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 September 30, ~~2017~~2018



	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: ~~201,089,000 outstanding~~242,600,829 outstanding shares of common stock as of October ~~31, 2017.~~29, 2018.

SRC ENERGY INC.

Index



		Page
Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Condensed Consolidated Balance Sheets as of September 30, ~~2017~~2018 and December 31, ~~2016~~2017	2

	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017	3

	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, ~~2017~~2018 and ~~2016~~2017	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2422

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4138

Item 4.	Controls and Procedures	4239

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings	4340

Item 1A.	Risk Factors	4340

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4341

Item 3.	Defaults of Senior Securities	4341

Item 4.	Mine Safety Disclosures	4341

Item 5.	Other Information	4341

Item 6.	Exhibits	4442

SIGNATURES		4543

SRC ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands, except share data)


ASSETS	September 30, 2017			December 31, 2016			September 30, 2018		December 31, 2017
Current assets:
Cash and cash equivalents	$	21,325		$	18,615		$	19,236	$	48,772
Accounts receivable:
Oil, natural gas, and NGL sales	72,309			25,728			110,912		86,013
Trade	45,280			6,805			29,559		18,134
Commodity derivative assets	—			297
Other current assets	6,289			2,739			11,996		7,116
Total current assets	145,203			54,184			171,703		160,035

Property and equipment:
Oil and gas properties, full cost method:
Unproved properties and land, not subject to depletion	327,154			398,547
Proved properties, net of accumulated depletion	758,135			424,082			1,364,116		970,584
Wells in progress	158,192			81,780			244,206		106,269
Unproved properties and land, not subject to depletion							748,695		793,669
Oil and gas properties, net	1,243,481			904,409			2,357,017		1,870,522
Other property and equipment, net	6,152			4,327			5,902		6,054
Total property and equipment, net	1,249,633			908,736			2,362,919		1,876,576
Cash held in escrow and other deposits	—			18,248
Goodwill	40,711			40,711			40,711		40,711
Other assets	2,359			2,234			3,599		2,242
Total assets	$	1,437,906		$	1,024,113		$	2,578,932	$	2,079,564

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	134,144		$	52,453		$	171,951	$	74,672
Revenue payable	58,742			16,557			82,670		64,111
Production taxes payable	37,017			17,673			77,115		52,413
Asset retirement obligations	2,738			2,683			2,771		3,246
Commodity derivative liabilities	786			2,874			18,570		7,865
Total current liabilities	233,427			92,240			353,077		202,307

Revolving credit facility	150,000			—			115,000		—
Notes payable, net of issuance costs	76,216			75,614			539,050		538,186
Commodity derivative liabilities	394			—			1,671		—
Asset retirement obligations	33,981			13,775			48,951		28,376
Deferred taxes							18,076		—
Other liabilities	2,268			1,745			2,308		2,261
Total liabilities	496,286			183,374			1,078,133		771,130

Commitments and contingencies (See Note 14)
Commitments and contingencies (See Note 15)

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: 200,909,101 and 200,647,572 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	201			201
Common stock - $0.001 par value, 400,000,000 and 300,000,000 shares authorized: 242,572,199 and 241,365,522 shares issued and outstanding as of September 30, 2018 and December 31, 2017, respectively							243		241
Additional paid-in capital	1,158,317			1,148,998			1,488,588		1,474,273
Retained deficit	(216,898		)	(308,460		)
Retained earnings (deficit)							11,968		(166,080		)
Total shareholders' equity	941,620			840,739			1,500,799		1,308,434

Total liabilities and shareholders' equity	$	1,437,906		$	1,024,113		$	2,578,932	$	2,079,564

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017		2016			Three Months Ended September 30,						Nine Months Ended September 30,
												2018			2017			2018			2017
Oil, natural gas, and NGL revenues	$	103,593		$	26,234		$	222,419	$	68,454		$	160,978		$	103,593		$	455,298		$	222,419
Sales of purchased oil	—			—			1,268		—
Total revenues	103,593			26,234			223,687		68,454

Expenses:
Lease operating expenses	5,154			3,819			13,894		14,963			10,360			4,316			29,868			13,008
Transportation and gathering												1,994			838			5,729			1,136
Production taxes	10,083			(1,461		)	21,013		2,509			12,824			10,083			41,325			21,013
Costs of purchased oil	—			—			1,518		—
Depreciation, depletion, and accretion	33,740			9,635			73,396		33,001			45,188			33,740			124,146			73,396
Full cost ceiling impairment	—			25,453			—		215,223
Unused commitment charge	—			205			669		505			—			—			—			669
General and administrative	8,484			8,236			24,289		23,199			10,685			8,484			29,691			24,289
Total expenses	57,461			45,887			134,779		289,400			81,051			57,461			230,759			133,511

Operating income (loss)	46,132			(19,653		)	88,908		(220,946		)
Operating income												79,927			46,132			224,539			88,908

Other income (expense):
Commodity derivatives gain (loss)	(2,383		)	407			2,324		(3,617		)	(8,529		)	(2,383		)	(28,604		)	2,324
Interest expense, net of amounts capitalized	—			—			—		—			—			—			—			—
Interest income	16			11			47		176			23			16			37			47
Other income (expense)	83			(1		)	385		3
Other income												125			83			152			385
Total other income (expense)	(2,284		)	417			2,756		(3,438		)	(8,381		)	(2,284		)	(28,415		)	2,756

Income (Loss) before income taxes	43,848			(19,236		)	91,664		(224,384		)
Income before income taxes												71,546			43,848			196,124			91,664

Income tax expense	—			5			—		106			8,918			—			18,076			—
Net income (loss)	$	43,848		$	(19,241	)	$	91,664	$	(224,490	)
Net income												$	62,628		$	43,848		$	178,048		$	91,664

Net income (loss) per common share:
Net income per common share:
Basic	$	0.22		$	(0.10	)	$	0.46	$	(1.36	)	$	0.26		$	0.22		$	0.74		$	0.46
Diluted	$	0.22		$	(0.10	)	$	0.46	$	(1.36	)	$	0.26		$	0.22		$	0.73		$	0.46

Weighted-average shares outstanding:
Basic	200,881,447			200,515,555			200,807,436		164,771,544			242,536,781			200,881,447			242,184,348			200,807,436
Diluted	201,460,915			200,515,555			201,326,129		164,771,544			243,560,046			201,460,915			243,207,058			201,326,129

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)

Nine Months Ended September 30,
2017 2016
Cash flows from operating activities:
Net income (loss) $ 91,664
$ (224,490 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and accretion 73,396
33,001
Full cost ceiling impairment —
215,223
Settlement of asset retirement obligation (4,077 ) (196 )
Stock-based compensation 8,390
7,285
Mark-to-market of commodity derivative contracts:
Total (gain) loss on commodity derivatives contracts (2,324 ) 3,617
Cash settlements on commodity derivative contracts 778
5,137
Changes in operating assets and liabilities:
Accounts receivable
Oil, natural gas, and NGL sales (46,581 ) 602
Trade (38,446 ) 2,679
Accounts payable and accrued expenses 1,413
1,761
Revenue payable 41,997
(363 )
Production taxes payable 17,548
(10,158 )
Other (941 ) (905 )
Net cash provided by operating activities 142,817
33,193

Cash flows from investing activities:
Acquisition of oil and gas properties and leaseholds (62,562 ) (503,357 )
Capital expenditures for drilling and completion activities (305,636 ) (72,375 )
Other capital expenditures (11,198 ) (3,078 )
Land and other property and equipment (4,087 ) (3,339 )
Cash held in escrow 18,248
(18,244 )
Proceeds from sales of oil and gas properties and other 77,017
24,223
Net cash used in investing activities (288,218 ) (576,170 )

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

Net increase (decrease) in cash and equivalents 2,710
(2,742 )

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

Cash and equivalents at end of period $ 21,325
$ 63,757



	Nine Months Ended September 30,
	2018			2017
Cash flows from operating activities:
Net income	$	178,048		$	91,664
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and accretion	124,146			73,396
Settlement of asset retirement obligation	(5,234		)	(4,077		)
Provision for deferred taxes	18,076			—
Stock-based compensation expense	9,347			8,390
Mark-to-market of commodity derivative contracts:
Total loss (gain) on commodity derivatives contracts	28,604			(2,324		)
Cash settlements on commodity derivative contracts	(13,263		)	778
Changes in operating assets and liabilities	3,830			(25,010		)
Net cash provided by operating activities	343,554			142,817

Cash flows from investing activities:
Acquisition of oil and gas properties and leaseholds	(129,069		)	(62,562		)
Capital expenditures for drilling and completion activities	(331,702		)	(305,636		)
Other capital expenditures	(26,439		)	(11,198		)
Acquisition of land and other property and equipment	(2,914		)	(4,058		)
Proceeds from sales of oil and gas properties and other	1,233			77,017
Net cash used in investing activities	(488,891		)	(306,437		)

Cash flows from financing activities:
Proceeds from the employee exercise of stock options	4,302			114
Payment of employee payroll taxes in connection with shares withheld	(1,106		)	(631		)
Proceeds from the revolving credit facility	115,000			170,000
Principal repayments on the revolving credit facility	—			(20,000		)
Fees on debt and equity issuances and revolving credit facility amendments	(2,173		)	(1,372		)
Capital lease payments	(222		)	—
Net cash provided by financing activities	115,801			148,111

Net decrease in cash, cash equivalents, and restricted cash	(29,536		)	(15,509		)

Cash, cash equivalents, and restricted cash at beginning of period	48,772			36,834

Cash, cash equivalents, and restricted cash at end of period	$	19,236		$	21,325

Supplemental Cash Flow Information (See Note ~~15)~~16)

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 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~~American under 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 condensed 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~~2017 was derived from the Company's annual consolidated financial statements included within its Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017 as filed with the SEC on February ~~23, 2017.~~21, 2018. 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.~~2017.

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~~revenues (“major customers”) for each of the periods presented are shown in the following table:


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,
Major Customers	2017	2016	2017	2016	2018	2017	2018	2017
Company A	30%	*	27%	*	23%	30%	13%	27%
Company B	27%	20%	26%	20%	21%	27%	19%	26%
Company C	13%	12%	15%	*	14%	13%	28%	15%
Company D	*	10%	*	11%	14%	*	11%	*
Company E	*	27%	*	38%	14%	*	16%	*

* 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~~contracts would not have a material adverse effect on us. Our oil and natural gas production

is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.

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

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


	As of	As of	As of	As of
Major Customers	September 30, 2017	December 31, 2016	September 30, 2018	December 31, 2017
Company A	25%	23%	23%	26%
Company B	16%	*	16%	16%
Company C	*	43%	14%	23%
Company D	*	10%	14%	*
Company E			*	11%

* 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,~~May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting ~~Standards~~Standard Update ("ASU") ~~2016-09, “Improvements to Employee Share-Based Payment Accounting”~~2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU ~~2016-09”~~2014-09”), which ~~intends~~establishes a comprehensive new revenue recognition standard designed to ~~improve~~depict the ~~accounting~~transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for ~~share-based payment transactions.~~those goods or services. In March 2016, the FASB released certain implementation guidance through ASU ~~2016-09 changes several aspects~~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 ~~accounting for share-based payment award transactions, including: (1) Accounting~~full or modified retrospective transition method, 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~~the standard became effective for ~~public businesses for fiscal years, and interim~~annual reporting periods ~~within those fiscal years,~~ beginning after December 15, ~~2016,~~2017 including interim periods within that period. The Company adopted the guidance using the modified retrospective method with ~~early adoption permitted. We adopted this pronouncement~~the effective date of January 1, ~~2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will~~2018. The Company did 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~~record a cumulative-effect adjustment to the opening balance of ~~$0.1 million to~~ retained earnings as ~~of the date of adoption.~~no adjustment was necessary. The adoption of the ~~other provisions~~Revenue ASUs did not ~~materially~~ impact net income or cash flows. See Note 14 for the ~~consolidated financial statements.~~

~~In January 2017,~~new disclosures required by 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.Revenue ASUs.

