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~~June 30, ~~2017~~2019



	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.~~Energy Inc.

(Exact name of registrant as specified in its charter)



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

1675 Broadway, Suite 2600

Denver, Colorado80202

(Address of principal executive offices) (Zip Code)

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

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



~~1675 Broadway, Suite 2600, Denver, CO~~	~~80202~~
~~(Address~~Title of ~~principal executive offices)~~ each class	~~(Zip Code)~~	Trading Symbol(s)	Name of each exchange on which registered
Common stock $.001 par value		SRCI	NYSE American

~~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)~~files). 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 filerý	☒	Accelerated filer	☐	~~Accelerated filer~~ o

Non-accelerated filero ~~(Do not check if a smaller reporting company)~~	☐	Smaller reporting companyo	☐

		Emerging growth companyo	☐

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~~243,473,491 outstanding shares of common stock as of ~~October 31, 2017.~~July 29, 2019.

SRC ENERGY INC.

Index



		Page
Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Condensed Consolidated Balance Sheets as of ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016~~2018	2

	Condensed Consolidated Statements of Operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	3

	Condensed Consolidated Statements of Cash Flows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	4

	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the six months ended June 30, 2019 and 2018	5

	Notes to Condensed Consolidated Financial Statements	56

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2421

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4137

Item 4.	Controls and Procedures	4238

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings	4339

Item 1A.	Risk Factors	4339

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4339

Item 3.	Defaults of Senior Securities	4339

Item 4.	Mine Safety Disclosures	4339

Item 5.	Other Information	4339

Item 6.	Exhibits	4440

SIGNATURES		4541

SRC ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands, except share data)


ASSETS	September 30, 2017			December 31, 2016			June 30, 2019		December 31, 2018
Current assets:
Cash and cash equivalents	$	21,325		$	18,615		$	27,839	$	49,609
Accounts receivable:
Oil, natural gas, and NGL sales	72,309			25,728			80,510		100,973
Trade	45,280			6,805			21,961		39,415
Commodity derivative assets	—			297			12,061		34,906
Other current assets	6,289			2,739			7,257		7,537
Total current assets	145,203			54,184			149,628		232,440

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			1,775,675		1,545,445
Wells in progress	158,192			81,780			175,400		227,262
Unproved properties and land, not subject to depletion							667,678		740,453
Oil and gas properties, net	1,243,481			904,409			2,618,753		2,513,160
Other property and equipment, net	6,152			4,327			4,881		5,540
Total property and equipment, net	1,249,633			908,736			2,623,634		2,518,700
Cash held in escrow and other deposits	—			18,248
Goodwill	40,711			40,711
Other assets	2,359			2,234			11,824		3,574
Total assets	$	1,437,906		$	1,024,113		$	2,785,086	$	2,754,714

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	134,144		$	52,453		$	76,648	$	150,010
Revenue payable	58,742			16,557			95,838		97,030
Production taxes payable	37,017			17,673			81,905		95,099
Asset retirement obligations	2,738			2,683			10,608		11,694
Commodity derivative liabilities	786			2,874
Total current liabilities	233,427			92,240			264,999		353,833

Revolving credit facility	150,000			—			165,000		195,000
Notes payable, net of issuance costs	76,216			75,614			539,977		539,360
Commodity derivative liabilities	394			—
Asset retirement obligations	33,981			13,775			38,609		40,052
Deferred taxes							74,238		37,967
Other liabilities	2,268			1,745			4,646		2,210
Total liabilities	496,286			183,374			1,087,469		1,168,422

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 shares authorized: 243,428,206 and 242,608,284 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively							243		243
Additional paid-in capital	1,158,317			1,148,998			1,499,213		1,492,107
Retained deficit	(216,898		)	(308,460		)
Retained earnings							198,161		93,942
Total shareholders' equity	941,620			840,739			1,697,617		1,586,292

Total liabilities and shareholders' equity	$	1,437,906		$	1,024,113		$	2,785,086	$	2,754,714

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 June 30,					Six Months Ended June 30,
												2019		2018			2019			2018
Oil, natural gas, and NGL revenues	$	103,593		$	26,234		$	222,419	$	68,454		$	162,602	$	147,087		$	352,057		$	294,320
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			13,230		11,612			30,590			19,508
Transportation and gathering												4,664		1,880			8,718			3,735
Production taxes	10,083			(1,461		)	21,013		2,509			13,185		15,058			20,271			28,501
Costs of purchased oil	—			—			1,518		—
Depreciation, depletion, and accretion	33,740			9,635			73,396		33,001			58,027		41,877			118,945			78,958
Full cost ceiling impairment	—			25,453			—		215,223
Unused commitment charge	—			205			669		505
General and administrative	8,484			8,236			24,289		23,199			9,243		9,406			18,712			19,006
Total expenses	57,461			45,887			134,779		289,400			98,349		79,833			197,236			149,708

Operating income (loss)	46,132			(19,653		)	88,908		(220,946		)
Operating income												64,253		67,254			154,821			144,612

Other income (expense):
Commodity derivatives gain (loss)	(2,383		)	407			2,324		(3,617		)
Commodity derivative gain (loss)												8,285		(14,294		)	(14,628		)	(20,075		)
Interest expense, net of amounts capitalized	—			—			—		—			—		—			—			—
Interest income	16			11			47		176			92		5			161			14
Other income (expense)	83			(1		)	385		3
Other income												75		6			136			27
Total other income (expense)	(2,284		)	417			2,756		(3,438		)	8,452		(14,283		)	(14,331		)	(20,034		)

Income (Loss) before income taxes	43,848			(19,236		)	91,664		(224,384		)
Income before income taxes												72,705		52,971			140,490			124,578

Income tax expense	—			5			—		106			18,237		3,347			36,271			9,158
Net income (loss)	$	43,848		$	(19,241	)	$	91,664	$	(224,490	)
Net income												$	54,468	$	49,624		$	104,219		$	115,420

Net income (loss) per common share:
Net income per common share:
Basic	$	0.22		$	(0.10	)	$	0.46	$	(1.36	)	$	0.22	$	0.20		$	0.43		$	0.48
Diluted	$	0.22		$	(0.10	)	$	0.46	$	(1.36	)	$	0.22	$	0.20		$	0.43		$	0.47

Weighted-average shares outstanding:
Basic	200,881,447			200,515,555			200,807,436		164,771,544			243,404,917		242,255,724			243,348,141			242,005,211
Diluted	201,460,915			200,515,555			201,326,129		164,771,544			244,130,245		244,464,776			243,709,915			243,954,673

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



	Six Months Ended June 30,
	2019			2018
Cash flows from operating activities:
Net income	$	104,219		$	115,420
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and accretion	118,945			78,958
Settlement of asset retirement obligations	(4,476		)	(4,089		)
Provision for deferred taxes	36,271			9,158
Stock-based compensation expense	6,825			5,942
Mark-to-market of commodity derivative contracts:
Total loss on commodity derivatives contracts	14,628			20,075
Cash settlements on commodity derivative contracts	7,715			(6,121		)
Cash premiums paid for commodity derivative contracts	(977		)	—
Changes in operating assets and liabilities	18,433			16,419
Net cash provided by operating activities	301,583			235,762

Cash flows from investing activities:
Acquisition of oil and gas properties and leaseholds, net of post-closing adjustments	116			(16,402		)
Capital expenditures for drilling and completion activities	(276,095		)	(213,906		)
Other capital expenditures	(28,262		)	(23,823		)
Acquisition of land and other property and equipment	(304		)	(1,581		)
Proceeds from sales of oil and gas properties and other	12,802			766
Net cash used in investing activities	(291,743		)	(254,946		)

Cash flows from financing activities:
Proceeds from the employee exercise of stock options	—			4,192
Payment of employee payroll taxes in connection with shares withheld	(1,126		)	(1,010		)
Proceeds from the revolving credit facility	—			25,000
Principal repayments on the revolving credit facility	(30,000		)	—
Fees on debt and equity issuances and revolving credit facility amendments	(379		)	(2,165		)
Capital lease payments	(105		)	(135		)
Net cash provided by (used in) financing activities	(31,610		)	25,882

Net increase (decrease) in cash and cash equivalents	(21,770		)	6,698

Cash and cash equivalents at beginning of period	49,609			48,772

Cash and cash equivalents at end of period	$	27,839		$	55,470

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

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

SRC ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(unaudited; in thousands, except share data)



	Number of Common Shares	Par Value Common Stock		Additional Paid-In Capital			Retained Deficit			Total Shareholders' Equity
Balance, December 31, 2017	241,365,522	$	241	$	1,474,273		$	(166,080	)	$	1,308,434
Shares issued under stock bonus and equity incentive plans	268,676	1		(1		)	—			—
Shares issued for exercise of stock options	268,303	—		1,064			—			1,064
Stock-based compensation	—	—		3,395			—			3,395
Payment of tax withholdings using withheld shares	—	—		(705		)	—			(705		)
Other activity	—	—		(73		)	—			(73		)
Net income	—	—		—			65,796			65,796
Balance, March 31, 2018	241,902,501	242		1,477,953			(100,284		)	1,377,911
Shares issued under stock bonus and equity incentive plans	69,420	—		—			—			—
Shares issued for exercise of stock options	524,159	—		3,127			—			3,127
Stock-based compensation	—	—		3,768			—			3,768
Payment of tax withholdings using withheld shares	—	—		(305		)	—			(305		)
Net income	—	—		—			49,624			49,624
Balance, June 30, 2018	242,496,080	$	242	$	1,484,543		$	(50,660	)	$	1,434,125



