the redeemed notes (104.688% for 2020, 103.125% for 2021,101.563%for 2022, and 100% for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest.Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to35%of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to106.25%of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

As ofDecember 31, 2017, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

2021 Senior Notes

In June 2016, the Company issued $80 millionaggregate principal amount of 9% Senior Notes due 2021 (the "2021 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal was June 13, 2021. Interest on the 2021 Senior Notes accrued at9%and began accruing on June 14, 2016. Interest was payable on June 15 and December 15 of each year, beginning on December 15, 2016. The 2021 Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the 2021 Senior Notes were $75.2 millionafter deductions of $4.8 millionfor expenses and underwriting discounts and commissions.

In December 2017, the Company repurchased all $80 million aggregate principal amount of the 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.

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Commodity Derivative Instruments

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Instruments

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.

A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may at times purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase.

A "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where the cost of the put is offset by the proceeds of the call. At settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term.

The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with five counterparties and an exchange. Three of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses are recorded in the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in it making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.

The Company’s commodity derivative contracts as of December 31, 2017 are summarized below:

Settlement Period	Derivative Instrument	Average Volumes (Bbls per day)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	40.00	$	57.50
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	40.00	$	57.75
Jan 1, 2018 - Dec 31, 2018	Collar	500	$	40.00	$	57.50
Jan 1, 2018 - Dec 31, 2018	Collar	2,500	$	45.00	$	58.00
Jan 1, 2018 - Dec 31, 2018	Collar	2,500	$	45.00	$	64.55
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	44.50	$	65.00
Jan 1, 2018 - Dec 31, 2018	Collar	1,500	$	44.50	$	65.00
Settlement Period	Derivative Instrument	Average Volumes (MMBtu per day)	Floor Price		Ceiling Price
Natural Gas - CIG Rocky Mountain
Jan 1, 2018 - Dec 31, 2018	Collar	10,000	$	2.25	$	2.82
Jan 1, 2018 - Dec 31, 2018	Collar	5,000	$	2.25	$	2.81

Subsequent to December 31, 2017, the Company added the following positions:

Settlement Period	Derivative Instrument	Average Volumes (Bbls per day)	Average Fixed Price
Propane - Mont Belvieu
Feb 1, 2018 - Dec 31, 2018	Swap	1,000	$	0.80

Offsetting of Derivative Assets and Liabilities

As of December 31, 2017 and 2016, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):

		As of December 31, 2017
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	1,960	$	(1,960	)	$	—
Commodity derivative contracts	Non-current assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	9,825	$	(1,960	)	$	7,865
Commodity derivative contracts	Non-current liabilities	$	—	$	—		$	—

		As of December 31, 2016
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	2,045	$	(1,748	)	$	297
Commodity derivative contracts	Non-current assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	4,622	$	(1,748	)	$	2,874
Commodity derivative contracts	Non-current liabilities	$	—	$	—		$	—

The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017			2016
Realized gain (loss) on commodity derivatives	$	39		$	2,355		$	1,577	$	30,466
Unrealized gain (loss) on commodity derivatives	(4,265		)	(10,105		)	4,905		1,790
Total gain (loss)	$	(4,226	)	$	(7,750	)	$	6,482	$	32,256

Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date net of the previously incurred premiums attributable to settled commodity contracts. During the year ended August 31, 2015, the Company liquidated oil derivatives with an average price of $82.79 and covering 372,500 barrels and received cash settlements of approximately $20.5 million. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Monthly settlement	$	1,062		$	4,396		$	2,331		$	11,212
Previously incurred premiums attributable to settled commodity contracts	(1,023		)	(2,041		)	(754		)	(1,255		)
Early liquidation	—			—			—			20,509
Total realized gain (loss)	$	39		$	2,355		$	1,577		$	30,466

Credit Related Contingent Features

As of December 31, 2017, three of the six counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the fourth counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fifth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

ASC 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

• Level 1: Quoted prices available in active markets for identical assets or liabilities;

• Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and

• Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations and asset acquisitions, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its unproved properties using market comparables which are deemed to be a Level 3 input. See Note 2 for additional information.

The acquisition of a group of assets in a business combination transaction and certain asset acquisitions requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired is calculated using a net discounted cash flow approach for the proved producing, proved undeveloped, probable, and possible properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using market comparables.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rate, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Notes 3 and 5 for additional information.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at December 31, 2017
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	—	$	—	$	—
Commodity derivative liability	$	—	$	7,865	$	—	$	7,865

	Fair Value Measurements at December 31, 2016
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	297	$	—	$	297
Commodity derivative liability	$	—	$	2,874	$	—	$	2,874

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At December 31, 2017, derivative instruments utilized by the Company consist of collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, cash held in escrow, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, cash held in escrow, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the notes payable is estimated to be $564.1 million at December 31, 2017. The Company determined the fair value of its notes payable at December 31, 2017 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes payable as Level 2.

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Interest Expense

12 Months Ended

Dec. 31, 2017

Interest and Debt Expense [Abstract]

Interest Expense

Interest Expense

The components of interest expense are (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Revolving credit facility	$	2,004		$	154		$	661		$	2,776
Notes payable	10,036			3,940			—			—
Amortization of debt issuance costs	3,084			1,638			431			853
Debt extinguishment costs	11,842			—			—			—
Less: interest capitalized	(15,124		)	(5,732		)	(1,092		)	(3,384		)
Interest expense, net	$	11,842		$	—		$	—		$	245

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Shareholders' Equity

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Note [Abstract]

Shareholders' Equity

Shareholders’ Equity

The Company's classes of stock are summarized as follows:

	As of December 31,
	2017		2016
Preferred stock, shares authorized	10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized	300,000,000		300,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding	241,365,522		200,647,572

Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors.  Since inception, the Company has not issued any preferred shares.

Shares of the Company’s common stock were issued during the years ended December 31, 2017 and 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, as described further below.

Sales of common stock

A summary of the transactions is shown in the following table.  Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions, and expenses of the offering.

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Number of common shares sold	40,250,000		90,275,000		—		18,613,952
Offering price per common share	$	7.76	$	6.02	$	—	$	10.75
Net proceeds (in thousands)	$	312,170	$	543,400	$	—	$	190,845

In November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 5,250,000 shares of common stock on the same terms and conditions. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to40,250,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were$312.2 million. The Company used the proceeds of the Offering to pay a portion of the purchase price of the GCII Acquisition, to repay a portion of the 2021 Senior Notes,and to repay amounts borrowed under the Revolver.

Common stock issued for acquisition of mineral property interests

During the periods presented, the Company issued shares of common stock in exchange for mineral property interests.  The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Number of common shares issued for mineral property leases	—		—		37,051		995,672
Number of common shares issued for acquisitions	—		—		4,418,413		4,648,136
Total common shares issued	—		—		4,455,464		5,643,808
Average price per common share	$	—	$	—	$	11.28	$	10.67
Aggregate value of shares issues (in thousands)	$	—	$	—	$	50,265	$	60,221

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Weighted-Average Shares Outstanding

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Weighted-Average Shares Outstanding

Weighted-Average Shares Outstanding

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31,2015
	2017	2016
Weighted-average shares outstanding - basic	206,167,506	173,774,035	107,789,554	94,628,665
Potentially dilutive common shares from:
Stock options	417,809	—	—	672,493
Restricted stock units and stock bonus shares	158,236	—	—	18,111
Weighted-average shares outstanding - diluted	206,743,551	173,774,035	107,789,554	95,319,269

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31, 2015
	2017	2016
Potentially dilutive common shares from:
Stock options	4,657,834	6,001,500	5,056,000	2,785,500
Performance-vested stock units1	951,884	478,510	—	—
Restricted stock units and stock bonus shares	285,448	890,336	915,867	145,000
Total	5,895,166	7,370,346	5,971,867	2,930,500

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant-date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting period").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of December 31, 2017, there were 4,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 110,158 shares were available for future grants. The shares available for future grant exclude 951,884 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards met the criterion to vest at their maximum multiplier.

The amount of stock-based compensation was as follows (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Stock options	$	5,076		$	5,417		$	2,161		$	4,741
Performance-vested stock units	2,938			1,047			—			—
Restricted stock units and stock bonus shares	4,977			4,232			7,162			2,950
Total stock-based compensation	12,991			10,696			9,323			7,691
Less: stock-based compensation capitalized	(1,766		)	(1,205		)	(892		)	(778		)
Total stock-based compensation expense	$	11,225		$	9,491		$	8,431		$	6,913

Stock options

No stock options were granted during the year ended December 31, 2017. During the periods presented, the Company granted the following stock options:

	Year Ended December 31, 2016		Four Months Ended December 31, 2015		Year Ended August 31, 2015
Number of options to purchase common shares	1,067,500		1,142,500		2,377,500
Weighted-average exercise price	$	7.19	$	10.84	$	11.55
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	3 - 5 years		3.7-5 years		3-5 years
Fair Value (in thousands)	$	3,860	$	6,591	$	13,266

The assumptions used in valuing stock options granted during each of the periods presented were as follows:

	Year Ended December 31, 2016		Four Months Ended December 31, 2015		Year Ended August 31, 2015
Expected term	6.4 years		6.5 years		6.5 years
Expected volatility	55	%	53	%	47	%
Risk-free rate	1.25 - 2.00%		1.8 - 2.0%		1.4 - 2.0%
Expected dividend yield	—	%	—	%	—	%

The following table summarizes activity for stock options for the periods presented:

	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, August 31, 2014	2,167,000		$	5.94	8.0 years	$	16,287
Granted	2,377,500		11.55
Exercised	(258,000	)	3.81			2,103
Forfeited	(110,000	)	4.97
Outstanding, August 31, 2015	4,176,500		9.29		8.6 years	8,187
Granted	1,142,500		10.84
Exercised	(188,000	)	6.56			981
Expired	(60,000	)	11.74
Forfeited	(15,000	)	11.68
Outstanding, December 31, 2015	5,056,000		9.71		8.7 years	4,351
Granted	1,067,500		7.19
Exercised	(20,000	)	3.19			117
Expired	—		—
Forfeited	(102,000	)	10.40
Outstanding, December 31, 2016	6,001,500		9.27		8.0 years	6,515
Granted	—		—
Exercised	(187,666	)	3.95			976
Expired	(41,000	)	11.98
Forfeited	(136,000	)	10.97
Outstanding, December 31, 2017	5,636,834		$	9.38	7.0 years	$	4,806
Outstanding, Exercisable at December 31, 2017	3,203,045		$	9.08	6.5 years	$	3,587

The following table summarizes information about issued and outstanding stock options as of December 31, 2017:

	Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life
Under $5.00	454,000	$	3.45	3.5 years	454,000	$	3.45	3.5 years
$5.00 - $6.99	1,012,000	6.38		6.9 years	558,400	6.45		5.8 years
$7.00 - $10.99	1,548,834	9.36		7.4 years	708,245	9.53		7.0 years
$11.00 - $13.46	2,622,000	11.58		7.4 years	1,482,400	11.59		7.4 years
Total	5,636,834	$	9.38	7.0 years	3,203,045	$	9.08	6.5 years

The estimated unrecognized compensation cost from stock options not vested as of December 31, 2017, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	9,697
Remaining vesting period	2.3 years

Restricted stock units and stock bonus awards

The Company grants restricted stock units and stock bonus awards to directors, eligible employees, and officers as a part of its equity incentive plan.  Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.

The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented:

	Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, August 31, 2014	293,333		$	10.60
Granted	547,699		11.17
Vested	(208,532	)	11.09
Forfeited	—		—
Not vested, August 31, 2015	632,500		10.93
Granted	919,604		10.08
Vested	(636,237	)	10.13
Forfeited	—		—
Not vested, December 31, 2015	915,867		10.63
Granted	464,533		7.66
Vested	(424,483	)	9.92
Forfeited	(65,581	)	8.99
Not vested, December 31, 2016	890,336		9.55
Granted	681,568		8.29
Vested	(455,772	)	9.21
Forfeited	(28,746	)	9.74
Not vested, December 31, 2017	1,087,386		$	8.89

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2017, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	7,113
Remaining vesting period	2.2 years

Performance-vested stock units

The Company grants performance-vested stock units ("PSUs") to certain executives under its long-term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, and the volatilities for each of the Company’s peers.