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.~~2018. 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. While the Company does not expect net income (loss) or cash flows to be impacted, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation, and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies, and control activities that will occur as a result of the adoption of this ASU. The Company plans to 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 estimates:~~ During the nine months ended 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 nine months ended 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
	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
Oil and gas properties, full cost method:
Costs of proved properties:
Producing and non-producing							$	2,148,278		$	1,629,789
Less, accumulated depletion and full cost ceiling impairments							(784,162		)	(659,205		)
Subtotal, proved properties, net							1,364,116			970,584

Costs of wells in progress							244,206			106,269

Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs	$	319,954		$	392,561		739,303			786,469
Land	7,200			5,986			9,392			7,200
Subtotal, unproved properties and land	327,154			398,547			748,695			793,669

Costs of wells in progress	158,192			81,780

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

Costs of other property and equipment:
Other property and equipment	7,790			5,063			9,462			8,134
Less, accumulated depreciation	(1,638		)	(736		)	(3,560		)	(2,080		)
Subtotal, other property and equipment, net	6,152			4,327			5,902			6,054

Total property and equipment, net	$	1,249,633		$	908,736		$	2,362,919		$	1,876,576

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 September 30, 2018 and 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 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 $25.5 million for the three months ended September 30, 2016. Impairments for the nine months ended September 30, 2016 totaled $215.2 million. No impairments were ~~recognized for the comparable 2017 periods.~~necessary.

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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Capitalized overhead	$	3,129	$	2,518	$	9,522	$	7,729


3.	3. Acquisitions ~~Swaps, and Divestitures~~

~~Acquisitions and Swaps~~

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

September ~~2017~~2018 Acquisition and Swap

In September ~~2017, we~~2018, the Company completed the ~~second closing~~purchase of ~~the GC Acquisition (as defined in "-June 2016 Acquisition"~~ ~~below). At the second closing, we acquired 335 operated~~ vertical ~~wells~~ and ~~7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the~~ horizontal wells ~~acquired~~in the Greeley-Crescent development area in Weld County, Colorado for $64.1 million in cash and ~~September 1, 2017 for~~ the ~~vertical wells acquired. At the second closing, the escrow balance~~assumption 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~~certain 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 ~~$22.6 million, composed of cash and assumed liabilities.~~

~~In August 2017, we also entered into an agreement with another party to trade approximately 4,000 net acres~~$96.8 million. This purchase was contemplated as part of the ~~Company's non-contiguous acreage for approximately 4,000 net acres within the Company's core operating area. This transaction is expected to close~~GCII Acquisition discussed below in ~~the fourth quarter of 2017.~~

~~March~~"‑December 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") pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million (the "GC Acquisition").

~~In June 2016, the Company closed on the portion of the assets comprised of undeveloped oil and gas leasehold interests and non-operated production.~~Acquisition." The effective date of this part of the transaction was ~~April~~September 1, ~~2016. As discussed above in "-~~ ~~September 2017 Acquisition"~~ ~~above,we closed on the second part of this~~2018. The transaction ~~covering the operated producing properties in September 2017.~~

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

~~The first closing~~ was accounted for ~~using the~~as an asset acquisition ~~method~~ under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at ~~fair values as of~~cost on the acquisition date of ~~June 14, 2016. Transaction costs of $0.5 million~~ r~~elated 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.September 27, 2018.

~~The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs),~~In September 2018, we completed a ~~discount rat~~etrade with another party of~~11.5%, and assumptions regarding~~ approximately 2,500 net acres. This transaction further enhances the ~~timing and amount~~contiguous nature of ~~future development and operating costs.~~the Company's acreage position.

August 2018 Acquisition

~~For th~~e~~three and nine months endedSeptember 30, 2017, the results of operations of the acquired assets, representing approximately$1.4 millionand$5.5 million of revenue, respectively, and $0.9 million and $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 nine months ended September 30, 2016 as if the first closing had occurred on January 1, 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 September 30, 2016 Nine Months Ended September 30, 2016
Oil, natural gas, and NGL revenues $ 26,234
$ 71,940
Net loss $ (19,241 ) $ (227,479 )

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

~~February 2016 Acquisition~~

~~On February 4, 2016,~~In August 2018, the Company completed the ~~acquisition~~purchase of ~~undeveloped oil~~leasehold acreage and ~~gas leasehold interests~~associated non-operated production for $37.6 million in cash and the assumption of certain liabilities for a total purchase price of ~~$10.0~~$38.0 million. The acreage increased our working interest in existing operations and planned wells. The transaction was accounted for as an asset acquisition under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of August 3, 2018.

December 2017 Acquisition

In December 2017, the Company completed the purchase of approximately 30,200 net acres and the associated non-operated production in the Greeley-Crescent development area in Weld County, Colorado for $576.4 million in cash and the assumption of certain liabilities for a total purchase price of $577.5 million ("GCII Acquisition"). The purchase price has been allocated as ~~$8.6~~$60.8 million to proved oil and gas properties and ~~$1.4~~$516.7 million to unproved oil and gas properties. ~~See Note 9 for further details as to~~The effective date of this part of the ~~preparation of these significant estimates.~~

~~Divestitures~~

In October 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of approximately 1,100 net acres and 22 gross (4 net) non-operated wells in progress for $11.6 million.transaction was November 1, 2017. The transaction ~~is expected~~was accounted for as an asset acquisition under ASC 805, Business Combinations, which requires the acquired assets and liabilities to ~~close in~~be recorded at cost on the ~~fourth quarter~~acquisition date of December 15, 2017. Additionally, we completed an additional divestiture to a separate private party of 37 operated vertical wells for total consideration of approximately $0.7 million in cash and the assumption by the buyers of $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 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 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 September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Depletion of oil and gas properties	$	32,944	$	9,273	$	71,389	$	31,981	$	44,230	$	32,944	$	121,259	$	71,389
Depreciation and accretion	796		362		2,007		1,020		958		796		2,887		2,007
Total DD&A Expense	$	33,740	$	9,635	$	73,396	$	33,001	$	45,188	$	33,740	$	124,146	$	73,396

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 nine months ended September 30, 2017, production of 3,715 MBOE and 8,280 MBOE, respectively, represented 2.2% and 4.8% of estimated total proved reserves, respectively. For the three and nine months ended September 30, 2016, production of 993 MBOE and 3,050 MBOE, respectively, represented 0.8% and 2.4% of estimated total proved reserves, respectively. DD&A expense was $9.08 per BOE and $9.70 per BOE for the three months ended September 30, 2017 and 2016, respectively, and was $8.86 per BOE and $10.82 per BOE for the nine months ended 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~~remediate the well, and ~~abandon the wells, and restore~~reclaim 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):


	Nine Months Ended September 30, 2017			Nine Months Ended September 30, 2018
Asset retirement obligations, December 31, 2016	$	16,458
Asset retirement obligations, December 31, 2017				$	31,622
Obligations incurred with development activities	2,782			1,488
Obligations assumed with acquisitions	23,521			26,150
Accretion expense	981			1,406
Obligations discharged with asset retirements and divestitures	(7,023		)	(8,944		)
Asset retirement obligation, September 30, 2017	$	36,719
Asset retirement obligation, September 30, 2018				$	51,722
Less, current portion	(2,738		)	(2,771		)
Long-term portion	$	33,981		$	48,951


6.	Revolving Credit Facility

On April 2, 2018, the Company entered into a second amended and restated credit agreement (the “Restated Credit Agreement”) with certain banks and other lenders. The ~~Company maintains~~Restated Credit Agreement provides a revolving credit facility (sometimes referred to as the "Revolver") ~~with~~and a ~~bank syndicate~~$25 million swingline facility with a maturity date of ~~December 15, 2019.~~April 2, 2023. The Revolver is available for working capital ~~requirements, capital expenditures,~~for exploration and production operations, acquisitions of oil and gas properties, and general corporate purposes and to support letters of credit. ~~As of~~At September 30, ~~2017,~~2018, the terms of the Revolver ~~provide~~provided for up to ~~$500 million~~$1.5 billion in borrowings, ~~subject to~~an aggregate elected commitment of $450 million, and a borrowing base limitation of ~~$400~~$550 million. ~~There was a $150.0 million~~As of September 30, 2018 and December 31, 2017, the outstanding principal balance ~~as of~~was $115.0 million and nil, respectively. At September 30, ~~2017 and~~2018, the Company had no ~~outstanding principal balance as of December 31, 2016. The Company has an outstanding letter~~letters of credit ~~of approximately $0.5 million.~~issued.

In ~~September 2017,~~October 2018, the lenders under the Revolver completed their ~~regular~~ semi-annual redetermination of our borrowing base. The borrowing base was increased from ~~$225~~$550 million to ~~$400~~$650 million, and we increased our aggregate elected commitment from $450 million to $500 million. ~~The next semi-annual redetermination is scheduled for April 2018.~~

Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or ~~the London Interbank Offered Rate ("LIBOR")~~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 nine months ended September 30, 2018 and 2017 was 4.0% and ~~2016 was~~ 3.3% ~~and~~ ~~2.6%~~, respectively.

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

The ~~Revolver~~Restated Credit Agreement 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~~the projected production from proved developed producing or total proved reserves as ~~projected~~reflected in the ~~semi-annual~~most recently completed reserve report.

Furthermore, the ~~Revolver~~Restated Credit Agreement requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the ~~end~~last day of any fiscal ~~quarter;~~quarter or (b) ~~as of the last day of any fiscal quarter~~ permit its ratio of current ~~ratio,~~assets to current liabilities, each as defined in the agreement, to be less than1.0to ~~1.0.~~1.0 as of the last day of any fiscal quarter. As ofSeptember 30, ~~2017,~~2018, the most recent compliance date, the C~~ompany~~Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.


7.	Notes Payable

2025 Senior Notes

In ~~June 2016,~~November 2017, the Company issued ~~$80~~$550 million aggregate principal amount of 9%6.25% Senior Notes ("due 2025 (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is ~~June 13, 2021.~~December 1, 2025. Interest on the 2025 Senior Notes accrues at 9%6.25% and began accruing on ~~June 14, 2016.~~November 29, 2017. Interest is payable on June 151 and December 151 of each ~~year.~~year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and will be guaranteed on a senior unsecured basis by any future subsidiaries of the Company that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility.November 29, 2017. The net proceeds from the sale of the 2025 Senior Notes were ~~$75.2~~$538.1 million after deductions of ~~$4.8~~$11.9 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of ~~10.6%~~ 6.6%. The net proceeds were used to fund the GCGCII Acquisition as discussed further in Note 3. 3, to repay our previously outstanding senior notes due 2021, and to pay off the outstanding Revolver balance.

At any time prior to December ~~14, 2018,~~1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the ~~Make-Whole Price~~principal amount plus an Applicable Premium (as defined in the Indenture) and accrued and ~~unpaid~~unpaid interest. On and after December ~~14, 2018,~~1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes ~~(104.50%~~ (104.688% for ~~2018, 102.25%~~2020, 103.125% for ~~2019,~~2021, 101.563%for 2022, and 100% for ~~2020~~2023 and thereafter, during the twelve-month period beginning on December 141 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December ~~14, 2018,~~1, 2020, the Company can, on one or more occasions, redeem up to35%of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to ~~109%~~106.25% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of ~~any restricted~~certain of its subsidiaries to, among other ~~things:~~restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications. The indenture governing the 2025 Senior Notes provides that, in certain circumstances, the notes will be guaranteed by one or more subsidiaries of the Company, in which case such guarantee would be made on a full and unconditional and joint and several senior unsecured basis.