	Number of Common Shares	Par Value Common Stock		Additional Paid-In Capital			Retained Earnings		Total Shareholders' Equity
Balance, December 31, 2018	242,608,284	$	243	$	1,492,107		$	93,942	$	1,586,292
Shares issued under stock bonus and equity incentive plans	709,042	—		—			—		—
Stock-based compensation	—	—		4,413			—		4,413
Payment of tax withholdings using withheld shares	—	—		(876		)	—		(876		)
Net income	—	—		—			49,751		49,751
Balance, March 31, 2019	243,317,326	243		1,495,644			143,693		1,639,580
Shares issued under stock bonus and equity incentive plans	110,880	—		—			—		—
Stock-based compensation	—	—		3,819			—		3,819
Payment of tax withholdings using withheld shares	—	—		(250		)	—		(250		)
Net income	—	—		—			54,468		54,468
Balance, June 30, 2019	243,428,206	$	243	$	1,499,213		$	198,161	$	1,697,617

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~~2018 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~~2018 as filed with the SEC on February ~~23, 2017.~~20, 2019. 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.~~2018.

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 June 30,		Six Months Ended June 30,
Major Customers	2017	2016	2017	2016	2019	2018	2019	2018
Company A	30%	*	27%	*	28%	*	26%	*
Company B	27%	20%	26%	20%	20%	17%	21%	17%
Company C	13%	12%	15%	*	16%	32%	18%	17%
Company D	*	10%	*	11%	11%	19%	10%	33%
Company E	*	27%	*	38%	*	21%	*	17%

* 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
Major Customers	June 30, 2019	December 31, 2018
Company A	18%	15%
Company B	15%	12%
Company C	13%	*
Company D	11%	13%
Company E	11%	12%

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

* less than 10%

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

Recently Adopted Accounting Pronouncements:

In ~~March~~February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting ~~Standards~~Standard Update ("ASU") ~~2016-09, “Improvements~~No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASC 842”). ASC 842 requires lessees to ~~Employee Share-Based Payment Accounting”~~recognize right-of-use (“~~ASU 2016-09”~~ROU”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.

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

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

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash-equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, and we must apply

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

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease payment liabilities on the balance sheet for leases representing the Company’s right to use the underlying assets over the lease term. Each lease that is recognized on the balance sheet will be classified as either finance or operating, with such classification affecting the pattern and ~~disclosing key information about leasing arrangements. In transition, lessees~~classification of expense recognition in the consolidated statements of operations and ~~lessors are required to recognize and measure leases at~~presentation within the ~~beginning~~statements of ~~the earliest period presented~~cash flows.

The Company adopted ASC 842 on January 1, 2019 using athe modified retrospective ~~approach.~~method. The ~~modified retrospective approach includes a number~~Company elected as part of its adoption to also use the optional transition methodology whereby previously reported periods continue to be reported in accordance with historical accounting guidance for leases that were in effect for those prior periods. Policy elections and practical expedients that ~~entities may elect~~the Company has implemented as part of adopting ASC 842 include (a) excluding from the balance sheet leases with terms that are less than or equal to ~~apply. An entity~~one year, (b) for all existing asset classes that ~~elects to apply~~contain both lease and non-lease components, combining these components together and accounting for them as a single lease component, (c) the package of practical expedients, ~~will, in effect, continue~~which among other things allows the Company to ~~account~~avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements, which were not accounted for ~~leases~~under the previous leasing guidance, that ~~commence~~existed or expired before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of ~~this standard~~ASC 842. The scope of ASC 842 does not apply to leases used in the exploration or use of minerals, oil, and natural gas.

The Company's adoption of ASC 842 resulted in an increase in other assets, accounts payable and accrued expenses, and other liabilities line items on ~~our~~the accompanying 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 occurbalance sheets as a result of the additional ROU assets and related lease liabilities. Upon adoption on January 1, 2019, the Company recognized approximately $2.4 million in ROU assets and $4.3 million in liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this ~~ASU. The Company plans to adopt~~guidance. See Note 14 for the ~~guidance using the modified retrospective method on the effective date of January 1, 2018.~~new disclosures required by ASC 842.

Recently Issued Accounting Pronouncements: 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~~estimate: Production taxes ~~based on recent historical experience~~are comprised primarily of two elements: severance tax 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.ad valorem tax. During the three months ended ~~September 30, 2016,~~March 31, 2019, the Company reduced its estimate for 2018 severance taxes. When preparing the 2018 severance tax return, the credit for ad valorem taxes ~~based~~was greater than originally estimated, resulting in a reduction of 2018 severance taxes. Based on ~~additional information received during that period. As a result,~~this analysis, the ~~Company decreased~~Company's prior year accrual was reduced, resulting in an approximate $7.9 million reduction to our production taxes, ~~to be paid by approximately $3.6 million~~ which ~~reduced~~increased our operating ~~loss~~income for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2019 by a corresponding amount, or ~~$0.02~~$0.03 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
Oil and gas properties, full cost method:	June 30, 2019			December 31, 2018
Costs of proved properties:
Producing and non-producing	$	2,732,288		$	2,385,958
Less, accumulated depletion and full cost ceiling impairments	(956,613		)	(840,513		)
Subtotal, proved properties, net	1,775,675			1,545,445

Costs of wells in progress	175,400			227,262

Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs	658,283			731,058
Land	9,395			9,395
Subtotal, unproved properties and land	667,678			740,453

Costs of other property and equipment:
Other property and equipment	10,020			9,642
Less, accumulated depreciation	(5,139		)	(4,102		)
Subtotal, other property and equipment, net	4,881			5,540

Total property and equipment, net	$	2,623,634		$	2,518,700

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

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
Less, accumulated depreciation (1,638 ) (736 )
Subtotal, other property and equipment, net 6,152
4,327

Total property and equipment, net $ 1,249,633
$ 908,736

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At ~~September~~June 30, ~~2017,~~2019 and December 31, 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. 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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Capitalized overhead	$	3,483	$	3,280	$	7,150	$	6,393

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


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

~~Acquisitions and Swaps~~

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

~~September 2017 Acquisition~~

~~In September 2017, we completed the second closing of the GC Acquisition (as defined in "-June 2016 Acquisition"~~ below). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company.

The total purchase price for the second closing was $31.3 million, composed of cash of $6.8 million and assumed liabilities of $24.5 million. The assumed liabilities included $20.9 million for asset retirement obligations.

~~August 2017 Acquisition and Swap~~

In August 2017, we acquired approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $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 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 in the fourth quarter of 2017.

~~March 2017 Acquisition~~

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

~~Acquisitions in the Second Half of 2016~~

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

~~June 2016 Acquisition~~

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

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

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

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

~~The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of11.5%, and assumptions regarding the timing and amount of future development and operating costs.~~

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

~~Divestitures~~

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. The transaction is expected to close 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 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.


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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Depletion of oil and gas properties	$	56,597	$	40,927	$	116,025	$	77,029
Depreciation and accretion	1,430		950		2,920		1,929
Total DD&A Expense	$	58,027	$	41,877	$	118,945	$	78,958

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Depletion of oil and gas properties $ 32,944
$ 9,273
$ 71,389
$ 31,981
Depreciation and accretion 796
362
2,007
1,020
Total DD&A Expense $ 33,740
$ 9,635
$ 73,396
$ 33,001

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the three and 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.


5.4.	Asset Retirement Obligations

~~Upon completion or acquisition of a well, the~~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):



	Six Months Ended June 30, 2019
Asset retirement obligations, December 31, 2018	$	51,746
Obligations incurred with development activities	1,278
Accretion expense	1,779
Obligations discharged with asset retirements and divestitures	(5,586		)
Asset retirement obligation, June 30, 2019	$	49,217
Less, current portion	(10,608		)
Long-term portion	$	38,609

Nine Months Ended September 30, 2017
Asset retirement obligations, December 31, 2016 $ 16,458
Obligations incurred with development activities 2,782
Obligations assumed with acquisitions 23,521
Accretion expense 981
Obligations discharged with asset retirements and divestitures (7,023 )
Asset retirement obligation, September 30, 2017 $ 36,719
Less, current portion (2,738 )
Long-term portion $ 33,981


6.5.	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 September~~At June 30, ~~2017,~~2019, the terms of the Revolver ~~provide~~provided for up to ~~$500 million~~$1.5 billion in borrowings, ~~subject to~~an aggregate elected commitment of $550 million, and a borrowing base limitation of ~~$400~~$700 million. ~~There was a $150.0 million~~As of June 30, 2019 and December 31, 2018, the outstanding principal balance ~~as of September~~was $165.0 million and $195.0 million, respectively. At June 30, ~~2017~~2019 and ~~no outstanding principal balance as of~~ December 31, ~~2016. The~~2018, the Company ~~has an outstanding letter~~had no letters of credit ~~of approximately $0.5 million.~~

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

Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate ("LIBOR") plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver.issued. The average annual interest rate for borrowings during the ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016~~2019 was ~~3.3% and~~ ~~2.6%, respectively.~~4.4%.