The assumptions used in valuing the PSUs granted were as follows:

	Year Ended December 31,
	2017		2016
Weighted-average expected term	2.9 years		2.7 years
Weighted-average expected volatility	59	%	58	%
Weighted-average risk-free rate	1.34	%	0.87	%

The fair value of the PSUs granted during the years ended December 31, 2017 and 2016 was $5.1 million and $4.0 million, respectively. As of December 31, 2017, unrecognized compensation for PSUs was $5.0 million and will be amortized through 2019. A summary of the status and activity of PSUs is presented in the following table:

	Number of Units1		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2015	—		$	—
Granted	490,713		8.10
Vested	—		—
Forfeited	(12,203	)	8.22
Not vested, December 31, 2016	478,510		8.09
Granted	473,374		10.79
Vested	—		—
Forfeited	—		—
Not vested, December 31, 2017	951,884		$	9.44

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

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Defined Contribution Plan

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Defined Contribution Plan

Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan (the "plan") for eligible employees. Effective January 1, 2017, the Company modified the plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation. The Company contributed approximately $0.7 million for year ended December 31, 2017, $0.4 million for the year ended December 31, 2016, $0.1 million for the four months ended December 31, 2015, and $0.1 million during the year ended August 31, 2015 to the plan.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The income tax provision is comprised of the following (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Current:
Federal	$	(99	)	$	106		$	—		$	(4	)
State	—			—			—			(111		)
Total current income tax expense (benefit)	(99		)	106			—			(115		)
Deferred:
Federal	48,631			(74,099		)	(45,332		)	10,820
State	4,371			(6,651		)	(4,074		)	972
Total deferred income tax (benefit) expense	53,002			(80,750		)	(49,406		)	11,792
Valuation allowance	(53,002		)	80,750			39,399			—
Income tax expense (benefit)	$	(99	)	$	106		$	(10,007	)	$	11,677

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Federal income tax at statutory rate	$	48,410		$	(74,489	)	$	(45,200	)	$	10,105
State income taxes, net of federal tax	4,371			(6,685		)	(4,062		)	908
Statutory depletion	(159		)	(287		)	(150		)	(451		)
Stock-based compensation	50			383			—			92
Non-deductible compensation	—			—			—			850
Impact of tax reform, net of valuation allowance	(99		)
Valuation allowance	(53,002		)	80,750			39,399			—
Other	330			434			6			173
Income tax expense (benefit)	$	(99	)	$	106		$	(10,007	)	$	11,677
Effective rate expressed as a percentage	—		%	—		%	8		%	39		%

On December 22, 2017, Congress signed Public Law No. 115-97, commonly referred to as the Tax Cut and Jobs Act of 2017 (“TCJA”). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21% beginning in January of 2018, the elimination of the corporate alternative minimum tax (“AMT”), the acceleration of depreciation for US tax purposes, limitations on deductibility of interest expense, the elimination of net operating loss carrybacks, and limitations on the use of future losses.  In accordance with ASC 740, Income Taxes, the impact of a change in tax law is recorded in the period of enactment. Consequently, the Company has recorded a decrease to its net deferred tax assets of $24.0 million with a corresponding net adjustment to the valuation allowance for the year ended December 31, 2017.  The Company also eliminated the $0.1 million deferred tax asset for its AMT credits and recorded a non-current tax receivable with a corresponding benefit to current income taxes. Based on the Company's current interpretation and subject to the release of the related regulations and any future interpretive guidance, the Company believes the effects of the change in tax law incorporated herein are substantially complete. As a result of other changes introduced by the TCJA, starting with compensation paid in 2018, Section 162(m) may limit us from deducting compensation, including performance-based compensation, in excess of $1 million paid to anyone who, starting in 2018, serves as the Chief Executive Officer or Chief Financial Officer, or who is among the three most highly compensated executive officers for any fiscal year. The only exception to this rule is for compensation that is paid pursuant to a binding contract in effect on November 2, 2017 that would have otherwise been deductible under the prior Section 162(m) rules. Accordingly, any compensation paid in the future pursuant to new compensation arrangements entered into after November 2, 2017, even if performance-based, will count towards the $1 million fiscal year deduction limit if paid to a covered executive. Additional information that may affect our income tax accounts and disclosures would include further clarification and guidance on how the Internal Revenue Service will implement tax reform, including guidance with respect to 100% bonus depreciation on self-constructed assets and Section 162(m), further clarification and guidance on how state taxing authorities will implement tax reform and the related effect on our state income tax returns, completion of our 2017 tax return filings, and the potential for additional guidance from the SEC or the FASB related to tax reform.

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):

	As of December 31,
	2017			2016
Deferred tax assets (liabilities):
Net operating loss carryforward	$	43,283		$	47,462
Stock-based compensation	5,237			5,576
Basis of oil and gas properties	(5,011		)	62,707
Statutory depletion	2,795			4,028
Unrealized loss on commodity derivative	1,939			1,334
Other	(615		)	(958		)
	47,628			120,149
Valuation allowance on tax assets	(47,628		)	(120,149		)
Deferred tax asset (liability), net	$	—		$	—

In connection with ASU 2016-09, deferred tax assets were increased by $4.5 million related to excess benefit net operating loss carryforwards along with a $4.5 million offsetting increase in the Company's valuation allowance. The impact of the adjustments netted to zero within retained earnings.

At December 31, 2017, the Company has U.S. Federal and state net operating loss carryforward of approximately $175.5 million that could be utilized to offset taxable income of future years. These net operating loss carryforwards will expire in various years beginning in 2025 with substantially all of the carryforwards expiring beginning in 2031.

At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making an assessment as to the future utilization of deferred tax assets. During the year ended December 31, 2017, the Company recognized a full valuation allowance on its net deferred tax assets. This decision was based on the fact that for the preceding three-year period, the Company has reported cumulative net losses. 

The ability of the Company to utilize its NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards.

The Company underwent an ownership change as defined in Section 382 of the Internal Revenue Code on December 31, 2016, as a result of our issuance of common stock. The amount of our taxable income for tax years ending after our ownership change, which may be offset by NOL carryovers from pre-change years, will be subject to an annual limitation, known as a Section 382 limitation. The Section 382 limitation is based on the value of our stock immediately before the ownership change multiplied by the long-term tax exempt rate in effect at the time of the ownership change, increased by built in gains recognized during the 5-year period beginning on the ownership change date. The identified change of ownership is not anticipated to restrict the Company's ability to utilize its NOLs.

As of December 31, 2017, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. The Company's federal and state tax returns filed since August 31, 2014 and August 31, 2013, respectively, remain subject to examination by tax authorities.

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Other Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Other Commitments and Contingencies

Other Commitments and Contingencies

Volume Commitments

The Company entered into firm sales agreements for its oil production with three counterparties during 2014 and entered into an additional firm sales agreement for its oil production in the third quarter 2017. Deliveries under two of the sales agreements commenced during 2015. Deliveries under the third agreement commenced in 2016. Deliveries under the fourth agreement are expected to commence in the fourth quarter of 2018. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described below, are as follows:

Year ending December 31,	Oil (MBbls)
2018	4,485
2019	5,167
2020	4,003
2021	1,672
2022	—
Thereafter	—
Total	15,327

During the years ended December 31, 2017 and 2016, and four months ended December 31, 2015, the Company incurred transportation deficiency charges of $0.7 million, $0.6 million, and $2.8 million, respectively, as we were unable to meet all of the obligations during the period. No such charges were incurred during the year ended August 31, 2015.

In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed during the third quarter of 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in mid-2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. We expect that our development plan will support the utilization of this capacity.

Litigation

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current proceedings are reasonably likely to have a material adverse impact on its business, financial position, results of operations, or cash flows.

Office Leases

In September 2016, the Company entered into a new 65-month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021.

Rent expense for office leases was $1.1 million for the year ended December 31, 2017, $1.0 million for year ended December 31, 2016, $0.3 million for the four months ended December 31, 2015, and $0.3 million for the year ended August 31, 2015.

Vehicle Leases

In December 2017, the Company entered into a leasing arrangement for its vehicles used in our normal operations. These leases expire after four years and are classified as capital leases. The assets associated with these capital leases are recorded within "Other property and equipment, net."

A schedule of the minimum lease payments under non-cancelable capital and operating leases as of December 31, 2017 follows (in thousands):

Year ending December 31:	Vehicles Leases			Office Leases
2018	$	76		$	840
2019	37			859
2020	37			878
2021	63			875
2022	—			477
Thereafter	—			—
Total minimum lease payments	$	213		$	3,929
Less: Amount representing estimated executory cost	(16		)
Net minimum lease payments	197
Less: Amount representing interest	(24		)
Present value of net minimum lease payments *	$	173

^* Reflected in the balance sheet as current and non-current obligations of $63 thousand and $110 thousand, respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively.

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Supplemental Schedule of Information to the Statements of Cash Flows

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Schedule of Information to the Statements of Cash Flows

Supplemental Schedule of Information to the Consolidated Statements of Cash Flows

The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
Supplemental cash flow information:	2017			2016
Interest paid	$	9,235		$	3,779		$	683		$	2,817
Income taxes paid	$	—		$	106		$	(150	)	$	202
Non-cash investing and financing activities:
Accrued well costs as of period end	$	56,348		$	42,779		$	31,414		$	33,071
Assets acquired in exchange for common stock	—			—			50,265			60,221
Asset retirement obligations incurred with development activities	3,398			773			1,819			7,051
Asset retirement obligations assumed with acquisitions	24,696			2,230			—			—
Obligations discharged with asset retirements and divestitures	$	(14,332	)	$	(4,739	)	$	—		$	—
Net changes in operating assets and liabilities:
Accounts receivable	$	(72,518	)	$	(13,063	)	$	5,696		$	3,446
Accounts payable and accrued expenses	5,823			2,283			3,954			(2,307		)
Revenue payable	47,345			2,254			(5,441		)	4,557
Production taxes payable	33,311			(7,095		)	3,631			5,121
Other	(1,131		)	(790		)	(1,037		)	(359		)
Changes in operating assets and liabilities	$	12,830		$	(16,411	)	$	6,803		$	10,458

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Unaudited Oil and Gas Reserves Information

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Unaudited Oil and Gas Reserves Information

Unaudited Oil and Natural Gas Reserves Information

Oil and Natural Gas Reserve Information:  Proved reserves are the estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made).  Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Proved oil and natural gas reserve information as of the period ends presented and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott.  Reserve information for the properties was prepared in accordance with guidelines established by the SEC.

The reserve estimates prepared as of each of the period ends presented were prepared in accordance with applicable SEC rules.  Proved oil and natural gas reserves are calculated based on the prices for oil and natural gas during the twelve-month period before the determination date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can generally be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking.

The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented:

	Oil (MBbl)		Natural Gas (MMcf)		NGL (MBbl)		MBOE
Balance, August 31, 2014	16,324		95,179		—		32,188
Revision of previous estimates	(1,699	)	(4,889	)	—		(2,513	)
Purchase of reserves in place	4,201		21,957		—		7,860
Extensions, discoveries, and other additions	11,465		73,392		—		23,696
Sale of reserves in place	(629	)	(4,337	)	—		(1,352	)
Production	(1,970	)	(7,344	)	—		(3,194	)
Balance, August 31, 2015	27,692		173,958		—		56,685
Revision of previous estimates	(10,917	)	(38,931	)	—		(17,407	)
Purchase of reserves in place	4,380		58,959		—		14,207
Extensions, discoveries, and other additions	8,263		62,301		—		18,647
Sale of reserves in place	(2,297	)	(14,149	)	—		(4,655	)
Production	(742	)	(3,468	)	—		(1,320	)
Balance, December 31, 2015	26,379		238,670		—		66,157
Revision of previous estimates	(7,788	)	(80,549	)	—		(21,213	)
Purchase of reserves in place	23,141		197,103		—		55,991
Extensions, discoveries, and other additions	1,457		13,018		—		3,627
Sale of reserves in place	(2,900	)	(24,235	)	—		(6,939	)
Production	(2,257	)	(12,086	)	—		(4,271	)
Balance, December 31, 2016	38,032		331,921		—		93,352
Revision of previous estimates	(3,038	)	(66,413	)	28,689		14,581
Purchase of reserves in place	12,150		117,167		13,424		45,103
Extensions, discoveries, and other additions	28,736		206,644		24,358		87,535
Sale of reserves in place	(660	)	(4,592	)	—		(1,425	)
Production	(5,824	)	(24,834	)	(2,518	)	(12,481	)
Balance, December 31, 2017	69,396		559,893		63,953		226,665
Proved developed and undeveloped reserves:
Developed at August 31, 2015	7,393		46,026		—		15,064
Undeveloped at August 31, 2015	20,299		127,932		—		41,621
Balance, August 31, 2015	27,692		173,958		—		56,685
Developed at December 31, 2015	8,410		56,751		—		17,868
Undeveloped at December 31, 2015	17,969		181,919		—		48,289
Balance, December 31, 2015	26,379		238,670		—		66,157
Developed at December 31, 2016	7,435		62,570		—		17,863
Undeveloped at December 31, 2016	30,597		269,351		—		75,489
Balance, December 31, 2016	38,032		331,921		—		93,352
Developed at December 31, 2017	26,552		219,279		24,251		87,350
Undeveloped at December 31, 2017	42,844		340,614		39,702		139,315
Balance, December 31, 2017	69,396		559,893		63,953		226,665

Notable changes in proved reserves for the year ended December 31, 2017 included:

• Purchases of reserves in place. For the year ended December 31, 2017, purchases of reserves in place of 45,103 MBOE were primarily attributable to the acquisition of proved reserves in the GCII Acquisition. Please see Note 3 for further information.

• Revision of previous estimates. For the year ended December 31, 2017, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 14,581 MBOE primarily as a result of updated pricing as well as shifting from reporting reserves on a 2-stream to a 3-stream basis.

• Extensions and discoveries. For the year ended December 31, 2017, total extensions and discoveries of 87,535 MBOE were primarily attributable to extending our development plan by a year due to the passage of time, the addition of a third rig for the second and third years of our development plan, and the drilling and completion of wells not previously proved.

Notable changes in proved reserves for the year ended December 31, 2016 included:

• Purchases of reserves in place. For the year ended December 31, 2016, purchases of reserves in place of 55,991 MBOE were primarily attributable to the acquisition of proved reserves in the GC Acquisition. Please see Note 3 for further information.

• Revision of previous estimates. For the year ended December 31, 2016, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 21,213 MBOE primarily as a result of the GC Acquisition and related changes to our development plan that resulted in the removal of certain legacy PUD locations from the three-year drilling plan.

• Extensions and discoveries. For the year ended December 31, 2016, total extensions and discoveries of 3,627 MBOE were primarily attributable to successful drilling in the Wattenberg Field. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Notable changes in proved reserves for the four months ended December 31, 2015 included:

• Purchases of reserves in place. For the four months ended December 31, 2015, purchases of reserves in place of 14,207 MBOE were attributable to the acquisition of proved reserves. Please see Note3 for further information.

• Revision of previous estimates. For the four months ended December 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17,407 MBOE. As the Company continued to revise its drilling plans, the development plan was changed to remove undeveloped reserves that were not projected to be drilled in the subsequent three years and reflected the lower development costs anticipated from transitioning to a monobore wellbore design and longer horizontal wells; in addition, we high-graded our inventory of wells to be drilled.

• Extensions and discoveries. For the four months ended December 31, 2015, total extensions and discoveries of 18,647 MBOE were primarily attributable to successful drilling in the Wattenberg Field. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Notable changes in proved reserves for the year ended August 31, 2015 included:

• Purchases of reserves in place. For the year ended August 31, 2015, purchases of reserves in place of 7,860 MBOE were attributable to the acquisition of proved reserves.

