UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~June~~September 30, 2017



	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

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 Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such filing). Yes ý No o

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: ~~200,873,103~~201,089,000 outstanding shares of common stock as of ~~July~~October 31, 2017.

SRC ENERGY INC.

Index



		Page
Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Condensed Consolidated Balance Sheets as of ~~June~~September 30, 2017 and December 31, 2016	2

	Condensed Consolidated Statements of Operations for the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016	3

	Condensed Consolidated Statements of Cash Flows for the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2324

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4041

Item 4.	Controls and Procedures	4142

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings	4243

Item 1A.	Risk Factors	4243

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4243

Item 3.	Defaults of Senior Securities	4243

Item 4.	Mine Safety Disclosures	4243

Item 5.	Other Information	4243

Item 6.	Exhibits	4344

SIGNATURES		4445

SRC ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands, except share data)


ASSETS	June 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Current assets:
Cash and cash equivalents	$	36,677		$	18,615		$	21,325		$	18,615
Accounts receivable:
Oil, natural gas, and NGL sales	37,727			25,728			72,309			25,728
Trade	28,630			6,805			45,280			6,805
Commodity derivative assets	1,579			297			—			297
Other current assets	4,075			2,739			6,289			2,739
Total current assets	108,688			54,184			145,203			54,184

Property and equipment:
Oil and gas properties, full cost method:
Unproved properties and land, not subject to depletion	327,433			398,547			327,154			398,547
Proved properties, net of accumulated depletion	601,572			424,082			758,135			424,082
Wells in progress	127,111			81,780			158,192			81,780
Oil and gas properties, net	1,056,116			904,409			1,243,481			904,409
Other property and equipment, net	6,312			4,327			6,152			4,327
Total property and equipment, net	1,062,428			908,736			1,249,633			908,736
Cash held in escrow and other deposits	19,794			18,248			—			18,248
Goodwill	40,711			40,711			40,711			40,711
Other assets	2,012			2,234			2,359			2,234
Total assets	$	1,233,633		$	1,024,113		$	1,437,906		$	1,024,113

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	97,850		$	52,453		$	134,144		$	52,453
Revenue payable	34,864			16,557			58,742			16,557
Production taxes payable	23,071			17,673			37,017			17,673
Asset retirement obligations	2,512			2,683			2,738			2,683
Commodity derivative liabilities	—			2,874			786			2,874
Total current liabilities	158,297			92,240			233,427			92,240

Revolving credit facility	90,000			—			150,000			—
Notes payable, net of issuance costs	76,010			75,614			76,216			75,614
Commodity derivative liabilities							394			—
Asset retirement obligations	12,673			13,775			33,981			13,775
Other liabilities	2,286			1,745			2,268			1,745
Total liabilities	339,266			183,374			496,286			183,374

Commitments and contingencies (See Note 14)

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: 200,842,129 and 200,647,572 shares issued and outstanding, respectively	201			201
Common stock - $0.001 par value, 300,000,000 shares authorized: 200,909,101 and 200,647,572 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively							201			201
Additional paid-in capital	1,154,912			1,148,998			1,158,317			1,148,998
Retained deficit	(260,746		)	(308,460		)	(216,898		)	(308,460		)
Total shareholders' equity	894,367			840,739			941,620			840,739

Total liabilities and shareholders' equity	$	1,233,633		$	1,024,113		$	1,437,906		$	1,024,113

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

SRC ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except share and per share data)


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,						Nine Months Ended September 30,
	2017		2016			2017		2016			2017			2016			2017		2016

Oil, natural gas, and NGL revenues	$	75,036	$	23,947		$	118,826	$	42,220		$	103,593		$	26,234		$	222,419	$	68,454
Sales of purchased oil	—		—			1,268		—			—			—			1,268		—
Total Revenues	75,036		23,947			120,094		42,220
Total revenues											103,593			26,234			223,687		68,454

Expenses:
Lease operating expenses	5,018		6,845			8,740		11,144			5,154			3,819			13,894		14,963
Production taxes	9,464		2,137			10,930		3,970			10,083			(1,461		)	21,013		2,509
Costs of purchased oil	—		—			1,518		—			—			—			1,518		—
Depreciation, depletion, and accretion	26,427		11,274			39,656		23,366			33,740			9,635			73,396		33,001
Full cost ceiling impairment	—		144,149			—		189,770			—			25,453			—		215,223
Unused commitment charge	—		232			669		300			—			205			669		505
General and administrative	7,605		7,520			15,805		14,963			8,484			8,236			24,289		23,199
Total expenses	48,514		172,157			77,318		243,513			57,461			45,887			134,779		289,400

Operating income (loss)	26,522		(148,210		)	42,776		(201,293		)	46,132			(19,653		)	88,908		(220,946		)

Other income (expense):
Commodity derivatives gain (loss)	1,328		(5,704		)	4,707		(4,024		)	(2,383		)	407			2,324		(3,617		)
Interest expense, net of amounts capitalized	—		—			—		—			—			—			—		—
Interest income	20		157			31		165			16			11			47		176
Other income	66		10			302		4
Other income (expense)											83			(1		)	385		3
Total other income (expense)	1,414		(5,537		)	5,040		(3,855		)	(2,284		)	417			2,756		(3,438		)

Income (Loss) before income taxes	27,936		(153,747		)	47,816		(205,148		)	43,848			(19,236		)	91,664		(224,384		)

Income tax expense	—		101			—		101			—			5			—		106
Net income (loss)	$	27,936	$	(153,848	)	$	47,816	$	(205,249	)	$	43,848		$	(19,241	)	$	91,664	$	(224,490	)

Net income (loss) per common share:
Basic	$	0.14	$	(0.89	)	$	0.24	$	(1.40	)	$	0.22		$	(0.10	)	$	0.46	$	(1.36	)
Diluted	$	0.14	$	(0.89	)	$	0.24	$	(1.40	)	$	0.22		$	(0.10	)	$	0.46	$	(1.36	)

Weighted-average shares outstanding:
Basic	200,831,063		172,013,551			200,769,817		146,703,144			200,881,447			200,515,555			200,807,436		164,771,544
Diluted	201,224,172		172,013,551			201,266,609		146,703,144			201,460,915			200,515,555			201,326,129		164,771,544

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

SRC ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited; in thousands)


	Six Months Ended June 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Cash flows from operating activities:
Net income (loss)	$	47,816		$	(205,249	)	$	91,664		$	(224,490	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and accretion	39,656			23,366			73,396			33,001
Full cost ceiling impairment	—			189,770			—			215,223
Settlement of asset retirement obligation							(4,077		)	(196		)
Stock-based compensation	5,360			4,911			8,390			7,285
Mark-to-market of commodity derivative contracts:
Total (gain) loss on commodity derivatives contracts	(4,707		)	4,024			(2,324		)	3,617
Cash settlements on commodity derivative contracts	234			4,651			778			5,137
Changes in operating assets and liabilities:
Accounts receivable
Oil, natural gas, and NGL sales	(12,000		)	812			(46,581		)	602
Trade	(21,628		)	(1,771		)	(38,446		)	2,679
Accounts payable and accrued expenses	(2,071		)	859			1,413			1,761
Revenue payable	18,400			(1,305		)	41,997			(363		)
Production taxes payable	5,714			(8,498		)	17,548			(10,158		)
Other	(2,316		)	665			(941		)	(905		)
Net cash provided by operating activities	74,458			12,235			142,817			33,193

Cash flows from investing activities:
Acquisition of oil and gas properties and leaseholds	(29,998		)	(498,701		)	(62,562		)	(503,357		)
Capital expenditures for drilling and completion activities	(178,606		)	(46,009		)	(305,636		)	(72,375		)
Other capital expenditures	(8,858		)	(911		)	(11,198		)	(3,078		)
Land and other property and equipment	(3,837		)	(491		)	(4,087		)	(3,339		)
Cash held in escrow	(1,546		)	(18,212		)	18,248			(18,244		)
Proceeds from sales of oil and gas properties	77,155			23,496
Proceeds from sales of oil and gas properties and other							77,017			24,223
Net cash used in investing activities	(145,690		)	(540,828		)	(288,218		)	(576,170		)

Cash flows from financing activities:
Proceeds from the sale of stock	—			565,398			—			565,398
Offering costs	—			(21,898		)	—			(21,987		)
Proceeds from the employee exercise of stock options	114			—			114			—
Payment of employee payroll taxes in connection with shares withheld	(565		)	(408		)	(631		)	(510		)
Proceeds from the revolving credit facility	110,000			55,000			170,000			55,000
Principal repayments on the revolving credit facility	(20,000		)	(133,000		)	(20,000		)	(133,000		)
Financing fees on amendments to the revolving credit facility	(255		)	(196		)	(1,372		)	(269		)
Proceeds from issuance of the notes payable	—			80,000			—			80,000
Financing fees on issuance of the notes payable	—			(4,168		)	—			(4,397		)
Net cash provided by financing activities	89,294			540,728			148,111			540,235

Net increase in cash and equivalents	18,062			12,135
Net increase (decrease) in cash and equivalents							2,710			(2,742		)

Cash and equivalents at beginning of period	18,615			66,499			18,615			66,499

Cash and equivalents at end of period	$	36,677		$	78,634		$	21,325		$	63,757

Supplemental Cash Flow Information (See Note 15)

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

SRC ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


1.	Organization and Summary of Significant Accounting Policies

Organization: SRC Energy Inc. (the "Company," "SRC Energy," "we," "us," or "our") is ~~a growth-oriented,~~an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids ("NGLs"), primarily in the Denver-Julesburg Basin ("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 MKT, 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 condensed 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”).

Interim Financial Information: The unaudited condensed consolidated interim financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X. The condensed consolidated balance sheet as of December 31, 2016 was derived from the Company's Annual Report on Form 10-K for the year ended December 31, 2016 as filed with the SEC on February 23, 2017. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations. The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2016.

In our opinion, the unaudited condensed consolidated financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements. However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

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


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended September 30,		Nine Months Ended September 30,
Major Customers	2017	2016	2017	2016	2017	2016	2017	2016
Company A	28%	17%	26%	21%	30%	*	27%	*
Company B	24%	*	25%	*	27%	20%	26%	20%
Company C	16%	*	17%	*	13%	12%	15%	*
Company D	13%	*	*	*	*	10%	*	11%
Company E	*	42%	*	43%	*	27%	*	38%
Company F	*	14%	*	10%
Company G	*	12%	*	11%
Company H	*	10%	*	*

* 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 ~~NGL~~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 ~~can~~could be ~~sold in the market in the event that it is not sold to the Company’s existing customers.~~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:~~table (these companies do not necessarily correspond to those presented above):

As of

Major Customers

June 30, 2017

December 31, 2016

September 30, 2017

December 31, 2016

Company A

18%

23%

25%

23%

Company B

15%

43%

16%

Company C

10%

43%

Company D

10%

Company E

* 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 utilized in, and all of our revenues are derived from, the oil and gas industry.