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.The next semi-annual redetermination is scheduled forNovember 2019. 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 proved developed producing or total proved reserves as projected in the semi-annual reserve report.~~

~~Furthermore, the Revolver requires~~positions, and require the Company to maintain compliance with certain financial and liquidity ratio covenants. ~~In particular, the Company must not (a) permit its ratio~~As of ~~total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than1.0to 1.0. As ofSeptember~~June 30, ~~2017,~~2019, 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.


7.6.	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% and began accruing on June 14, 2016.~~6.25%. Interest is payable on June 151 and December 151 of each year. 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. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. November 29, 2017. The associated expenses and underwriting discounts and commissions are amortized using the effective interest method at an effective interest rate of ~~10.6%~~ 6.6%.~~The net proceeds were used to fund the GC Acquisition as discussed further in Note 3.~~

At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes at the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of ~~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. As of~~September~~June 30, ~~2017,~~2019, none of the Company's subsidiaries met the criteria in the Indenture to be considered a guarantor of the 2025 Senior Notes.

As ofJune 30, 2019, the most recent compliance date, the Company was in compliance with ~~these~~the Indenture covenants and expects to remain in compliance throughout the next 12-month period.


8.7.	Commodity Derivative Instruments

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

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

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

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

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

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

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

The Company’s commodity derivative contracts as of ~~September~~June 30, ~~2017~~2019 are summarized below:

Settlement Period

Derivative

Instrument

Volumes

(Bbls per day)

Weighted-Average

Floor Price

Weighted-Average Ceiling Price

Crude Oil - NYMEX WTI

July 1, 2019 - Dec 31, 2019

Collar

16,000

55.00

70.65

Settlement Period

Derivative

Instrument

Volumes

(MMBtu per day)

Weighted-Average
Floor Price

Weighted-Average Ceiling Price

Natural Gas - NYMEX Henry Hub

July 1, 2019 - Dec 31, 2019

Collar

30,000

3.00

3.50

Settlement Period

Derivative

Instrument

Volumes

(MMBtu per day)

Fixed Basis Difference

Natural Gas - CIG Rocky Mountain

July 1, 2019 - Dec 31, 2019

Swap

30,000

(0.75

)

Settlement Period

Derivative

Instrument

Volumes
(Bbls per day)

Weighted-Average Fixed Price

Propane - Mont Belvieu

July 1, 2019 - Dec 31, 2019

Swap

2,000

37.52

Settlement Period
Derivative
Instrument

Average Volumes
(Bbls
per month)

Floor
Price

Ceiling
Price
Crude Oil - NYMEX WTI
Oct 1, 2017 - Dec 31, 2017 Collar 30,667
$ 40.00
$ 60.00
Oct 1, 2017 - Dec 31, 2017 Collar 20,000
$ 45.00
$ 70.00
Oct 1, 2017 - Dec 31, 2017 Collar 30,667
$ 40.00
$ 65.00
Oct 1, 2017 - Dec 31, 2017 Collar 30,667
$ 40.00
$ 65.00
Oct 1, 2017 - Dec 31, 2017 Collar 15,333
$ 45.00
$ 65.00
Oct 1, 2017 - Dec 31, 2017 Collar 15,333
$ 45.00
$ 65.10
Jan 1, 2018 - Dec 31, 2018 Collar 76,042
$ 40.00
$ 57.60

Settlement Period
Derivative
Instrument

Average Volumes
(MMBtu
per month)

Floor
Price

Ceiling
Price
Natural Gas - NYMEX Henry Hub
Oct 1, 2017 - Dec 31, 2017 Collar 100,000
$ 2.75
$ 4.00
Oct 1, 2017 - Dec 31, 2017 Collar 153,333
$ 2.75
$ 3.90
Oct 1, 2017 - Dec 31, 2017 Collar 92,000
$ 2.75
$ 4.10
Oct 1, 2017 - Dec 31, 2017 Collar 15,333
$ 3.00
$ 4.31
Oct 1, 2017 - Dec 31, 2017 Collar 110,400
$ 3.00
$ 4.30
Oct 1, 2017 - Dec 31, 2017 Collar 199,333
$ 3.00
$ 3.88
Oct 1, 2017 - Dec 31, 2017 Collar 199,333
$ 3.00
$ 3.91

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

~~Subsequent to September 30, 2017, 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

Offsetting of Derivative Assets and Liabilities

As of ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016,~~2018, 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 June 30, 2019
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	$	15,749	$	(3,688	)	$	12,061
Commodity derivative contracts	Noncurrent assets	$	502	$	(502	)	$	—	Noncurrent assets	—		—			—
Commodity derivative contracts	Current liabilities	$	2,000	$	(1,214	)	$	786	Current liabilities	3,688		(3,688		)	—
Commodity derivative contracts	Noncurrent liabilities	$	896	$	(502	)	$	394	Noncurrent liabilities	$	—	$	—		$	—



		As of December 31, 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
Commodity derivative contracts	Current assets	$	39,485	$	(4,579	)	$	34,906
Commodity derivative contracts	Noncurrent assets	—		—			—
Commodity derivative contracts	Current liabilities	4,579		(4,579		)	—
Commodity derivative contracts	Noncurrent liabilities	$	—	$	—		$	—

As of December 31, 2016
Underlying
Balance Sheet
Location
Gross Amounts of Recognized Assets and Liabilities
Gross Amounts Offset in the
Balance Sheet

Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
Commodity derivative contracts Current assets $ 2,045
$ (1,748 ) $ 297
Commodity derivative contracts Noncurrent assets $ —
$ —
$ —
Commodity derivative contracts Current liabilities $ 4,622
$ (1,748 ) $ 2,874
Commodity derivative contracts Noncurrent liabilities $ —
$ —
$ —

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019			2018
Realized gain (loss) on commodity derivatives	$	3,304	$	(5,883	)	$	8,217		$	(7,955	)
Unrealized gain (loss) on commodity derivatives	4,981		(8,411		)	(22,845		)	(12,120		)
Total gain (loss)	$	8,285	$	(14,294	)	$	(14,628	)	$	(20,075	)

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Realized gain (loss) on commodity derivatives $ 116
$ (13 ) $ (26 ) $ 2,868
Unrealized gain (loss) on commodity derivatives (2,499 ) 420
2,350
(6,485 )
Total gain (loss) $ (2,383 ) $ 407
$ 2,324
$ (3,617 )

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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Monthly settlement	$	3,962		$	(5,883	)	$	9,194		$	(7,955	)
Premiums paid	(658		)	—			(977		)	—
Total realized gain (loss)	$	3,304		$	(5,883	)	$	8,217		$	(7,955	)

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Monthly settlement $ 376
$ 497
$ 927
$ 4,398
Previously incurred premiums attributable to settled commodity contracts (260 ) (510 ) (953 ) (1,530 )
Total realized gain (loss) $ 116
$ (13 ) $ (26 ) $ 2,868

~~Credit Related~~Credit-Related Contingent Features

As of ~~September~~June 30, ~~2017, three~~2019, all of the ~~six~~ counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the ~~credit facility~~Revolver and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the fourth counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fifth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.


9.8.	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,~~measurement includes 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 producing properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using market comparables.

obligations. 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~~reclamation 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.~~reclamation. 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~~Note 4 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 June 30, 2019
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	—	$	—	$	—	$	—	$	12,061	$	—	$	12,061
Commodity derivative liability	$	—	$	1,180	$	—	$	1,180	$	—	$	—	$	—	$	—



	Fair Value Measurements at December 31, 2018
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	34,906	$	—	$	34,906
Commodity derivative liability	$	—	$	—	$	—	$	—

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

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At ~~September~~June 30, ~~2017,~~2019, 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 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~~$499.1 million at ~~September~~June 30, ~~2017.~~2019. The Company determined the fair value of its notes payable at ~~September~~June 30, ~~2017~~2019 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.~~9.	Interest Expense

The components of interest expense are (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revolving credit facility	$	2,132		$	85		$	4,305		$	85
Notes payable	8,594			8,594			17,188			17,188
Amortization of issuance costs and other	851			1,113			1,648			2,000
Less: interest capitalized	(11,577		)	(9,792		)	(23,141		)	(19,273		)
Interest expense, net of amounts capitalized	$	—		$	—		$	—		$	—

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.