AsAs of September 30, ~~2017,~~2018, 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~~seven counterparties. Five of the counterparties are lenders in the ~~Revolver.~~Restated Credit Agreement. 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 September 30, ~~2017~~2018 are summarized below:

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



Settlement Period	Derivative Instrument	Volumes (Bbls per day)	Weighted-Average Floor Price			Weighted-Average Ceiling Price
Crude Oil - NYMEX WTI
Oct 1, 2018 - Dec 31, 2018	Collar	10,000	$	43.63		$	61.29
Jan 1, 2019 - Dec 31, 2019	Collar	6,000	$	55.00		$	74.31

Settlement Period	Derivative Instrument	Volumes (MMBtu per day)	Weighted-Average Floor Price			Weighted-Average Ceiling Price
Natural Gas - CIG Rocky Mountain
Oct 1, 2018 - Dec 31, 2018	Collar	15,000	$	2.25		$	2.82

Settlement Period	Derivative Instrument	Volumes (MMBtu per day)	Fixed Basis Difference
Natural Gas - CIG Rocky Mountain
Jan 1, 2019 - Dec 31, 2019	Swap	10,000	$	(0.79	)

Settlement Period	Derivative Instrument	Volumes (Bbls per day)	Weighted-Average Fixed Price
Propane - Mont Belvieu
Oct 1, 2018 - Dec 31, 2018	Swap	1,000	$	33.60
Jan 1, 2019 - Dec 31, 2019	Swap	2,000	$	37.52

Subsequent to September 30, ~~2017,~~2018, the Company added the following positions:

Settlement Period
Derivative
Instrument
Average Volumes
(Bbls
per month)
Floor
Price

Ceiling
Price
Crude Oil - NYMEX WTI
Jan 1, 2018 - Dec 31, 2018 Collar 76,042
$ 45.00
$ 58.00



Settlement Period	Derivative Instrument	Volumes (MMBtu per day)	Weighted-Average Fixed Basis Difference
Natural Gas - CIG Rocky Mountain
Nov 1, 2018 - Dec 31, 2018	Swap	50,000	$	(0.21	)
Jan 1, 2019 - Dec 31, 2019	Swap	20,000	$	(0.74	)

Offsetting of Derivative Assets and Liabilities

As of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, 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 September 30, 2017								As of September 30, 2018
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	$	1,214	$	(1,214	)	$	—	Current assets	$	1,740	$	(1,740	)	$	—
Commodity derivative contracts	Noncurrent assets	$	502	$	(502	)	$	—	Noncurrent assets	1,078		(1,078		)	—
Commodity derivative contracts	Current liabilities	$	2,000	$	(1,214	)	$	786	Current liabilities	20,310		(1,740		)	18,570
Commodity derivative contracts	Noncurrent liabilities	$	896	$	(502	)	$	394	Noncurrent liabilities	$	2,749	$	(1,078	)	$	1,671


		As of December 31, 2016								As of December 31, 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	$	2,045	$	(1,748	)	$	297	Current assets	$	1,960	$	(1,960	)	$	—
Commodity derivative contracts	Noncurrent assets	$	—	$	—		$	—	Noncurrent assets	—		—			—
Commodity derivative contracts	Current liabilities	$	4,622	$	(1,748	)	$	2,874	Current liabilities	9,825		(1,960		)	7,865
Commodity derivative contracts	Noncurrent liabilities	$	—	$	—		$	—	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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Realized gain (loss) on commodity derivatives	$	116		$	(13	)	$	(26	)	$	2,868		$	(8,273	)	$	116		$	(16,228	)	$	(26	)
Unrealized gain (loss) on commodity derivatives	(2,499		)	420			2,350			(6,485		)	(256		)	(2,499		)	(12,376		)	2,350
Total gain (loss)	$	(2,383	)	$	407		$	2,324		$	(3,617	)	$	(8,529	)	$	(2,383	)	$	(28,604	)	$	2,324

Realized gains and losses ~~include cash received from~~represent the monthly settlement of derivative contracts at their scheduled maturity date, ~~and~~net of 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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Monthly settlement	$	376		$	497		$	927		$	4,398		$	(8,273	)	$	376		$	(16,228	)	$	927
Previously incurred premiums attributable to settled commodity contracts	(260		)	(510		)	(953		)	(1,530		)	—			(260		)	—			(953		)
Total realized gain (loss)	$	116		$	(13	)	$	(26	)	$	2,868
Total realized loss													$	(8,273	)	$	116		$	(16,228	)	$	(26	)

Credit Related Contingent Features

As of September 30, ~~2017, three~~2018, five of the ~~six~~seven 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,~~sixth and seventh counterparties, which isare not ~~a lender~~lenders 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 and~~ certain asset acquisitions. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, ~~business combinations and~~ asset acquisitions, and asset retirement obligations, respectively.

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

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

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation 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 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 September 30, 2017 and December 31, 2016~~ by level within the fair value hierarchy (in thousands):


	Fair Value Measurements at September 30, 2017								Fair Value Measurements at September 30, 2018
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Commodity derivative liability	$	—	$	1,180	$	—	$	1,180	$	—	$	20,241	$	—	$	20,241


	Fair Value Measurements at December 31, 2016								Fair Value Measurements at December 31, 2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	297	$	—	$	297	$	—	$	—	$	—	$	—
Commodity derivative liability	$	—	$	2,874	$	—	$	2,874	$	—	$	7,865	$	—	$	7,865

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 September 30, ~~2017,~~2018, derivative instruments utilized by the Company consist of ~~puts~~swaps and collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued 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, 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~~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 ~~Senior Notes~~notes payable is estimated to be ~~$84.8~~$514.3 million at September 30, ~~2017.~~2018. The Company determined the fair value of its notes payable at September 30, ~~2017~~2018 by using observable ~~market based~~market-based information for these debt ~~instruments of similar amounts and duration.~~instruments. The Company has classified the notes payable as Level 2.1.


10.	Interest Expense

The components of interest expense are (in thousands):

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Revolving bank credit facility $ 1,016
$ —
$ 1,286
$ 154
Notes payable 1,800
1,800
5,400
2,120
Amortization of issuance costs 1,090
467
2,267
1,076
Less, interest capitalized (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 September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Weighted-average shares outstanding - basic 200,881,447
200,515,555
200,807,436
164,771,544
Potentially dilutive common shares from:
Stock options 415,524
—
412,902
—
Restricted stock units and stock bonus shares 163,944
—
105,791
—
Weighted-average shares outstanding - diluted 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 September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Potentially dilutive common shares from:
Stock options 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
Restricted stock units and stock bonus shares 308,094
1,003,879
497,806
1,003,879
Total 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.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revolving bank credit facility	$	376		$	1,016		$	461		$	1,286
Notes payable	8,593			1,800			25,781			5,400
Amortization of issuance costs and other	905			1,090			2,905			2,267
Less: interest capitalized	(9,874		)	(3,906		)	(29,147		)	(8,953		)
Interest expense, net of amounts capitalized	$	—		$	—		$	—		$	—


~~12.~~11.	Equity and Stock-Based Compensation

Equity

At the 2018 annual meeting of shareholders of the Company held on May 18, 2018, the shareholders approved the Third Amended and Restated Articles of Incorporation of the Company to increase the number of authorized shares of common stock of the Company from 300,000,000 to 400,000,000.

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~~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"~~period"). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo ~~Model.~~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 September 30, ~~2017,~~2018, there were ~~4,500,000~~10,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which ~~86,464~~4,251,410 shares were available for future ~~grants.~~grant. The shares available for future grant exclude ~~951,884~~1,555,263 shares which have been reserved for future vesting of performance-vested stock units ~~under~~in the ~~assumption~~event that these awards ~~met~~meet the ~~criterion~~criteria to vest at their maximum multiplier.

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Stock options	$	1,277		$	1,274		$	3,825		$	4,107		$	1,072		$	1,277		$	3,470		$	3,825
Performance-vested stock units	807			354			2,130			692			1,187			807			3,216			2,130
Restricted stock units and stock bonus shares	1,386			1,023			3,779			3,341			1,771			1,386			4,507			3,779
Total stock-based compensation	$	3,470		$	2,651		$	9,734		$	8,140		$	4,030		$	3,470		$	11,193		$	9,734
Less: stock-based compensation capitalized	(440		)	(278		)	(1,344		)	(856		)	(625		)	(440		)	(1,846		)	(1,344		)
Total stock-based compensation expensed	$	3,030		$	2,373		$	8,390		$	7,284		$	3,405		$	3,030		$	9,347		$	8,390

Stock options

No stock options were granted during the three and nine months ended September 30, 2018 or 2017. ~~During the periods presented, the Company granted the following stock options:~~

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

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



	~~Nine Months Ended September 30, 2016~~
~~Expected term~~	~~6.4 years~~
~~Expected volatility~~	55	%
~~Risk free rate~~	~~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
Outstanding, December 31, 2017								5,636,834		$	9.38	7.0 years	$	4,806
Granted	—		—					—		—
Exercised	(30,000	)	3.79			140		(823,883	)	5.36			4,611
Expired	(41,000	)	11.98					(23,400	)	11.27
Forfeited	(104,000	)	11.60					(104,917	)	9.57
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
Outstanding, September 30, 2018								4,684,634		$	10.07	6.6 years	$	2,505
Outstanding, Exercisable at September 30, 2018								3,142,430		$	10.25	6.4 years	$	1,452

The following table summarizes information about issued and outstanding stock options as of September 30, ~~2017:~~2018:


	Outstanding Options				Exercisable Options				Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life	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	$	3.49	3.9 years	574,000	$	3.46	3.8 years	35,000	$	3.31	3.8 years	35,000	$	3.31	3.8 years
$5.00 - $6.99	1,012,000	6.38		7.2 years	549,000	6.45		6.0 years	723,800	6.30		6.7 years	389,200	6.27		5.9 years
$7.00 - $10.99	1,592,500	9.34		7.7 years	658,661	9.50		7.3 years	1,362,334	9.42		6.7 years	864,830	9.49		6.4 years
$11.00 - $13.46	2,622,000	11.58		7.7 years	1,364,700	11.58		7.6 years	2,563,500	11.58		6.7 years	1,853,400	11.57		6.6 years
Total	5,826,500	$	9.23	7.2 years	3,146,361	$	8.77	6.6 years	4,684,634	$	10.07	6.6 years	3,142,430	$	10.25	6.4 years

The estimated unrecognized compensation cost from stock options not vested as of September 30, ~~2017,~~2018, which will be recognized ratably over the remaining vesting phase, is as follows:


Unrecognized compensation cost (in thousands)	$	11,101	$	5,685
Remaining vesting phase	2.5 years		1.8 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~~under 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 nine months ended September 30, ~~2017:~~2018:


	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		$	9.54
Not vested, December 31, 2017					1,087,386		$	8.89
Granted	669,323		8.27		747,168		9.35
Vested	(336,445	)	9.17		(439,945	)	8.77
Forfeited	(24,807	)	9.85		(54,111	)	9.56
Not vested, September 30, 2017	1,198,407		$	8.93
Not vested, September 30, 2018					1,340,498		$	9.16

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of September 30, ~~2017,~~2018, which will be recognized ratably over the remaining vesting phase, is as follows:


Unrecognized compensation cost (in thousands)	$	8,232	$	9,075
Remaining vesting phase	2.3 years		2.0 years

Performance-vested stock units

The Company grants two types of 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.

Goal-Based PSUs - These PSUs are earned and vested after 2020 based on a discretionary assessment by the Compensation Committee. This assessment is anticipated to measure the performance of the Company and the executives over the defined vesting period. As vesting is based on the discretion of the Compensation Committee, we have not yet met the requirements of establishing an accounting grant date for them. This will occur when the Compensation Committee determines and communicates the vesting percentage to the award recipients, which will then trigger the service inception date, the fair value of the awards, and the associated expense recognition period. As of September 30, 2018, 281,872 Goal-Based PSUs had been awarded to certain executives.