Recently Adopted Accounting Pronouncements:

In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 is not expected to materially 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 November 2016, the FASB issued 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. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, and we must apply

the guidance retrospectively to all periods presented. We are currently evaluating the impact of the adoption of this standard on our condensed consolidated financial statements.

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 condensed consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. ~~Currently, we have~~While the Company does not ~~identified any contracts that would require a change from~~expect net income (loss) or cash flows to be impacted, the ~~entitlements method, historically used~~Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain ~~domestic natural~~pipeline gathering, transportation, and gas ~~sales, to the sales method of accounting. We are continuing~~processing agreements. The Company continues to evaluate the ~~provisions~~expected disclosure requirements, changes to relevant business practices, accounting policies, and control activities that will occur as a result of ~~these ASUs as pertinent~~the adoption of this ASU. The Company plans to ~~certain sales contracts and, in particular, as they relate to disclosure requirements.~~adopt the guidance using the modified retrospective method on the effective date of January 1, 2018.

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.

Change in ~~estimate:~~estimates: During the ~~six~~nine months ended ~~June~~September 30, 2017, the Company adjusted its estimate for production taxes based on recent historical experience and additional information received during the period. During the ~~three~~nine months ended June 30, 2017, the Company increased the accrual for production taxes to be paid by approximately $0.9 million, which decreased our operating income by a corresponding amount and had a negligible impact to net income per basic and diluted common share. ~~During the six months ended June~~September 30, 2017, the Company decreased the accrual for production taxes to be paid by approximately $1.1 million, which increased our operating income by a corresponding amount, or $0.01 per basic and diluted common share. During the three months ended September 30, 2016, the Company reduced its estimate for ad valorem taxes based on additional information received during that period. As a result, the Company decreased taxes to be paid by approximately $3.6 million which reduced our operating loss for the three and nine months ended September 30, 2016 by a corresponding amount, or $0.02 per basic and diluted common share.


2.	Property and Equipment

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


	As of			As of			As of			As of
	June 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Oil and gas properties, full cost method:
Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs	$	320,233		$	392,561		$	319,954		$	392,561
Land	7,200			5,986			7,200			5,986
Subtotal, unproved properties and land	327,433			398,547			327,154			398,547

Costs of wells in progress	127,111			81,780			158,192			81,780

Costs of proved properties:
Producing and non-producing	1,186,594			969,239			1,375,937			969,239
Less, accumulated depletion and full cost ceiling impairments	(585,022		)	(545,157		)	(617,802		)	(545,157		)
Subtotal, proved properties, net	601,572			424,082			758,135			424,082

Costs of other property and equipment:
Other property and equipment	7,533			5,063			7,790			5,063
Less, accumulated depreciation	(1,221		)	(736		)	(1,638		)	(736		)
Subtotal, other property and equipment, net	6,312			4,327			6,152			4,327

Total property and equipment, net	$	1,062,428		$	908,736		$	1,249,633		$	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 ~~June~~September 30, 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. At ~~June~~September 30, 2016, the carrying value of our oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation, resulting in an impairment of ~~$144.1~~$25.5 million for the three months ended ~~June~~September 30, 2016. Impairments for the ~~six~~nine months ended ~~June~~September 30, 2016 totaled ~~$189.8~~$215.2 million. No impairments were recognized for the comparable 2017 periods.

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

Three Months Ended June 30, Six Months Ended June 30,
2017 2016 2017 2016
Capitalized overhead $ 2,531
$ 2,339
$ 5,211
$ 2,988



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Capitalized overhead	$	2,518	$	1,757	$	7,729	$	4,745


3.	Acquisitions, Swaps, and Divestitures

Acquisitions and Swaps

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

September 2017 Acquisition

In ~~June~~September 2017, we ~~executed a purchase~~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 ~~sale agreement with a private party~~7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the ~~acquisition~~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 $31.3 million, composed of cash of $6.8 million and assumed liabilities of $24.5 million. The assumed liabilities included $20.9 million for asset retirement obligations.

August 2017 Acquisition and Swap

In August 2017, we 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 ~~$21~~$22.6 million, ~~net~~composed of ~~customary closing adjustments. The transaction is expected to close in the third quarter of 2017. We~~cash and assumed liabilities.

In August 2017, we also entered into ~~a separate~~an agreement with another party to trade approximately 4,000 net acres of the Company's non-contiguous acreage for approximately 4,000 net acres within the Company's core operating area. This transaction is ~~also~~ expected to close

in the ~~third~~fourth quarter of 2017.

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 $25.0 million, composed of cash and assumed liabilities.

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 (the "GC Agreement") ~~with a large publicly-traded company~~ 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"). ~~Estimated net daily production from the acquired properties was approximately 2,400 BOE at the time of entering into the GC Agreement.~~

In June 2016, the Company closed on the portion of the assets comprised of ~~the~~ undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. AAs discussed above in "- September 2017 Acquisition" above,we closed on the second ~~closing will cover~~part of this transaction covering the operated producing properties ~~and is expected to be completed~~ in the third quarter of 2017, subject to certain closing conditions. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, the effective date will be April 1, 2016 for the horizontal wells to be acquired, and the first day of the calendar month in which the closing for such properties occurs for the vertical wells.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 million related 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
Proved oil and gas properties ⁽¹⁾	$	132,903
Unproved oil and gas properties	353,511
Total fair value of assets acquired	$	486,414

⁽¹⁾ Proved 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 of 11.5%, and assumptions regarding the timing and amount of future development and operating costs.

For the three and ~~six~~nine months ended ~~June~~September 30, 2017, the results of operations of the acquired assets, representing approximately $1.4 million and $~~3.8~~5.5 million of revenue, respectively, and ~~$1.0~~$0.9 million and ~~$2.9~~$5.0 million of operating income, respectively, have been included in the Company's condensed consolidated statements of operations.

The following table presents the unaudited pro forma combined results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2016 as if the first closing had occurred on January 1, ~~2016.~~2015. 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)	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016			Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
Oil and gas revenues	25,589		$	45,706
Oil, natural gas, and NGL revenues						$	26,234		$	71,940
Net loss	(155,380	)	$	(208,538	)	$	(19,241	)	$	(227,479	)

Net loss per common share
Basic	(0.63	)	$	(0.94	)	$	(0.10	)	$	(1.14	)
Diluted	(0.63	)	$	(0.94	)	$	(0.10	)	$	(1.14	)

February 2016 Acquisition

On February 4, 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. ~~This allocation reflects~~See Note 9 for further details as to the preparation of these significant ~~use of~~ estimates.

Divestitures

~~We completed divestitures of acreage outside of~~In October 2017, we executed a purchase and sale agreement with a private party resulting in the ~~Company's core development area~~divestiture of approximately ~~10,700~~1,100 net ~~undeveloped~~ acres ~~along with~~and 22 gross (4 net) non-operated wells in progress for $11.6 million. The transaction is expected to close in the ~~associated production. For three and six months ended June 30, 2017, the transactions resulted in proceeds~~fourth quarter of 2017. Additionally, we completed an additional divestiture to a separate private party of 37 operated vertical wells for total consideration of approximately ~~$6.5 million and $77.2~~$0.7 million in cash and the assumption by the buyers of ~~$0.6~~$2.3 million in liabilities.

During the nine months ended September 30, 2017, we completed divestitures of approximately 10,700 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $75.1 million in cash and the assumption by the buyers of $1.7 million in asset retirement obligations and $0.6 million in ~~liabilities, respectively.~~other liabilities. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.

In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres and 107 vertical wells, along with the associated production, 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.~~liabilities and $3.6 million in asset retirement obligations. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.


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

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016		2017		2016		2017		2016
Depletion of oil and gas properties	$	25,742	$	10,965	$	38,445	$	22,708	$	32,944	$	9,273	$	71,389	$	31,981
Depreciation and accretion	685		309		1,211		658		796		362		2,007		1,020
Total DD&A Expense	$	26,427	$	11,274	$	39,656	$	23,366	$	33,740	$	9,635	$	73,396	$	33,001

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 three and ~~six~~nine months ended ~~June~~September 30, 2017, production of ~~2,969~~3,715 MBOE and ~~4,566~~8,280 MBOE, respectively, represented ~~1.9%~~2.2% and ~~2.9%~~4.8% of estimated total proved reserves, respectively. For the three and ~~six~~nine months ended ~~June~~September 30, 2016, production of ~~1,010~~993 MBOE and ~~2,057~~3,050 MBOE, respectively, represented ~~1.0%~~0.8% and ~~2.0%~~2.4% of estimated total proved reserves, respectively. DD&A expense was ~~$8.90~~$9.08 per BOE and ~~$11.16~~$9.70 per BOE for the three months ended ~~June~~September 30, 2017 and 2016, respectively, and was ~~$8.69~~$8.86 per BOE and ~~$11.36~~$10.82 per BOE for the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, 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):


	Six Months Ended June 30, 2017			Nine Months Ended September 30, 2017
Asset retirement obligations, December 31, 2016	$	16,458		$	16,458
Obligations incurred with development activities	1,527			2,782
Obligations assumed with acquisitions	1,098			23,521
Accretion expense	602			981
Obligations discharged with asset retirements and divestitures	(4,500		)	(7,023		)
Asset retirement obligation, June 30, 2017	$	15,185
Asset retirement obligation, September 30, 2017				$	36,719
Less, current portion	(2,512		)	(2,738		)
Long-term portion	$	12,673		$	33,981


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 ~~June~~September 30, 2017, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of ~~$225~~$400 million. There was a ~~$90.0~~$150.0 million outstanding principal balance as of ~~June~~September 30, 2017 and no outstanding principal balance as of December 31, 2016. The Company has an outstanding letter of credit of approximately $0.5 million.

In ~~April~~September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from ~~$160~~$225 million to ~~$225 million; however, the Company chose to limit its elected commitments to $210~~$400 million. The next semi-annual redetermination is scheduled for ~~November 2017.~~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 the London Interbank Offered Rate ("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 ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 was ~~2.8%~~3.3% 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. ~~Under the requirements,~~In particular, the Company ~~on a quarterly basis,~~ must not (a) ~~at any time~~ permit its ratio of total funded debt ~~as of such time~~ to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to ~~1.0;~~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 than 1.0 to 1.0. As of ~~June~~September 30, 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

In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes ("Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each ~~year, beginning on December 15, 2016.~~year. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and ~~are~~will be guaranteed on a senior unsecured basis by ~~the Company’s existing and~~any future subsidiaries of the Company that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 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 of 10.6%. .The net proceeds were used to fund the GC Acquisition as discussed further in Note 3.