~~12.~~10.	Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase"). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's condensed consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of ~~September~~June 30, ~~2017,~~2019, there were ~~4,500,000~~10,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which ~~86,464~~1,164,414 shares were available for future ~~grants.~~grant. The shares available for future grant exclude ~~951,884~~1,973,768 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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Stock options	$	795		$	1,195		$	1,822		$	2,398
Performance-vested stock units	1,258			1,173			2,329			2,029
Restricted stock units and stock bonus shares	1,766			1,400			4,081			2,736
Total stock-based compensation	$	3,819		$	3,768		$	8,232		$	7,163
Less: stock-based compensation capitalized	(677		)	(622		)	(1,407		)	(1,221		)
Total stock-based compensation expense	$	3,142		$	3,146		$	6,825		$	5,942

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

Stock options

No stock options were granted during the three and ~~nine~~six months ended ~~September~~June 30, ~~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~~	—	%

2019 or 2018. The following table summarizes activity for stock options for the ~~periods~~period presented:



	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 2018	4,652,634		$	10.06	6.4 years	$	49
Granted	—		—
Exercised	—		—			—
Expired	(12,000	)	11.81
Forfeited	(48,800	)	7.46
Outstanding, June 30, 2019	4,591,834		$	10.09	5.9 years	$	58
Outstanding, Exercisable at June 30, 2019	3,771,134		$	10.30	5.7 years	$	58

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
Granted —
—

Exercised (30,000 ) 3.79
140
Expired (41,000 ) 11.98

Forfeited (104,000 ) 11.60

Outstanding, September 30, 2017 5,826,500
$ 9.23
7.2 years $ 8,076
Outstanding, Exercisable at September 30, 2017 3,146,361
$ 8.77
6.6 years $ 5,660

The following table summarizes information about issued and outstanding stock options as of ~~September~~June 30, ~~2017:~~2019:



	Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life
Under $5.00	35,000	$	3.31	3.1 years	35,000	$	3.31	3.1 years
$5.00 - $6.99	683,000	6.29		5.8 years	433,600	6.25		5.1 years
$7.00 - $10.99	1,360,334	9.42		5.9 years	997,934	9.40		5.8 years
$11.00 - $13.46	2,513,500	11.57		5.9 years	2,304,600	11.56		5.9 years
Total	4,591,834	$	10.09	5.9 years	3,771,134	$	10.30	5.7 years

Outstanding Options Exercisable Options
Range of Exercise Prices Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life
Under $5.00 600,000
$ 3.49
3.9 years 574,000
$ 3.46
3.8 years
$5.00 - $6.99 1,012,000
6.38
7.2 years 549,000
6.45
6.0 years
$7.00 - $10.99 1,592,500
9.34
7.7 years 658,661
9.50
7.3 years
$11.00 - $13.46 2,622,000
11.58
7.7 years 1,364,700
11.58
7.6 years
Total 5,826,500
$ 9.23
7.2 years 3,146,361
$ 8.77
6.6 years

The estimated unrecognized compensation cost from stock options not vested as of ~~September~~June 30, ~~2017,~~2019, which will be recognized ratably over the remaining vesting ~~phase,~~period, is as follows:



Unrecognized compensation (in thousands)	$	2,484
Remaining vesting period	1.5 years

Unrecognized compensation cost (in thousands) $ 11,101
Remaining vesting phase 2.5 years

Restricted stock units and stock bonus awards

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

The following table summarizes activity for restricted stock units and stock bonus awards for the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2019:



	Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2018	1,639,918		$	8.07
Granted	1,535,984		4.87
Vested	(582,615	)	8.62
Forfeited	(50,378	)	6.40
Not vested, June 30, 2019	2,542,909		$	6.04

Number of Shares Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016 890,336
$ 9.54
Granted 669,323
8.27
Vested (336,445 ) 9.17
Forfeited (24,807 ) 9.85
Not vested, September 30, 2017 1,198,407
$ 8.93

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of ~~September~~June 30, ~~2017,~~2019, which will be recognized ratably over the remaining vesting ~~phase,~~period, is as follows:



Unrecognized compensation cost (in thousands)	$	12,065
Remaining vesting period	2.2 years

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

Performance-vested stock units

The Company ~~grants~~has granted three 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~~For the years prior to 2019, the PSUs will be settled in shares of the Company’s common ~~stock following~~stock. For PSUs granted in 2019, if the PSUs vested are in an amount equal to or less than the target amount, they will be settled in shares of the Company's common stock. If the PSUs vested are in an amount greater than the target amount, then at the discretion of the Board of Directors, the value of the vested amount of PSUs in excess of the value of the PSU target amount may be paid wholly or partially in cash. All PSUs are settled at 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 June 30, 2019, 274,898 Goal-Based PSUs had been awarded to certain executives.

Relative Total Shareholder Return ("Relative TSR") PSUs - The vesting criterion for the Relative TSR PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

Absolute Total Shareholder Return ("Absolute TSR") PSUs - The vesting criterion for the Absolute TSR PSUs is based on a comparison of the Company’s TSR for the measurement period compared to the TSR goals outlined in the award. 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 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.awards.

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



	Six Months Ended June 30,
	2019		2018
Weighted-average expected term	2.9 years		2.8 years
Weighted-average expected volatility	48	%	52	%
Weighted-average risk-free rate	2.49	%	2.41	%

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

~~The fair value of the PSUs granted during the nine months ended September 30, 2017 and 2016 was $5.1 million and $4.0 million, respectively.~~ As of ~~September~~June 30, ~~2017,~~2019, unrecognized compensation cost for TSR PSUs was ~~$5.8~~$7.7 million and will be amortized through ~~2019. A summary of~~2021. The following table summarizes activity for TSR PSUs for the ~~status and activity of PSUs is presented in the following table:~~six months ended June 30, 2019:


	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, 2018				780,028	$	11.73
Granted	473,374	10.79		918,842	5.74
Vested	—	—		—	—
Forfeited	—	—		—	—
Not vested, September 30, 2017	951,884	$	9.44
Not vested, June 30, 2019				1,698,870	$	8.49


~~13.~~11.	Weighted-Average Shares Outstanding

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



	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Weighted-average shares outstanding — basic	243,404,917	242,255,724	243,348,141	242,005,211
Potentially dilutive common shares from:
Stock options	13,719	421,316	12,611	387,634
TSR PSUs ¹	277,364	1,372,019	209,431	1,223,542
Restricted stock units and stock bonus shares	434,245	415,717	139,732	338,286
Weighted-average shares outstanding — diluted	244,130,245	244,464,776	243,709,915	243,954,673

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 June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Potentially dilutive common shares from:
Stock options ¹	4,556,834	3,353,700	4,556,834	3,564,617
TSR PSUs ^1,2	773,954	—	1,233,375	—
Goal-Based PSUs ^2,3	274,898	281,872	274,898	281,872
Restricted stock units and stock bonus shares ¹	695,353	2,772	704,948	10,005
Total	6,301,039	3,638,344	6,770,055	3,856,494

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.


12.	Income Taxes

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

The effective combined U.S. federal and state income tax rates for the three and six months ended June 30, 2019 were 25% and 26%, respectively. For the three and six months ended June 30, 2018, the effective tax rates were 6% and 7%, respectively. The effective tax rates for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016 were nil. The effective tax rates for the three and nine months ended September 30, 2017 and 2016 were based upon a full year forecasted tax provision and differs~~2019 differed from the statutory rate primarily due to state income taxes, non-deductible expenses, and tax deficiencies recognized in connection with the ~~recognition~~vesting of astock awards. The 2018 rates differed from the statutory rates due primarily to the release of 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~~June 30, ~~2017,~~2019, 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~~June 30, ~~2017.~~2019. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of ~~September~~June 30, ~~2017,~~2019, 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~~As of June 30, 2019, the Company believes it will be able to generate sufficient future positive 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. In addition to the future positive net income, the temporary deferred tax liabilities exceed the deferred tax assets, resulting in the ability to utilize all deferred tax assets to offset future taxable income resulting from the reversal of the deferred tax liabilities.

13. 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 ~~cumulative losses through September 30, 2017, we~~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 June 30,				Six Months Ended June 30,
Revenues (in thousands):	2019		2018		2019		2018
Oil	$	132,098	$	114,857	$	279,178	$	231,061
Natural Gas and NGLs	30,504		32,230		72,879		63,259
	$	162,602	$	147,087	$	352,057	$	294,320

14. Leases

The Company evaluates contractual arrangements at inception to determine if the agreement is a lease or contains an identifiable lease component as defined by ASC 842. When evaluating contracts to determine appropriate classification and recognition under ASC 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, whether renewal or termination options are reasonably certain to be exercised, and future lease payments to be included in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating contracts that meet the definition of a lease under ASC 842 include:

Discount Rate - Unless implicitly defined, the Company will determine the present value of future lease payments using an estimated incremental secured borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease commencement.

Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain these options will be exercised. There are no available options to extend that the Company is reasonably certain to exercise.

Currently, the Company has operating leases for asset classes that include office space, drilling rigs, and equipment rentals primarily used in development and field operations. The Company has financing leases for vehicles. We have provided a ~~full valuation allowance reducing~~residual value guarantee for our vehicle leases. Certain leases also contain optional extension periods that allow for lease terms to be extended for up to an additional 5 years.

Costs associated with the ~~net realizable benefits.~~Company’s operating leases are either expensed or capitalized depending on how the underlying asset is utilized. For example, costs associated with drilling rigs are capitalized as part of the development of the Company’s oil and gas properties. Refer to the Company’s 2018 Form 10-K for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability, the Company considers all the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments.