Total Shareholder Return ("TSR") PSUs - The vesting criterion for the TSR PSUs is based on a comparison of the Company’s ~~total shareholder return ("TSR")~~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 TSR PSUs granted were as follows:


	Nine Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2018		2017
Weighted-average expected term	2.9 years		2.7 years		2.8 years		2.9 years
Weighted-average expected volatility	59	%	58	%	52	%	59	%
Weighted-average risk-free rate	1.34	%	0.87	%	2.41	%	1.34	%

The fair value of the TSR PSUs granted during the nine months ended September 30, 2018 and 2017 ~~and 2016~~ was ~~$5.1~~$4.2 million and ~~$4.0~~$5.1 million, respectively. As of September 30, ~~2017,~~2018, unrecognized compensation cost for TSR PSUs was ~~$5.8~~$6.0 million and will be amortized through ~~2019.~~2020. A summary of the status and activity of TSR 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
Not vested, December 31, 2017				951,884	$	9.44
Granted	473,374	10.79		321,507	13.11
Vested	—	—		—	—
Forfeited	—	—		—	—
Not vested, September 30, 2017	951,884	$	9.44
Not vested, September 30, 2018				1,273,391	$	10.36


12.	Weighted-Average Shares Outstanding

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Weighted-average shares outstanding — basic	242,536,781	200,881,447	242,184,348	200,807,436
Potentially dilutive common shares from:
Stock options	230,067	415,524	332,953	412,902
TSR PSUs ¹	411,738	—	336,882	—
Restricted stock units and stock bonus shares	381,460	163,944	352,875	105,791
Weighted-average shares outstanding — diluted	243,560,046	201,460,915	243,207,058	201,326,129

¹ The number of awards assumes that the associated vesting condition is met at the respective period end based on market prices as of the respective period end. 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.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Potentially dilutive common shares from:
Stock options ¹	3,456,300	4,726,500	3,438,167	4,756,500
TSR PSUs ^1,2	160,754	951,884	160,754	951,884
Goal-Based PSUs ^2,3	281,872	—	281,872	—
Restricted stock units and stock bonus shares ¹	13,907	308,094	13,907	497,806
Total	3,912,833	5,986,478	3,894,700	6,206,190

¹ Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities had an anti-dilutive effect on earnings per share.

² The number of awards reflects the target amount of shares granted. 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.

³ Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities are considered contingently issuable, and the performance criteria are not considered met as of period end.


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.

During the three months ended March 31, 2018, the Company concluded it is more likely than not it will realize the benefits of its net deferred tax assets by the end of 2018 as a result of current year ordinary income. This conclusion was based upon the Company’s projection of cumulative positive net income for the three-year period ended December 31, 2018. The release of the valuation allowance is reflected in the Company’s estimated annual effective tax rate since the realization of the Company’s deferred tax assets is supported by current year ordinary income. The Company is projecting a net deferred tax liability with a full release of its beginning valuation allowance by the end of 2018.

The effective tax rates for the three and nine months ended September 30, 2018 were 12% and 9%, respectively. For the three and nine months ended September 30, 2017, ~~and 2016~~the effective tax rates were nil. The effective tax rates for the three and nine months ended September 30, 2018 and 2017 ~~and 2016 were based upon a full year forecasted tax provision and differs~~differed from the statutory ~~rate~~rates due primarily ~~due~~ to the ~~recognition~~release of a valuation ~~allowance~~allowances previously recorded against deferred tax assets. ~~There were no significant discrete items recorded during the three and nine months ended September 30, 2017 and 2016.~~

As of September 30, ~~2017,~~2018, we had no liability for unrecognized tax benefits. The Company believes that there are no new items ~~nor~~or 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 September 30, ~~2017.~~2018. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of September 30, ~~2017,~~2018, 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~~As of September 30, ~~2017,~~2018, the Company believes it will be able to generate sufficient future taxable income within the carryforward periods and, accordingly, believes that it is more likely than not that its net deferred income tax assets will be fully realized.

14. Revenue from Contracts with Customers

Sales of oil, natural gas, and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. All of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.



	Three Months Ended September 30,				Nine Months Ended September 30,
Revenues (in thousands):	2018		2017		2018		2017
Oil	$	123,540	$	73,144	$	354,601	$	154,232
Natural Gas and NGLs	37,438		30,449		100,697		68,187
	$	160,978	$	103,593	$	455,298	$	222,419

Natural Gas and NGLs Sales

Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. For these contracts, we have ~~provided a full valuation allowance reducing~~concluded that the midstream processing entity is our customer. We recognize natural gas and NGL revenues based on the net ~~realizable benefits.~~amount of the proceeds received from the midstream processing.

Oil Sales

Our oil sales contracts are generally structured in one of the following ways:

We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third party costs are recorded as transportation and gathering in our condensed consolidated statements of operations.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606. As of September 30, 2018, we had contract assets recorded within other current assets of $1.6 million representing cash advances to customers which are expected to be realized within a year.

Prior-Period Performance Obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales when that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three and nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.


~~14.~~15.	Other Commitments and Contingencies

~~Volume~~Oil Commitments

The Company entered into firm sales agreements for its oil production with ~~three counterparties during 2014 and entered into an additional firm sales agreement for its oil production in the third quarter 2017.~~four counterparties. Deliveries under ~~two~~three of the sales agreements ~~commenced during 2015. Deliveries under the third agreement commenced in 2016.~~have commenced. Deliveries under the fourth agreement are expected to commence in the ~~second~~first quarter of ~~2018.~~2019. 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	1,072
2018	4,942
Remainder of 2018		1,072
2019	5,167	5,167
2020	4,003	4,003
2021	1,672	1,672
2022		—
Thereafter	—	—
Total	16,856	11,914

~~During the nine months ended 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.~~ During the third quarter of ~~2017,~~2018, 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,~~obligations; although, this cannot be guaranteed.

Natural Gas Commitments

In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.

The first agreement includes a new 200 MMcf per day processing plant ("Mewbourn 3") as well as the expansion of a related gathering system. ~~Both are currently expected to be completed by late~~Starting in August 2018, ~~although the start-up date is undetermined at this time.~~Mewbourn 3 was complete and in service. Our share of the commitment ~~will require~~requires 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years.

The second agreement ~~also~~ includes ~~a new 200~~an additional 300 MMcf per day processing plant ("O'Connor 2"), including up to 100 MMcf per day of bypass, as well as the expansion of a related gathering system. ~~Both are currently~~Construction of the plant is underway and is expected to be ~~completed~~placed into service in ~~2019, although~~ the ~~start-up date is undetermined at this time.~~second quarter of 2019. Our share of the commitment will require an additional 43.8 MMcf per day to be delivered after the plant in-service date for a period of 7 years.

These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. ~~We expect~~If we are unable to fulfill all of our contractual obligations and our obligations are not sufficiently reduced by the collective volumes delivered by other producers, we may be required to pay penalties or damages pursuant to these agreements. During the third quarter of 2018, we were able to meet all of our delivery obligations, and we anticipate that our ~~development plan~~current gross operated production will ~~support the utilization of~~continue to meet our future delivery obligations; although, 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 September 30, 2017 follows (in thousands):

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

~~Rent expense for offices leases was $0.2 million for the three months ended September 30, 2017~~ ~~and 2016, respectively. For the~~ ~~nine months ended September 30, 2017 and 2016, rent expense for office leases was $0.9 million and $0.5 million, respectively.~~cannot be guaranteed.

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~~proceedings are reasonably likely to have a material adverse impact on ~~our~~the Company's business, financial position, results of operations, or cash flows.

Office leases

The Company’s principal office space located in Denver is under lease through July 2022. Current rent under the lease is approximately $66,000 per month. The Company also has a field office lease in Greeley which requires monthly payments of $7,500 through October 2021.

Rent expense for offices leases was $0.3 million and $0.2 million for the three months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018 and 2017, rent expense for office leases was $0.7 million and $0.9 million, respectively.

Vehicle Leases

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

A schedule of the minimum lease payments under non-cancellable capital and operating leases as of September 30, 2018 follows (in thousands):



Year ending December 31:	Vehicles Leases			Office Leases
Remainder of 2018	$	41		$	222
2019	163			896
2020	163			916
2021	189			913
2022	136			500
Thereafter	—			—
Total minimum lease payments	$	692		$	3,447
Less: Amount representing estimated executory cost	(57		)
Net minimum lease payments	635
Less: Amount representing interest	(92		)
Present value of net minimum lease payments ^*	$	543

^* Reflected in the balance sheet as current and non-current obligations of $111 thousand and $432 thousand, respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively.


~~15.~~16.	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):


	Nine Months Ended September 30,						Nine Months Ended September 30,
Supplemental cash flow information:	2017			2016			2018			2017
Interest paid	$	4,796		$	159		$	17,701		$	4,796
Income taxes paid	—			106

Non-cash investing and financing activities:
Accrued well costs as of period end	$	122,387		$	32,299		$	143,015		$	122,387
Asset retirement obligations incurred with development activities	2,782			366			1,488			2,782
Asset retirement obligations assumed with acquisitions	23,521			2,046			26,150			23,521
Obligations discharged with asset retirements and divestitures	(7,023		)	(3,997		)	$	(8,944	)	$	(7,023	)

Net changes in operating assets and liabilities:
Accounts receivable							$	(31,170	)	$	(85,027	)
Accounts payable and accrued expenses							(842		)	1,413
Revenue payable							15,858			41,997
Production taxes payable							20,504			17,548
Other							(520		)	(941		)
Changes in operating assets and liabilities							$	3,830		$	(25,010	)


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 September 30, ~~2017~~2018 and its results of operations for the three and nine months ended September 30, ~~2017~~2018 and ~~2016.~~2017. 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~~2017 filed with the SEC on February ~~23, 2017.~~21, 2018. 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 and referenced in “Risk Factors.” We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

Proposition 112

As discussed in the "Risk Factors" section of ~~January 1, 2017, our~~this report, certain groups opposed to oil and natural gas ~~processing agreements with DCP Midstream were modified~~hydraulic fracturing operations have proposed Proposition 112, which is included on Colorado’s November 6, 2018 ballot. Proposition 112 would impose a minimum setback distance of 2,500 feet between any new oil and gas development and any occupied structures or defined "vulnerable areas." If this proposition is enacted, it would apply prospectively to ~~allow us~~oil and gas development permitted on or after the effective date of the law, which is expected to ~~take title to~~be December 2018. Although there is significant uncertainty about how this law would be interpreted and implemented, if approved by the ~~NGLs resulting from~~voters, it could have significant adverse effects on the ~~processing~~Company’s long-term operations, reserves, and financial condition. See “Risk Factors - Proposition 112, if approved, would have a material adverse effect on our future drilling inventory and other aspects of our ~~natural gas. Based~~business.” If Proposition 112 is enacted, we will consider all available courses of action, including potential legal challenges, legislative reformation, and regulatory modifications, but the outcome of any such efforts and the effect that they might have on ~~this,~~the Company is unknown. We do not believe that Proposition 112 would impact existing wells, current drilling or completion activities, or future wells that have been approved by the state. We currently have state-approved and permitted drilling locations that we ~~began reporting reserves, sales volumes, prices,~~believe would be grandfathered under Proposition 112 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 comparabilitywould provide approximately two years of ~~2017 with prior periods.~~drilling inventory.