At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes at the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at ~~the~~a redemption price atequal to a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the 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 109% 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~~any restricted subsidiaries to, among other things: (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 of ~~June~~September 30, 2017, the most recent compliance date, the Company was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.


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.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying condensed 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 resulting from contract settlement of derivatives are recorded in the condensed 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 condensed consolidated statements of cash flows.

The Company’s commodity derivative contracts as of ~~June~~September 30, 2017 are summarized below:

Settlement Period
Derivative
Instrument

Average Volumes
(Bbls
per month)

Floor
Price

Ceiling
Price
Crude Oil - NYMEX WTI
July 1, 2017 - Dec 31, 2017 Collar 30,667
$ 40.00
$ 60.00
July 1, 2017 - Dec 31, 2017 Collar 20,000
$ 45.00
$ 70.00
July 1, 2017 - Dec 31, 2017 Collar 30,667
$ 40.00
$ 65.00
July 1, 2017 - Aug 31, 2017 Put 20,000
$ 55.00
—
July 1, 2017 - Dec 31, 2017 Collar 30,667
$ 40.00
$ 65.00
July 1, 2017 - Dec 31, 2017 Collar 15,333
$ 45.00
$ 65.00
July 1, 2017 - Dec 31, 2017 Collar 15,333
$ 45.00
$ 65.10

Settlement Period
Derivative
Instrument

Average Volumes
(MMBtu
per month)

Floor
Price

Ceiling
Price
Natural Gas - NYMEX Henry Hub
July 1, 2017 - Dec 31, 2017 Collar 100,000
$ 2.75
$ 4.00
July 1, 2017 - Dec 31, 2017 Collar 153,333
$ 2.75
$ 3.90
Sep 1, 2017 - Dec 31, 2017 Collar 91,500
$ 2.75
$ 4.10
Sep 1, 2017 - Dec 31, 2017 Collar 15,250
$ 3.00
$ 4.31
July 1, 2017 - Dec 31, 2017 Collar 110,400
$ 3.00
$ 4.30
July 1, 2017 - Dec 31, 2017 Collar 199,333
$ 3.00
$ 3.88
July 1, 2017 - Dec 31, 2017 Collar 199,333
$ 3.00
$ 3.91

Natural Gas - CIG Rocky Mountain
July 1, 2017 - Aug 31, 2017 Collar 110,000
$ 2.50
$ 3.06
July 1, 2017 - Dec 31, 2017 Collar 200,000
$ 2.50
$ 3.27
July 1, 2017 - Dec 31, 2017 Collar 100,000
$ 2.60
$ 3.20



Settlement Period	Derivative Instrument	Average Volumes (Bbls per month)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Oct 1, 2017 - Dec 31, 2017	Collar	30,667	$	40.00	$	60.00
Oct 1, 2017 - Dec 31, 2017	Collar	20,000	$	45.00	$	70.00
Oct 1, 2017 - Dec 31, 2017	Collar	30,667	$	40.00	$	65.00
Oct 1, 2017 - Dec 31, 2017	Collar	30,667	$	40.00	$	65.00
Oct 1, 2017 - Dec 31, 2017	Collar	15,333	$	45.00	$	65.00
Oct 1, 2017 - Dec 31, 2017	Collar	15,333	$	45.00	$	65.10
Jan 1, 2018 - Dec 31, 2018	Collar	76,042	$	40.00	$	57.60

Settlement Period	Derivative Instrument	Average Volumes (MMBtu per month)	Floor Price		Ceiling Price
Natural Gas - NYMEX Henry Hub
Oct 1, 2017 - Dec 31, 2017	Collar	100,000	$	2.75	$	4.00
Oct 1, 2017 - Dec 31, 2017	Collar	153,333	$	2.75	$	3.90
Oct 1, 2017 - Dec 31, 2017	Collar	92,000	$	2.75	$	4.10
Oct 1, 2017 - Dec 31, 2017	Collar	15,333	$	3.00	$	4.31
Oct 1, 2017 - Dec 31, 2017	Collar	110,400	$	3.00	$	4.30
Oct 1, 2017 - Dec 31, 2017	Collar	199,333	$	3.00	$	3.88
Oct 1, 2017 - Dec 31, 2017	Collar	199,333	$	3.00	$	3.91

Natural Gas - CIG Rocky Mountain
Oct 1, 2017 - Dec 31, 2017	Collar	200,000	$	2.50	$	3.27
Oct 1, 2017 - Dec 31, 2017	Collar	100,000	$	2.60	$	3.20
Jan 1, 2018 - Dec 31, 2018	Collar	456,250	$	2.25	$	2.81

Subsequent to ~~June~~September 30, 2017, the Company added the following positions:


Settlement Period	Derivative Instrument	Average Volumes (Bbls per month)	Floor Price		Ceiling Price		Derivative Instrument	Average Volumes (Bbls per month)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Jan 1, 2018 - Dec 31, 2018	Collar	76,042	$	40.00	$	57.60	Collar	76,042	$	45.00	$	58.00

Settlement Period	Derivative Instrument	Average Volumes (MMBtu per month)	Floor Price		Ceiling Price
Natural Gas - CIG Rocky Mountain
Jan 1, 2018 - Dec 31, 2018	Collar	456,250	$	2.25	$	2.81

Offsetting of Derivative Assets and Liabilities

As of ~~June~~September 30, 2017 and December 31, 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 condensed consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying condensed 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 June 30, 2017								As of September 30, 2017
Underlying	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		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	$	1,863	$	(284	)	$	1,579	Current assets	$	1,214	$	(1,214	)	$	—
Commodity derivative contracts	Noncurrent assets	$	—	$	—		$	—	Noncurrent assets	$	502	$	(502	)	$	—
Commodity derivative contracts	Current liabilities	$	284	$	(284	)	$	—	Current liabilities	$	2,000	$	(1,214	)	$	786
Commodity derivative contracts	Noncurrent liabilities	$	—	$	—		$	—	Noncurrent liabilities	$	896	$	(502	)	$	394



		As of December 31, 2016
Underlying	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	Noncurrent assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	4,622	$	(1,748	)	$	2,874
Commodity derivative contracts	Noncurrent liabilities	$	—	$	—		$	—

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Realized gain (loss) on commodity derivatives	$	(23	)	$	436		$	(142	)	$	2,881		$	116		$	(13	)	$	(26	)	$	2,868
Unrealized gain (loss) on commodity derivatives	1,351			(6,140		)	4,849			(6,905		)	(2,499		)	420			2,350			(6,485		)
Total gain (loss)	$	1,328		$	(5,704	)	$	4,707		$	(4,024	)	$	(2,383	)	$	407		$	2,324		$	(3,617	)

Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date and the previously incurred premiums attributable to settled commodity contracts. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Monthly settlement	$	327		$	946		$	551		$	3,901		$	376		$	497		$	927		$	4,398
Previously incurred premiums attributable to settled commodity contracts	(350		)	(510		)	(693		)	(1,020		)	(260		)	(510		)	(953		)	(1,530		)
Total realized gain (loss)	$	(23	)	$	436		$	(142	)	$	2,881		$	116		$	(13	)	$	(26	)	$	2,868

Credit Related Contingent Features

As of ~~June~~September 30, 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.


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 flow or other 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.~~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 ~~through business combinations~~ is calculated using a net discounted cash flow approach for the producing 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 the same inputs as described in the paragraph above. For the asset retirement liability assumed, the fair value is determined using the same inputs as described in the paragraph below. See Note 3 for additional information.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 rates, 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 ~~Note~~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 as of ~~June~~September 30, 2017 and December 31, 2016 by level within the fair value hierarchy (in thousands):


	Fair Value Measurements at June 30, 2017								Fair Value Measurements at September 30, 2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	1,579	$	—	$	1,579	$	—	$	—	$	—	$	—
Commodity derivative liability	$	—	$	—	$	—	$	—	$	—	$	1,180	$	—	$	1,180



	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 ~~June~~September 30, 2017, derivative instruments utilized by the Company consist of puts and 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~~Senior Notes is estimated to be ~~$85.6~~$84.8 million at ~~June~~September 30, 2017. The Company determined the fair value of its notes payable at ~~June~~September 30, 2017 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes as Level 2.


10.	Interest Expense

The components of interest expense are (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Revolving bank credit facility	$	227		$	13		$	270		$	154		$	1,016		$	—		$	1,286		$	154
Notes payable	1,800			320			3,600			320			1,800			1,800			5,400			2,120
Amortization of issuance costs	677			314			1,177			609			1,090			467			2,267			1,076
Less, interest capitalized	(2,704		)	(647		)	(5,047		)	(1,083		)	(3,906		)	(2,267		)	(8,953		)	(3,350		)
Interest expense, net of amounts capitalized	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—


11.	Weighted-Average Shares Outstanding

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


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016	2017	2016	2017	2016
Weighted-average shares outstanding - basic	200,831,063	172,013,551	200,769,817	146,703,144	200,881,447	200,515,555	200,807,436	164,771,544
Potentially dilutive common shares from:
Stock options	360,423	—	411,819	—	415,524	—	412,902	—
Restricted stock units and stock bonus shares	32,686	—	84,973	—	163,944	—	105,791	—
Weighted-average shares outstanding - diluted	201,224,172	172,013,551	201,266,609	146,703,144	201,460,915	200,515,555	201,326,129	164,771,544

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:


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016	2017	2016	2017	2016
Potentially dilutive common shares from:
Stock options	4,786,500	5,589,500	4,786,500	5,589,500	4,726,500	5,903,500	4,756,500	5,903,500
Performance-vested stock units ¹	951,884	478,510	951,884	478,510	951,884	478,510	951,884	478,510
Restricted stock units and stock bonus shares	872,193	1,069,890	522,014	1,069,890	308,094	1,003,879	497,806	1,003,879
Total	6,610,577	7,137,900	6,260,398	7,137,900	5,986,478	7,385,889	6,206,190	7,385,889

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.


12.	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, warrants, 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 phase"). 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 condensed 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 ~~June~~September 30, 2017, there were 4,500,000 common shares authorized for grant under the 2015 Plan, of which ~~1,150,015~~86,464 shares were ~~remaining~~available for future ~~issuance.~~

grants. The shares available for future grant exclude 951,884 shares which have been reserved for future vesting of performance-vested stock units under the assumption that these awards met the criterion to vest at their maximum multiplier.