The Company’s total lease costs were as follows (in thousands):



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Finance lease cost:
Amortization of ROU assets	$	63	$	123
Interest on lease liabilities	7		15

Operating lease cost	1,173		1,777
Short-term lease cost ¹	27,783		69,846
Total Lease Cost	$	29,026	$	71,761

¹ Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than or equal to one year. These costs primarily include drilling activities and field equipment rentals. It is expected that this amount will fluctuate primarily with the number of drilling rigs that the Company is operating under short-term agreements.

Other information related to the Company’s leases is as follows (in thousands, except lease terms and discount rates):



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	1,173	$	1,777
Financing cash flows from finance leases	47		105

ROU assets obtained in exchange for new finance lease liabilities	43		138
ROU assets obtained in exchange for new operating lease liabilities	4,006		8,538



	As of June 30, 2019
Weighted-average remaining lease term - finance leases	3.0 years
Weighted-average remaining lease term - operating leases	2.0 years
Weighted-average discount rate - finance leases	4.75	%
Weighted-average discount rate - operating leases	4.75	%

As of June 30, 2019 and through the date of issuance of these financial statements, the Company has no material lease arrangements which are scheduled to commence in the future. Maturities for the Company’s operating and finance lease liabilities included on the accompanying condensed balance sheets as of June 30, 2019 were as follows (in thousands):



Year	Finance Leases			Operating Leases
2019	$	94		$	2,471
2020	188			4,684
2021	215			1,550
2022	185			500
2023	25			—
Thereafter	—			—
Total lease payments	$	707		$	9,205
Less imputed interest	(57		)	(420		)
Total lease liability	$	650		$	8,785

As of December 31, 2018, minimum future contractual payments were as follows (in thousands):



Year	Rig Contracts		Capital Leases		Operating Leases
2019	$	11,102	$	183	$	896
2020	—		186		916
2021	—		204		913
2022	—		167		500
2023	—		—		—
Thereafter	—		—		—

Amounts recorded on the Company’s accompanying condensed balance sheets were as follows (in thousands):



As of June 30, 2019	Financing Leases		Operating Leases
Other property and equipment, net	$	755	$	—
Other assets	—		7,161

Accounts payable and accrued expenses	161		4,629
Other liabilities	489		4,156
	$	650	$	8,785


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

~~Volume~~Oil Commitments

The Company has 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 of~~ the sales agreements ~~commenced during 2015. Deliveries under the third agreement commenced in 2016. Deliveries under the fourth agreement are expected to commence in the second quarter of 2018.~~have commenced. 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, 2019		Oil
Year ending December 31, 2019		(MBbls)
Remainder of 2019		2,605
2020		4,003
2021		1,672
Total		8,280

Year ending December 31, Oil
(MBbls)
Remainder of 2017 1,072
2018 4,942
2019 5,167
2020 4,003
2021 1,672
Thereafter —
Total 16,856

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~~second quarter of ~~2017,~~2019, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery ~~obligations, although~~obligations. However, this cannot be guaranteed.

In the third quarter of 2019, the Company entered into an agreement for the transportation of additional oil production. Under this new agreement, which is a collaboration with several other parties, our baseline volume commitment is for 15,000 Bbls per day for a seven year term. Deliveries under this sales agreement are expected to commence in the third quarter of 2019, but the initial obligation may be reduced as the existing pipeline is currently under allocation. If we are unable to fulfill all of our minimum volume commitment and such commitment is not sufficiently reduced by offsetting production delivered by other parties, we may be required to pay demand charges on any unfulfilled capacity.

Natural Gas Commitments

In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we ~~have agreed~~entered into two facilities expansion agreements with DCP Midstream, LP ("DCP Midstream") to ~~participate in the expansion of~~expand and improve its natural gas gathering pipelines and processing ~~capacity in~~facilities. DCP Midstream completed and turned on line the ~~D-J Basin. The~~ first ~~agreement includes a new~~of the two 200 MMcf per day ~~processing~~plants in August 2018. The second plant ~~as well as the expansion of a related gathering system. Both are~~is currently being commissioned and is expected to be ~~completed by late 2018, although~~placed fully into service during the ~~start-up date is undetermined at this time. Our share~~third quarter of 2019. We are bound to the volume requirements in these agreements on the first day of the ~~commitment will~~calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to DCP Midstream, and incremental wellhead volume commitments of 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in 2019, although the start-up date is undetermined at this time. Our share of the commitment will requireand 43.8 MMcf per day ~~to be delivered after~~for the ~~plant in-service date~~first and second agreements, respectively, for ~~a period of~~ 7 years. ~~These~~If we are unable to fulfill all of our contractual obligations ~~can be~~and our obligations are not sufficiently reduced by the collective volumes delivered ~~to the plants~~ by other producers, inwe may be required to pay penalties or damages pursuant to these agreements. During the ~~D-J Basin that are in excess~~second quarter of ~~such producers' total commitment. We expect~~2019, 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 this capacity.~~

~~Office leases~~

~~In September 2016, the Company entered into a new 65-month lease~~continue to meet our future delivery obligations. We are also required 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 schedulethree years of the ~~minimum lease payments under non-cancelable operating leases as of September 30, 2017 follows (in thousands):~~contracts to guarantee a certain target profit margin to DCP Midstream on these incremental volumes. Payments made to date for such quantities have not been significant.

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.~~

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.


~~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):



	Six Months Ended June 30,
Supplemental cash flow information:	2019			2018
Interest paid	$	21,139		$	17,448

Non-cash investing and financing activities:
Accrued well costs as of period end	$	52,531		$	75,705
Asset retirement obligations incurred with development activities	1,278			473
Asset retirement obligations assumed with acquisitions	—			5
Obligations discharged with asset retirements and divestitures	$	(5,586	)	$	(5,964	)

Net changes in operating assets and liabilities:
Accounts receivable	$	33,541		$	2,797
Accounts payable and accrued expenses	(685		)	(42		)
Revenue payable	(1,208		)	5,377
Production taxes payable	(13,849		)	8,199
Other	634			88
Changes in operating assets and liabilities	$	18,433		$	16,419

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

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


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

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of ~~September~~June 30, ~~2017~~2019 and its results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016.~~2018. 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~~2018 filed with the SEC on February ~~23, 2017.~~20, 2019. 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.

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

Overview

SRC Energy is 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~~Our oil and natural gas ~~for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.~~

~~Our drilling and completion~~ activities are focused in the Wattenberg Field, ~~in Weld County, Colorado,~~ an area that covers the western flank of the D-J Basin. ~~Currently,~~ All of our activities and planned drilling locations are located in Weld County, Colorado, and 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% 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, cash flow, future growth, and ~~cash flow.~~carrying value of our oil and gas properties. 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~~four years.


	Year Ended December 31,				Year Ended August 31,						Year Ended December 31,
	2016		2015		2015		2014		2013		2018		2017		2016		2015
Average NYMEX prices
Oil (per Bbl)	$	43.20	$	48.73	$	60.65	$	100.39	$	94.58	$	64.94	$	50.93	$	43.20	$	48.73
Natural gas (per Mcf)	$	2.52	$	2.58	$	3.12	$	4.38	$	3.55	$	3.09	$	3.00	$	2.52	$	2.58

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

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Oil (NYMEX WTI)
Average NYMEX Price $ 48.18
$ 44.90
$ 49.44
$ 41.23
Realized Price 42.37
35.67
42.04
31.47
Differential $ (5.81 ) $ (9.23 ) $ (7.40 ) $ (9.76 )

Gas (NYMEX Henry Hub)
Average NYMEX Price $ 2.99
$ 2.88
$ 3.03
$ 2.34
Realized Price 2.35
2.73
2.39
2.18
Differential $ (0.64 ) $ (0.15 ) $ (0.64 ) $ (0.16 )

NGL Realized Price $ 17.32
$ —
$ 15.49
$ —



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Oil (NYMEX-WTI)
Average NYMEX Price	$	59.78		$	68.03		$	57.31		$	65.46
Realized Price *	52.75			61.22			50.32			58.48
Differential *	$	(7.03	)	$	(6.81	)	$	(6.99	)	$	(6.98	)

Natural Gas (NYMEX-Henry Hub)
Average NYMEX Price	$	2.64		$	2.80		$	2.89		$	2.90
Realized Price *	1.58			1.64			2.04			1.87
Differential *	$	(1.06	)	$	(1.16	)	$	(0.85	)	$	(1.03	)

NGL Realized Price	$	9.39		$	17.65		$	10.95		$	18.30

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

Market conditions in the Wattenberg Field can 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~~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,~~extent the Company's oil production exceeded its firm sales commitments ~~and~~during the six months ended June 30, 2019, the surplus oil production was sold at a reduced differential as compared to our committed volumes. ~~Relating to the sale of~~

Our natural gas ~~prior~~sales tend to ~~January 1, 2017,~~trend 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 ~~price we received included payment for a percentage~~second quarter of ~~the value attributable~~2019 decreased to ~~the natural gas liquids produced with the natural gas. Beginning~~$1.95 from $2.95 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~~2019, resulting 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~~basis difference for CIG to ~~a low of $42.48 per Bbl on June 21, 2017, and the~~ NYMEX-Henry Hub ~~natural gas price ranged~~increasing from ~~a low of $2.56 per MMBtu on February 21, 2017~~$0.20 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.$0.69.