Overview

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

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

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately ~~90%~~85% of our proved ~~producing~~developed reserves and anticipate operating ~~substantially all~~a majority 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		2017		2016		2015		2015		2014		2013
Average NYMEX prices
Oil (per Bbl)	$	43.20	$	48.73	$	60.65	$	100.39	$	94.58	$	50.93	$	43.20	$	48.73	$	60.65	$	100.39	$	94.58
Natural gas (per Mcf)	$	2.52	$	2.58	$	3.12	$	4.38	$	3.55	$	3.00	$	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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Oil (NYMEX WTI)
Oil (NYMEX-WTI)
Average NYMEX Price	$	48.18		$	44.90		$	49.44		$	41.23		$	69.76		$	48.18		$	66.89		$	49.44
Realized Price	42.37			35.67			42.04			31.47
Differential	$	(5.81	)	$	(9.23	)	$	(7.40	)	$	(9.76	)
Realized Price *													63.48			41.89			60.13			41.73
Differential *													$	(6.28	)	$	(6.29	)	$	(6.76	)	$	(7.71	)

Gas (NYMEX Henry Hub)
Natural Gas (NYMEX-Henry Hub)
Average NYMEX Price	$	2.99		$	2.88		$	3.03		$	2.34		$	2.90		$	2.99		$	2.90		$	3.03
Realized Price	2.35			2.73			2.39			2.18			1.79			2.35			1.84			2.39
Differential	$	(0.64	)	$	(0.15	)	$	(0.64	)	$	(0.16	)	$	(1.11	)	$	(0.64	)	$	(1.06	)	$	(0.64	)

NGL Realized Price	$	17.32		$	—		$	15.49		$	—		$	19.93		$	17.32		$	18.91		$	15.49

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

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The differential between the prices 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 and continuing through the current period, 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 $51.67 per Bbl on Friday, September 29, 2017, a decline of 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. There has been significant volatility in the price of oil and natural gas since mid-2014. During the nine months ended September 30, 2018, the NYMEX-WTI oil price ranged from a high of $77.41 per Bbl on June 27, 2018 to a low of $59.20 per Bbl on February 9, 2018, and the NYMEX-Henry Hub natural gas price ranged from a low of $2.55 per MMBtu on February 12, 2018 to a high of $3.63 per MMBtu on January 29, 2018. As reflected in published data, the price for WTI oil settled at $60.46 per Bbl on December 29, 2017. Comparably, the price of oil settled at $73.16 per Bbl on Friday, September 28, 2018, an increase of 21% from December 29, 2017. NYMEX-Henry Hub natural gas traded at $2.95 per Mcf on December 29, 2017, but increased approximately 2% as of September 28, 2018 to $3.01. While we use NYMEX-Henry Hub to calculate our natural gas differentials, our natural gas sales tend to trend more closely with Colorado Interstate Gas – Rocky Mountains as published in Inside FERC’s Gas Market Report, published by Platts ("CIG"). Average CIG prices for the third quarter of 2018 increased to $2.18 from $1.83 in the second quarter of 2018, and the basis difference for CIG to NYMEX-Henry Hub decreased from $0.97 to $0.72.

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 September 30, ~~2017,~~2018, 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 September 30, ~~2017:~~2018:

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

482

456

135

617

488

628

602

146

774

646

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

208

194

191

399

227

364

338

310

674

397

In addition to the producing wells summarized in the preceding table, as of September 30, ~~2017,~~2018, we were the operator of 4677 gross ~~(36~~(66 net) horizontal wells in progress, which excludes 1930 gross ~~(14~~(23 net) wells for which we have only set surface casings. As of September 30, ~~2017,~~2018, we are participating in ~~107~~29 gross ~~(22~~(9 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~~the remediation and ~~abandoning~~reclamation of the vast majority of the operated vertical wellbores. During the nine months ended September 30, ~~2017,~~2018, we plugged 86146 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 September 30, ~~2017,~~2018, our average daily production increased to ~~40,378~~49,165 BOED as compared to ~~10,794~~40,378 BOED for the three months ended September 30, ~~2016.~~2017. During the first nine months of ~~2017,~~2018, our average net daily production was ~~30,331~~47,416 BOED. By comparison, during the nine months ended September 30, ~~2016,~~2017, our average production rate was ~~11,133~~30,331 BOED. As of September 30, ~~2017, approximatel~~2018, over 99% oyf~~99%~~ofour 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~~proved undeveloped acreage ~~development is~~are located either in or adjacent to the Wattenberg ~~Field.~~Field, and we seek to acquire developed and undeveloped oil and gas properties in the same area. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.

Develop and exploit existing oil and gas properties. Our principal growth strategy has been to develop and exploit our properties to add reserves. In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient and safest 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~~Use the latest technology to maximize returns and improve hydrocarbon ~~recovery through increased~~recovery. Our development objective for individual well ~~density.~~ ~~We utilize what we believe~~optimization is to ~~be industry best practices in our effort~~drill and complete wells with lateral lengths of mostly 7,000' to ~~determine the optimal recovery area~~10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each ~~well. Early horizontal~~leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development 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 perprogram.

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

~~Complete selective acquisitions.~~Operate in a safe manner and work in partnership with our surrounding stakeholders. WeWhile our scale of operations has increased significantly, we continue to focus on maintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to ~~acquire developed~~utilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities. Such practices include building our infrastructure out ahead of operations to minimize traffic, working with our service providers to minimize dust and ~~undeveloped oil~~lighting issues, and ~~gas properties, primarily~~constructing sound walls to minimize noise. We value our positive relationship with local governing entities and the communities in ~~the Wattenberg Field. We generally~~which we operate and 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.~~to continually achieve a status of operator of choice.

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

Control and reduce emissions from our production facilities. We place high importance on achieving compliance with all applicable air quality rules and regulations and reducing emissions continues to be a top environmental priority. To minimize these emissions, we employ best management practices such as using available direct pipeline take-away access and pneumatic actuated instrument devices and working with suppliers to deploy diesel engines that meet the ~~latest technology~~U.S. Environmental Protection Agency Tier 4 standand. We also control emissions and minimize flaring of gas by recovering natural gas and actively pursuing sufficient take-away capacity for associated produced gas and the use of vapor recovery equipment. We continue 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 implement a continuous improvement philosophy in optimizingevolve the ~~value per acre~~design of our ~~leasehold throughout our development program.~~production facilities to produce oil and natural gas with fewer air emissions, including those emissions for which there are public health standards (e.g. ozone and particulate matter).

Significant Developments

~~We continue to be opportunistic with respect to acquisition efforts to increase our working interests~~Acquisitions 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~~Trade

In September we2018, the Company completed the ~~second closing~~purchase 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~~in the Greeley-Crescent development area in Weld County, Colorado for ~~the vertical wells acquired. The purchase and sale agreement for the GC Acquisition was signed~~$64.1 million in ~~May 2016,~~cash and the ~~first closing was completed in June 2016. At the second closing, the escrow balance~~assumption 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~~certain 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 ~~$22.6 million, composed~~$96.8 million. The effective date of ~~cash and assumed liabilities.~~this purchase was September 1, 2018.

In ~~March 2017,~~September 2018, we ~~acquired developed~~completed a trade with another party of approximately 2,500 net acres. This transaction further enhances the contiguous nature of the Company's acreage position.

In August 2018, the Company completed the purchase of leasehold acreage and ~~undeveloped oil~~associated non-operated production for $37.6 million in cash and ~~gas leasehold interests~~the assumption of certain liabilities for a total purchase price of ~~$25.0 million, composed of cash and assumed liabilities.~~

~~Divestitures~~

In October 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of approximately 1,100 net acres and 22 gross (4 net) non-operated wells in progress for $11.6$38.0 million. The ~~transaction is expected to close~~acreage increased our working interest in ~~the 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 $0.7 million in cash~~existing operations and ~~the assumption by the buyers of $2.3 million in liabilities.~~

planned wells.

Revolving Credit Facility

In ~~September 2017,~~October 2018, the lenders under ~~our revolving credit facility (sometimes referred to as~~ the ~~"Revolver")~~Revolver completed their ~~regular~~ semi-annual redetermination of our borrowing base. The borrowing base was increased from ~~$225~~$550 million to ~~$400~~$650 million, and we increased our aggregate elected commitment from $450 million to $500 million. The next semi-annual redetermination is scheduled for April 2018. Due to the outstanding principal balance and letters of credit, approximately $249.5 million of the borrowing base was available to use for future borrowings as of September 30, 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 believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve ~~reasonable~~attractive 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 nine months ended September 30, ~~2017,~~2018, we drilled ~~87 operated~~ 89 operated horizontal wells and ~~completed~~ 87turned 54 operated horizontal wells. to sales. As ofSeptember 30, ~~2017,~~2018, the Company had 9 gross (8 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the fourth quarter. As of September 30, 2018, we are the operator of 4677 gross ~~(36 ne~~t)(66 net) horizontal wells in progress, ~~which~~which excludes 1930 gross ~~(14~~(23 net) horizontal wells for ~~which~~which we have only set surface casings. The majority of this activity was funded through cash flows from operations. For ~~2017~~2018 as a whole, we expect to ~~dri~~lldrill 118 ~~gro~~ssgross (101 net) operated horizontal wells ~~primarily~~and complete approximately 127 gross (112 net) operated horizontal wells with mid-length and long laterals targeting the Codell and Niobrara formations.

For the nine months ended September 30, ~~2017,~~2018, we participated in the ~~completion~~completion of 16 32gross (1 (6net) non-operated horizontal wells. As of September 30, ~~2017,~~2018, we are participating in ~~107~~ 29gross ~~(22 n~~(9net) non-operated ho~~et) non-operated horizontal~~rizontal 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~~NYMEX-WTI oil traded at $~~53.75~~60.46 per Bbl on December ~~30, 2016,~~29, 2017, but has since ~~declined~~increased approximately 4%21% as of September ~~29, 2017~~28, 2018 to $~~51.67.~~ ~~Natural~~73.16. NYMEX-Henry Hub natural gas traded at $~~3.72~~2.95 per Mcf on December ~~30, 2016,~~29, 2017, but ~~declined~~increased approximately ~~19%~~2% as of September ~~29, 2017~~28, 2018 to ~~$3.01~~. ~~Lower~~$3.01. Although NYMEX-WTI oil prices have increased in 2018, they continue to be volatile and are out of our control. If oil prices decrease, this could (i) reduce our cash flow which could, 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~~We continually focus 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.

~~We have been able to reduce~~managing drilling and completion costs ~~due to~~through a combination of ~~optimizing~~ well ~~designs, lower contract rates for drilling rigs, fewer~~design optimization, reductions in the average days to drill, and ~~lower completion costs.~~employment of current technological advancements. This focus on cost ~~reduction has supported~~management helps support well-level economics ~~giving consideration to the current prices of~~under varying 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.gas pricing environments.

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, midstreamMidstream companies that operate the natural gas processing facilities and gathering pipelines in the ~~area~~Wattenberg Field continue to make significant capital investments to increase the capacity of their systems. ~~While these actions have helped~~From time to ~~increase~~time, our production has been and may continue to be adversely impacted by the lack of processing capacity, ~~for~~resulting in high natural gas gathering line pressures. Second and third quarter 2018 results were impacted by this lack of spare gas processing capacity, which resulted in persistently high line pressures and the inability to maintain consistent production flows. Further exacerbating the midstream constraints were above average temperatures in Colorado in June and continuing into July as well as unplanned shutdowns of natural gas processing ~~we continue~~facilities. As a result, many of the Company's wells could not be produced consistently, and the Company was unable to ~~experience line pressures exceeding system limits primarily due~~turn recently completed wells to ~~further growth in field-wide production volumes.~~sales as desired.

To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream ~~has announced plans for~~is developing 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~~support the expansion of natural gas gathering and processing capacity ~~in the D-J Basin.~~through agreements that impose baseline and incremental volume commitments, which we are currently exceeding. The initial ~~plan includes~~plans included a new 200 MMcf per day processing plant ~~as well as~~("Mewbourn 3"), and the expansion of a related gathering system, ~~both expected to be completed by late~~which became operational in August 2018. ~~Additionally, through~~Through the same framework, all of the parties agreed to a development plan to add another ~~200 MMcf/d~~300 MMcf per day plant ("O'Connor 2"), including up to 100 MMcf per day of bypass, that is expected to be in service in the second quarter of 2019. ~~These agreements impose~~In addition, DCP Midstream has announced the development of a ~~baseline and incremental volume commitment~~third plant ("Bighorn"), which ~~we are currently exceeding.~~could have capacity up to 1 Bcf per day, including bypass, with an in-service date after 2019.