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Stock options	$	1,302		$	1,423		$	2,548		$	2,833		$	1,277		$	1,274		$	3,825		$	4,107
Performance-vested stock units	798			338			1,323			338			807			354			2,130			692
Restricted stock units and stock bonus shares	1,047			1,106			2,393			2,318			1,386			1,023			3,779			3,341
Total stock-based compensation	$	3,147		$	2,867		$	6,264		$	5,489		$	3,470		$	2,651		$	9,734		$	8,140
Less: stock-based compensation capitalized	(462		)	(475		)	(904		)	(578		)	(440		)	(278		)	(1,344		)	(856		)
Total stock-based compensation expensed	$	2,685		$	2,392		$	5,360		$	4,911		$	3,030		$	2,373		$	8,390		$	7,284

Stock options

No stock options were granted during the three and ~~six~~nine months ended ~~June~~September 30, 2017. During the periods presented, the Company granted the following stock options:


	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2016
Number of options to purchase common shares	105,000		594,500		350,000		944,500
Weighted-average exercise price	$	6.93	$	7.58	$	6.55	$	7.20
Term (in years)	10 years		10 years		10 years		10 years
Vesting Period (in years)	5 years		3 - 5 years		5 years		3 - 5 years
Fair Value (in thousands)	$	399	$	2,128	$	1,253	$	3,381

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



	~~Six~~Nine Months Ended ~~June~~September 30, 2016
Expected term	~~6.3~~6.4 years
Expected volatility	55	%
Risk free rate	~~1.50~~1.25 - 1.75%
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)		Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 2016	6,001,500		$	9.27	8.0 years	$	6,515	6,001,500		$	9.27	8.0 years	$	6,515
Granted	—		—					—		—
Exercised	(30,000	)	3.79			140		(30,000	)	3.79			140
Expired	(35,000	)	12.09					(41,000	)	11.98
Forfeited	(80,000	)	11.68					(104,000	)	11.60
Outstanding, June 30, 2017	5,856,500		$	9.24	7.5 years	$	2,308
Outstanding, Exercisable at June 30, 2017	2,898,361		$	8.78	6.7 years	$	1,964
Outstanding, September 30, 2017								5,826,500		$	9.23	7.2 years	$	8,076
Outstanding, Exercisable at September 30, 2017								3,146,361		$	8.77	6.6 years	$	5,660

The following table summarizes information about issued and outstanding stock options as of ~~June~~September 30, 2017:


	Outstanding Options				Exercisable Options			Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price per Share		Options	Weighted-Average Exercise Price per Share		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	600,000	4.1 years	$	3.49	559,000	$	3.47	600,000	$	3.49	3.9 years	574,000	$	3.46	3.8 years
$5.00 - $6.99	1,012,000	7.4 years	6.38		485,000	6.44		1,012,000	6.38		7.2 years	549,000	6.45		6.0 years
$7.00 - $10.99	1,592,500	8.0 years	9.34		499,661	9.41		1,592,500	9.34		7.7 years	658,661	9.50		7.3 years
$11.00 - $13.46	2,652,000	7.9 years	11.58		1,354,700	11.57		2,622,000	11.58		7.7 years	1,364,700	11.58		7.6 years
Total	5,856,500	7.5 years	$	9.24	2,898,361	$	8.78	5,826,500	$	9.23	7.2 years	3,146,361	$	8.77	6.6 years

The estimated unrecognized compensation cost from stock options not vested as of ~~June~~September 30, 2017, which will be recognized ratably over the remaining vesting phase, is as follows:


Unrecognized compensation cost (in thousands)	$	12,523	$	11,101
Remaining vesting phase	2.8 years		2.5 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 ~~six~~nine months ended ~~June~~September 30, 2017:


	Number of Shares		Weighted-Average Grant-Date Fair Value		Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016	890,336		$	9.55	890,336		$	9.54
Granted	552,950		8.57		669,323		8.27
Vested	(261,071	)	9.28		(336,445	)	9.17
Forfeited	(20,101	)	10.09		(24,807	)	9.85
Not vested, June 30, 2017	1,162,114		$	9.12
Not vested, September 30, 2017					1,198,407		$	8.93

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of ~~June~~September 30, 2017, which will be recognized ratably over the remaining vesting phase, is as follows:


Unrecognized compensation cost (in thousands)	$	8,859	$	8,232
Remaining vesting phase	2.6 years		2.3 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 as well as the volatilities for each of the Company’s peers.

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


	Six Months Ended June 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Weighted-average expected term	2.9 years		2.7 years		2.9 years		2.7 years
Weighted-average expected volatility	59	%	58	%	59	%	58	%
Weighted-average risk-free rate	1.34	%	0.87	%	1.34	%	0.87	%

The fair value of the PSUs granted during the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 was $5.1 million and $4.0 million, respectively. As of ~~June~~September 30, 2017, unrecognized compensation cost for PSUs was ~~$6.6~~$5.8 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		Number of Units¹	Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016	478,510	$	8.09	478,510	$	8.09
Granted	473,374	10.79		473,374	10.79
Vested	—	—		—	—
Forfeited	—	—		—	—
Not vested, June 30, 2017	951,884	$	9.44
Not vested, September 30, 2017				951,884	$	9.44


13.	Income Taxes

We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

The effective tax rates for the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 were ~~nil compared to nil for the three and six months ended June 30, 2016.~~nil. The effective tax rates for the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 were based upon a full year forecasted tax provision and differs from the statutory rate primarily due to the recognition of a valuation allowance recorded against deferred tax assets. There were no significant discrete items recorded during the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016.

As of ~~June~~September 30, 2017, we had no liability for 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. Most of the Company's tax returns filed since

August 31, 2011 are still subject to examination by tax authorities. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions, and we are not currently under any state income tax examinations.

No significant uncertain tax positions were identified as of any date on or before ~~June~~September 30, 2017. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of ~~June~~September 30, 2017, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon our cumulative losses through ~~June~~September 30, 2017, we have provided a full valuation allowance reducing the net realizable benefits.


14.	Other Commitments and Contingencies

Volume Commitments

~~During 2014, the~~The Company entered into firm sales agreements for its oil production with three ~~counterparties.~~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 second 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	Oil
Year ending December 31,	(MBbls)	(MBbls)
Remainder of 2017	2,145	1,072
2018	4,255	4,942
2019	4,255	5,167
2020	3,700	4,003
2021	1,672	1,672
Thereafter	—	—
Total	16,027	16,856

During the ~~six~~nine months ended ~~June~~September 30, 2017, the Company incurred deficiency charges of $0.7 million as we were unable to meet all of the obligations during the period. ~~No deficiency charges were incurred during the three months ended June 30, 2017.~~ During the ~~second~~third quarter of 2017, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations, although this cannot be guaranteed.

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 ~~plan~~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 by late 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. ~~This~~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 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 ~~obligation~~obligations can be reduced by the collective volumes delivered to the ~~plant~~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.

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. A schedule of the minimum lease payments under non-cancelable operating leases as of ~~June~~September 30, 2017 follows (in thousands):


Year ending December 31,	Rent	Rent
Remainder of 2017	354	$	208
2018	840	840
2019	859	859
2020	878	878
2021	875	875
Thereafter	477	477
Total	4,283	$	4,137

Rent expense for offices leases was $0.2 million ~~and $0.2 million~~ for the three months ended ~~June~~September 30, 2017 and 2016, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, rent expense for office leases was ~~$0.6~~$0.9 million and ~~$0.3~~$0.5 million, respectively.

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 matters of contention are reasonably likely to have a material adverse impact on our business, financial position, results of operations, or cash flows.

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. We are working with the CDPHE to respond to its concerns. We cannot predict the outcome of this matter, but we expect that any potential resolution of these claims would be on a field-wide basis.


15.	Supplemental Schedule of Information to the Condensed Consolidated Statements of Cash Flows

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


	Six Months Ended June 30,					Nine Months Ended September 30,
Supplemental cash flow information:	2017			2016		2017			2016
Interest paid	$	3,864		$	159	$	4,796		$	159
Income taxes paid	—			101		—			106

Non-cash investing and financing activities:
Accrued well costs as of period end	$	87,699		$	18,349	$	122,387		$	32,299
Asset retirement obligations incurred with development activities	1,527			366		2,782			366
Asset retirement obligations assumed with acquisitions	1,098			1,692		23,521			2,046
Obligations discharged with asset retirements and divestitures	(4,500		)	—		(7,023		)	(3,997		)


ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of ~~June~~September 30, 2017 and its results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016. It should be read in conjunction with the “Selected Financial Data” and the accompanying audited consolidated financial statements and related notes thereto contained in the Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 23, 2017. Unless the context otherwise requires, references to "SRC Energy," "we," "us," "our," or the "Company" in this report refer to the registrant, SRC Energy Inc., and its subsidiaries.

This section and other parts of this Quarterly Report on Form 10-Q contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Statement Concerning Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q. 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 is ~~a growth-oriented,~~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 drilling and completion activities are focused in the Wattenberg Field 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 and Niobrara formations, 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 ~~87%~~90% 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,								Year Ended December 31,				Year Ended August 31,
	2016		2015		2015		2014		2013		2012		2016		2015		2015		2014		2013
Average NYMEX prices
Oil (per Bbl)	$	43.20	$	48.73	$	60.65	$	100.39	$	94.58	$	94.88	$	43.20	$	48.73	$	60.65	$	100.39	$	94.58
Natural gas (per Mcf)	$	2.52	$	2.58	$	3.12	$	4.38	$	3.55	$	2.82	$	2.52	$	2.58	$	3.12	$	4.38	$	3.55

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.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Oil (NYMEX WTI)
Average NYMEX Price	$	48.24		$	45.59		$	50.08		$	39.39		$	48.18		$	44.90		$	49.44		$	41.23
Realized Price	41.15			35.06			41.75			29.37			42.37			35.67			42.04			31.47
Differential	$	(7.09	)	$	(10.53	)	$	(8.33	)	$	(10.02	)	$	(5.81	)	$	(9.23	)	$	(7.40	)	$	(9.76	)

Gas (NYMEX Henry Hub)
Average NYMEX Price	$	3.08		$	2.15		$	3.04		$	2.07		$	2.99		$	2.88		$	3.03		$	2.34
Realized Price	2.29			2.04			2.42			1.93			2.35			2.73			2.39			2.18
Differential	$	(0.79	)	$	(0.11	)	$	(0.62	)	$	(0.14	)	$	(0.64	)	$	(0.15	)	$	(0.64	)	$	(0.16	)

NGL Realized Price	$	13.18		$	—		$	14.12		$	—		$	17.32		$	—		$	15.49		$	—

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 actually 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 nine months ended September 30, 2017, the NYMEX-WTI oil price ranged from a high of $54.48 per Bbl on February 23, 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 ~~$46.02~~$51.67 per Bbl on Friday, ~~June 30,~~September 29, 2017, a decline of ~~14%~~4% from December 30, 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 ~~June~~September 30, 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.

Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of ~~June~~September 30, 2017:

Vertical Wells

Operated Wells

Non-Operated Wells

Totals

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

166

145

128

294

176

482

456

135

617

488

Horizontal Wells

Operated Wells

Non-Operated Wells

Totals

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

161

153

178

339

184

208

194

191

399

227

In addition to the producing wells summarized in the preceding table, as of ~~June~~September 30, 2017, we were the operator of 5946 gross ~~(50~~(36 net) horizontal wells in progress, which excludes 2519 gross ~~(20~~(14 net) wells for which we have only set surface casings. As of~~June~~ September 30, 2017, we are participating in 89 107 gross ~~(13 net)~~(22 net) 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.

As we develop our acreage through horizontal drilling, we have an active program for plugging and abandoning ~~vertical wellbores with a~~the vast majority of the operated ~~wells planned to be plugged over the next year.~~vertical wellbores. During the ~~six~~nine months ended ~~June~~September 30, 2017, we plugged 3586 wells and returned the associated acreage to the property owners.

On May 2, 2017, the Colorado Oil and Gas Conservation Commission issued a Notice to Operators (NTO) to verify the location of all flowlines associated with operated wells and the integrity of those flowlines. The Company has completed all field work associated with the NTO and filed the required paperwork regarding its operations ahead of the June 30, 2017 deadline.

Production

For the three months ended ~~June~~September 30, 2017, our average daily production increased to ~~32,624~~40,378 BOED as compared to ~~11,098~~10,794 BOED for the three months ended ~~June~~September 30, 2016. During the first ~~six~~nine months of 2017, our average net daily production was ~~25,224~~30,331 BOED. By comparison, during the ~~six~~nine months ended ~~June~~September 30, 2016, our average production rate was ~~11,304~~11,133 BOED. As of ~~June~~September 30, 2017, approximately 99% of our daily 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 and around the D-J Basin, where we have significant operating experience. All of our current wells and our planned acreage development is located either in or adjacent to the Wattenberg Field. 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.

Improve hydrocarbon recovery through increased well density. We utilize what we believe to be industry best practices in our effort to determine the optimal recovery area for each well. Early horizontal well development in the Wattenberg Field generally assumed optimal recoveries would be obtained utilizing between 12 and 16 wells per 640-acre section. As horizontal well development has matured, well density assumptions have generally increased beyond 16 wells per

section depending on the specific area of the field being drilled.

Complete selective acquisitions. We seek to acquire developed and undeveloped oil and gas properties, primarily in the Wattenberg Field. We generally seek acquisitions that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation.

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.

Use the latest technology to maximize returns. Our development objective for individual well optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical 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 ~~provide~~implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.

Significant Developments

We continue to be opportunistic with respect to acquisition efforts to increase our working interests and drilling location inventory. Further, in an effort to extend the length of laterals and/or increase working interests in our wells, we will continue to enter into land and working interest swaps.

Acquisitions

In September, we completed the second closing of 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 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 $31.3 million, composed of cash of $6.8 million and assumed liabilities of $24.5 million. The assumed liabilities included $20.9 million for asset retirement obligations.

In August 2017, we 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 ~~$21~~$22.6 million, ~~net~~composed of customary closing adjustments. The transaction is expected to close in the third quarter of 2017. We also entered into a separate agreement with another party to trade approximately 4,000 net acres of the Company's non-contiguous acreage for approximately 4,000 net acres within the Company's core operating area. This transaction is also expected to close in the third quarter of 2017.

~~Acquisitions~~cash and assumed liabilities.

In March 2017, we ~~closed an acquisition comprised primarily of~~acquired developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.0 million, composed of cash and assumed liabilities.

Divestitures

Revolving Credit Facility

In ~~April~~September 2017, the lenders under our revolving credit facility (sometimes referred to as the "Revolver") completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from ~~$160~~$225 million to ~~$225 million; however, the Company chose to limit aggregate elected commitments to~~ ~~$210 million~~.$400 million. The next semi-annual redetermination is scheduled for ~~November 2017.~~April 2018. Due to the outstanding principal balance and letters of credit, approximately ~~$119.5~~$249.5 million of the borrowing base was available to use for future borrowings as of ~~June~~September 30, ~~2017.~~2017, subject to our covenant requirements.

Drilling and Completion Operations

Our drilling and completion schedule drives our production forecast and our expected future cash flows. ~~We have been able to reduce per-well drilling and completion costs significantly over the past two years.~~ 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 further 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 ~~six~~nine months ended ~~June~~September 30, 2017, we drilled 6387 operated horizontal wells and completed 4887 operated horizontal wells. As of ~~June~~September 30, 2017, we are the operator of 5946 gross ~~(50~~(36 net) horizontal wells in progress, which excludes 2519 gross ~~(20~~(14 net) horizontal wells for which we have only set surface casings. For 2017 as a whole, we expect to drill ~~116~~118 gross operated horizontal wells, primarily mid-length and long laterals targeting the Codell and Niobrara formations.

For the ~~six~~nine months ended ~~June~~September 30, 2017, we participated in the completion of 2016 gross (2(1 net) non-operated horizontal wells. As of ~~June~~September 30, 2017, we are participating in 89107 gross ~~(13~~(22 net) 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 declined approximately ~~14%~~4% as of ~~June 30,~~September 29, 2017 to $~~46.02.~~51.67. Natural gas traded at $3.72 per Mcf on December 30, 2016, but declined approximately ~~18%~~19% as of ~~June 30,~~September 29, 2017 to ~~$3.04~~$3.01. O~~il prices continue to remain significantly lower than they were in the first half of 2014, when they were near $100/bbl.~~ Lower oil prices (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) may 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) may result in marginally productive oil and natural gas wells being abandoned as non-commercial, and (vi) may 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) our ability to satisfy our financial and volume commitment obligations, (iv) completion of acquisitions of additional properties and reserves, and (v) 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.

~~The decline in commodity prices since mid-2014 has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs.~~ We have been able to reduce drilling and completion costs due to a combination of optimizing well designs, lower contract rates for drilling rigs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics ~~in spite of~~giving consideration to the ~~severe drop in 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.

From time to time, our production has been adversely impacted by high natural gas gathering line pressures. Where it is cost effective, we install wellhead compression to enhance our ability to inject natural gas into the gathering system and, in some instances, install larger gathering lines to help mitigate the impact of high line pressures. Additionally, midstream companies that operate the natural gas gathering pipelines in the area continue to make significant capital investments to increase the capacity of their systems. While these actions have helped ~~reduce overall line pressures in the field, some of our producing locations have been curtailed on occasion due~~ to increase capacity for natural gas processing, we continue to experience line pressures exceeding system ~~limits.~~limits primarily due to further growth in field-wide production volumes.

To address 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 participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. The initial plan includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system, both expected to be completed by late 2018. Additionally, through the same framework, all of the parties ~~are working~~agreed to ~~form~~ a ~~cooperative~~ development plan to add another 200 MMcf/d plant ~~by mid-2019.~~in 2019. These agreements impose a baseline and incremental volume commitment which we are currently exceeding.

We have extended the use of oil gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases to these systems. We believe that oil gathering lines have several benefits, including a) reduced need to use trucks to gather our oil, 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 oil storage capacity, resulting in lower production location facility costs, and d) generally improved community relations.

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 ~~June~~September 30, 2017, we have identified over ~~1,200~~1,100 drilling locations across our acreage position. For 2017, we expect to drill ~~116~~118 gross operated horizontal wells of mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion program will cost ~~between $320 million and $340~~approximately $360 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. Additionally, 2017 drilling and

completion expenditures associated with non-operated properties isare expected to be ~~between $40~~approximately $60 million, ~~and $60 million.~~which is net of capital we expect to recover as described in "- Capital Expenditures" below. Full-year 2017 production is forecasted to be between ~~32,000~~33,000 BOED and ~~34,000~~35,000 BOED. Assuming a 2018 development program similar to what the Company has done in 2017, we expect to achieve year-over-year production growth of 25% or greater, while funding a majority of our expenditures through internally generated cash flow.

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

Results of Operations

Material changes ofto certain items in our condensed consolidated statements of operations included in our condensed consolidated financial statements for the periods presented are discussed below.

For the three months ended ~~June~~September 30, 2017 compared to the three months ended ~~June~~September 30, 2016

For the three months ended ~~June~~September 30, 2017, we reported net income of ~~$27.9~~$43.8 million compared to net loss of ~~$153.8~~$19.2 million during the three months ended ~~June~~September 30, 2016. Net income per basic and diluted share was ~~$0.14~~$0.22 for the three months ended ~~June~~September 30, 2017 compared to net loss per basic and diluted share of ~~$0.89~~$0.10 for the three months ended ~~June~~September 30, 2016. Net income per basic share for the three months ended ~~June~~September 30, 2017 increased by ~~$1.03~~$0.32 primarily due to the ceiling test impairment of ~~$144.1~~$25.5 million incurred during the three months ended ~~June~~September 30, 2016 ~~whereas~~(whereas no ceiling test impairment was recognized during the three months ended ~~June~~September 30, ~~2017.~~2017) and the 295% increase in revenues period over period. Revenues increased ~~213%~~ during the three months ended ~~June~~September 30, 2017 compared with the three months ended ~~June~~September 30, 2016 due to a ~~194%~~274% increase in production and a 7%6% increase in realized prices. As of ~~June~~September 30, 2017, we hahad 1,016 gross d~~633gross~~ producing wells, of ~~which339~~w~~ere~~hich 399 were horizontal, compared with ~~620~~635 gross producing wells, of which ~~223~~245 were horizontal, as of ~~June~~September 30, 2016.