• Revision of previous estimates. For the year ended August 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,513 MBOE. As the Company continued to revise its drilling plans toward horizontal drilling, the vertical proved undeveloped and vertical developed non-producing locations were removed from its development plan.

• Extensions and discoveries. For the year ended August 31, 2015, total extensions and discoveries of 23,696 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 67 vertical exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.

Standardized Measure of Discounted Future Net Cash Flows:  The following discussion relates to the standardized measure of future net cash flows from our proved reserves and changes therein related to estimated proved reserves.  Future oil and natural gas sales have been computed by applying average prices of oil and natural gas as discussed below.  Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the period based on period-end costs.  The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs.  Future income tax expenses were calculated by applying period-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities.  All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows.  Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves.  Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation.

The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands):

	As of December 31,									As of August 31, 2015
	2017			2016			2015
Future cash inflow	$	5,493,507		$	2,180,673		$	1,710,610		$	2,046,615
Future production costs	(1,291,369		)	(644,093		)	(462,097		)	(653,009		)
Future development costs	(1,048,856		)	(584,537		)	(340,449		)	(510,720		)
Future income tax expense	(285,349		)	(90,195		)	(108,172		)	(144,399		)
Future net cash flows	2,867,933			861,848			799,892			738,487
10% annual discount for estimated timing of cash flows	(1,267,258		)	(427,587		)	(408,939		)	(372,658		)
Standardized measure of discounted future net cash flows	$	1,600,675		$	434,261		$	390,953		$	365,829

There have been significant fluctuations in the posted prices of oil and natural gas during the last three years.  Prices actually received from purchasers of the Company’s oil and natural gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices.

The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:

	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2017 (Average)	$	46.57	$	2.21	$	16.06
December 31, 2016 (Average)	$	36.07	$	2.44	$	—
December 31, 2015 (Average)	$	41.33	$	2.60	$	—
August 31, 2015 (Average)	$	53.27	$	3.28	$	—

The prices for the December 31, 2017 oil and natural gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from January 1, 2017 through December 31, 2017. The December 31, 2017 oil price of $46.57 per barrel (West Texas Intermediate Cushing) was $10.50 higher than the December 31, 2016 oil price of $36.07 per barrel. The December 31, 2017 natural gas price of $2.21 per Mcf (Henry Hub) was $0.23 lower than the December 31, 2016 price of $2.44 per Mcf.

Changes in the Standardized Measure of Discounted Future Net Cash Flows:  The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Standardized measure, beginning of period	$	434,261		$	390,953		$	365,829		$	402,699
Sale and transfers, net of production costs	(306,754		)	(81,468		)	(25,222		)	(98,486		)
Net changes in prices and production costs	135,525			(64,387		)	(81,968		)	(233,051		)
Extensions, discoveries, and improved recovery	811,564			18,795			116,343			173,918
Changes in estimated future development costs	(25,969		)	(6,016		)	(7,195		)	10,002
Previously estimated development costs incurred during the period	170,296			62,502			5,923			4,957
Revision of quantity estimates	165,267			(110,306		)	(36,820		)	(38,340		)
Accretion of discount	47,635			44,703			14,610			57,629
Net change in income taxes	(113,523		)	5,104			25,263			58,547
Divestitures of reserves	(7,157		)	(26,839		)	(43,754		)	(19,234		)
Purchase of reserves in place	260,999			228,855			77,024			56,795
Changes in timing and other	28,531			(27,635		)	(19,080		)	(9,607		)
Standardized measure, end of period	$	1,600,675		$	434,261		$	390,953		$	365,829

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Unaudited Financial Data

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Unaudited Financial Data

Unaudited Financial Data

The Company’s unaudited quarterly financial information is as follows (in thousands, except share data):

	Year Ended December 31, 2017
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Revenues	$	43,790	$	75,036	$	103,593		$	140,097
Expenses	27,536		48,514		57,461			71,420
Operating income	16,254		26,522		46,132			68,677
Other income (expense)	3,626		1,414		(2,284		)	(17,958		)
Income before income taxes	19,880		27,936		43,848			50,719
Income tax benefit	—		—		—			(99		)
Net income	$	19,880	$	27,936	$	43,848		$	50,818
Net income per common share: (1)
Basic	$	0.10	$	0.14	$	0.22		$	0.23
Diluted (2)	$	0.10	$	0.14	$	0.22		$	0.23
Weighted-average shares outstanding:
Basic	200,707,891		200,831,063		200,881,447			222,072,930
Diluted	201,309,251		201,224,172		201,460,915			222,917,611

	Year Ended December 31, 2016
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	18,273		$	23,947		$	26,234		$	38,695
Expenses	71,356			172,157			45,887			29,324
Operating income (loss)	(53,083		)	(148,210		)	(19,653		)	9,371
Other income (expense)	1,682			(5,537		)	417			(4,070		)
Income (loss) before income taxes	(51,401		)	(153,747		)	(19,236		)	5,301
Income tax expense	—			101			5			—
Net income (loss)	$	(51,401	)	$	(153,848	)	$	(19,241	)	$	5,301
Net income (loss) per common share: (1)
Basic	$	(0.42	)	$	(0.89	)	$	(0.10	)	$	0.03
Diluted (2)	$	(0.42	)	$	(0.89	)	$	(0.10	)	$	0.03
Weighted-average shares outstanding:
Basic	121,392,736			172,013,551			200,515,555			200,585,800
Diluted	121,392,736			172,013,551			200,515,555			201,254,678

¹  The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

²  Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive.

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Organization and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation:  The Company operates in one business segment, and all of its operations are located in the United States of America.

At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc. When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

Change of Year-End

Change of Year-End:  On February 25, 2016, the Company's Board of Directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year.

Use of Estimates

Use of Estimates:The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents:  The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements.

Oil and Gas Properties

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is the impairment test prescribed by SEC regulations.  The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties.  The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During theyear ended December 31, 2017, the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company recognized ceiling test impairments of$215.2 million,$125.2 million, and$16.0 million, respectively.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials and are held constant for the productive life of each well.

Oil and Natural Gas Reserves

Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest

Capitalized Interest:The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 10 for additional information.

Capitalized Overhead

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information.

Other Property and Equipment

Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment, and software), office leasehold improvements, office furniture and equipment, and buildings are stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its other property and equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. 

Revenue Payable

Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received.

Asset Retirement Obligations

Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset.  Asset retirement costs ("ARCs") related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment.

Business Combinations

Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under FASB Accounting Standards Codification ("ASC") 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.

Goodwill

Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination.  Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31^st. During 2016, we changed the date of our annual goodwill impairment assessment to October 1^st. With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge.

When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit.  If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge.  The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill.  For purposes of assessing goodwill, the Company only has one reporting unit.

We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.

Oil and Natural Gas Sales

Oil, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests.  Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the product is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers

Major Customers:    The Company sells production to a small number of customers as is customary in the industry.

Lease Operating Expenses

Lease Operating Expenses:  Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities.

Stock-Based Compensation

Stock-Based Compensation:  The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model.  For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation.  The compensation is recognized over the vesting period of the grant. 

Income Tax

Income Tax:  Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions were identified as of any date on or before December 31, 2017.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of December 31, 2017, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Financial Instruments

Financial Instruments: Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Commodity Derivative Instruments

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative gain (loss) line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate.

Transportation Commitment Charge

Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements:

In November 2016, the FASB issued Accounting Standards Update ("ASU") 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. We adopted this pronouncement effective October 1, 2017 and have applied it retrospectively. Upon adoption, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2016. This change resulted in a decrease to net cash used in investing activities of $18.2 million. Additionally, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2017. This change resulted in an increase to net cash used in investing activities of $18.2 million. The adoption of this standard did not impact cash flows for the 4-months ended December 31, 2015 nor the year ended August 31, 2015. We have included a tabular reconciliation of cash, cash equivalents, and restricted cash in the discussion of "Cash Held in Escrow" above.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance did not impact the consolidated financial statements.

Recently Issued Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued various ASUs, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The Company will adopt these ASUs with an effective date of January 1, 2018, using the modified retrospective method. While we have not yet completed all aspects of the adoption of the standard, based on our current assessment of contracts with customers, we do not believe there will be any impact to the timing of our revenue recognition or our operating income (loss), net income (loss), and cash flows. The Company is in the process of evaluating changes, if any, to accounting policies and internal control procedures along with continuing to assess additional disclosures which may be required upon implementation of these ASUs.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

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Organization and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Cash and Cash Equivalents

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows:

	As of December 31,						As of August 31, 2015
	2017		2016		2015
Cash and cash equivalents	$	48,772	$	18,615	$	66,499	$	133,908
Restricted cash included in cash held in escrow and other deposits	—		18,219		—		—
	$	48,772	$	36,834	$	66,499	$	133,908

Restrictions on Cash and Cash Equivalents

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows:

	As of December 31,						As of August 31, 2015
	2017		2016		2015
Cash and cash equivalents	$	48,772	$	18,615	$	66,499	$	133,908
Restricted cash included in cash held in escrow and other deposits	—		18,219		—		—
	$	48,772	$	36,834	$	66,499	$	133,908

Schedule of Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):

	As of December 31,
	2017		2016
Trade accounts payable	$	624	$	786
Accrued well costs	56,348		42,779
Accrued G&A	6,017		4,292
Accrued LOE	5,249		3,140
Accrued interest	3,125		320
Accrued other	3,309		1,136
	74,672		52,453

Schedule of Customers With Balances Greater Than 10% of Total Receivables

The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue (“major customers”) for each of the periods presented are shown in the following table:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31, 2015
	2017	2016
Company A	33%	*	*	*
Company B	24%	20%	15%	11%
Company C	17%	20%	*	*
Company D	*	16%	*	*
Company E	*	13%	*	*
Company F	*	*	57%	65%
Company G	*	*	12%	*

* less than 10%

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):

	As of December 31,
	2017	2016
Company A	26%	23%
Company B	23%	*
Company C	16%	*
Company D	11%	43%
Company E	*	10%

* less than 10%

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Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Schedule of Capitalized Costs

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):

	As of December 31,
	2017			2016
Oil and gas properties, full cost method:
Costs of proved properties:
Producing and non-producing	$	1,629,789		$	969,239
Less, accumulated depletion and full cost ceiling impairments	(659,205		)	(545,157		)
Subtotal, proved properties, net	970,584			424,082
Costs of wells in progress	106,269			81,780
Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs	786,469			392,561
Land	7,200			5,986
Subtotal, unproved properties and land	793,669			398,547
Costs of other property and equipment:
Other property and equipment	8,134			5,063
Less, accumulated depreciation	(2,080		)	(736		)
Subtotal, other property and equipment, net	6,054			4,327
Total property and equipment, net	$	1,876,576		$	908,736

Schedule of Costs Incurred

Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Capitalized overhead	$	10,293	$	7,074	$	1,091	$	2,049

Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Acquisition of property:
Unproved	$	538,489	$	365,548	$	38,779	$	32,701
Proved	139,154		152,363		51,085		51,400
Exploration costs	—		43,154		23,697		146,892
Development costs	460,875		87,782		17,742		4,957
Other property and equipment, and land	4,397		7,506		395		741
Capitalized interest, capitalized G&A, and other	26,677		18,744		4,415		7,051
Total costs incurred	$	1,169,592	$	675,097	$	136,113	$	243,742

Schedule of Capitalized Costs Excluded from Amortization

The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2017 (in thousands):

	Period Incurred
	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31,				Total as of December 31, 2017
	2017		2016				2015		2014 and Prior
Unproved leasehold acquisition costs	$	537,470	$	223,907	$	23,068	$	456	$	1,568	$	786,469
Unproved development costs	26,056		—		—		—		—		26,056
Total unevaluated costs	$	563,526	$	223,907	$	23,068	$	456	$	1,568	$	812,525

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Acquisitions and Divestitures (Tables) - Greeley-Crescent Agreement

12 Months Ended

Dec. 31, 2017

Business Acquisition [Line Items]

Schedule of Fair Value of Acquisition

The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price	June 14, 2016
Consideration given:
Cash	$	485,141
Net liabilities assumed, including asset retirement obligations	1,273
Total consideration given	$	486,414
Allocation of Purchase Price(1)
Proved oil and gas properties	$	132,903
Unproved oil and gas properties	353,511
Total fair value of assets acquired	$	486,414

⁽¹⁾ Oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of11.5%, and assumptions regarding the timing and amount of future development and operating costs.