We have extended the use of oil and water gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases or areas to these systems. We believe ~~that oil~~these 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. As these gathering lines are currently being expanded, we have experienced and expect to continue to experience some delays in placing our pads on production.

Oil transportation and takeaway capacity has increased with the expansion of certain interstate pipelines servicing the Wattenberg Field. ~~This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets.~~ We strive to reduce the negative differential that we have historically realized on our oil production depending

on transportation commitments, local refinery demand, and our production volumes. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."

~~As of September 30, 2017, we have identified over 1,100 drilling locations across our acreage position.~~ For~~For 2017,~~2018, we expect to dr~~ill~~drill 118 gross operated horizontal wells (89 of which were drilled through September 30, 2018) with mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion program will cost approximately ~~$360~~$580 million ($408.3 million of which was incurred through September 30, 2018) and ~~will~~that it should 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 associatedreserves. We currently estimate that full-year 2018 production will average approximately 50,000 BOED with ~~non-operated properties are expected to be~~the oil mix being approximately ~~$60 million, which is net~~ 45% of ~~capital we expect to recover as described in "-~~ ~~Capital Expenditures~~" below. Full-year 2017 production is forecasted to be between 33,000 BOED and 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. production.

Other than the foregoing and the aforementioned Proposition 112, we do not know of any trends, events, or uncertainties that have had, during the periods covered by this report, or are reasonably expected to have, a material impact on our sales, revenues, expenses, liquidity, or capital resources.

Results of Operations

Material changes to 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 September 30, ~~2017~~2018 compared to the three months ended September 30, ~~2016~~2017

For the three months ended September 30, ~~2017,~~2018, we reported net income of ~~$43.8~~$62.6 million compared to net ~~loss~~income of ~~$19.2~~$43.8 million during the three months ended September 30, ~~2016.~~2017. Net income per basic and diluted share was $0.26 for the three months ended September 30, 2018 compared to net income per basic and diluted share of $0.22 for the three months ended September 30, 2017 compared to net loss per basic and diluted share of $0.10 for the three months ended September 30, 2016. Net income per basic share for the three months ended September 30, 2017 increased by $0.32 primarily due to the ceiling test impairment of $25.5 million incurred during the three months ended September 30, 2016 (whereas no ceiling test impairment was recognized during the three months ended September 30, 2017) and the 295% increase in revenues period over period. Revenues increased during the three months ended September 30, 2017 compared with the three months ended September 30, 2016 due to a 274% increase in production and a 6% increase in realized prices. As of September 30, 2017, we had 1,016 gross ~~producing wells, of which 399 were horizontal, compared with 635 gross producing wells, of which 245 were horizontal, as of September 30, 2016.~~

2017.

Oil, Natural Gas, and NGL Production and Revenues - For the three months ended September 30, ~~2017,~~2018, we recorded total oil, natural gas, and NGL revenues of ~~$103.6~~$161.0 million compared to ~~$26.2~~$103.6 million for the three months ended September 30, ~~2016,~~2017, an increase of ~~$77.4~~$57.4 million or ~~295%~~55%. The following table summarizes key production and revenue statistics:


	Three Months Ended September 30,				Percentage		Three Months Ended September 30,				Percentage
	2017		2016		Change		2018		2017		Change
Production:
Oil (MBbls) ¹	1,726		517		234	%	1,915		1,726		11	%
Natural Gas (MMcf) ²	7,412		2,855		160	%	9,471		7,412		28	%
NGLs (MBbls) ³	753		—		nm
MBOE ⁴	3,715		993		274	%
BOED ⁵	40,378		10,794		274	%
NGLs (MBbls) ¹							1,030		753		37	%
MBOE ³							4,523		3,714		22	%
BOED ⁴							49,165		40,378		22	%

Revenues (in thousands):
Oil	$	73,144	$	18,451	296	%	$	123,540	$	73,144	69	%
Natural Gas	17,402		7,783		124	%	16,908		17,402		(3	)%
NGLs ³	13,047		—		nm
NGLs							20,530		13,047		57	%
	$	103,593	$	26,234	295	%	$	160,978	$	103,593	55	%
Average sales price:
Oil	$	42.37	$	35.67	19	%
Oil ⁵							$	63.48	$	41.89	52	%
Natural Gas	2.35		2.73		(14	)%	1.79		2.35		(24	)%
NGLs ³	17.32		—		nm
BOE	$	27.89	$	26.42	6	%
NGLs							19.93		17.32		15	%
BOE ⁵							$	35.15	$	27.66	27	%

¹~~"MBbl"~~ "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.

⁵⁴"BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.

⁵Adjusted to include the effect of transportation and gathering expenses.

Net oil, natural gas, and NGL production for the three months ended September 30, ~~2017~~2018 averaged ~~40,378~~49,165 BOED, an increase of ~~274%~~22% over average production of ~~10,794~~40,378 BOED in the three months ended September 30, ~~2016.~~2017. From September 30, ~~2016~~2017 to September 30, ~~2017,~~2018, our well count increased by 91170 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 ~~274%~~22% increase in production and the 6%27% increase in average sales prices resulted in a significant increase in revenues.

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


	Three Months Ended September 30,				Three Months Ended September 30,
	2017		2016		2018		2017
Production costs	$	4,223	$	3,529	$	10,181	$	4,223
Workover	93		290		179		93
Transportation and gathering	838		—
Total LOE	$	5,154	$	3,819	$	10,360	$	4,316

Per BOE:
Production costs	$	1.14	$	3.55	$	2.25	$	1.14
Workover	0.03		0.29		0.04		0.03
Transportation and gathering	0.23		—
Total LOE	$	1.40	$	3.84	$	2.29	$	1.17

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells ~~and our overall production volumes~~ and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the three months ended September 30, ~~2017,~~2018, we experienced increased production expense compared to the three months ended September 30, 2017 due to a 45% increase in net operated wells. In addition, elevated line pressures temporarily drove operating costs on a per unit basis higher in the third quarter of 2018 as the Company incurred incremental costs without the typical benefit of flush production from its new wells.

Transportation and gathering - Transportation and gathering was $2.0 million, or $0.44 per BOE, for the three months ended September 30, ~~2016~~2018~~due~~, compared to ~~a 113% increase~~$0.8 million, or $0.23 per BOE, for the three months ended September 30, 2017. Coinciding with the increasing production in ~~horizontal operated wells~~2018, the Company has increased the volume of its production that is sold and a~~274%increase in~~delivered at the downstream interconnect. This has the effect of increasing both the net price received for the production ~~volumes. In addition, in the third quarter, we began delivering under new gathering agreements which resulted in~~and transportation and gathering ~~charges. Unit operating~~costs. While costs ~~benefited from larger~~attributable to volumes sold at the interconnect of ~~early production~~the pipeline are reported as an expense, the Company analyzes these charges on ~~the horizontal wells turned to sales during the quarter in addition to the production from wells turned to sales after the third quarter of 2016.~~a net basis within revenue for comparability with wellhead sales.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. ~~During~~Production taxes were $12.8 million, or $2.83 per BOE, for the three months ended September 30, ~~2017, production taxes were~~2018, compared to $10.1 million, or $2.71 per BOE, ~~compared to $(1.5) million, or $(1.47) per BOE,~~ during the ~~prior year period.~~three months ended September 30, 2017. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were ~~9.7%~~8.0% and ~~(5.6)%~~9.7% for the three months ended September 30, 2018 and 2017, ~~and 2016,~~ respectively. During the three months ended September 30, 2017, the production tax rate 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 September 30,				Three Months Ended September 30,
(in thousands)	2017		2016		2018		2017
Depletion of oil and gas properties	$	32,944	$	9,273	$	44,230	$	32,944
Depreciation and accretion	796		362		958		796
Total DD&A	$	33,740	$	9,635	$	45,188	$	33,740

DD&A expense per BOE	$	9.08	$	9.70	$	9.99	$	9.08

For the three months ended September 30, ~~2017,~~2018, DD&A was ~~$9.08~~$9.99 per BOE compared to ~~$9.70~~$9.08 per BOE for the three months ended September 30, ~~2016.~~2017. The ~~decrease~~increase 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 recentrecent 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~~whereby the ratio of production volumes for the quarter to the beginning of quarter estimated total reserves determines the depletion rate.

~~Full cost ceiling impairment~~ - During the three months ended September 30, 2017, we had no impairment as compared to an impairment of $25.5 million for the three months ended 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 September 30,						Three Months Ended September 30,
(in thousands)	2017			2016			2018			2017
G&A costs incurred	$	11,002		$	9,993		$	13,836		$	11,002
Capitalized costs	(2,518		)	(1,757		)	(3,151		)	(2,518		)
Total G&A	$	8,484		$	8,236		$	10,685		$	8,484

Non-Cash G&A	$	3,030		$	2,375		$	3,405		$	3,030
Cash G&A	5,454			5,861			7,280			5,454
Total G&A	$	8,484		$	8,236		$	10,685		$	8,484

Non-Cash G&A per BOE	$	0.82		$	2.39		$	0.75		$	0.82
Cash G&A per BOE	1.47			5.90			1.61			1.47
G&A Expense per BOE	$	2.29		$	8.29		$	2.36		$	2.29

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 ~~$8.5~~$10.7 million for the third quarter of ~~2017~~2018 were 3%26% higher than G&A for the same period of ~~2016.~~2017. This increase is primarily due to a ~~32%~~ 25% increase in employee headcount from ~~89 at September 30, 2016 to~~ 117 at September 30, 2017 ~~which~~to 146 at September 30, 2018. Additionally, G&A for the three months ended September 30, 2018 was ~~offset~~elevated by ~~a reduction~~expenses incurred in ~~professional fees incurred due to decreased deal activity~~support of Colorado oil and ~~contract services during 2017.~~gas legislative activities.

Our G&A expense for the three months ended September 30, ~~2017~~2018 includes stock-based compensation of ~~$3.0~~$3.4 million compared to ~~$2.4~~$3.0 million for the three months ended 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.2017.

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 September 30, ~~2016~~2017 to the three months ended September 30, ~~2017~~2018 reflects our ~~overall increase in G&A activity.~~increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

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 September 30, ~~2017,~~2018, we realized a ~~cash~~ settlement ~~gain~~loss of ~~$0.1 million, net of previously incurred premiums attributable to the settled commodity contracts.~~ $8.3 million. For the prior comparable period, we realized a ~~cash~~ settlement ~~loss~~ gainof ~~$13.0 thousand,~~$0.1 million, net of previously incurred premiums attributable to the settled commodity contracts.

In addition, for the three months ended September 30, ~~2017,~~2018, we recorded an unrealized loss of ~~$2.5~~$0.3 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the three months ended September 30, ~~2016,~~2017, we reported an unrealized ~~gain~~loss of ~~$0.4~~$2.5 million. Unrealized ~~gains and~~ losses are non-cash items.

Income taxes - WeAs more fully described in Item 1. Financial Statements – Note 13, Income Taxes, we reported no income tax expense of $8.9 million for the three months ended September 30, ~~2017 or~~2018 as compared to no income tax expense for the comparable prior year period. ~~During~~The effective tax rates for the three and nine months ended September 30, ~~2017~~2018 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 September 30,~~ 2017 ~~and 2016, the effective tax rate~~ differed from the statutory ~~rate~~rates due primarily ~~due~~ to the ~~recognition~~release of ~~the~~ valuation ~~allowance~~allowances previously 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 September 30, 2017. During the 2016 comparable period, we reached the same conclusion; therefore, a valuation allowance has been provided as of September 30, 2016.