Oil, Natural Gas, and NGL Production and Revenues - For the three months ended ~~June~~September 30, 2017, we recorded total oil, natural gas, and NGL revenues of ~~$75.0~~$103.6 million compared to ~~$23.9~~$26.2 million for the three months ended ~~June~~September 30, 2016, an increase of ~~$51.1~~$77.4 million or ~~213%~~295%. The following table summarizes key production and revenue statistics:


	Three Months Ended June 30,				Percentage		Three Months Ended September 30,				Percentage
	2017		2016		Change		2017		2016		Change
Production:
Oil (MBbls) ¹	1,262		508		148	%	1,726		517		234	%
Natural Gas (MMcf) ²	6,264		3,015		108	%	7,412		2,855		160	%
NGLs (MBbls) ³	662		—		nm		753		—		nm
MBOE ⁴	2,969		1,010		194	%	3,715		993		274	%
BOED ⁵	32,624		11,098		194	%	40,378		10,794		274	%

Revenues (in thousands):
Oil	$	51,939	$	17,793	192	%	$	73,144	$	18,451	296	%
Natural Gas	14,364		6,154		133	%	17,402		7,783		124	%
NGLs ³	8,733		—		nm		13,047		—		nm
	$	75,036	$	23,947	213	%	$	103,593	$	26,234	295	%
Average sales price:
Oil	$	41.15	$	35.06	17	%	$	42.37	$	35.67	19	%
Natural Gas	$	2.29	$	2.04	12	%	2.35		2.73		(14	)%
NGLs ³	$	13.18	$	—	nm		17.32		—		nm
BOE	$	25.28	$	23.71	7	%	$	27.89	$	26.42	6	%

¹"MBbl" refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.

²"MMcf" refers to one million cubic feet of natural gas.

³For 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.

⁴"MBOE" refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of natural gas by converting each six MMcf of natural gas to one MBbl of oil.

⁵"BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.

Net oil, natural gas, and NGL production for the three months ended ~~June~~September 30, 2017 averaged ~~32,624~~40,378 BOED, an increase of ~~194%~~274% over average production of ~~11,098~~10,794 BOED in the three months ended ~~June~~September 30, 2016. From ~~June~~September 30, 2016 to ~~June~~September 30, 2017, our well count increased by 7491 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 ~~194%~~274% increase in production and the 7%6% increase in average sales prices resulted in a significant increase in revenues.

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


	Three Months Ended June 30,				Three Months Ended September 30,
	2017		2016		2017		2016
Production costs	$	4,863	$	6,669	$	4,223	$	3,529
Workover	155		176		93		290
Transportation and gathering					838		—
Total LOE	$	5,018	$	6,845	$	5,154	$	3,819

Per BOE:
Production costs	$	1.64	$	6.60	$	1.14	$	3.55
Workover	0.05		0.17		0.03		0.29
Transportation and gathering					0.23		—
Total LOE	$	1.69	$	6.77	$	1.40	$	3.84

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells inand 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 three months ended ~~June~~September 30, 2017, we experienced ~~decreased~~increased production expense compared to three months ended ~~June~~September 30, 2016 ~~primarily~~ due to ~~significantly less expense related to environmental remediation~~a 113% increase in horizontal operated wells and ~~regulatory compliance projects during 2017, the~~a ~~consolidation of our operations into a more central geographic operating area,~~ 274%increase in production volumes. In addition, in the third quarter, we began delivering under new gathering agreements which resulted in transportation and gathering charges~~and a 26% reduction in our total number of vertical wells through divestitures and plugging activities.~~. Unit operating costs benefited from larger volumes of early production on the ~~23 horizontal~~horizontal wells turned to sales during the quarter in addition to the production from wells turned to sales after the ~~second~~third quarter of 2016.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. During the three months ended June 30, 2017, the Company increased its estimate for production taxes based on recent historical experience and additional information received during the period. Based on this analysis, the Company's prior period accruals were increased, resulting in an approximate $0.9 million increase to our production taxes. During the three months ended JuneSeptember 30, 2017, production taxes were ~~$9.5~~$10.1 million, or ~~$3.19~~$2.71 per BOE, compared to ~~$2.1~~$(1.5) million, or ~~$2.12~~$(1.47) per BOE, during the prior year period. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were ~~12.6%~~9.7% and ~~8.9%~~(5.6)% for the three months ended ~~June~~September 30, 2017 and 2016, respectively. During the three months ended ~~June~~September 30, 2017, the production tax rate ~~was increased to mirror~~reflects the significant increase in new production and its impact on severance tax. As discussed in Note 1, during the three months ended September 30, 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:


	Three Months Ended June 30,				Three Months Ended September 30,
(in thousands)	2017		2016		2017		2016
Depletion of oil and gas properties	$	25,742	$	10,965	$	32,944	$	9,273
Depreciation and accretion	685		309		796		362
Total DD&A	$	26,427	$	11,274	$	33,740	$	9,635

DD&A expense per BOE	$	8.90	$	11.16	$	9.08	$	9.70

For the three months ended ~~June~~September 30, 2017, DD&A was ~~$8.90~~$9.08 per BOE compared to ~~$11.16~~$9.70 per BOE for the three months ended ~~June~~September 30, 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 impairments of our full cost pool that primarily occurred during the first half of 2016 and the increase in our total proved reserves. 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 determines the depletion rate.

Full cost ceiling impairment - During the three months ended ~~June~~September 30, 2017, we had no impairment as compared to an impairment of ~~$144.1~~$25.5 million for the three months ended ~~June~~September 30, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.

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


	Three Months Ended June 30,						Three Months Ended September 30,
(in thousands)	2017			2016			2017			2016
G&A costs incurred	$	10,136		$	9,859		$	11,002		$	9,993
Capitalized costs	(2,531		)	(2,339		)	(2,518		)	(1,757		)
Total G&A	$	7,605		$	7,520		$	8,484		$	8,236

Non-Cash G&A	$	2,685		$	2,391		$	3,030		$	2,375
Cash G&A	4,920			5,129			5,454			5,861
Total G&A	$	7,605		$	7,520		$	8,484		$	8,236

Non-Cash G&A per BOE	$	0.90		$	2.37		$	0.82		$	2.39
Cash G&A per BOE	1.66			5.08			1.47			5.90
G&A Expense per BOE	$	2.56		$	7.45		$	2.29		$	8.29

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 ~~$7.6~~$8.5 million for the ~~second~~third quarter of 2017 were 1%3% higher than G&A for the same period of 2016. This increase is primarily due to a ~~53%~~32% increase in employee headcount from 7389 at ~~June~~September 30, 2016 to ~~112~~117 at ~~June~~September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity and contract services during 2017.

Our G&A expense for the three months ended ~~June~~September 30, 2017 includes stock-based compensation of ~~$2.7~~$3.0 million compared to $2.4 million for the three months ended ~~June~~September 30, 2016. Stock-based compensation is a non-cash charge that is based on the calculated fair value of stock options, performance-vested 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-vested 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.

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 three months ended ~~June~~September 30, 2016 to the three months ended ~~June~~September 30, 2017 reflects our overall increase in G&A activity.

Commodity derivative gains (losses) - As more fully described in Item 1. Financial Statements – Note 8, Commodity Derivative Instruments, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the three months ended ~~June~~September 30, 2017, we realized a cash settlement ~~loss~~gain of ~~less than~~ $0.1 million, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement ~~gain~~loss of ~~$0.4 million,~~$13.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts.

In addition, for the three months ended ~~June~~September 30, 2017, we recorded an unrealized ~~gain~~loss of ~~$1.4~~$2.5 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the three months ended ~~June~~September 30, 2016, we reported an unrealized ~~loss~~gain of ~~$6.1~~$0.4 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense for the three months ended ~~June~~September 30, 2017 or the prior year period. During the three months ended ~~June~~September 30, 2017 and 2016, the effective tax rates were substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the three months ended ~~June~~September 30, 2017 and 2016, the effective tax rate differed from the statutory rate primarily due to the recognition of the valuation allowance recorded against deferred tax assets.

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 cumulative losses in the prior periods 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 ~~June~~September 30, 2017. During the 2016 comparable period, we reached the same conclusion; therefore, a valuation allowance has been provided as of ~~June~~September 30, 2016.

For the ~~six~~nine months ended ~~June~~September 30, 2017 compared to the ~~six~~nine months ended ~~June~~September 30, 2016

For the ~~six~~nine months ended ~~June~~September 30, 2017, we reported net income of ~~$47.8~~$91.7 million compared to net loss of ~~$205.2~~$224.5 million during the ~~six~~nine months ended ~~June~~September 30, 2016. Net income per basic and diluted share was ~~$0.24~~$0.46 for the ~~six~~nine months ended ~~June~~September 30, 2017 compared to net loss per basic and diluted share of ~~$1.40~~$1.36 for the ~~six~~nine months ended ~~June~~September 30, 2016. Net income per basic share for the ~~six~~nine months ended ~~June~~September 30, 2017 increased by ~~$1.64~~$1.82 primarily due to the ceiling test impairment of ~~$189.8~~$215.2 million incurred during the ~~six~~nine months ended ~~June~~September 30, 2016 ~~whereas~~(whereas no ceiling test impairment was recognized during the ~~six~~nine months ended ~~June~~September 30, ~~2017.~~2017) and the 225% increase in revenues period over period. Revenues increased ~~181%~~ during the ~~six~~nine months ended ~~June~~September 30, 2017 compared with the ~~six~~nine months ended ~~June~~September 30, 2016 due to a ~~122%~~171% increase in production and a ~~27%~~20% increase in realized prices. As of ~~June~~September 30, 2017, we had ~~633~~1,016 gross producing wells, of which~~339~~ 399 werehorizontal, compared with ~~620~~635 gross producing wells, of which ~~223~~245 were horizontal, as of ~~June~~September 30, 2016.

Oil, Natural Gas, and NGL Production and Revenues - For the ~~six~~nine months ended ~~June~~September 30, 2017, we recorded total oil, natural gas, and NGL revenues of ~~$118.8~~$222.4 million compared to ~~$42.2~~$68.5 million for the ~~six~~nine months ended ~~June~~September 30, 2016, an increase of ~~$76.6~~$154.0 million or ~~181%~~225%. The following table summarizes key production and revenue statistics:


	Six Months Ended June 30,				Percentage		Nine Months Ended September 30,				Percentage
	2017		2016		Change		2017		2016		Change
Production:
Oil (MBbls)	1,942		1,035		88	%	3,668		1,552		136	%
Natural Gas (MMcf)	9,710		6,136		58	%	17,122		8,991		90	%
NGLs (MBbls) ¹	1,005		—		nm		1,758		—		nm
MBOE	4,566		2,057		122	%	8,280		3,050		171	%
BOED	25,224		11,304		123	%	30,331		11,133		172	%

Revenues (in thousands):
Oil	$	81,088	$	30,387	167	%	$	154,232	$	48,838	216	%
Natural Gas	23,543		11,833		99	%	40,945		19,616		109	%
NGLs ¹	14,195		—		nm		27,242		—		nm
	$	118,826	$	42,220	181	%	$	222,419	$	68,454	225	%
Average sales price:
Oil	$	41.75	$	29.37	42	%	$	42.04	$	31.47	34	%
Natural Gas	$	2.42	$	1.93	25	%	2.39		2.18		10	%
NGLs ¹	$	14.12	$	—	nm		15.49		—		nm
BOE	$	26.03	$	20.52	27	%	$	26.86	$	22.44	20	%

¹For 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.