Schedule of Pro Forma Results

The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

(in thousands)	Year Ended December 31, 2016
Oil, natural gas, and NGL revenues	$	110,635
Net loss	$	(218,578	)
Net loss per common share
Basic	$	(1.10	)
Diluted	$	(1.10	)

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Depletion, depreciation and accretion ("DD&A") (Tables)

12 Months Ended

Dec. 31, 2017

Other Costs and Disclosures [Abstract]

Schedule of Depletion, Depreciation and Amortization

DD&A consisted of the following (in thousands):

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Depletion of oil and gas properties	$	109,287	$	45,193	$	18,371	$	65,158
Depreciation and accretion	3,022		1,485		405		711
Total DD&A Expense	$	112,309	$	46,678	$	18,776	$	65,869

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):

	Year Ended December 31,
	2017			2016
Beginning asset retirement obligation	$	16,458		$	13,400
Obligations incurred with development activities	3,398			773
Obligations assumed with acquisitions	24,696			2,230
Accretion expense	1,554			1,046
Obligations discharged with asset retirements and divestitures	(14,332		)	(4,739		)
Revisions in previous estimates	(152		)	3,748
Ending asset retirement obligation	$	31,622		$	16,458
Less, current portion	(3,246		)	(2,683		)
Non-current portion	$	28,376		$	13,775

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Commodity Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Commodity Derivative Contracts

The Company’s commodity derivative contracts as of December 31, 2017 are summarized below:

Settlement Period	Derivative Instrument	Average Volumes (Bbls per day)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	40.00	$	57.50
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	40.00	$	57.75
Jan 1, 2018 - Dec 31, 2018	Collar	500	$	40.00	$	57.50
Jan 1, 2018 - Dec 31, 2018	Collar	2,500	$	45.00	$	58.00
Jan 1, 2018 - Dec 31, 2018	Collar	2,500	$	45.00	$	64.55
Jan 1, 2018 - Dec 31, 2018	Collar	1,000	$	44.50	$	65.00
Jan 1, 2018 - Dec 31, 2018	Collar	1,500	$	44.50	$	65.00
Settlement Period	Derivative Instrument	Average Volumes (MMBtu per day)	Floor Price		Ceiling Price
Natural Gas - CIG Rocky Mountain
Jan 1, 2018 - Dec 31, 2018	Collar	10,000	$	2.25	$	2.82
Jan 1, 2018 - Dec 31, 2018	Collar	5,000	$	2.25	$	2.81

Subsequent to December 31, 2017, the Company added the following positions:

Settlement Period	Derivative Instrument	Average Volumes (Bbls per day)	Average Fixed Price
Propane - Mont Belvieu
Feb 1, 2018 - Dec 31, 2018	Swap	1,000	$	0.80

Schedule of Fair Value of Derivatives

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):

		As of December 31, 2017
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	1,960	$	(1,960	)	$	—
Commodity derivative contracts	Non-current assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	9,825	$	(1,960	)	$	7,865
Commodity derivative contracts	Non-current liabilities	$	—	$	—		$	—

		As of December 31, 2016
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	2,045	$	(1,748	)	$	297
Commodity derivative contracts	Non-current assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	4,622	$	(1,748	)	$	2,874
Commodity derivative contracts	Non-current liabilities	$	—	$	—		$	—

Schedule of Loss Recognized in Statements of Operations

The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017			2016
Realized gain (loss) on commodity derivatives	$	39		$	2,355		$	1,577	$	30,466
Unrealized gain (loss) on commodity derivatives	(4,265		)	(10,105		)	4,905		1,790
Total gain (loss)	$	(4,226	)	$	(7,750	)	$	6,482	$	32,256

Schedule of Hedge Realized Gains (Losses)

The following table summarizes derivative realized gains and losses during the periods presented (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Monthly settlement	$	1,062		$	4,396		$	2,331		$	11,212
Previously incurred premiums attributable to settled commodity contracts	(1,023		)	(2,041		)	(754		)	(1,255		)
Early liquidation	—			—			—			20,509
Total realized gain (loss)	$	39		$	2,355		$	1,577		$	30,466

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured on a Recurring Basis

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at December 31, 2017
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	—	$	—	$	—
Commodity derivative liability	$	—	$	7,865	$	—	$	7,865

	Fair Value Measurements at December 31, 2016
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	297	$	—	$	297
Commodity derivative liability	$	—	$	2,874	$	—	$	2,874

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Interest Expense (Tables)

12 Months Ended

Dec. 31, 2017

Interest and Debt Expense [Abstract]

Schedule of the Components of Interest Expense

The components of interest expense are (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Revolving credit facility	$	2,004		$	154		$	661		$	2,776
Notes payable	10,036			3,940			—			—
Amortization of debt issuance costs	3,084			1,638			431			853
Debt extinguishment costs	11,842			—			—			—
Less: interest capitalized	(15,124		)	(5,732		)	(1,092		)	(3,384		)
Interest expense, net	$	11,842		$	—		$	—		$	245

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Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Note [Abstract]

Schedule of Classes of Stock

The Company's classes of stock are summarized as follows:

	As of December 31,
	2017		2016
Preferred stock, shares authorized	10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized	300,000,000		300,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding	241,365,522		200,647,572

Schedule of Common Stock Sold in Public Offering

A summary of the transactions is shown in the following table.  Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions, and expenses of the offering.

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Number of common shares sold	40,250,000		90,275,000		—		18,613,952
Offering price per common share	$	7.76	$	6.02	$	—	$	10.75
Net proceeds (in thousands)	$	312,170	$	543,400	$	—	$	190,845

Schedule of Common Stock Issued For Acquisition of Mineral Interests and Services

The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.

	Year Ended December 31,				Four Months Ended December 31, 2015		Year Ended August 31, 2015
	2017		2016
Number of common shares issued for mineral property leases	—		—		37,051		995,672
Number of common shares issued for acquisitions	—		—		4,418,413		4,648,136
Total common shares issued	—		—		4,455,464		5,643,808
Average price per common share	$	—	$	—	$	11.28	$	10.67
Aggregate value of shares issues (in thousands)	$	—	$	—	$	50,265	$	60,221

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Weighted-Average Shares Outstanding (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Reconciliation of Weighted-average Shares Outstanding Basic and Diluted

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31,2015
	2017	2016
Weighted-average shares outstanding - basic	206,167,506	173,774,035	107,789,554	94,628,665
Potentially dilutive common shares from:
Stock options	417,809	—	—	672,493
Restricted stock units and stock bonus shares	158,236	—	—	18,111
Weighted-average shares outstanding - diluted	206,743,551	173,774,035	107,789,554	95,319,269

Schedule of Potentially Dilutive Securities

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share:

	Year Ended December 31,		Four Months Ended December 31, 2015	Year Ended August 31, 2015
	2017	2016
Potentially dilutive common shares from:
Stock options	4,657,834	6,001,500	5,056,000	2,785,500
Performance-vested stock units1	951,884	478,510	—	—
Restricted stock units and stock bonus shares	285,448	890,336	915,867	145,000
Total	5,895,166	7,370,346	5,971,867	2,930,500

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Stock-based Compensation Expense Recognized

he amount of stock-based compensation was as follows (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Stock options	$	5,076		$	5,417		$	2,161		$	4,741
Performance-vested stock units	2,938			1,047			—			—
Restricted stock units and stock bonus shares	4,977			4,232			7,162			2,950
Total stock-based compensation	12,991			10,696			9,323			7,691
Less: stock-based compensation capitalized	(1,766		)	(1,205		)	(892		)	(778		)
Total stock-based compensation expense	$	11,225		$	9,491		$	8,431		$	6,913

Schedule of Employee Stock Options Granted During the Period

No stock options were granted during the year ended December 31, 2017. During the periods presented, the Company granted the following stock options:

	Year Ended December 31, 2016		Four Months Ended December 31, 2015		Year Ended August 31, 2015
Number of options to purchase common shares	1,067,500		1,142,500		2,377,500
Weighted-average exercise price	$	7.19	$	10.84	$	11.55
Term (in years)	10 years		10 years		10 years
Vesting Period (in years)	3 - 5 years		3.7-5 years		3-5 years
Fair Value (in thousands)	$	3,860	$	6,591	$	13,266

Schedule of Assumptions Used In Valuing Stock Options

The assumptions used in valuing the PSUs granted were as follows:

	Year Ended December 31,
	2017		2016
Weighted-average expected term	2.9 years		2.7 years
Weighted-average expected volatility	59	%	58	%
Weighted-average risk-free rate	1.34	%	0.87	%

The assumptions used in valuing stock options granted during each of the periods presented were as follows:

	Year Ended December 31, 2016		Four Months Ended December 31, 2015		Year Ended August 31, 2015
Expected term	6.4 years		6.5 years		6.5 years
Expected volatility	55	%	53	%	47	%
Risk-free rate	1.25 - 2.00%		1.8 - 2.0%		1.4 - 2.0%
Expected dividend yield	—	%	—	%	—	%

Summary of Stock Option Activity Under Stock Option

The following table summarizes activity for stock options for the periods presented:

	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, August 31, 2014	2,167,000		$	5.94	8.0 years	$	16,287
Granted	2,377,500		11.55
Exercised	(258,000	)	3.81			2,103
Forfeited	(110,000	)	4.97
Outstanding, August 31, 2015	4,176,500		9.29		8.6 years	8,187
Granted	1,142,500		10.84
Exercised	(188,000	)	6.56			981
Expired	(60,000	)	11.74
Forfeited	(15,000	)	11.68
Outstanding, December 31, 2015	5,056,000		9.71		8.7 years	4,351
Granted	1,067,500		7.19
Exercised	(20,000	)	3.19			117
Expired	—		—
Forfeited	(102,000	)	10.40
Outstanding, December 31, 2016	6,001,500		9.27		8.0 years	6,515
Granted	—		—
Exercised	(187,666	)	3.95			976
Expired	(41,000	)	11.98
Forfeited	(136,000	)	10.97
Outstanding, December 31, 2017	5,636,834		$	9.38	7.0 years	$	4,806
Outstanding, Exercisable at December 31, 2017	3,203,045		$	9.08	6.5 years	$	3,587

Schedule of Issued and Outstanding Stock Options

The following table summarizes information about issued and outstanding stock options as of December 31, 2017:

	Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life
Under $5.00	454,000	$	3.45	3.5 years	454,000	$	3.45	3.5 years
$5.00 - $6.99	1,012,000	6.38		6.9 years	558,400	6.45		5.8 years
$7.00 - $10.99	1,548,834	9.36		7.4 years	708,245	9.53		7.0 years
$11.00 - $13.46	2,622,000	11.58		7.4 years	1,482,400	11.59		7.4 years
Total	5,636,834	$	9.38	7.0 years	3,203,045	$	9.08	6.5 years

Schedule of Unrecognized Compensation Cost

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2017, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	7,113
Remaining vesting period	2.2 years

The estimated unrecognized compensation cost from stock options not vested as of December 31, 2017, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	9,697
Remaining vesting period	2.3 years

Summary of Restricted Stock Awards

The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented:

	Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, August 31, 2014	293,333		$	10.60
Granted	547,699		11.17
Vested	(208,532	)	11.09
Forfeited	—		—
Not vested, August 31, 2015	632,500		10.93
Granted	919,604		10.08
Vested	(636,237	)	10.13
Forfeited	—		—
Not vested, December 31, 2015	915,867		10.63
Granted	464,533		7.66
Vested	(424,483	)	9.92
Forfeited	(65,581	)	8.99
Not vested, December 31, 2016	890,336		9.55
Granted	681,568		8.29
Vested	(455,772	)	9.21
Forfeited	(28,746	)	9.74
Not vested, December 31, 2017	1,087,386		$	8.89

Schedule of Nonvested Share Activity

A summary of the status and activity of PSUs is presented in the following table:

	Number of Units1		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2015	—		$	—
Granted	490,713		8.10
Vested	—		—
Forfeited	(12,203	)	8.22
Not vested, December 31, 2016	478,510		8.09
Granted	473,374		10.79
Vested	—		—
Forfeited	—		—
Not vested, December 31, 2017	951,884		$	9.44

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Components of Income Taxes

The income tax provision is comprised of the following (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Current:
Federal	$	(99	)	$	106		$	—		$	(4	)
State	—			—			—			(111		)
Total current income tax expense (benefit)	(99		)	106			—			(115		)
Deferred:
Federal	48,631			(74,099		)	(45,332		)	10,820
State	4,371			(6,651		)	(4,074		)	972
Total deferred income tax (benefit) expense	53,002			(80,750		)	(49,406		)	11,792
Valuation allowance	(53,002		)	80,750			39,399			—
Income tax expense (benefit)	$	(99	)	$	106		$	(10,007	)	$	11,677

Schedule of Reconciliation of Income Taxes

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Federal income tax at statutory rate	$	48,410		$	(74,489	)	$	(45,200	)	$	10,105
State income taxes, net of federal tax	4,371			(6,685		)	(4,062		)	908
Statutory depletion	(159		)	(287		)	(150		)	(451		)
Stock-based compensation	50			383			—			92
Non-deductible compensation	—			—			—			850
Impact of tax reform, net of valuation allowance	(99		)
Valuation allowance	(53,002		)	80,750			39,399			—
Other	330			434			6			173
Income tax expense (benefit)	$	(99	)	$	106		$	(10,007	)	$	11,677
Effective rate expressed as a percentage	—		%	—		%	8		%	39		%

Schedule of Deferred Tax Assets and Liabilities

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):

	As of December 31,
	2017			2016
Deferred tax assets (liabilities):
Net operating loss carryforward	$	43,283		$	47,462
Stock-based compensation	5,237			5,576
Basis of oil and gas properties	(5,011		)	62,707
Statutory depletion	2,795			4,028
Unrealized loss on commodity derivative	1,939			1,334
Other	(615		)	(958		)
	47,628			120,149
Valuation allowance on tax assets	(47,628		)	(120,149		)
Deferred tax asset (liability), net	$	—		$	—

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Other Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Contractual Commitment Over the Next Five Years

Our commitments over the next five years, excluding the contingent commitment described below, are as follows:

Year ending December 31,	Oil (MBbls)
2018	4,485
2019	5,167
2020	4,003
2021	1,672
2022	—
Thereafter	—
Total	15,327

Operating Leases of Lessee Disclosure

A schedule of the minimum lease payments under non-cancelable capital and operating leases as of December 31, 2017 follows (in thousands):

Year ending December 31:	Vehicles Leases			Office Leases
2018	$	76		$	840
2019	37			859
2020	37			878
2021	63			875
2022	—			477
Thereafter	—			—
Total minimum lease payments	$	213		$	3,929
Less: Amount representing estimated executory cost	(16		)
Net minimum lease payments	197
Less: Amount representing interest	(24		)
Present value of net minimum lease payments *	$	173

^* Reflected in the balance sheet as current and non-current obligations of $63 thousand and $110 thousand, respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively.