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~~June 30, ~~2017,~~2019, 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~~June 30, ~~2017:~~2019:

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

512

495

165

677

539

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

433

409

321

754

466

In addition to the producing wells summarized in the preceding table, as of ~~September~~June 30, ~~2017,~~2019, we were the operator of 46122 gross ~~(36~~(115 net) horizontal wells in ~~progress, which excludes 19 gross (14 net) wells for which we have only set surface casings.~~progress. As of ~~September~~June 30, ~~2017,~~2019, we are participating in ~~107~~39 gross ~~(22~~(5 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~~six months ended ~~September~~June 30, ~~2017,~~2019, we ~~plugged 86~~reclaimed 58 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, our average daily production increased to 40,378 BOED as compared to 10,794 BOED for the three months ended September 30, 2016. During the first nine months of 2017, our average net daily production was 30,331 BOED. By comparison, during the nine months ended September 30, 2016, our average production rate was 11,133 BOED. As of September 30, 2017, approximately~~99%~~of~~our daily production was from horizontal wells.~~

~~Strategy~~

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

~~Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience.~~ All of our current wells and our planned acreage development is located either in or adjacent to the Wattenberg Field. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.

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

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

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

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

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

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

~~Use the latest technology to maximize returns.~~ Our development objective for individual well optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.

~~Significant Developments~~

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

~~Acquisitions~~

In September, we completed the second closing of the GC Acquisition. At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. The purchase and sale agreement for the GC Acquisition was signed in May 2016, and the first closing was completed in June 2016. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $31.3 million, composed of cash of $6.8 million and assumed liabilities of $24.5 million. The assumed liabilities included $20.9 million for asset retirement obligations.

In August 2017, we executed a purchase and sale agreement with a private party for the acquisition of approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.

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

~~Divestitures~~

~~Revolving Credit Facility~~

In September 2017, the lenders under our revolving credit facility (sometimes referred to as the "Revolver") completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from $225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018. Due to the outstanding principal balance and letters of credit, approximately $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.~~forecast. 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 and operating conditions are favorable, we may choose to accelerate drilling and completion ~~activities.~~activities, assuming adequate gas processing capacity is available at the time.

During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, we drilled ~~87 operated~~ 59 operated horizontal wells and ~~completed~~ 87turned 58 operated horizontal wells. to sales. As of~~September~~ June 30, ~~2017,~~2019, the Company had 12 gross (11 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the third quarter. As of June 30, 2019, we are the operator of 46122 gross ~~(36 ne~~t)(115 net) horizontal wells in ~~progress, which excludes~~19~~gross (14net) horizontal wells for which we have only set surface casings.~~progress. All of this activity was funded through cash flows from operations. For ~~2017~~2019 as a whole, we expect to ~~drill 118 gro~~ssdrill 99 gross (90 net) operated horizontal wells ~~primarily~~and complete approximately 68 gross (62 net) operated horizontal wells with mid-length and long laterals targeting the Codell and Niobrara formations.

For the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, we participated in the ~~completion~~completion of 16 8gross (1 (0.4net) non-operated horizontal wells. As of~~September~~June 30, ~~2017,~~2019, we are participating in ~~107~~ 39gross ~~(22 net)~~(5net) non-operated ~~horizontal~~horizontal wells in progress.

Production

For the three months ended June 30, 2019, our average daily production increased to 60,833 BOED as compared to 47,646 BOED for the three months ended June 30, 2018. During the first six months of 2019, our average net daily production was 63,288 BOED. By comparison, during the six months ended June 30, 2018, our average production rate was 46,528 BOED. As of June 30, 2019, approximately 98% of our daily production was from horizontal wells.

Gas gathering and processing constraints have continued to limit production growth and ultimately restrict well performance within the DJ Basin. DCP Midstream, our primary gas gathering and processing service provider, has maintained a system-wide producer allocation which is intended to stabilize line pressures. In addition, significant planned and unplanned downtime reduced system capacity throughout the second quarter and first half of 2019. This resulted in consistently high line pressures, restricting our ability to maintain consistent production levels, and we have continued to shut-in and curtail our production. The ~~Company~~aggregate volumes currently shut-in are approximately 25,000 BOED with an approximate 33% oil cut. This volume and oil cut is ~~actively conveying its interests~~based upon what the wells were producing at the time they were shut in. In response to these conditions, we planned our 2019 budgeted activity to adjust the cadence of both drilling and completion operations and reduced our year-over-year capital expenditures budget by approximately 35% in ~~many~~order to optimize capital efficiency.

Strategy

Our primary objective has been to enhance shareholder value by increasing our net asset value, net reserves, and cash flow through acquisitions and development of oil and gas properties. In light of current midstream constraints in the D-J basin and the current commodity price environment, we have increased our emphasis on financial discipline to maximize capital efficiency. This along with other key elements of our business strategy are described below:

•

Maximize shareholder value and maintain financial discipline with a goal of establishing free cash flow at the corporate level. We have continued toalign our capital expenditures with our cash flows by adjusting our operating activities depending on commodity prices and infrastructure capacity. We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt. Towards this goal, we have reduced our operational activities during 2019 as further described below in Significant Developments.


•	Concentrate on our existing core area in the D-J Basin, where we have significant operating experience. All of our current wells and our proved undeveloped acreage are located in the Wattenberg Field. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.


•	Develop and exploit existing oil and gas properties. A 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 safest and most efficient and economical way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells. There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.

•

Use the latest technology to maximize returns and improve hydrocarbon recovery. Our development objective for individual well optimization is to primarily 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, coupled with production results, to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.

•

Control and reduce emissions from our drilling and completion activities and production facilities. We place high importance on achieving compliance with all applicable air quality rules and regulations and the further reduction of emissions continues to be a top priority. To minimize emissions, we employ best management practices such as contracting an electric hydraulic stimulation fleet, utilizing all available direct pipeline take-away access and pneumatic actuated instrument devices, and working with suppliers to deploy diesel engines that meet the U.S. Environmental Protection Agency Tier 4 standard. We control emissions and minimize flaring of gas during the drilling and completion process. We use additional vapor recovery equipment during production for further emissions reduction. We continue to evolve the design of our 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).

•

Operate in a safe manner and work in partnership with our surrounding stakeholders. While our scale of operations has increased significantly, we continue to focus on maintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to utilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities. Such practices include building our infrastructure out ahead of operations to minimize traffic, working with our service providers to minimize dust and lighting issues, and constructing sound walls to minimize noise. We value our positive relationship with local governmental entities and the communities in which we operate and seek 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, including midstream availability, permit. Our high degree of operational control, as well as our focus on operating efficiencies that provide short return on investment cycle times, is central to our operating strategy.

•

Acquire and develop assets near established infrastructure. We have historically targeted acquisitions of contiguous acreage to focus our development plans on areas where technically-capable, financially-stable midstream companies have existing assets and plans for additional investment. We continue to work collaboratively with these companies to proactively identify expansion opportunities that complement our current development plans. This enables the use of gathering pipelines, which reduces the need to use trucks and thereby reduces traffic and noise.

Significant Developments

Operations

In May 2019, we released our completion crew. In our continuing effort to reduce air emissions, we plan to test an electric hydraulic stimulation fleet beginning in the third quarter of 2019. Furthermore, we will release one of our drilling rigs in the third quarter of 2019 and expect to operate one drilling rig for the remainder of the ~~underlying non-operated wells~~year and into 2020.

Legislative Matters

New legislation governing oil and gas development in ~~progress through signed or anticipated agreements.~~Colorado, referred to as SB19-181, and titled "Protect Public Welfare Oil and Gas Operations," became law in April 2019. Among other things, SB19-181 provides that local governments have land use authority to regulate the siting of oil and gas locations, states that it is in the public interest to regulate the development of oil and gas resources in a manner that protects public health, safety, and welfare, including protection of the environment and wildlife resources, and modifies requirements related to statutory pooling. There is ongoing rulemaking associated with this legislation that will affect the implementation and effect of the law. SB19-181 could have a variety of effects on our operations, but we believe that some of these impacts may be mitigated by the fact that the statute places a significant emphasis on local control of oil and gas regulatory matters, and all of our planned future development activities are in Weld County, a jurisdiction in which there is a strong support of the oil and gas industry.

Revolving Credit Facility

In April 2019, the lenders under the Revolver completed their semi-annual redetermination of our borrowing base. The borrowing base was increased from $650 million to $700 million, and we increased our aggregate elected commitment from $500 million to $550 million.

Trends and Outlook

~~Oil~~NYMEX-WTI oil traded at$~~53.75~~45.15per Bbl onDecember ~~30, 2016,~~28, 2018, but ~~has sincedeclined~~increasedapproximately4%29%as of~~September 29, 2017~~June 28, 2019to$~~51.67.~~ ~~Natural~~58.20. NYMEX-Henry Hub natural gas traded at$~~3.72~~3.25per Mcf onDecember ~~30, 2016,~~28, 2018, butdeclinedapproximately~~19%~~26%as of~~September 29, 2017~~June 28, 2019to ~~$3.01~~. ~~Lower~~$2.42. Although NYMEX-WTI oil prices increased over the first half in 2019, 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~~the exploration and ~~replacing~~replacement of 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~~shut-in as non-commercial, and (vi) ~~may~~ cause ceiling test impairments.