Net oil, natural gas, and NGL production for the ~~six~~nine months ended ~~June~~September 30, 2017 averaged ~~25,224~~30,331 BOED, an increase of ~~123%~~172% over average production of ~~11,304~~11,133 BOED in the ~~six~~nine months ended ~~June~~September 30, 2016. From ~~June~~September 30, 2016 to ~~June~~September 30, 2017, our well count increased by 91 ne74~~net~~t 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 ~~122%~~171% increase in production and the ~~27%~~20% 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):


	Six Months Ended June 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Production costs	$	8,336	$	10,935	$	12,511	$	14,464
Workover	404		209		$	497	$	499
Transportation and gathering					$	886	$	—
Total LOE	$	8,740	$	11,144	$	13,894	$	14,963

Per BOE:
Production costs	$	1.83	$	5.32	$	1.51	$	4.74
Workover	0.09		0.10		0.06		0.16
Transportation and gathering					0.11		—
Total LOE	$	1.92	$	5.42	$	1.68	$	4.90

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells inand our overall production volumes and, to a lesser extent, on ~~fluctuation~~fluctuations in oil field service costs and changes in the production mix of oil and natural gas.During the ~~six~~nine months ended ~~June~~September 30, 2017, we experienceddecreasedproduction expense compared to the ~~six~~nine months ended ~~June~~September 30, 2016 primarily due to significantly less expense related to environmental remediation and regulatory compliance projects during 2017 and the consolidation of our operations into a more central geographic operating area. This decrease was partially offset by transportation and ~~a 26% reduction in our total number of vertical wells through divestitures and plugging activities.~~gathering charges resulting from new gathering agreements. Unit operating costs benefited from larger volumes of early production on ~~the 48 horizontal~~the 87 horizontal wells turned to sales during the ~~six~~nine months ended ~~June~~September 30, 2017 in addition to the production on wells turned to sales after the ~~second~~ thirdquarter of2016.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. During the six months ended June 30, 2017, the Company reduced its estimate for production taxes based on recent historical experience and additional information received during the period. Based on this analysis, the Company's accrual was reduced, resulting in an approximate $1.1 million reduction to our production taxes. Production taxes were ~~$10.9~~$21.0 million, or ~~$2.39~~$2.54 per BOE, for the ~~six~~nine months ended ~~June~~September 30, 2017, compared to ~~$4.0~~$2.5 million, or ~~$1.93~~$0.82 per BOE, for the ~~six~~nine months ended ~~June~~September 30, 2016. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were ~~9.2%~~9.4% and ~~9.4%~~3.7% for the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, respectively. During the nine months ended September 30, 2017, the Company adjusted its estimates for production taxes to reflect a significant increase in new production. As discussed in Note 1, during the nine months ended September 30, 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:


	Six Months Ended June 30,				Nine Months Ended September 30,
(in thousands)	2017		2016		2017		2016
Depletion of oil and gas properties	$	38,445	$	22,708	$	71,389	$	31,981
Depreciation and accretion	1,211		658		2,007		1,020
Total DD&A	$	39,656	$	23,366	$	73,396	$	33,001

DD&A expense per BOE	$	8.69	$	11.36	$	8.86	$	10.82

For the ~~six~~nine months ended ~~June~~September 30, 2017, DD&A was ~~$8.69~~$8.86 per BOE compared to ~~$11.36~~$10.82 per BOE for the ~~six~~nine months ended ~~June~~September 30, 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 impairments of our full cost pool that primarily occurred during the first half of 2016 and the increase in our total proved reserves. 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 ~~six~~nine months ended ~~June~~September 30, 2017, we had no impairment as compared to an impairment of ~~$189.8~~$215.2 million for the ~~six~~nine months ended ~~June~~September 30, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.

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


	Six Months Ended June 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			2016
G&A costs incurred	$	21,016		$	17,951		$	32,018		$	27,944
Capitalized costs	(5,211		)	(2,988		)	(7,729		)	(4,745		)
Total G&A	$	15,805		$	14,963		$	24,289		$	23,199

Non-Cash G&A	$	5,360		$	4,910		$	8,390		$	7,285
Cash G&A	10,445			10,053			15,899			15,914
Total G&A	$	15,805		$	14,963		$	24,289		$	23,199

Non-Cash G&A per BOE	$	1.17		$	2.39		$	1.01		$	2.39
Cash G&A per BOE	2.29			4.89			1.92			5.22
G&A Expense per BOE	$	3.46		$	7.28		$	2.93		$	7.61

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 ~~$15.8~~$24.3 million for the ~~second~~third quarter of 2017 were 6%5% higher than G&A for the same period of 2016. This increase is primarily due to a ~~53%~~32% increase in employee headcount from 7389 at ~~June~~September 30, 2016 to ~~112~~117 at ~~June~~September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity and contract services during 2017.

Our G&A expense for the ~~six~~nine months ended ~~June~~September 30, 2017 includes stock-based compensation of ~~$5.4~~$8.4 million compared to ~~$4.9~~$7.3 million for the ~~six~~nine months ended ~~June~~September 30, 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 ~~six~~nine months ended ~~June~~September 30, 2016 to the ~~six~~nine months ended ~~June~~September 30, 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 Item 1. Financial Statements – Note 8, Commodity Derivative Instruments, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the ~~six~~nine months ended ~~June~~September 30, 2017, we realized a cash settlement loss of ~~$0.1 million,~~$26.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $2.9 million.

In addition, for the ~~six~~nine months ended ~~June~~September 30, 2017, we recorded an unrealized gain of ~~$4.8~~$2.4 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the ~~six~~nine months ended ~~June~~September 30, 2016, we reported an unrealized loss of ~~$6.9~~$6.5 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense for the ~~six~~nine months ended ~~June~~September 30, 2017 or the prior year period. As explained in more detail in the "-Income taxes" section above, during the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, the effective tax rates were substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, the effective tax rate differed from the statutory rate primarily due to the recognition of the valuation allowance recorded against deferred tax assets.

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. During the ~~six~~nine months ended ~~June~~September 30, 2017, the NYMEX-WTI oil price ranged from a high of $54.48 per Bbl on February 23, 2017 to a low of $42.48 per Bbl on June 21, 2017, while 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. These 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.

At ~~June~~September 30, 2017, we had cash and cash equivalents of ~~$36.7~~$21.3 million, $80.0 million outstanding on our Senior Notes, and a ~~$90.0~~$150.0 million outstanding balance under our revolving credit facility. Our sources and (uses) of funds for the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 are summarized below (in thousands):


	Six Months Ended June 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net cash provided by operations	$	74,458		$	12,235		$	142,817		$	33,193
Capital expenditures	(221,299		)	(546,112		)	(383,483		)	(582,149		)
Net cash provided by other investing activities	75,609			5,284			95,265			5,979
Net cash (used in) provided by equity financing activities	(451		)	543,092			(517		)	542,901
Net cash provided by (used in) debt financing activities	89,745			(2,364		)	148,628			(2,666		)
Net increase in cash and equivalents	$	18,062		$	12,135
Net increase (decrease) in cash and equivalents							$	2,710		$	(2,742	)

Net cash provided by operating activities was ~~$74.5~~$142.8 million and ~~$12.2~~$33.2 million for the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, respectively. The increase in cash from operating activities reflects the increase in realized commodity prices and production.

Net cash provided by other investing activities was ~~$75.6~~$95.3 million and ~~$5.3~~$6.0 million for the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2017, we received proceeds from the sale of oil and gas properties and other of $77.0 million, and $18.2 million was released from an escrow account relating to an acquisition. For the nine months ended September 30, 2016, we received proceeds from the sale of oil and gas properties of ~~$77.2 million and $23.5 million, respectively. These~~$24.2 million; these inflows were offset by net cash deposited in escrow of ~~$1.5 million and~~ $18.2 ~~million for the six months ended June 30, 2017 and 2016, respectively.~~million.

During the ~~six~~nine months ended ~~June~~September 30, 2017, we received cash proceeds from borrowing ~~$110.0~~$170.0 million under the Revolver and used cash proceeds from a divestiture to repay $20.0 million of ~~this balance.~~these borrowings.

Credit Facility

The Revolver has a maturity date of December 15, 2019. The agreement was most recently amended in ~~April~~September 2017. 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, discounted by 10%. Amounts borrowed under the Revolver are secured by certain of our assets, including~~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 ~~April 28,~~September 27, 2017, the borrowing base was increased from $~~160~~225 million to $~~225 million; however, the Company chose to limit aggregate elected commitments to$210~~400 million. As of ~~June~~September 30, 2017, there was a $~~90.0~~150.0 million outstanding principal balance and $0.5 million in letters of credit outstanding,

leaving $~~119.5~~249.5 million available to us for future borrowings. The next semi-annual redetermination is scheduled for ~~November 2017.~~April 2018. Interest on the Revolver accrues at a variable rate. The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization.

The Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. ~~Under the requirements,~~In particular, the Company ~~on a quarterly basis,~~ must not (a) ~~at any time~~ permit its ratio of total funded debt ~~as of such time~~ 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 than 1.0 to 1.0.

Senior Notes

On June 14, 2016, the Company issued $80 million aggregate principal amount of the Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each ~~year, beginning on December 15, 2016.~~year. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and ~~are~~will be guaranteed on a senior unsecured basis by ~~the Company’s existing and~~any future subsidiaries of the Company that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes at the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100.0% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the 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 109.00% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

Capital Expenditures

Capital expenditures for ~~oil~~drilling and ~~natural gas~~completion activities totaled ~~$268.1~~$159.5 million and ~~$535.8~~$383.0 million for the ~~six~~three and nine months ended ~~June~~September 30, 2017, ~~and 2016,~~ respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):


	Six Months Ended June 30,				Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
Capital expenditures for drilling and completion activities
Operated					$	94,971	$	290,717
Non-operated					64,561		92,311
Total					159,532		383,028
	2017		2016
Acquisitions of oil and gas properties and leasehold	$	32,842	$	499,766
Capital expenditures for drilling and completion activities	223,496		32,944
Acquisitions of oil and gas properties and leasehold*					56,835		89,677
Capitalized interest, capitalized G&A, and other	11,796		3,099		5,718		17,514
Accrual basis capital expenditures*	$	268,134	$	535,809
Accrual basis capital expenditures**					$	222,085	$	490,219

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

The ~~majority of~~year-to-date non-operated capital expenditures ~~during~~are driven by the ~~six~~Company's decision to participate in several wells located within our core operating area. The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements. If successful, the Company anticipates recovering approximately 50% of the year-to-date non-operated capital expenditures.