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Supplemental Schedule of Information to the Statements of Cash Flows (Tables)

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of Supplemental Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
Supplemental cash flow information:	2017			2016
Interest paid	$	9,235		$	3,779		$	683		$	2,817
Income taxes paid	$	—		$	106		$	(150	)	$	202
Non-cash investing and financing activities:
Accrued well costs as of period end	$	56,348		$	42,779		$	31,414		$	33,071
Assets acquired in exchange for common stock	—			—			50,265			60,221
Asset retirement obligations incurred with development activities	3,398			773			1,819			7,051
Asset retirement obligations assumed with acquisitions	24,696			2,230			—			—
Obligations discharged with asset retirements and divestitures	$	(14,332	)	$	(4,739	)	$	—		$	—
Net changes in operating assets and liabilities:
Accounts receivable	$	(72,518	)	$	(13,063	)	$	5,696		$	3,446
Accounts payable and accrued expenses	5,823			2,283			3,954			(2,307		)
Revenue payable	47,345			2,254			(5,441		)	4,557
Production taxes payable	33,311			(7,095		)	3,631			5,121
Other	(1,131		)	(790		)	(1,037		)	(359		)
Changes in operating assets and liabilities	$	12,830		$	(16,411	)	$	6,803		$	10,458

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Unaudited Oil and Gas Reserves Information (Tables)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year

The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented:

	Oil (MBbl)		Natural Gas (MMcf)		NGL (MBbl)		MBOE
Balance, August 31, 2014	16,324		95,179		—		32,188
Revision of previous estimates	(1,699	)	(4,889	)	—		(2,513	)
Purchase of reserves in place	4,201		21,957		—		7,860
Extensions, discoveries, and other additions	11,465		73,392		—		23,696
Sale of reserves in place	(629	)	(4,337	)	—		(1,352	)
Production	(1,970	)	(7,344	)	—		(3,194	)
Balance, August 31, 2015	27,692		173,958		—		56,685
Revision of previous estimates	(10,917	)	(38,931	)	—		(17,407	)
Purchase of reserves in place	4,380		58,959		—		14,207
Extensions, discoveries, and other additions	8,263		62,301		—		18,647
Sale of reserves in place	(2,297	)	(14,149	)	—		(4,655	)
Production	(742	)	(3,468	)	—		(1,320	)
Balance, December 31, 2015	26,379		238,670		—		66,157
Revision of previous estimates	(7,788	)	(80,549	)	—		(21,213	)
Purchase of reserves in place	23,141		197,103		—		55,991
Extensions, discoveries, and other additions	1,457		13,018		—		3,627
Sale of reserves in place	(2,900	)	(24,235	)	—		(6,939	)
Production	(2,257	)	(12,086	)	—		(4,271	)
Balance, December 31, 2016	38,032		331,921		—		93,352
Revision of previous estimates	(3,038	)	(66,413	)	28,689		14,581
Purchase of reserves in place	12,150		117,167		13,424		45,103
Extensions, discoveries, and other additions	28,736		206,644		24,358		87,535
Sale of reserves in place	(660	)	(4,592	)	—		(1,425	)
Production	(5,824	)	(24,834	)	(2,518	)	(12,481	)
Balance, December 31, 2017	69,396		559,893		63,953		226,665
Proved developed and undeveloped reserves:
Developed at August 31, 2015	7,393		46,026		—		15,064
Undeveloped at August 31, 2015	20,299		127,932		—		41,621
Balance, August 31, 2015	27,692		173,958		—		56,685
Developed at December 31, 2015	8,410		56,751		—		17,868
Undeveloped at December 31, 2015	17,969		181,919		—		48,289
Balance, December 31, 2015	26,379		238,670		—		66,157
Developed at December 31, 2016	7,435		62,570		—		17,863
Undeveloped at December 31, 2016	30,597		269,351		—		75,489
Balance, December 31, 2016	38,032		331,921		—		93,352
Developed at December 31, 2017	26,552		219,279		24,251		87,350
Undeveloped at December 31, 2017	42,844		340,614		39,702		139,315
Balance, December 31, 2017	69,396		559,893		63,953		226,665

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands):

	As of December 31,									As of August 31, 2015
	2017			2016			2015
Future cash inflow	$	5,493,507		$	2,180,673		$	1,710,610		$	2,046,615
Future production costs	(1,291,369		)	(644,093		)	(462,097		)	(653,009		)
Future development costs	(1,048,856		)	(584,537		)	(340,449		)	(510,720		)
Future income tax expense	(285,349		)	(90,195		)	(108,172		)	(144,399		)
Future net cash flows	2,867,933			861,848			799,892			738,487
10% annual discount for estimated timing of cash flows	(1,267,258		)	(427,587		)	(408,939		)	(372,658		)
Standardized measure of discounted future net cash flows	$	1,600,675		$	434,261		$	390,953		$	365,829

Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves

The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:

	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2017 (Average)	$	46.57	$	2.21	$	16.06
December 31, 2016 (Average)	$	36.07	$	2.44	$	—
December 31, 2015 (Average)	$	41.33	$	2.60	$	—
August 31, 2015 (Average)	$	53.27	$	3.28	$	—

Schedule of Changes in the Standardized Measure for Discounted Cash Flows

The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Year Ended December 31,						Four Months Ended December 31, 2015			Year Ended August 31, 2015
	2017			2016
Standardized measure, beginning of period	$	434,261		$	390,953		$	365,829		$	402,699
Sale and transfers, net of production costs	(306,754		)	(81,468		)	(25,222		)	(98,486		)
Net changes in prices and production costs	135,525			(64,387		)	(81,968		)	(233,051		)
Extensions, discoveries, and improved recovery	811,564			18,795			116,343			173,918
Changes in estimated future development costs	(25,969		)	(6,016		)	(7,195		)	10,002
Previously estimated development costs incurred during the period	170,296			62,502			5,923			4,957
Revision of quantity estimates	165,267			(110,306		)	(36,820		)	(38,340		)
Accretion of discount	47,635			44,703			14,610			57,629
Net change in income taxes	(113,523		)	5,104			25,263			58,547
Divestitures of reserves	(7,157		)	(26,839		)	(43,754		)	(19,234		)
Purchase of reserves in place	260,999			228,855			77,024			56,795
Changes in timing and other	28,531			(27,635		)	(19,080		)	(9,607		)
Standardized measure, end of period	$	1,600,675		$	434,261		$	390,953		$	365,829

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Unaudited Financial Data (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Schedule of Unaudited Quarterly Financial Data

The Company’s unaudited quarterly financial information is as follows (in thousands, except share data):

	Year Ended December 31, 2017
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter
Revenues	$	43,790	$	75,036	$	103,593		$	140,097
Expenses	27,536		48,514		57,461			71,420
Operating income	16,254		26,522		46,132			68,677
Other income (expense)	3,626		1,414		(2,284		)	(17,958		)
Income before income taxes	19,880		27,936		43,848			50,719
Income tax benefit	—		—		—			(99		)
Net income	$	19,880	$	27,936	$	43,848		$	50,818
Net income per common share: (1)
Basic	$	0.10	$	0.14	$	0.22		$	0.23
Diluted (2)	$	0.10	$	0.14	$	0.22		$	0.23
Weighted-average shares outstanding:
Basic	200,707,891		200,831,063		200,881,447			222,072,930
Diluted	201,309,251		201,224,172		201,460,915			222,917,611

	Year Ended December 31, 2016
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	18,273		$	23,947		$	26,234		$	38,695
Expenses	71,356			172,157			45,887			29,324
Operating income (loss)	(53,083		)	(148,210		)	(19,653		)	9,371
Other income (expense)	1,682			(5,537		)	417			(4,070		)
Income (loss) before income taxes	(51,401		)	(153,747		)	(19,236		)	5,301
Income tax expense	—			101			5			—
Net income (loss)	$	(51,401	)	$	(153,848	)	$	(19,241	)	$	5,301
Net income (loss) per common share: (1)
Basic	$	(0.42	)	$	(0.89	)	$	(0.10	)	$	0.03
Diluted (2)	$	(0.42	)	$	(0.89	)	$	(0.10	)	$	0.03
Weighted-average shares outstanding:
Basic	121,392,736			172,013,551			200,515,555			200,585,800
Diluted	121,392,736			172,013,551			200,515,555			201,254,678

¹  The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.

²  Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive.

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Organization and Summary of Significant Accounting Policies (Details) $ in Thousands	4 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2015 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($) segment	Dec. 31, 2016 USD ($)	Aug. 31, 2015 USD ($)	Jan. 01, 2017 USD ($)	Jun. 14, 2016	Aug. 31, 2014 USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments | segment			1
Cash and cash equivalents	$ 66,499		$ 48,772	$ 18,615	$ 133,908
Restricted cash included in cash held in escrow and other deposits	0		0	18,219	0
Cash, cash equivalents, restricted cash and cash held in escrow and other deposits	66,499		$ 48,772	36,834	$ 133,908			$ 34,753
Net cash flows, discount rate (percent)			10.00%		10.00%
Remittance period			30 days
Cash held in escrow			$ (18,200)	(18,200)
Accounts Payable, Current [Abstract]
Trade accounts payable			624	786
Accrued well costs			56,348	42,779
Accrued G&A			6,017	4,292
Accrued LOE			5,249	3,140
Accrued interest			3,125	320
Accrued other			3,309	1,136
Accounts payable and accrued expenses			74,672	52,453
Concentration Risk [Line Items]
Cash held in escrow and other deposits			0	18,248
Net cash used in investing activities	(84,937)		(1,040,306)	(617,916)	$ (269,569)
Full cost ceiling impairment	$ 125,230		0	215,223	$ 16,000
Accounting Standards Update 2016-18
Concentration Risk [Line Items]
Net cash used in investing activities		$ 18,200		$ (18,200)
Accumulated Earnings (Deficit)
Concentration Risk [Line Items]
Adoption of ASU 2016-09			$ (102)
Accumulated Earnings (Deficit) | Accounting Standards Update 2016-09
Concentration Risk [Line Items]
Adoption of ASU 2016-09						$ 100
Customer concentration risk | Oil and Gas revenues | Company A
Concentration Risk [Line Items]
Risk percentage			33.00%
Customer concentration risk | Oil and Gas revenues | Company B
Concentration Risk [Line Items]
Risk percentage	15.00%		24.00%	20.00%	11.00%
Customer concentration risk | Oil and Gas revenues | Company C
Concentration Risk [Line Items]
Risk percentage			17.00%	20.00%
Customer concentration risk | Oil and Gas revenues | Company D
Concentration Risk [Line Items]
Risk percentage				16.00%
Customer concentration risk | Oil and Gas revenues | Company E
Concentration Risk [Line Items]
Risk percentage	13.00%
Customer concentration risk | Oil and Gas revenues | Company F
Concentration Risk [Line Items]
Risk percentage	57.00%				65.00%
Customer concentration risk | Oil and Gas revenues | Company G
Concentration Risk [Line Items]
Risk percentage	12.00%
Customer concentration risk | Accounts receivable | Company A
Concentration Risk [Line Items]
Risk percentage			26.00%	23.00%
Customer concentration risk | Accounts receivable | Company B
Concentration Risk [Line Items]
Risk percentage			23.00%
Customer concentration risk | Accounts receivable | Company C
Concentration Risk [Line Items]
Risk percentage			16.00%
Customer concentration risk | Accounts receivable | Company D
Concentration Risk [Line Items]
Risk percentage			11.00%	43.00%
Customer concentration risk | Accounts receivable | Company E
Concentration Risk [Line Items]
Risk percentage				10.00%
D-J Basin, Colorado | Greeley-Crescent Agreement
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net cash flows, discount rate (percent)							11.50%
Concentration Risk [Line Items]
Cash held in escrow and other deposits		$ 18,200		$ 18,200

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Property and Equipment (Schedule of Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Costs of proved properties:
Producing and non-producing	$ 1,629,789	$ 969,239
Less, accumulated depletion and full cost ceiling impairments	(659,205)	(545,157)
Subtotal, proved properties, net	970,584	424,082
Costs of wells in progress	106,269	81,780
Costs of unproved properties and land, not subject to depletion:
Unproved properties and land	793,669	398,547
Costs of other property and equipment:
Other property and equipment	8,134	5,063
Less, accumulated depreciation	(2,080)	(736)
Subtotal, other property and equipment, net	6,054	4,327
Total property and equipment, net	1,876,576	908,736
Unproved leasehold acquisition costs
Costs of unproved properties and land, not subject to depletion:
Unproved properties and land	786,469	392,561
Unproved development costs | Land
Costs of unproved properties and land, not subject to depletion:
Unproved properties and land	$ 7,200	$ 5,986

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Property and Equipment (Narrative) (Details) - USD ($)	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Reserve Quantities [Line Items]
Full cost ceiling impairment	$ 125,230,000	$ 0	$ 215,223,000	$ 16,000,000
Unproved properties impairment	125,230,000	0	215,223,000	16,000,000
Unproved properties
Reserve Quantities [Line Items]
Unproved properties impairment	$ 0	$ 0	$ 18,900,000	$ 15,400,000

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Property and Equipment (Schedule of Capitalized Overhead) (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Property, Plant and Equipment [Abstract]
Capitalized overhead	$ 1,091	$ 10,293	$ 7,074	$ 2,049

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Property and Equipment (Schedule of Costs Incurred) (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Acquisition of property:
Unproved	$ 38,779	$ 538,489	$ 365,548	$ 32,701
Proved	51,085	139,154	152,363	51,400
Exploration costs	23,697	0	43,154	146,892
Development costs	17,742	460,875	87,782	4,957
Other property and equipment, and land	395	4,397	7,506	741
Capitalized interest, capitalized G&A, and other	4,415	26,677	18,744	7,051
Total costs Incurred	$ 136,113	$ 1,169,592	$ 675,097	$ 243,742

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Property and Equipment (Schedule of Capitalized Costs Excluded from Amortization) (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015	Aug. 31, 2014
Property, Plant and Equipment [Line Items]
Total unevaluated costs	$ 23,068	$ 563,526	$ 223,907	$ 456	$ 1,568
Unevaluated costs, not subject to amortization		812,525
Unproved leasehold acquisition costs
Property, Plant and Equipment [Line Items]
Total unevaluated costs	23,068	537,470	223,907	456	1,568
Unevaluated costs, not subject to amortization		786,469
Unproved development costs
Property, Plant and Equipment [Line Items]
Total unevaluated costs	$ 0	26,056	$ 0	$ 0	$ 0
Unevaluated costs, not subject to amortization		$ 26,056