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

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

~~We have been able to reduce~~continually focus on 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,Multiple midstream 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~~Until such time that these ~~actions have helped to increase capacity for natural gas processing, we~~facilities are operational, our production has been, and most likely will continue to ~~experience line pressures exceeding system limits primarily due to further growth in field-wide production volumes.~~be, adversely impacted by a lack of available processing capacity.

To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream has ~~announced plans for~~been developing multiple projects including new processing plants, ~~low pressure~~an expansion of its low- and high-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 inthrough agreements that impose baseline and incremental volume commitments, which we are currently exceeding. DCP Midstream's second expansion under this arrangement is the ~~D-J Basin. The initial plan includes a new~~O'Connor processing complex, which is currently being expanded by 200 MMcf per day of processing ~~plant as well as~~capacity along with the ability to bypass an incremental 100 MMcf per day. This processing expansion ~~of a related gathering system, both~~is expected to be ~~completed by late 2018. Additionally, through~~placed in service during the ~~same framework, all~~third quarter of 2019. DCP Midstream has also recently announced an offload agreement with Western Midstream Partners, LP for up to 225 MMcf per day of incremental processing capacity in 2020 at Western’s facility. Further, DCP Midstream has secured the land and permits for the development of another facility ("Bighorn"), where DCP Midstream could add processing capacity of up to 1 Bcf per day, including bypass.

As a result of the ~~parties agreed~~current lack of gas processing capacity, a system-wide volume allocation limiting each producer’s throughput was implemented in November 2017 and has not been lifted. In an effort to apace development with midstream capacity, we will release one of our two drilling rigs during third quarter of 2019 and will run one rig for the remainder of the year and into 2020. Additionally, we dropped our sole completion crew during the second quarter of 2019. As gas processing capacity increases, we plan to ~~add another 200 MMcf/d plant~~bring back one completion crew in the third quarter of 2019. ~~These agreements impose a baseline and incremental volume commitment which~~We will be utilizing an electric fleet upon the crew's return to service. In our continuing effort to reduce our emissions, we ~~are currently exceeding.~~want to test the efficiency of the electric fleet for its possible usage in 2020.

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 continue to be expanded, we have experienced and may continue to experience some delays in placing our pads on production.

Oil ~~transportation and~~pipeline takeaway capacity utilization has increased ~~with~~as oil production in the basin has grown. However, capacity decreased in the second quarter of 2019 when a portion of a third-party crude oil pipeline system was converted to NGL service. To address the projected demand for additional capacity, several open seasons have been announced for 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 continuously 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 ~~2017,~~2019, we expect to dr~~ill 118~~ drill 99 gross operated horizontal wells (59 of which were drilled through June 30, 2019) with mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate ~~this~~that total capital expenditures, including operated drilling and completion ~~program~~costs, limited leasehold acquisition costs and selected non-operated drilling and completion costs, will ~~cost approximately $360~~be between $425 million and $450 million and will lead to ~~a significant~~an increase in production and associated proved developed producing reserves while allowing us to retain significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions. Additionally, 2017 drilling and completion expenditures associated with non-operated properties are expected to be approximately $60 million, whichreserves. Our current estimate is ~~net of capital we expect to recover as described in "-~~ ~~Capital Expenditures" below. Full-year 2017~~that full-year 2019 production ~~is forecasted to be~~will average between ~~33,000~~63,000 BOED and ~~35,000 BOED. Assuming a 2018 development program similar~~66,000 BOED with oil making up 42% to ~~what the Company has done in 2017, we expect to achieve year-over-year production growth~~45% of ~~25% or greater, while funding a majority of our expenditures through internally generated cash flow.~~ production.

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

Results of Operations

Material changes 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~~June 30, ~~2017~~2019 compared to the three months ended ~~September~~June 30, ~~2016~~2018

For the three months ended ~~September~~June 30, ~~2017,~~2019, we reported net income of ~~$43.8~~$54.5 million compared to net ~~loss~~income of ~~$19.2~~$49.6 million during the three months ended ~~September~~June 30, ~~2016.~~2018. Net income per basic and diluted share was $0.22 for the three months ended ~~September~~June 30, ~~2017~~2019 compared to net ~~loss~~income per basic and diluted share of ~~$0.10~~$0.20 for the three months ended ~~September~~June 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.~~2018.

Oil, Natural Gas, and NGL Production and Revenues - For the three months ended ~~September~~June 30, ~~2017,~~2019, we recorded total oil, natural gas, and NGL revenues of ~~$103.6~~$162.6 million compared to ~~$26.2~~$147.1 million for the three months ended ~~September~~June 30, ~~2016,~~2018, an increase of ~~$77.4~~$15.5 million or ~~295%~~11%. The following table summarizes key production and revenue statistics:


	Three Months Ended September 30,				Percentage		Three Months Ended June 30,				Percentage
	2017		2016		Change		2019		2018		Change
Production:
Oil (MBbls) ¹	1,726		517		234	%	2,441		1,846		32	%
Natural Gas (MMcf) ²	7,412		2,855		160	%	11,905		8,987		32	%
NGLs (MBbls) ³	753		—		nm
MBOE ⁴	3,715		993		274	%
BOED ⁵	40,378		10,794		274	%
NGLs (MBbls) ¹							1,111		992		12	%
MBOE ³							5,536		4,336		28	%
BOED ⁴							60,833		47,646		28	%

Revenues (in thousands):
Oil	$	73,144	$	18,451	296	%	$	132,098	$	114,857	15	%
Natural Gas	17,402		7,783		124	%	20,069		14,714		36	%
NGLs ³	13,047		—		nm
NGLs							10,435		17,516		(40	)%
	$	103,593	$	26,234	295	%	$	162,602	$	147,087	11	%
Average sales price:
Oil	$	42.37	$	35.67	19	%
Natural Gas	2.35		2.73		(14	)%
NGLs ³	17.32		—		nm
BOE	$	27.89	$	26.42	6	%
Oil ⁵							$	52.75	$	61.22	(14	)%
Natural Gas ⁵							1.58		1.64		(4	)%
NGLs							9.39		17.65		(47	)%
BOE ⁵							$	28.53	$	33.50	(15	)%

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~~June 30, ~~2017~~2019 averaged ~~40,378~~60,833 BOED, an increase of ~~274%~~28% over average production of ~~10,794~~47,646 BOED in the three months ended ~~September~~June 30, ~~2016.~~2018. From ~~September~~June 30, ~~2016~~2018 to ~~September~~June 30, ~~2017,~~2019, our well count increased by 91165 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%~~28% increase in production ~~and~~resulted in an increase in revenues which was partially offset by the ~~6% increase~~15% decrease in average sales ~~prices resulted in a significant increase in revenues.~~prices.

~~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 June 30,
	2017		2016		2019		2018
Production costs	$	4,223	$	3,529	$	12,963	$	11,433
Workover	93		290		267		179
Transportation and gathering	838		—
Total LOE	$	5,154	$	3,819	$	13,230	$	11,612

Per BOE:
Production costs	$	1.14	$	3.55	$	2.34	$	2.64
Workover	0.03		0.29		0.05		0.04
Transportation and gathering	0.23		—
Total LOE	$	1.40	$	3.84	$	2.39	$	2.68

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 thethree months ended ~~September~~June 30, ~~2017,~~2019, we experienced increased production expense compared to thethree months ended ~~September~~June 30, ~~2016~~2018 due to ~~a 113%~~an increase in ~~horizontal~~net operated ~~wells~~wells.