During the nine months ended ~~June 30, 2017 were associated with the cost of drilling and completing wells. During the six months ended June~~September 30, 2017, we drilled 6387 operated horizontal wells and completed 4887 operated horizontal wells. As of ~~June~~September 30, 2017, we are the operator ofo 59f 46 gross ~~(50~~(36 net) h~~horizontal~~orizontal wells in progress ~~which excludes~~ ~~25 gross (20 net) horizontal wells for which we have only set surface casings. All of the wells in progress at June 30, 2017 are scheduled to commence production before December 31, 2017.~~.

For the ~~six~~nine months ended ~~June~~September 30, 2017, we have participated in ~~the completion of 20~~123 gross ~~(2 net) non-operated horizontal wells. As of June 30, 2017, we are participating in 89 gross (13~~(23 net) non-operated horizontal ~~wells in progress.~~wells.

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, ~~and~~ 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 the remainder of 2017.

We anticipate that our 2017 drilling and completion capital expenditures for operated wells will be ~~between $320 million and $340~~approximately $360 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. Additionally, 2017 drilling and completion expenditures associated with non-operated properties isare expected to be ~~between $40~~approximately $60 million, ~~and $60 million.~~which is net of capital we expect to recover as described in "- Capital Expenditures" above. Assuming a 2018 development program similar to what the Company has done in 2017, we expect to achieve year-over-year production growth of 25% or greater, while funding a majority of our expenditures through internally generated cash flow.

For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility. However, should this not meet 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 Natural 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 ~~June~~September 30, 2017, we had open positions covering ~~0.9~~1.3 million barrels of oil and ~~7,235~~8,984 MMcf of natural gas. We do not use derivative instruments for speculative purposes.

During the ~~six~~nine months ended ~~June~~September 30, 2017, we reported an unrealized commodity activity gain of ~~$4.8~~$2.4 million. Unrealized gains are non-cash items. We also reported a realized loss of ~~$0.1 million,~~$26.0 thousand, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.

At ~~June~~September 30, 2017, we estimated that the fair value of our various commodity derivative contracts was a net ~~asset~~liability of ~~$1.6~~$1.2 million. See Item 1. Financial Statements – Note 9, Fair Value Measurements, for a description of the methods we use to estimate the fair values of commodity derivative instruments.

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 measure we currently report.

Adjusted EBITDA

We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed 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, cash flows from operations, investing, or financing activities, and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP. We believe that adjusted EBITDA is a 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):


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
Adjusted EBITDA:
Net income (loss)	$	27,936		$	(153,848	)	$	47,816		$	(205,249	)	$	43,848		$	(19,241	)	$	91,664		$	(224,490	)
Depreciation, depletion, and accretion	26,427			11,274			39,656			23,366			33,740			9,635			73,396			33,001
Full cost ceiling impairment	—			144,149			—			189,770			—			25,453			—			215,223
Income tax expense	—			101			—			101			—			5			—			106
Stock-based compensation	2,685			2,392			5,360			4,911			3,030			2,374			8,390			7,285
Mark-to-market of commodity derivative contracts:
Total (gain) loss on commodity derivatives contracts	(1,328		)	5,704			(4,707		)	4,024			2,383			(407		)	(2,324		)	3,617
Cash settlements on commodity derivative contracts	153			1,592			234			4,651			544			486			778			5,137
Interest income, net of interest expense	(20		)	(167		)	(31		)	(169		)	(16		)	(11		)	(47		)	(176		)
Adjusted EBITDA	$	55,853		$	11,197		$	88,328		$	21,405		$	83,529		$	18,294		$	171,857		$	39,703

Critical Accounting Policies

We prepare our condensed 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 condensed 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.

There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used from those disclosed in the "Management’s Discussion and Analysis of Financial Condition and Results of Operations" section of the Annual Report on Form 10-K filed with the SEC on February 23, 2017 and in the financial statements and accompanying notes contained in that report. Item 1. Financial Statements – Note 1, Organization and Summary of Significant Accounting Policies, to the accompanying condensed consolidated financial statements included elsewhere in this report provides information regarding recently issued accounting pronouncements.

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 production, future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, future production relative to volume commitments, and the closing and effect of proposed transactions.

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.

See "Risk Factors" in this report and in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 23, 2017 for a discussion of risk factors that affect our business, financial condition, and results of operations. These risks include, among others, those associated with the following:

declines in oil and natural gas prices;

operating hazards that adversely affect our ability to conduct business;

uncertainties in the estimates of proved reserves;

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

the strength and financial resources of our competitors;

our ability to complete, and the effect of, pending and planned transactions;

our ability to successfully identify, execute, and effectively integrate acquisitions;

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."


ITEM 3.	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 ~~69%~~71% and ~~68%~~69% of our revenue during the three and ~~six~~nine months ended ~~June~~September 30, 2017, respectively, was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a ~~$6.3~~$8.6 million and ~~$9.7~~$18.3 million change in revenues during the three and ~~six~~nine months ended ~~June~~September 30, 2017, respectively, a $0.25 per Mcf change in our realized natural gas price would have resulted in a ~~$1.6~~$1.9 million and ~~$2.4~~$4.3 million change in our natural gas revenues for the three and ~~six~~nine months ended ~~June~~September 30, 2017, respectively, and a $5 per barrel change in our realized NGL price would have resulted in a ~~$3.3~~$3.8 million and ~~$5.0~~$8.8 million change in our NGL revenues for the three and ~~six~~nine months ended ~~June~~September 30, 2017, respectively.

During the three months ended ~~June~~September 30, 2017, the price of oil, natural gas, and NGLs increased relative to the ~~second~~third quarter of 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 of ~~June~~September 30, 2017, we had open oil derivatives in a net ~~asset~~liability position with a fair value of ~~$1.6~~$1.2 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 ~~$0.6~~$1.4 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 ~~$2.1~~$1.2 million. A summary of our open positions as of ~~June~~September 30, 2017 is set forth in Item 1. Financial Statements - Note 8, Commodity Derivative Instruments.

Interest Rate Risk - At ~~June~~September 30, 2017, we had $~~90.0~~150 million in 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 ~~six~~nine months ended ~~June~~September 30, 2017, we incurred interest at an annualized rate of ~~2.8%~~3.3%. 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%, our interest payments in each of the three and ~~six~~nine months ended ~~June~~September 30, 2017 would have changed by ~~$0.1 million.~~$0.3 million and $0.4 million, respectively.

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 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~~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 ~~second~~third quarter of 2017 as the amounts due to us from counterparties has increased.


ITEM 4.	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-Q (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.

PART II


Item 1.	Legal Proceedings

Except as disclosed in Note 14 to the accompanying condensed consolidated financial statements, during the quarter, there were no material developments regarding legal matters, which were previously described under Item 3, Legal Proceedings, of the Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 23, 2017. This information should be considered carefully together with other information in this report and other reports and materials we file with the SEC.


Item 1A.	Risk Factors

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity, and the trading price of our common stock are described under Item 1A, Risk Factors, of the Annual Report on Form 10-K filed with the SEC on February 23, 2017. This information should be considered carefully together with other information in this report and other reports and materials that we file with the SEC.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of equity securities by the Company

Period Total Number of Shares Purchased Average Price Paid per Share
April 1, 2017 - April 30, 2017 ⁽¹⁾
890
$ 8.11
May 1, 2017 - May 31, 2017 ⁽¹⁾
16,945
$ 7.07
June 1, 2017 - June 30, 2017 ⁽¹⁾
1,096
$ 6.29
Total 18,931



Period	Total Number of Shares Purchased	Average Price Paid per Share
July 1, 2017 - July 31, 2017 ⁽¹⁾	—	$	—
August 1, 2017 - August 31, 2017 ⁽¹⁾	5,167	$	7.68
September 1, 2017 - September 30, 2017 ⁽¹⁾	3,235	$	7.95
Total	8,402

(1) Pursuant to statutory minimum withholding requirements, certain of our employees 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 any publicly announced repurchase plan.


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable


Item 5.	Other Information

~~None.~~On August 18, 2017, the Company amended its bylaws to, among other things, include advance notice provisions pursuant to which a shareholder seeking to propose a candidate for election as director or other business at a meeting of the Company’s shareholders is required to provide advance notice of the proposal to the Company. This notice must contain specified information regarding the shareholder and the proposal and must generally be provided (i) in the case of an annual meeting, not earlier than the 120th day, and not later than the 90th day, prior to the first anniversary of the preceding year’s annual meeting and (ii) in the case of a special meeting, not earlier than the 90th day, and not later than the 80th day, prior to such meeting. Subject to certain possible exceptions set forth in the amended and restated bylaws, notice of proposals to be made at the Company’s 2018 annual meeting of shareholders must be provided no earlier than February 15, 2018 and no later than March 19, 2018.

Item 6. Exhibits



Exhibit Number		Exhibit
~~3.1~~3.2		~~Second~~ Amended and Restated ~~Articles of Incorporation~~Bylaws of SRC Energy Inc. ~~(the "Company")~~, effective as of ~~June 15,~~August 18, 2017 ~~(incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on June 20, 2017).~~
~~3.2.1~~		~~Bylaws of the Company (including Amendment No. 1 thereto) (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K filed on April 22, 2016)~~
~~3.2.2~~		~~Amendment No. 2 to Bylaws of the Company, effective as of June 15, 2017 (incorporated by reference to Exhibit 3.2.2 to the Company’s Current Report on Form 8-K filed on June 20, 2017)~~
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 adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
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 adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
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		Eleventh Amendment to Amended and Restated Credit Agreement, dated as of September 27, 2017, among SRC Energy Inc. (formerly known as Synergy Resources Corporation), SunTrust Bank as Administrative Agent and as an Issuing Bank, and the lenders party thereto *
101.INS		XBRL Instance 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

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 ~~3rd~~1st day of ~~August,~~November, 2017.



	SRC Energy Inc.

	/s/ Lynn A. Peterson
	Lynn A. Peterson, President and Chief Executive Officer (Principal Executive Officer)

	/s/ James P. Henderson
	James P. Henderson, Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

	/s/ Jared C. Grenzenbach
	Jared C. Grenzenbach, Vice President and Chief Accounting Officer (Principal Accounting Officer)