For the nine months ended September 30, ~~2017~~2018 compared to the nine months ended September 30, ~~2016~~2017

For the nine months ended September 30, ~~2017,~~2018, we reported net income of ~~$91.7~~$178.0 million compared to net ~~loss~~income of ~~$224.5~~$91.7 million during the nine months ended September 30, ~~2016.~~2017. Net income per basic and diluted share was $0.74 and $0.73, respectively, for the nine months ended September 30, 2018 compared to net income per basic and diluted share of $0.46 for the nine months ended September 30, 2017 compared to net loss per basic and diluted share of $1.36 for the nine months ended September 30, 2016. Net income per basic share for the nine months ended September 30, 2017 increased by $1.82 primarily due to the ceiling test impairment of $215.2 million incurred during the nine months ended September 30, 2016 (whereas no ceiling test impairment was recognized during the nine months ended September 30, 2017) and the 225% increase in revenues period over period. Revenues increased during the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 due to a 171% increase in production and a 20% increase in realized prices. As of September 30, 2017, we had 1,016 gross producing wells, o~~f which 399 were~~ ~~horizontal, compared with 635 gross producing wells, of which 245 were horizontal, as of September 30, 2016.~~2017.

Oil, Natural Gas, and NGL Production and Revenues - For the nine months ended September 30, ~~2017,~~2018, we recorded total oil, natural gas, and NGL revenues of ~~$222.4~~$455.3 million compared to ~~$68.5~~$222.4 million for the nine months ended September 30, ~~2016,~~2017, an increase of ~~$154.0~~$232.9 million or ~~225%~~105%. The following table summarizes key production and revenue statistics:

Nine Months Ended September 30, Percentage
2017 2016 Change
Production:
Oil (MBbls) 3,668
1,552
136 %
Natural Gas (MMcf) 17,122
8,991
90 %
NGLs (MBbls) ¹
1,758
—
nm
MBOE 8,280
3,050
171 %
BOED 30,331
11,133
172 %

Revenues (in thousands):
Oil $ 154,232
$ 48,838
216 %
Natural Gas 40,945
19,616
109 %
NGLs ¹
27,242
—
nm
$ 222,419
$ 68,454
225 %
Average sales price:
Oil $ 42.04
$ 31.47
34 %
Natural Gas 2.39
2.18
10 %
NGLs ¹
15.49
—
nm
BOE $ 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.



	Nine Months Ended September 30,				Percentage
	2018		2017		Change
Production:
Oil (MBbls)	5,802		3,668		58	%
Natural Gas (MMcf)	26,177		17,122		53	%
NGLs (MBbls)	2,780		1,758		58	%
MBOE	12,945		8,280		56	%
BOED	47,416		30,331		56	%

Revenues (in thousands):
Oil	$	354,601	$	154,232	130	%
Natural Gas	48,139		40,945		18	%
NGLs	52,558		27,242		93	%
	$	455,298	$	222,419	105	%
Average sales price:
Oil	$	60.13	$	41.73	44	%
Natural Gas	1.84		2.39		(23	)%
NGLs	18.91		15.49		22	%
BOE	$	34.73	$	26.72	30	%

Net oil, natural gas, and NGL production for the nine months ended September 30, ~~2017~~2018 averaged ~~30,331~~47,416 BOED, an increase of ~~172%~~56% over average production of ~~11,133~~30,331 BOED in the nine months ended September 30, ~~2016.~~2017. From September 30, ~~2016~~2017 to September 30, ~~2017,~~2018, our well count increased by 91170 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 ~~171%~~56% increase in production and ~~the 20%~~30% 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):


	Nine Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2018		2017
Production costs	$	12,511	$	14,464	$	29,328	$	12,511
Workover	$	497	$	499	540		497
Transportation and gathering	$	886	$	—
Total LOE	$	13,894	$	14,963	$	29,868	$	13,008

Per BOE:
Production costs	$	1.51	$	4.74	$	2.27	$	1.51
Workover	0.06		0.16		0.04		0.06
Transportation and gathering	0.11		—
Total LOE	$	1.68	$	4.90	$	2.31	$	1.57

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells ~~and our overall production volumes~~ and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the nine months ended September 30, ~~2017,~~2018, we experienced ~~decreased~~increased production expense compared to the nine months ended September 30, ~~2016~~2017 primarilydue to ~~significantly less expense related to environmental remediation~~a 45% increase in net operated wells. In addition, elevated line pressures temporarily drove operating costs on a unit basis higher in the second and ~~regulatory compliance projects during 2017 and~~third quarter of 2018 as the~~consolidation~~ Company incurred incremental costs without the typical benefit of ~~our operations into a more central geographic operating area~~flush production from its new wells.

~~. This decrease was partially offset by transportation~~Transportation and gathering ~~charges resulting from new~~- Transportation and gathering ~~agreements. Unit operating costs benefited from larger volumes of early production on th~~was $5.7 million, or $0.44 per BOE, for the ~~e 87 horizontal wells turned to sales during the~~nine months ended September 30, 2018, compared to $1.1 million, or $0.14 per BOE, for the nine months ended September 30, 2017. In the first half of 2017,~~in addition~~ a majority of the Company's production was delivered to the purchaser at the wellhead whereas, in 2018, the

Company has increased the proportion of its production that is sold and delivered at the downstream interconnect. This has the effect of increasing both the net price received for the production and transportation and gathering costs. While costs attributable to volumes sold at the interconnect of the pipeline are reported as an expense, the Company analyzes these charges on ~~wells turned to sales after thethirdquarter of2016.~~a net basis within revenue for comparability with wellhead sales.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $41.3 million, or $3.19 per BOE, for the nine months ended September 30, 2018, compared to $21.0 million, or $2.54 per BOE, for the nine months ended September 30, ~~2017, compared to $2.5 million, or $0.82 per BOE, for the nine months ended September 30, 2016.~~2017. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were ~~9.4%~~9.1% and ~~3.7%~~9.4% for the nine months ended September 30, 2018 and 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:


	Nine Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2017		2016		2018		2017
Depletion of oil and gas properties	$	71,389	$	31,981	$	121,259	$	71,389
Depreciation and accretion	2,007		1,020		2,887		2,007
Total DD&A	$	73,396	$	33,001	$	124,146	$	73,396

DD&A expense per BOE	$	8.86	$	10.82	$	9.59	$	8.86

For the nine months ended September 30, ~~2017,~~2018, DD&A was ~~$8.86~~$9.59 per BOE compared to ~~$10.82~~$8.86 per BOE for the nine months ended September 30, ~~2016.~~ 2017. The ~~decrease~~increase 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 recentrecent 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~~whereby the ratio of production volumes for the quarter to the beginning of the quarter estimated total reserves ~~determined~~determines the depletion rate.

~~Full cost ceiling impairment~~ - During the nine months ended September 30, 2017, we had no impairment as compared to an impairment of $215.2 million for the nine months ended 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:


	Nine Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2018			2017
G&A costs incurred	$	32,018		$	27,944		$	39,298		$	32,018
Capitalized costs	(7,729		)	(4,745		)	(9,607		)	(7,729		)
Total G&A	$	24,289		$	23,199		$	29,691		$	24,289

Non-Cash G&A	$	8,390		$	7,285		$	9,347		$	8,390
Cash G&A	15,899			15,914			20,344			15,899
Total G&A	$	24,289		$	23,199		$	29,691		$	24,289

Non-Cash G&A per BOE	$	1.01		$	2.39		$	0.72		$	1.01
Cash G&A per BOE	1.92			5.22			1.57			1.92
G&A Expense per BOE	$	2.93		$	7.61		$	2.29		$	2.93

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 ~~$24.3~~$29.7 million for the ~~third quarter of 2017~~nine months ended September 30, 2018 were 5%22% higher than G&A for the same period of ~~2016.~~2017. This increase is primarily due to a ~~32%~~25% increase in employee headcount from ~~89 at September 30, 2016 to~~ 117 at September 30, 2017 ~~which~~to 146 at September 30, 2018. Additionally, G&A for the nine months ended September 30, 2018 was ~~offset~~elevated by ~~a reduction~~expenses incurred in ~~professional fees incurred due to decreased deal activity~~support of Colorado oil and ~~contract services~~gas legislative activities during ~~2017.~~the third quarter of 2018.

Our G&A expense for the nine months ended September 30, ~~2017~~2018 includes stock-based compensation of ~~$8.4~~$9.3 million compared to ~~$7.3~~$8.4 million for the nine months ended September 30, ~~2016.~~2017.

properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the nine months ended September 30, ~~2016~~2017 to the nine months ended September 30, ~~2017~~2018 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 nine months ended September 30, ~~2017,~~2018, we realized a ~~cash~~settlement loss of $16.2 million. For the prior comparable period, we realized a settlement loss of $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 nine months ended September 30, ~~2017,~~2018, we recorded an unrealized ~~gain~~loss of ~~$2.4~~$12.4 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the nine months ended September 30, ~~2016,~~2017, we reported an unrealized ~~loss~~gain of ~~$6.5~~$2.4 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense of $18.1 million for the nine months ended September 30, ~~2017 or~~2018 as compared to no income tax expense for the comparable prior year period. As explained in more detail in the "-Income taxes" section above, during the nine months ended 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 nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, the effective tax rate differed from the statutory rate due primarily ~~due~~ to the ~~recognition~~release of ~~the~~ valuation ~~allowance~~allowances previously 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.~~facilities, and proceeds from the sale of properties. 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 current capital resources, including cash flows from operating activities, cash on hand, and 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. During the nine months ended September 30, 2018, our drilling and completions expenditures were primarily covered by cash flows from operating activities. 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 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, while the NYMEX-Henry Hub naturalOil and 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 September 30, ~~2017,~~2018, we had cash, ~~and~~ cash equivalents, and restricted cash of ~~$21.3~~$19.2 million, ~~$80.0~~$550.0 million outstanding on our Senior 2025 Notes, and a ~~$150.0~~$115.0 million balance outstanding ~~balance~~ under our revolving credit facility. Our sources and (uses) of funds for the nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 are summarized below (in thousands):


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2018			2017
Net cash provided by operations	$	142,817		$	33,193		$	343,554		$	142,817
Capital expenditures	(383,483		)	(582,149		)	(490,124		)	(383,454		)
Net cash provided by other investing activities	95,265			5,979			1,233			77,017
Net cash (used in) provided by equity financing activities	(517		)	542,901
Net cash provided by (used in) debt financing activities	148,628			(2,666		)
Net increase (decrease) in cash and equivalents	$	2,710		$	(2,742	)
Net cash provided by (used in) equity financing activities							3,039			(517		)
Net cash provided by debt financing activities							112,762			148,628
Net increase in cash, cash equivalents, and restricted cash							$	(29,536	)	$	(15,509	)

Net cash provided by operating activities was ~~$142.8~~$343.6 million and ~~$33.2~~$142.8 million for the nine months ended September 30, 2018 and 2017, ~~and 2016, respectively.~~respectively. The increase in cash from operating activities reflects the increase in realized commodity prices and production.

~~Net~~Net cash provided by other investing activities was ~~$95.3~~$1.2 millionand ~~$6.0~~$77.0 millionfor thenine months endedSeptember 30, 2018and2017, ~~and 2016, respectively. For the nine months ended September 30, 2017, we received~~respectively, which were primarily comprised of 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 $24.2 million; these inflows were offset by net cash deposited in escrow of $18.2 million.

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

Credit Facility

The Revolver has a maturity date of ~~December 15, 2019. The agreement was most recently amended in September 2017.~~April 2, 2023. The Revolver has a maximum loan commitment of ~~$500 million;~~$1.5 billion; however, the maximum amount ~~that we can borrow~~available to be borrowed at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the ~~lesser~~least of the aggregate maximum ~~loan~~credit amount, the aggregate elected commitment, or the borrowing base. The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the Revolver. The value of the collateral will generally be derived with reference to the estimated discounted future net cash flows from our proved oil and natural gas reserves. The collateral includes substantially all of our producing wells and developed oil and gas leases.