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Acquisitions and Divestitures (Narrative) (Details) $ in Thousands						1 Months Ended					3 Months Ended	4 Months Ended	12 Months Ended
	Nov. 01, 2017 USD ($)	Sep. 30, 2017 USD ($) well	Jun. 14, 2016 USD ($) a bbl / d	May 02, 2016 USD ($) a	Feb. 04, 2016 USD ($)	Nov. 30, 2017 USD ($) a bbl / d	Aug. 31, 2017 USD ($) a	Mar. 31, 2017 USD ($)	Oct. 31, 2016 USD ($)	Apr. 30, 2016 USD ($) a Boe well	Oct. 31, 2016 acquisition	Dec. 31, 2015 USD ($) Boe	Dec. 31, 2017 USD ($) a Boe	Dec. 31, 2016 USD ($) Boe	Aug. 31, 2015 USD ($) Boe
Business Acquisition [Line Items]
Mineral acres, net | a						30,200
Cash held in escrow and other deposits													$ 0	$ 18,248
Proceeds from sales of oil and gas properties and other												$ 0	$ 93,573	$ 25,350	$ 6,239
Production of BOE (in Boe's) | Boe												1,320,000	12,481,000	4,271,000	3,194,000
Disposal Group, disposed of by sale, not discontinued operations
Business Acquisition [Line Items]
Mineral acres, net | a													16,000
Proceeds from sales of oil and gas properties and other													$ 91,600
Assumption of liabilities													22,200
Asset retirement obligations													5,200
Disposal Group, disposed of by sale, not discontinued operations | Adams County, Colorado
Business Acquisition [Line Items]
Mineral acres, net | a										3,700
Number of vertical wells | well										107
Cash held in escrow and other deposits										$ 500
Proceeds from sales of oil and gas properties and other										$ 24,700
Production of BOE (in Boe's) | Boe										200
Greeley-Crescent Agreement II | D-J Basin, Colorado
Business Acquisition [Line Items]
Total purchase price	$ 569,500					$ 568,000
Production of barrels of oil equivalent per day | bbl / d						2,500
Cash	568,100
Series of individually immaterial business acquisitions
Business Acquisition [Line Items]
Total purchase price					$ 10,000			$ 25,100	$ 13,500
Acquisitions of certain assets | acquisition											4
Proved oil and gas properties					8,600
Unproved oil and gas properties					$ 1,400
Greeley-Crescent Agreement | Wattenberg Field
Business Acquisition [Line Items]
Mineral acres, net | a				33,100
Total purchase price				$ 505,000
Mineral acres, gross | a				72,000
Greeley-Crescent Agreement | D-J Basin, Colorado
Business Acquisition [Line Items]
Mineral acres, net | a			33,100
Total purchase price		$ 30,300	$ 486,414
Production of barrels of oil equivalent per day | bbl / d			800
Cash		$ 6,300	$ 485,141
Number of vertical wells | well		335
Number of horizontal wells | well		7
Cash held in escrow and other deposits		$ 18,200												$ 18,200
Escrow balance returned to company		11,400
Assumed liabilities		24,000
Assumed asset retirement obligations		$ 20,900
Transaction costs			500
Proved oil and gas properties			132,903
Unproved oil and gas properties			$ 353,511
Pro forma revenue since acquisition date													5,400
Pro forma net income since acquisition date													$ 4,700
Private party August 2017
Business Acquisition [Line Items]
Total purchase price							$ 22,600
Acres expected to be traded | a							3,200
Mineral acres, gross | a							1,000
Proved oil and gas properties | Greeley-Crescent Agreement II | D-J Basin, Colorado
Business Acquisition [Line Items]
Total purchase price	59,900
Proved oil and gas properties | Series of individually immaterial business acquisitions
Business Acquisition [Line Items]
Total purchase price								15,300
Proved oil and gas properties | Private party August 2017
Business Acquisition [Line Items]
Total purchase price							$ 6,700
Unproved properties | Greeley-Crescent Agreement II | D-J Basin, Colorado
Business Acquisition [Line Items]
Total purchase price	$ 509,600
Unproved properties | Series of individually immaterial business acquisitions
Business Acquisition [Line Items]
Total purchase price								9,400
Unproved properties | Private party August 2017
Business Acquisition [Line Items]
Total purchase price							$ 15,900
Other assets and land | Series of individually immaterial business acquisitions
Business Acquisition [Line Items]
Total purchase price								$ 400

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Acquisitions and Divestitures (Schedule of Fair Value of Acquisition) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Jun. 14, 2016	Dec. 31, 2017	Aug. 31, 2015
Business Acquisition [Line Items]
Net cash flows, discount rate (percent)			10.00%	10.00%
D-J Basin, Colorado | Greeley-Crescent Agreement
Business Acquisition [Line Items]
Cash	$ 6,300	$ 485,141
Net liabilities assumed, including asset retirement obligations		1,273
Total consideration given	$ 30,300	486,414
Proved oil and gas properties		132,903
Unproved oil and gas properties		353,511
Total fair value of assets acquired		$ 486,414
Net cash flows, discount rate (percent)		11.50%

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Acquisitions and Divestitures (Schedule of Pro Forma Results) (Details) - D-J Basin, Colorado - Greeley-Crescent Agreement $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) $ / shares
Business Acquisition [Line Items]
Oil and gas revenues | $	$ 110,635
Net income | $	$ (218,578)
Net (loss) income per common share
Basic (in dollars per share) | $ / shares	$ (1.10)
Diluted (in dollars per share) | $ / shares	$ (1.10)

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Depletion, depreciation and accretion ("DD&A") (Details) Boe in Thousands, $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015 USD ($) Boe $ / Boe	Dec. 31, 2017 USD ($) Boe $ / Boe	Dec. 31, 2016 USD ($) Boe $ / Boe	Aug. 31, 2015 USD ($) Boe $ / Boe
Other Costs and Disclosures [Abstract]
Depletion of oil and gas properties	$ 18,371	$ 109,287	$ 45,193	$ 65,158
Depreciation and accretion	405	3,022	1,485	711
Total DDA Expense	$ 18,776	$ 112,309	$ 46,678	$ 65,869
Production of BOE (in Boe's) | Boe	1,320	12,481	4,271	3,194
Percentage of total reserves	2.00%	5.20%	4.40%	5.30%
DDA expense per BOE (in dollars per BOE) | $ / Boe	14.22	9.00	10.93	20.62

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Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligation	$ 16,458	$ 13,400
Obligations incurred with development activities	3,398	773
Obligations assumed with acquisitions	24,696	2,230
Accretion expense	1,554	1,046
Obligations discharged with asset retirements and divestitures	(14,332)	(4,739)
Revisions in previous estimates	(152)	3,748
Ending asset retirement obligation	31,622	16,458
Less, current portion	(3,246)	(2,683)
Non-current portion	$ 28,376	$ 13,775

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Revolving Credit Facility (Details)	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 01, 2017 USD ($)
Line of Credit Facility [Line Items]
Amount outstanding	$ 0	$ 0
Line of credit | Revolving credit facility
Line of Credit Facility [Line Items]
Total borrowing commitment	500,000,000
Borrowing base	400,000,000		$ 225,000,000
Amount outstanding	$ 0	$ 0
Average interest rate	3.40%	2.60%
Term of covenants	5 years
Maximum funded debt to EBITDAX	4.0
Current ratio covenant		1.0
Line of credit | Letter of credit
Line of Credit Facility [Line Items]
Amount outstanding	$ 500,000

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Notes Payable (Details) - USD ($)		1 Months Ended		3 Months Ended	4 Months Ended	12 Months Ended
	Jun. 14, 2016	Dec. 31, 2017	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015	Nov. 30, 2017
Debt Instrument [Line Items]
Payments of Debt Issuance Costs					$ 0	$ 13,145,000	$ 5,159,000	$ 2,316,000
Senior notes | Six Point Two Five Percent Senior Notes Due 2025 [Member]
Debt Instrument [Line Items]
Face value of promissory note									$ 550,000,000
Debt instrument stated interest rate (percent)									6.25%
Debt instrument effective interest rate (percent)									6.60%
Senior notes | 9% Senior notes due 2021
Debt Instrument [Line Items]
Face value of promissory note	$ 80,000,000	$ 80,000,000		$ 80,000,000		80,000,000
Debt instrument stated interest rate (percent)	9.00%
Proceeds from sale of Senior Notes	$ 75,200,000		$ 538,100,000
Payments of Debt Issuance Costs			$ 11,900,000
Redemption price (percent)				100.00%
Debt issuance costs	$ 4,800,000
Required makewhole payment		8,200,000		$ 8,200,000		$ 8,200,000
Write off of deferred debt issuance cost		$ 3,600,000
Senior notes | 9% Senior notes due 2021 | 2020
Debt Instrument [Line Items]
Redemption price (percent)				104.688%
Senior notes | 9% Senior notes due 2021 | 2021
Debt Instrument [Line Items]
Redemption price (percent)				103.125%
Senior notes | 9% Senior notes due 2021 | 2022
Debt Instrument [Line Items]
Redemption price (percent)				101.563%
Senior notes | 9% Senior notes due 2021 | 2023
Debt Instrument [Line Items]
Redemption price (percent)				100.00%
Senior notes | 9% Senior notes due 2021 | Prior to December 1, 2020
Debt Instrument [Line Items]
Redemption price (percent)				106.25%
Amount of principal that can be redeemed (percent)				35.00%

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Commodity Derivative Instruments (Schedule of Commodity Derivative Contracts) (Details)	2 Months Ended	12 Months Ended
	Feb. 21, 2018 bbl / d $ / bbl	Dec. 31, 2017 MMBTU / d bbl / d $ / bbl $ / MMBTU
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d		1,000
Floor Price		40
Ceiling Price		57.50
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d		1,000
Floor Price		40
Ceiling Price		57.75
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d		500
Floor Price		40
Ceiling Price		57.50
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d		2,500
Floor Price		45
Ceiling Price		58
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d		2,500
Floor Price		45
Ceiling Price		64.55
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d		1,000
Floor Price		44.50
Ceiling Price		65
Crude Oil | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d		1,500
Floor Price		44.50
Ceiling Price		65
Natural Gas | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volumes (MMBtu per day) | MMBTU / d		10,000
Floor Price | $ / MMBTU		2.25
Ceiling Price | $ / MMBTU		2.82
Natural Gas | Jan 1, 2018 - Dec 31, 2018 | Collar
Derivatives, Fair Value [Line Items]
Average Volumes (MMBtu per day) | MMBTU / d		5,000
Floor Price | $ / MMBTU		2.25
Ceiling Price | $ / MMBTU		2.81
Subsequent event | Propane | Feb 1, 2018 - Dec 31, 2018 | Swap
Derivatives, Fair Value [Line Items]
Average Volume (BBl's per day) | bbl / d	1,000
Average fixed price (in dollars per gallon)	0.8

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Commodity Derivative Instruments (Schedule of Fair Value of Derivatives) (Details) - Commodity derivative contracts - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets
Derivatives, Fair Value [Line Items]
Derivative asset, Gross Amount Recognized	$ 1,960	$ 2,045
Derivative asset, Gross Amounts Offset in the Balance Sheet	(1,960)	(1,748)
Derivative asset, Net	0	297
Non-current assets
Derivatives, Fair Value [Line Items]
Derivative asset, Gross Amount Recognized	0	0
Derivative asset, Gross Amounts Offset in the Balance Sheet	0	0
Derivative asset, Net	0	0
Current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, Gross Amount Recognized	9,825	4,622
Derivative liability, Gross Amounts Offset in the Balance Sheet	(1,960)	(1,748)
Derivative liability, Net	7,865	2,874
Non-current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, Gross Amount Recognized	0	0
Derivative liability, Gross Amounts Offset in the Balance Sheet	0	0
Derivative liability, Net	$ 0	$ 0

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Commodity Derivative Instruments (Schedule of Gain (Loss) Recognized in Statements of Operations) (Details) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Aug. 31, 2015 USD ($) $ / bbl bbl
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Realized gain (loss) on commodity derivatives	$ 1,577	$ 39	$ 2,355	$ 30,466
Unrealized gain (loss) on commodity derivatives	4,905	(4,265)	(10,105)	1,790
Total gain (loss)	$ 6,482	$ (4,226)	$ (7,750)	$ 32,256
Average price of liquidated swaps (in dollars per share) | $ / bbl				82.79
Number of barrels liquidated (in bbl) | bbl				372,500
Early liquidation				$ 20,500

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Commodity Derivative Instruments (Schedule of Hedge Realized Gains (Losses)) (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Monthly settlement	$ 2,331	$ 1,062	$ 4,396	$ 11,212
Previously incurred premiums attributable to settled commodity contracts	(754)	(1,023)	(2,041)	(1,255)
Early liquidation	0	0	0	20,509
Total realized gain (loss)	$ 1,577	$ 39	$ 2,355	$ 30,466

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Commodity Derivative Instruments (Narrative) (Details)	Dec. 31, 2017 counterparty
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of counterparties	6
Credit facility syndicate
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of counterparties	3

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Level 2 | Estimate of Fair Value Measurement
Financial Liabilities:
Notes payable	$ 564,100
Recurring
Financial Assets:
Commodity derivative asset	0	$ 297
Financial Liabilities:
Commodity derivative liability	7,865	2,874
Recurring | Level 1
Financial Assets:
Commodity derivative asset	0	0
Financial Liabilities:
Commodity derivative liability	0	0
Recurring | Level 2
Financial Assets:
Commodity derivative asset	0	297
Financial Liabilities:
Commodity derivative liability	7,865	2,874
Recurring | Level 3
Financial Assets:
Commodity derivative asset	0	0
Financial Liabilities:
Commodity derivative liability	$ 0	$ 0