~~As a result of the~~ ~~regular semi-annual redetermination of our borrowing base on September 27, 2017,~~In October 2018, the borrowing base was increased from $~~225~~550 million to $~~400 million.~~650 million; however, our elected commitment amount was $500 million. As of ~~September 30, 2017,~~October 31, 2018, there was a~~$150.0~~ $145.0 million~~outstanding~~ principal balance outstanding and ~~$0.5 million~~no in letters of credit outstanding, leaving $~~249.5~~355.0 million available to us for future borrowings. The next semi-annual redetermination is scheduled for April ~~2018.~~2019. Interest on the Revolver accrues at a variable rate. The interest rate pricing grid ~~contains a graduated~~provides for an escalation in applicable margin ~~for~~based on increased ~~utilization.~~utilization of the Revolver.

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

2025 Senior Notes

~~On June 14, 2016,~~In November 2017, the Company issued ~~$80~~$550 million aggregate principal amount of ~~the~~6.25% Senior Notes due 2025 (the 2025 Senior Notes) in a private placement to qualified institutional buyers. The maturity for the payment of principal is ~~June 13, 2021.~~December 1, 2025. Interest on the 2025 Senior Notes accrues at 9%6.25% and began accruing on ~~June 14, 2016.~~November 29, 2017. Interest is payable on June 151 and December 151 of each year. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and will be guaranteed on a senior unsecured basis by 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 periodyear, 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.June 1, 2018.

Capital Expenditures

Capital expenditures for drilling and completion activities totaled ~~$159.5~~$408.3 million and $383.0 million for the ~~three and~~ nine months ended September 30, 2018 and 2017, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):


					Nine Months Ended September 30,
	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017		2018		2017
Capital expenditures for drilling and completion activities					$	408,334	$	383,028
Operated	$	94,971	$	290,717
Non-operated	64,561		92,311
Total	159,532		383,028

Acquisitions of oil and gas properties and leasehold*	56,835		89,677		162,081		89,677
Capitalized interest, capitalized G&A, and other	5,718		17,514		40,037		17,514
Accrual basis capital expenditures**	$	222,085	$	490,219	$	610,452	$	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 year-to-date non-operated capital expenditures are driven by the 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 September 30, ~~2017,~~2018, we drilled 8789 operated horizontal wells and ~~completed 87~~turned 54 operated horizontal ~~wells.~~ wells to sales. As ofSeptember 30, ~~2017,~~2018, the Company had 9 gross (8 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the fourth quarter. As of September 30, 2018, we are the operator o~~f 46~~of 77 gross ~~(36~~(66 net) h~~orizontal~~horizontal wells in progress,. which excludes 30 gross (23 net) wells for which we have only set surface casings. All of the wells in progress at September 30, 2018 are scheduled to commence production before December 31, 2019. The majority of this activity was funded through cash flows from operations.

For the nine months ended September 30, ~~2017,~~2018, we ~~have~~ participated in ~~123~~61 gross ~~(23~~(14 net) ~~non-operated~~non-operated horizontal 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, development results, acquisitions and divestitures, and downstream infrastructure and 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.~~2018.

We anticipate that our ~~2017~~full-year 2018 drilling and completion capital expenditures for operated wells will be approximately ~~$360~~$580 million ~~for the year.~~($408.3 million of which was incurred through September 30, 2018). 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 are expected to be approximately $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 ~~September 30, 2017,~~October 23, 2018, we had open positions covering ~~1.3~~3.1 million barrels of oil and ~~8,984~~15,380 MMcf of natural gas. We do not use derivative instruments for speculative purposes.

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

During the nine months ended September 30, ~~2017,~~2018, we reported an unrealized commodity activity ~~gain~~loss of ~~$2.4~~$12.4 million. Unrealized ~~gains~~losses are non-cash items. We also reported a realized loss of ~~$26.0 thousand,~~$16.2 million, representing the ~~cash~~ settlement of commodity contracts settled during the ~~period, net of previously incurred premiums attributable to the settled commodity contracts.~~period.

At September 30, ~~2017,~~2018, we estimated that the fair value of our various commodity derivative contracts was a net liability of ~~$1.2~~$20.2 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 that 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.~~net income. 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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Adjusted EBITDA:
Net income (loss)	$	43,848		$	(19,241	)	$	91,664		$	(224,490	)
Net income													$	62,628		$	43,848		$	178,048		$	91,664
Depreciation, depletion, and accretion	33,740			9,635			73,396			33,001			45,188			33,740			124,146			73,396
Full cost ceiling impairment	—			25,453			—			215,223
Stock-based compensation expense													3,405			3,030			9,347			8,390
Mark-to-market of commodity derivative contracts:
Total loss (gain) on commodity derivatives contracts													8,529			2,383			28,604			(2,324		)
Cash settlements on commodity derivative contracts													(7,142		)	544			(13,263		)	778
Interest income													(23		)	(16		)	(37		)	(47		)
Income tax expense	—			5			—			106			8,918			—			18,076			—
Stock-based compensation	3,030			2,374			8,390			7,285
Mark-to-market of commodity derivative contracts:
Total (gain) loss on commodity derivatives contracts	2,383			(407		)	(2,324		)	3,617
Cash settlements on commodity derivative contracts	544			486			778			5,137
Interest income, net of interest expense	(16		)	(11		)	(47		)	(176		)
Adjusted EBITDA	$	83,529		$	18,294		$	171,857		$	39,703		$	121,503		$	83,529		$	344,921		$	171,857

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~~21, 2018 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 and the construction and effect of additional midstream infrastructure, future differentials, future production relative to volume commitments, and the ~~closing~~potential implementation and ~~effect~~effects of ~~proposed transactions.~~Proposition 112 and our responses thereto.

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~~2017 filed with the SEC on February ~~23, 2017~~21, 2018 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;~~fracturing and Proposition 112;

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 ~~71% and 69%~~77% of our revenue during the three and nine months ended September 30, ~~2017, respectively,~~2018 was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a ~~$8.6~~$9.6 million and ~~$18.3~~$29.0 million change in revenues during the three and nine months ended September 30, ~~2017, respectively,~~2018, respectively; a $0.25 per Mcf change in our realized natural gas price would have resulted in a ~~$1.9~~$2.4 million and ~~$4.3~~$6.5 million change in our natural gas revenues for the three and nine months ended September 30, ~~2017, respectively,~~2018, respectively; and a $5 per barrel change in our realized NGL price would have resulted in a ~~$3.8~~$5.2 million and ~~$8.8~~$13.9 million change in our NGL revenues for the three and nine months ended September 30, ~~2017,~~2018, respectively.

During the three months ended September 30, ~~2017,~~2018, the price of oil, natural gas, and NGLs increased relative to the ~~third~~second quarter of ~~2016.~~2018. 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 September 30, ~~2017,~~2018, we had open oil and natural gas derivatives in a net liability position with a fair value of ~~$1.2~~$20.2 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 ~~$1.4~~$16.1 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 ~~$1.2~~$7.8 million. ~~A summary of our open positions as of~~ ~~September 30, 2017~~ ~~is set forth in Item 1. Financial Statements - Note 8,~~ ~~Commodity Derivative Instruments.~~

Interest Rate Risk - At September 30, ~~2017,~~2018, we had ~~$150~~$115.0 million ~~in debt~~ outstanding under our revolving credit facility. Interest on amounts borrowed under our credit facility accrues at a variable rate, based upon either the Prime Rate or LIBOR plus an applicable margin. During the three and nine months ended September 30, ~~2017,~~2018, we incurred interest ~~at an annualized rate~~expense of ~~3.3%. We~~$0.4 million and $0.5 million on our revolving credit facility, respectively. When we have balances outstanding under the revolving credit facility, 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~~expense in ~~each of~~ the three and nine months ended September 30, ~~2017~~2018 would have changed by ~~$0.3 million and $0.4 million, respectively.~~approximately $0.1 million.

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

Counterparty Risk - As described in ~~"- Commodity~~"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,~~well-capitalized, well-established, and well-known counterparties that have been approved by our senior officers. There can be no assurance, however, that our practice effectively mitigates counterparty risk.

We believe that our exposure to counterparty risk increased slightly during the third quarter of ~~2017~~2018 as the amounts due to us from counterparties ~~has~~have 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~~During the ~~accompanying condensed consolidated financial statements, during the~~ quarter ended September 30, 2018, there were no material developments regarding the 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.~~21, 2018. This information should be considered carefully together with other information in this report and other reports and materials we file with the SEC. We are subject to various legal proceedings from time to time in the ordinary course of our business, but there are currently no pending legal proceedings to which we are subject that we believe to be material.


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.~~21, 2018. This information should be considered carefully together with other information in this report and other reports and materials that we file with the SEC.

Proposition 112, if approved, would have a material adverse effect on our future drilling inventory and other aspects of our business.

Proposition 112 is a proposed statutory amendment that will be voted on in Colorado in November 2018. Proposition 112 would require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or “vulnerable areas,” a term defined to include playgrounds, permanent sports fields, amphitheaters, public parks, public open space, public and community drinking water sources, irrigation canals, reservoirs, lakes, rivers, perennial or intermittent streams and creeks and any additional areas designated by the state or a local government. Proposition 112 would not apply to federal lands. If implemented, Proposition 112 would have a variety of adverse effects on our business. In particular, the expanded setback requirement (current law generally requires a setback between oil and gas wells and occupied structures of 500 feet) would make it unlawful to drill many of our currently planned locations, and would limit our ability to add drilling locations to our inventory in the future. The Colorado Oil and Gas Conservation Commission has estimated that Proposition 112 would make drilling unlawful on approximately 85 percent of the non-federal surface area of the state of Colorado, including approximately 85 percent of the non-federal surface area of Weld County. The remaining land available for drilling would likely be reduced over time as additional occupied structures are built and additional areas are designated as vulnerable. Proposition 112’s limitation on our existing and potential future locations would significantly restrict our opportunities for growth and, over time, would likely have a materially adverse effect on our results of operations, financial condition and ability to attract capital.

The implementation of Proposition 112 could have other potential adverse effects on our business, including, but not limited to:

additional constraints on midstream capacity if midstream infrastructure and services are not expanded as currently expected,

increased operating costs,

greater difficulties in maintaining leases through production,

increased expenses related to legal, regulatory, or legislative actions that we may pursue in response to the implementation of the proposition, and

inability to meet commitments related to our future production.

Finally, even if Proposition 112 is not approved, we expect that some political leaders will propose new regulations to restrict oil and natural gas development activities by other means in an attempt to address concerns underlying the proposition. We cannot predict the outcome of any such proposals, but they could have material and adverse effects on our business.


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
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



Period	Total Number of Shares Purchased	Average Price Paid per Share
July 1, 2018 - July 31, 2018 ⁽¹⁾	—	$	—
August 1, 2018 - August 31, 2018 ⁽¹⁾	7,077	9.85
September 1, 2018 - September 30, 2018 ⁽¹⁾	2,899	$	9.31
Total	9,976

(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~~applicable.


Item 5.	Other Information

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.None.

Item 6. Exhibits



Exhibit Number		Exhibit
~~3.2~~10.1		~~Amended and Restated Bylaws~~Form of ~~SRC Energy Inc., effective as of August 18, 2017~~Goal Based Performance-Vested Stock Unit Agreement *
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 ~~1st~~31st day of ~~November, 2017.~~October, 2018.



	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 and Chief Financial Officer ~~and Treasurer~~ (Principal Financial Officer)

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



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



(in thousands)	Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
Oil, natural gas, and NGL revenues	$	26,234		$	71,940
Net loss	$	(19,241	)	$	(227,479	)

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



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



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



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