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Interest Expense (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Debt Instrument [Line Items]
Amortization of debt issuance costs	$ 431	$ 3,084	$ 1,638	$ 853
Debt extinguishment costs	0	11,842	0	0
Less: interest capitalized	(1,092)	(15,124)	(5,732)	(3,384)
Interest expense, net	0	11,842	0	245
Revolving credit facility | Revolving credit facility
Debt Instrument [Line Items]
Interest from debt	661	2,004	154	2,776
Notes payable
Debt Instrument [Line Items]
Interest from debt	$ 0	$ 10,036	$ 3,940	$ 0

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Shareholders' Equity (Common Stock Transactions) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	4 Months Ended	12 Months Ended
	Nov. 30, 2017	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Classes of stock
Preferred stock, shares authorized			10,000,000	10,000,000
Preferred stock, par value (in dollars per share)			$ 0.01	$ 0.01
Preferred stock, shares issued			0	0
Preferred stock, shares outstanding				0
Common stock, shares authorized			300,000,000	300,000,000
Common stock, par value (in dollars per share)			$ 0.001	$ 0.001
Common stock, shares issued			241,365,522	200,647,572
Common stock, shares outstanding			241,365,522	200,647,572
Sale of common stock
Number of common shares sold (in shares)	35,000,000	0	40,250,000	90,275,000	18,613,952
Offering price per common share (in dollars per share)		$ 0		$ 6.0193852119	$ 10.75
Net proceeds		$ 0	$ 312,170	$ 543,400	$ 190,845
Common stock issued for acquisition of mineral interests
Number of common shares issued for mineral property leases (in shares)		37,051.000	0	0	995,672
Business acquisition, shares issued (in shares)		4,418,413.000	0	0	4,648,136
Number of common shares sold (in shares)		4,455,464	0	0	5,643,808
Average price per common share (in dollars per share)		$ 11.28	$ 0.00	$ 0.00	$ 10.67
Aggregate value of shares issued		$ 50,265	$ 0	$ 0	$ 60,221
IPO
Sale of common stock
Offering price per common share (in dollars per share)			$ 7.76
Over-Allotment option
Sale of common stock
Number of common shares sold (in shares)	5,250,000
Over-allotment option, exercise period	30 days

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Weighted-Average Shares Outstanding (Details) - shares	3 Months Ended								4 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted-average shares outstanding - basic (in shares)	222,072,930	200,881,447	200,831,063	200,707,891	200,585,800	200,515,555	172,013,551	121,392,736	107,789,554	206,167,506	173,774,035	94,628,665
Potentially dilutive common shares from:
Stock options (in shares)									0	417,809	0	672,493
Restricted stock units and stock bonus shares (in shares)									0	158,236		18,111
Performance-vested stock units (in shares)											0
Weighted-average shares outstanding - diluted (in shares)	222,917,611	201,460,915	201,224,172	201,309,251	201,254,678	200,515,555	172,013,551	121,392,736	107,789,554	206,743,551	173,774,035	95,319,269
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares)									5,971,867	5,895,166	7,370,346	2,930,500
Stock options
Potentially dilutive common shares from:
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares)									5,056,000	4,657,834	6,001,500	2,785,500
Performance stock units
Potentially dilutive common shares from:
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares)									0	285,448	890,336	0
Restricted stock units and stock bonus shares
Potentially dilutive common shares from:
Potentially dilutive common shares having anti-dilutive effect on earnings per share (in shares)									915,867	951,884	478,510	145,000

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Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	4 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining vesting phase			2 years 3 months 29 days
Unrecognized compensation expense			$ 9,697
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years 8 months 12 days		3 years	3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		5 years		5 years	5 years
2015 Equity Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized			4,500,000
Number of shares available for grant			110,158
Number of shares reserved for future vestings			951,884
Stock bonus plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized					2,000,000
Restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining vesting phase			2 years 2 months 29 days
Granted (shares)		919,604	681,568	464,533	547,699
Unrecognized compensation expense			$ 7,113
Restricted stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Restricted stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			5 years
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Granted (shares)			473,374	490,713
Fair value of stock granted			$ 5,100	$ 4,000
Unrecognized compensation expense			$ 5,000
Performance stock units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier (percent)	0.00%
Performance stock units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier (percent)	200.00%

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Stock-Based Compensation (Stock Based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation	$ 12,991	$ 10,696
Less: stock-based compensation capitalized	(1,766)	(1,205)
Total stock-based compensation expense	11,225	9,491
Stock options
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation	5,076	5,417
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation	2,938	1,047
Restricted stock units and stock bonus shares
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation	$ 4,977	$ 4,232

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Stock-Based Compensation (Non-Qualified Stock Options Granted) (Details) - USD ($) $ / shares in Units, $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of options to purchase common shares	1,142,500	0	1,067,500	2,377,500
Weighted-average exercise price (in dollars per share)	$ 10.84	$ 0.00	$ 7.19	$ 11.55
Term	10 years		10 years	10 years
Fair Value	$ 6,591		$ 3,860	$ 13,266
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years 8 months 12 days		3 years	3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	5 years		5 years	5 years

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Stock-Based Compensation (Stock Option Assumptions) (Details)	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term	6 years 6 months		6 years 4 months 23 days	6 years 6 months
Expected volatility (percent)	53.00%		55.00%	47.00%
Risk-free rate, minimum (percent)	1.80%	0.00%	1.25%	1.40%
Risk-free rate, maximum (percent)	2.00%	0.00%	2.00%	2.00%
Expected dividend yield (percent)	0.00%		0.00%	0.00%
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term		2 years 10 months 7 days	2 years 8 months 12 days
Expected volatility (percent)		59.00%	58.00%
Weighted-average risk free rate (percent)		1.34%	0.87%

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Stock-Based Compensation (Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015	Aug. 31, 2014
Summary of activity for stock options (in shares):
Outstanding, Beginning balance (shares)	4,176,500	6,001,500	5,056,000	2,167,000
Granted (shares)	1,142,500	0	1,067,500	2,377,500
Exercised (shares)	(188,000)	(187,666)	(20,000)	(258,000)
Forfeited (shares)	(15,000)	(136,000)	(102,000)	(110,000)
Expired (shares)	(60,000)	(41,000)	0
Outstanding, Ending balance (shares)	5,056,000	5,636,834	6,001,500	4,176,500	2,167,000
Outstanding, Exercisable at end of period (shares)		3,203,045
Weighted Average Exercise Price (in dollars per share):
Beginning balance, Weighted average exercise price (in dollars per share)	$ 9.29	$ 9.27	$ 9.71	$ 5.94
Granted, weighted average exercise price (in dollars per share)	10.84	0.00	7.19	11.55
Exercised, weighted average exercise price (in dollars per share)	6.56	3.95	3.19	3.81
Forfeited, weighted average exercise price (in dollars per share)	11.68	10.97	10.40	4.97
Expired, weighted average exercise price (in dollars per share)	11.74	11.98	0.00
Ending balance, Weighted average exercise price (in dollars per share)	$ 9.71	9.38	$ 9.27	$ 9.29	$ 5.94
Outstanding, exercisable, weighted average exercise price (in dollars per share)		$ 9.08
Weighted-Average Remaining Contractual Life
Weighted average remaining contractual life	8 years 7 months 25 days	7 years 4 days	8 years	8 years 7 months 6 days	8 years
Outstanding, Exercisable		6 years 5 months 23 days
Aggregate Intrinsic Value:
Beginning balance, aggregate intrinsic value	$ 4,351	$ 4,806	$ 6,515	$ 8,187	$ 16,287
Exercised, aggregate intrinsic value	981	976	117	2,103
Ending balance, aggregate intrinsic value	$ 4,351	4,806	$ 6,515	$ 8,187	$ 16,287
Outstanding, Exercisable at end of period		$ 3,587

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Stock-Based Compensation (Issued and Outstanding Option Details) (Details) - $ / shares	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015	Aug. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding options (in shares)		5,636,834
Weighted average exercise price (in dollars per share)	$ 9.71	$ 9.38	$ 9.27	$ 9.29	$ 5.94
Weighted-Average Remaining Contractual Life, Outstanding Options	8 years 7 months 25 days	7 years 4 days	8 years	8 years 7 months 6 days	8 years
Exercisable options (in shares)		3,203,045
Exercisable options, weighted average exercise price (in dollars per share)		$ 9.08
Weighted-Average Remaining Contractual Life, Exercisable Options		6 years 5 months 23 days
Under $5.00
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price range maximum (in dollars per share)		$ 5.00
Outstanding options (in shares)		454,000
Weighted average exercise price (in dollars per share)		$ 3.45
Weighted-Average Remaining Contractual Life, Outstanding Options		3 years 6 months 7 days
Exercisable options (in shares)		454,000
Exercisable options, weighted average exercise price (in dollars per share)		$ 3.45
Weighted-Average Remaining Contractual Life, Exercisable Options		3 years 6 months 7 days
$5.00 - $6.99
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price range minimum (in dollars per share)		$ 5.00
Exercise price range maximum (in dollars per share)		$ 6.99
Outstanding options (in shares)		1,012,000
Weighted average exercise price (in dollars per share)		$ 6.38
Weighted-Average Remaining Contractual Life, Outstanding Options		6 years 11 months 1 day
Exercisable options (in shares)		558,400
Exercisable options, weighted average exercise price (in dollars per share)		$ 6.45
Weighted-Average Remaining Contractual Life, Exercisable Options		5 years 9 months 15 days
$7.00 - $10.99
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price range minimum (in dollars per share)		$ 7.00
Exercise price range maximum (in dollars per share)		$ 10.99
Outstanding options (in shares)		1,548,834
Weighted average exercise price (in dollars per share)		$ 9.36
Weighted-Average Remaining Contractual Life, Outstanding Options		7 years 5 months 1 day
Exercisable options (in shares)		708,245
Exercisable options, weighted average exercise price (in dollars per share)		$ 9.53
Weighted-Average Remaining Contractual Life, Exercisable Options		7 years 4 days
$11.00 - $13.46
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price range minimum (in dollars per share)		$ 11.00
Exercise price range maximum (in dollars per share)		$ 13.46
Outstanding options (in shares)		2,622,000
Weighted average exercise price (in dollars per share)		$ 11.58
Weighted-Average Remaining Contractual Life, Outstanding Options		7 years 4 months 28 days
Exercisable options (in shares)		1,482,400
Exercisable options, weighted average exercise price (in dollars per share)		$ 11.59
Weighted-Average Remaining Contractual Life, Exercisable Options		7 years 4 months 21 days

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Stock-Based Compensation (Restricted Stock and Performance-vested Stock Units Activity) (Details) - $ / shares	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Restricted stock
Number of Shares
Nonvested, Beginning balance (shares)	632,500	890,336	915,867	293,333
Granted (shares)	919,604	681,568	464,533	547,699
Vested (shares)	(636,237)	(455,772)	(424,483)	(208,532)
Forfeited (shares)	0	(28,746)	(65,581)	0
Nonvested, Ending balance (shares)	915,867	1,087,386	890,336	632,500
Weighted Average Grant Date Fair Value (in dollars per share)
Nonvested, beginning balance (in dollars per share)	$ 10.93	$ 9.55	$ 10.63	$ 10.60
Granted (in dollars per share)	10.08	8.29	7.66	11.17
Vested (in dollars per share)	10.13	9.21	9.92	11.09
Forfeited (in dollars per share)	0.00	9.74	8.99	0.00
Nonvested, ending balance (in dollars per share)	$ 10.63	$ 8.89	$ 9.55	$ 10.93
Performance stock units
Number of Shares
Nonvested, Beginning balance (shares)		478,510	0
Granted (shares)		473,374	490,713
Vested (shares)		0	0
Forfeited (shares)		0	(12,203)
Nonvested, Ending balance (shares)	0	951,884	478,510
Weighted Average Grant Date Fair Value (in dollars per share)
Nonvested, beginning balance (in dollars per share)		$ 8.09	$ 0.00
Granted (in dollars per share)		10.79	8.10
Vested (in dollars per share)		0.00	0.00
Forfeited (in dollars per share)		0.00	8.22
Nonvested, ending balance (in dollars per share)	$ 0.00	$ 9.44	$ 8.09

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Defined Contribution Plan (Details) - USD ($) $ in Millions		4 Months Ended	12 Months Ended
	Jan. 01, 2017	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Retirement Benefits [Abstract]
Employer matching contribution percent of employees' gross pay	100.00%
Percent of employer matching contribution	6.00%
Contribution cost recognized		$ 0.1	$ 0.7	$ 0.4	$ 0.1

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Income Taxes (Schedule of Components of Income Taxes) (Details) - USD ($) $ in Thousands	3 Months Ended								4 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Current:
Federal									$ 0	$ (99)	$ 106	$ (4)
State									0	0	0	(111)
Total current income tax expense (benefit)									0	(99)	106	(115)
Deferred:
Federal									(45,332)	48,631	(74,099)	10,820
State									(4,074)	4,371	(6,651)	972
Total deferred income tax (benefit) expense									(49,406)	53,002	(80,750)	11,792
Valuation allowance									39,399	(53,002)	80,750	0
Income tax expense (benefit)	$ (99)	$ 0	$ 0	$ 0	$ 0	$ 5	$ 101	$ 0	$ (10,007)	$ (99)	$ 106	$ 11,677

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Income Taxes (Schedule of Reconciliation of Income Taxes) (Details) - USD ($) $ in Thousands	3 Months Ended								4 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Income Tax Disclosure [Abstract]
Federal income tax at statutory rate									$ (45,200)	$ 48,410	$ (74,489)	$ 10,105
State income taxes, net of federal tax									(4,062)	4,371	(6,685)	908
Statutory depletion									(150)	(159)	(287)	(451)
Stock-based compensation									0	50	383	92
Non-deductible compensation									0	0	0	850
Impact of tax reform, net of valuation allowance										(99)
Valuation allowance									39,399	(53,002)	80,750	0
Other									6	330	434	173
Income tax expense (benefit)	$ (99)	$ 0	$ 0	$ 0	$ 0	$ 5	$ 101	$ 0	$ (10,007)	$ (99)	$ 106	$ 11,677
Effective rate expressed as a percentage									8.00%	0.00%	0.00%	39.00%

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Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Net operating loss carryforward	$ 43,283	$ 47,462
Stock-based compensation	5,237	5,576
Basis of oil and gas properties	(5,011)
Basis of oil and gas properties		62,707
Statutory depletion	2,795	4,028
Unrealized loss on commodity derivative	1,939	1,334
Other	(615)	(958)
Deferred tax assets, gross	47,628	120,149
Valuation allowance on tax assets	(47,628)	(120,149)
Deferred tax asset (liability), net	$ 0	$ 0

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Income Taxes (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Operating Loss Carryforwards [Line Items]
Deferred tax assets expense (benefit)	$ 24.0
Decrease in AMT deferred tax assets	0.1
Domestic tax authority
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	175.5
Valuation Allowance | Accounting Standard Update 2016-09
Operating Loss Carryforwards [Line Items]
Deferred tax assets expense (benefit)	(4.5)
NOL | Accounting Standard Update 2016-09
Operating Loss Carryforwards [Line Items]
Deferred tax assets expense (benefit)	$ (4.5)

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Other Commitments and Contingencies (Narrative) (Details)	1 Months Ended		4 Months Ended	12 Months Ended
	Sep. 30, 2016	Jul. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) counterparty	Dec. 31, 2017 USD ($) MMcfe	Dec. 31, 2016 USD ($)	Aug. 31, 2015 USD ($) counterparty
Long-term Purchase Commitment [Line Items]
Transport agreement number of counterparties | counterparty			2			3
Unused commitment charge | $			$ 2,802,000	$ 669,000	$ 597,000	$ 0
Rent expense | $			$ 300,000	$ 1,100,000	$ 1,000,000	$ 300,000
Agreement One
Long-term Purchase Commitment [Line Items]
Processing plant capacity (in MMcfe) | MMcfe				200
Share of the commitment (in MMcfe) | MMcfe				46.4
Commitment term				7 years
Agreement Two
Long-term Purchase Commitment [Line Items]
Processing plant capacity (in MMcfe) | MMcfe				200
Share of the commitment (in MMcfe) | MMcfe				43.8
Commitment term				7 years
Denver
Long-term Purchase Commitment [Line Items]
Lease term	65 months
Monthly rent expense | $				$ 62,000
Greeley, Colorado
Long-term Purchase Commitment [Line Items]
Monthly rent expense | $		$ 7,500

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Other Commitments and Contingencies (Volume Commitments) (Details) bbl / yr in Thousands	Dec. 31, 2017 bbl / yr
Commitments and Contingencies Disclosure [Abstract]
2018	4,485
2019	5,167
2020	4,003
2021	1,672
2022	0
Thereafter	0
Total	15,327

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Other Commitments and Contingencies (Minimum Lease Payments Under Non-Cancelable Operating Leases) (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Vehicles Leases
Operating Leased Assets [Line Items]
Capital lease, 2018	$ 76
Capital lease, 2019	37
Capital lease, 2020	37
Capital lease 2021	63
Capital lease 2022	0
Capital lease, thereafter	0
Total minimum capital lease payments	213
Less: Amount representing estimated executory cost	(16)
Net minimum lease payments	197
Less: Amount representing interest	(24)
Present value of net minimum lease payments	173
Vehicles Leases | Accounts payable and accrued expenses
Operating Leased Assets [Line Items]
Present value of net minimum lease payments	63
Vehicles Leases | Other liabilities
Operating Leased Assets [Line Items]
Present value of net minimum lease payments	110
Office Leases
Operating Leased Assets [Line Items]
Operating lease, 2018	840
Operating lease, 2019	859
Operating lease, 2020	878
Operating lease, 2021	875
Operating lease, 2022	477
Operating lease, thereafter	0
Total minimum operating lease payments	$ 3,929

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Supplemental Schedule of Information to the Statements of Cash Flows (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Supplemental cash flow information:
Interest paid	$ 683	$ 9,235	$ 3,779	$ 2,817
Income taxes paid	(150)	0	106	202
Non-cash investing and financing activities:
Accrued well costs as of period end	31,414	56,348	42,779	33,071
Assets acquired in exchange for common stock	50,265	0	0	60,221
Asset retirement obligations incurred with development activities	1,819	3,398	773	7,051
Asset retirement obligations assumed with acquisitions	0	24,696	2,230	0
Obligations discharged with asset retirements and divestitures	0	(14,332)	(4,739)	0
Net changes in operating assets and liabilities:
Accounts receivable	5,696	(72,518)	(13,063)	3,446
Accounts payable and accrued expenses	3,954	5,823	2,283	(2,307)
Revenue payable	(5,441)	47,345	2,254	4,557
Production taxes payable	3,631	33,311	(7,095)	5,121
Other	(1,037)	(1,131)	(790)	(359)
Changes in operating assets and liabilities	$ 6,803	$ 12,830	$ (16,411)	$ 10,458

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Unaudited Oil and Gas Reserves Information (Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year) (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015 Boe Mcf bbl	Dec. 31, 2017 Boe Mcf bbl	Dec. 31, 2016 Boe Mcf bbl	Aug. 31, 2015 Boe Mcf bbl
Oil (MBbl)
Proved developed and undeveloped reserves:
Beginning Balance	27,692	38,032	26,379	16,324
Revision of previous estimates	(10,917)	(3,038)	(7,788)	(1,699)
Purchase of reserves in place	4,380	12,150	23,141	4,201
Extensions, discoveries, and other additions	8,263	28,736	1,457	11,465
Sale of reserves in place	(2,297)	(660)	(2,900)	(629)
Production	(742)	(5,824)	(2,257)	(1,970)
Ending Balance	26,379	69,396	38,032	27,692
Proved developed reserves:
Proved developed reserves	8,410	26,552	7,435	7,393
Proved undeveloped reserves:
Proved undeveloped reserves	17,969	42,844	30,597	20,299
Natural Gas (MMcf)
Proved developed and undeveloped reserves:
Beginning Balance | Mcf	173,958	331,921	238,670	95,179
Revision of previous estimates | Mcf	(38,931)	(66,413)	(80,549)	(4,889)
Purchase of reserves in place | Mcf	58,959	117,167	197,103	21,957
Extensions, discoveries, and other additions | Mcf	62,301	206,644	13,018	73,392
Sale of reserves in place | Mcf	(14,149)	(4,592)	(24,235)	(4,337)
Production | Mcf	(3,468)	(24,834)	(12,086)	(7,344)
Ending Balance | Mcf	238,670	559,893	331,921	173,958
Proved developed reserves:
Proved developed reserves | Mcf	56,751	219,279	62,570	46,026
Proved undeveloped reserves:
Proved undeveloped reserves | Mcf	181,919	340,614	269,351	127,932
NGL (MBbl)
Proved developed and undeveloped reserves:
Beginning Balance	0	0	0	0
Revision of previous estimates	0	28,689	0	0
Purchase of reserves in place	0	13,424	0	0
Extensions, discoveries, and other additions	0	24,358	0	0
Sale of reserves in place	0	0	0	0
Production	0	(2,518)	0	0
Ending Balance	0	63,953	0	0
Proved developed reserves:
Proved developed reserves	0	24,251	0	0
Proved undeveloped reserves:
Proved undeveloped reserves	0	39,702	0	0
MBOE
Proved developed and undeveloped reserves:
Balance (Boe) | Boe	56,685	93,352	66,157	32,188
Revisions of previous estimates (Boe) | Boe	(17,407)	14,581	(21,213)	(2,513)
Purchase of reserves in place (Boe) | Boe	14,207	45,103	55,991	7,860
Extensions, discoveries, and other additions (Boe) | Boe	18,647	87,535	3,627	23,696
Sales of reserves in place (Boe) | Boe	(4,655)	(1,425)	(6,939)	(1,352)
Production (Boe) | Boe	(1,320)	(12,481)	(4,271)	(3,194)
Balance (Boe) | Boe	66,157	226,665	93,352	56,685
Proved developed reserves:
Proved developed reserves (Boe) | Boe	17,868	87,350	17,863	15,064
Proved undeveloped reserves:
Proved undeveloped reserves (Boe) | Boe	48,289	139,315	75,489	41,621

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Unaudited Oil and Gas Reserves Information (Narrative) (Details) Boe in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015 Boe $ / bbl $ / Mcf	Dec. 31, 2017 Boe $ / bbl $ / Mcf	Dec. 31, 2016 Boe $ / bbl $ / Mcf	Aug. 31, 2015 Boe well $ / bbl $ / Mcf
Reserve Quantities [Line Items]
Exploratory wells | well				67
Net cash flows, discount rate (percent)		10.00%		10.00%
MBOE
Reserve Quantities [Line Items]
Purchase of reserves in place (Boe)	14,207	45,103	55,991	7,860
Revisions of previous estimates (Boe)	(17,407)	14,581	(21,213)	(2,513)
Extensions, discoveries, and other additions (Boe)	18,647	87,535	3,627	23,696
Oil (MBbl)
Reserve Quantities [Line Items]
Price per unit used to prepare reserve estimates, based upon average prices | $ / bbl	41.33	46.57	36.07	53.27
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / bbl		10.50
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf	2.60	2.21	2.44	3.28
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf		(0.23)
Wattenberg Field | MBOE
Reserve Quantities [Line Items]
Extensions, discoveries, and other additions (Boe)				23,696

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Unaudited Oil and Gas Reserves Information (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2015	Aug. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 5,493,507	$ 2,180,673	$ 1,710,610	$ 2,046,615
Future production costs	(1,291,369)	(644,093)	(462,097)	(653,009)
Future development costs	(1,048,856)	(584,537)	(340,449)	(510,720)
Future income tax expense	(285,349)	(90,195)	(108,172)	(144,399)
Future net cash flows	2,867,933	861,848	799,892	738,487
10% annual discount for estimated timing of cash flows	(1,267,258)	(427,587)	(408,939)	(372,658)
Standardized measure of discounted future net cash flows	$ 1,600,675	$ 434,261	$ 390,953	$ 365,829	$ 402,699

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Unaudited Oil and Gas Reserves Information (Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves) (Details)	Dec. 31, 2017 $ / bbl $ / Mcf	Dec. 31, 2016 $ / bbl $ / Mcf	Dec. 31, 2015 $ / bbl $ / Mcf	Aug. 31, 2015 $ / bbl $ / Mcf
Oil (MBbl)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price per unit used to prepare reserve estimates, based upon average prices	46.57	36.07	41.33	53.27
Natural Gas (MMcf)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf	2.21	2.44	2.60	3.28
NGL (MBbl)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price per unit used to prepare reserve estimates, based upon average prices	16.06	0.00	0.00	0.00

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Unaudited Oil and Gas Reserves Information (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning of year	$ 365,829	$ 434,261	$ 390,953	$ 402,699
Sale and transfers, net of production costs	(25,222)	(306,754)	(81,468)	(98,486)
Net changes in prices and production costs	(81,968)	135,525	(64,387)	(233,051)
Extensions, discoveries, and improved recovery	116,343	811,564	18,795	173,918
Changes in estimated future development costs	(7,195)	(25,969)	(6,016)	10,002
Development costs incurred during the period	5,923	170,296	62,502	4,957
Revision of quantity estimates	(36,820)	165,267	(110,306)	(38,340)
Accretion of discount	14,610	47,635	44,703	57,629
Net change in income taxes	25,263	(113,523)	5,104	58,547
Divestitures of reserves	(43,754)	(7,157)	(26,839)	(19,234)
Purchase of reserves in place	77,024	260,999	228,855	56,795
Changes in timing and other	(19,080)	28,531	(27,635)	(9,607)
Standardized measure, end of year	$ 390,953	$ 1,600,675	$ 434,261	$ 365,829

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Unaudited Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								4 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 140,097	$ 103,593	$ 75,036	$ 43,790	$ 38,695	$ 26,234	$ 23,947	$ 18,273
Expenses	71,420	57,461	48,514	27,536	29,324	45,887	172,157	71,356	$ 173,599	$ 204,931	$ 318,724	$ 127,221
Operating income (loss)	68,677	46,132	26,522	16,254	9,371	(19,653)	(148,210)	(53,083)	(139,461)	157,585	(211,575)	(2,378)
Other income (expense)	(17,958)	(2,284)	1,414	3,626	(4,070)	417	(5,537)	1,682	6,522	(15,202)	(7,508)	32,097
Income (Loss) before income taxes	50,719	43,848	27,936	19,880	5,301	(19,236)	(153,747)	(51,401)	(132,939)	142,383	(219,083)	29,719
Income tax expense (benefit)	(99)	0	0	0	0	5	101	0	(10,007)	(99)	106	11,677
Net income (loss)	$ 50,818	$ 43,848	$ 27,936	$ 19,880	$ 5,301	$ (19,241)	$ (153,848)	$ (51,401)	$ (122,932)	$ 142,482	$ (219,189)	$ 18,042
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.23	$ 0.22	$ 0.14	$ 0.10	$ 0.03	$ (0.10)	$ (0.89)	$ (0.42)	$ (1.14)	$ 0.69	$ (1.26)	$ 0.19
Diluted (in dollars per share)	$ 0.23	$ 0.22	$ 0.14	$ 0.10	$ 0.03	$ (0.10)	$ (0.89)	$ (0.42)	$ (1.14)	$ 0.69	$ (1.26)	$ 0.19
Weighted-average shares outstanding:
Basic (in shares)	222,072,930	200,881,447	200,831,063	200,707,891	200,585,800	200,515,555	172,013,551	121,392,736	107,789,554	206,167,506	173,774,035	94,628,665
Diluted (in shares)	222,917,611	201,460,915	201,224,172	201,309,251	201,254,678	200,515,555	172,013,551	121,392,736	107,789,554	206,743,551	173,774,035	95,319,269