Transportation and a~~274%~~gathering - Transportation and gathering costs were $4.7 million, or $0.84 per BOE, for the three months ended June 30, 2019, compared to $1.9 million, or $0.43 per BOE, for the three months ended June 30, 2018. Coinciding with the increase in its production ~~volumes. In addition,~~ in 2019, the ~~third quarter, we began delivering under new gathering agreements which resulted in~~Company has increased the volume 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 ~~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 $13.2 million, or $2.38 per BOE, for the three months ended ~~September~~June 30, ~~2017, production taxes were $10.1~~2019, compared to $15.1 million, or ~~$2.71 per BOE, compared to $(1.5) million, or $(1.47)~~$3.47 per BOE, during the ~~prior year period. Taxes tend to increase or decrease primarily based on the value of production sold.~~three months ended June 30, 2018. As a percentage of revenues, production taxes were ~~9.7%~~8.1% and ~~(5.6)%~~10.2% for the three months ended ~~September~~June 30, ~~2017~~2019 and ~~2016,~~2018, 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 June 30,
(in thousands)	2017		2016		2019		2018
Depletion of oil and gas properties	$	32,944	$	9,273	$	56,597	$	40,927
Depreciation and accretion	796		362		1,430		950
Total DD&A	$	33,740	$	9,635	$	58,027	$	41,877

DD&A expense per BOE	$	9.08	$	9.70	$	10.48	$	9.66

For the three months ended ~~September~~June 30, ~~2017,~~2019, DD&A was ~~$9.08~~$10.48 per BOE compared to ~~$9.70~~$9.66 per BOE for the three months ended ~~September~~June 30, ~~2016.~~2018. 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 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,
(in thousands) 2017 2016
G&A costs incurred $ 11,002
$ 9,993
Capitalized costs (2,518 ) (1,757 )
Total G&A $ 8,484
$ 8,236

Non-Cash G&A $ 3,030
$ 2,375
Cash G&A 5,454
5,861
Total G&A $ 8,484
$ 8,236

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



	Three Months Ended June 30,
(in thousands)	2019			2018
Total Non-Cash G&A	$	3,819		$	3,768
Total Cash G&A	8,932			8,953
Capitalized G&A Costs	(3,508		)	(3,315		)
Total G&A Expense	$	9,243		$	9,406

Non-Cash G&A Expense	$	3,142		$	3,146
Cash G&A Expense	6,101			6,260
Total G&A Expense	$	9,243		$	9,406

Non-Cash G&A Expense per BOE	$	0.57		$	0.73
Cash G&A Expense per BOE	1.10			1.44
G&A Expense per BOE	$	1.67		$	2.17

G&A includes overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $9.2 million for the second quarter of 2019 were 2% lower than G&A for the same period of 2018.

Our G&A expense for the three months ended June 30, 2019 includes stock-based compensation of $3.1 million compared to $3.1 million for the three months ended June 30, 2018.

Commodity derivative gains (losses) - As more fully described in Item 1. Financial Statements – Note 7, Commodity Derivative Instruments, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the three months ended June 30, 2019, we realized a settlement gain of $3.3 million. For the prior comparable period, we realized a settlementlossof$5.9 million.

In addition, for the three months ended June 30, 2019, we recorded an unrealized gain of $5.0 million to recognize the mark-to-market change in fair value of our commodity contracts. By comparison, in the three months ended June 30, 2018, we reported an unrealized loss of $8.4 million. Unrealized gains and losses are non-cash items.

Income taxes - As more fully described in Item 1. Financial Statements – Note 12, Income Taxes, we reported income tax expense of $18.2 million for the three months ended June 30, 2019 as compared to $3.3 million for the comparable prior year period. The effective tax rate for the three months ended June 30, 2018 differed from the statutory rates due primarily to the release of valuation allowances previously recorded against deferred tax assets.

For the six months ended June 30, 2019 compared to the six months ended June 30, 2018

For the six months ended June 30, 2019, we reported net income of $104.2 million compared to net income of $115.4 million during the six months ended June 30, 2018. Net income per basic and diluted share was $0.43 for the six months ended June 30, 2019 compared to net income per basic and diluted share of $0.48 and $0.47, respectively, for the six months ended June 30, 2018.

Oil, Natural Gas, and NGL Production and Revenues - For the six months ended June 30, 2019, we recorded total oil, natural gas, and NGL revenues of $352.1 million compared to $294.3 million for the six months ended June 30, 2018, an increase of $57.7 million or 20%. The following table summarizes key production and revenue statistics:



	Six Months Ended June 30,				Percentage
	2019		2018		Change
Production:
Oil (MBbls)	5,408		3,887		39	%
Natural Gas (MMcf)	23,296		16,706		39	%
NGLs (MBbls)	2,165		1,750		24	%
MBOE	11,455		8,422		36	%
BOED	63,288		46,528		36	%

Revenues (in thousands):
Oil	$	279,178	$	231,061	21	%
Natural Gas	49,173		31,231		57	%
NGLs	23,706		32,028		(26	)%
	$	352,057	$	294,320	20	%
Average sales price:
Oil	$	50.32	$	58.48	(14	)%
Natural Gas	2.04		1.87		9	%
NGLs	10.95		18.30		(40	)%
BOE	$	29.97	$	34.50	(13	)%

Net oil, natural gas, and NGL production for the six months ended June 30, 2019 averaged 63,288 BOED, an increase of 36% over average production of 46,528 BOED in the six months ended June 30, 2018. From June 30, 2018 to June 30, 2019, our well count increased by 165 net horizontal wells, growing our reserves and daily production totals. The 36% production resulted in an increase in revenues which was partially offset by the 13% decrease in average sales prices.

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



	Six Months Ended June 30,
	2019		2018
Production costs	$	30,244	$	19,147
Workover	346		361
Total LOE	$	30,590	$	19,508

Per BOE:
Production costs	$	2.64	$	2.27
Workover	0.03		0.04
Total LOE	$	2.67	$	2.31

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas.During thesix months ended June 30, 2019, we experiencedincreasedproduction expense compared to thesix months ended June 30, 2018primarilydue to an increase in net operated wells.

Transportation and gathering - Transportation and gathering costs were $8.7 million, or $0.76 per BOE, for the six months ended June 30, 2019, compared to $3.7 million, or $0.44 per BOE, for the six months ended June 30, 2018. Coinciding with the increase in its production in 2019, the Company has increased the volume 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 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 the three months ended March 31, 2019, the Company reduced its estimate for 2018 severance taxes. When preparing the 2018 severance tax return, we determined that the credit for ad valorem taxes would be greater than originally estimated, resulting in a reduction of 2018 severance taxes. Based on this analysis, the Company's prior year accrual was reduced, resulting in an approximate $7.9 million reduction to our production taxes. Production taxes were $20.3 million, or $1.77 per BOE, for the six months ended June 30, 2019, compared to $28.5 million, or $3.38 per BOE, for the six months ended June 30, 2018. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 5.8% and 9.7% for the six months ended June 30, 2019 and 2018, respectively, with the 2019 period reflecting the effect of the change in estimate.

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



	Six Months Ended June 30,
(in thousands)	2019		2018
Depletion of oil and gas properties	$	116,025	$	77,029
Depreciation and accretion	2,920		1,929
Total DD&A	$	118,945	$	78,958

DD&A expense per BOE	$	10.38	$	9.38

For the six months ended June 30, 2019, DD&A was $10.38 per BOE compared to $9.38 per BOE for the six months ended June 30, 2018. The increase in the DD&A rate was the result of recent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, whereby the ratio of production volumes for the quarter to the beginning of the quarter estimated total reserves determines the depletion rate.

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



	Six Months Ended June 30,
(in thousands)	2019			2018
Total Non-Cash G&A	$	8,232		$	7,163
Total Cash G&A	17,682			18,299
Capitalized G&A Costs	(7,202		)	(6,456		)
Total G&A Expense	$	18,712		$	19,006

Non-Cash G&A Expense	$	6,825		$	5,942
Cash G&A Expense	11,887			13,064
Total G&A Expense	$	18,712		$	19,006

Non-Cash G&A Expense per BOE	$	0.60		$	0.71
Cash G&A Expense per BOE	1.04			1.55
G&A Expense per BOE	$	1.64		$	2.26

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~~$18.7 million for the ~~third quarter of 2017~~six months ended June 30, 2019 were ~~3% higher~~2% lower than G&A for the same period of ~~2016. This increase is primarily due to a 32% increase~~2018. Cash G&A for the six months ended June 30, 2018 was elevated by expenses incurred in ~~employee headcount from 89 at September 30, 2016 to 117 at September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity~~support of Colorado oil and ~~contract services~~gas legislative activities during ~~2017.~~the second quarter of 2018.

Our G&A expense for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 includes stock-based compensation of ~~$3.0~~$6.8 million compared to ~~$2.4~~$5.9 million for the ~~three~~six months ended ~~September~~June 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.2018.

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~~six months ended ~~September~~June 30, ~~2016~~2018 to the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 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)~~ derivatives - As more fully described in Item 1. Financial Statements – Note 8, 7, 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~~six months ended ~~September~~June 30, ~~2017,~~2019, we realized a ~~cash~~ settlement gain of ~~$0.1~~$8.2 million. For the prior comparable period, we realized a settlement loss of $8.0 million, net of previously incurred premiums attributable to the settled commodity contracts. ~~For the prior comparable period, we realized a cash settlement loss of $13.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts.~~

In addition, for the ~~three~~six months ended ~~September~~June 30, ~~2017,~~2019, we recorded an unrealized loss of ~~$2.5~~$22.8 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the ~~three~~six months ended ~~September~~June 30, ~~2016, we reported an unrealized gain of $0.4 million. Unrealized gains and losses are non-cash items.~~

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

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of cumulative losses in the prior periods and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation

allowance has been provided as of 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 compared to the nine months ended September 30, 2016~~

For the nine months ended September 30, 2017, we reported net income of $91.7 million compared to net loss of $224.5 million during the nine months ended September 30, 2016. Net income per basic and diluted share was $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.~~

~~Oil, Natural Gas, and NGL Production and Revenues~~ - For the nine months ended September 30, 2017, we recorded total oil, natural gas, and NGL revenues of $222.4 million compared to $68.5 million for the nine months ended September 30, 2016, an increase of $154.0 million or 225%. 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.

Net oil, natural gas, and NGL production for the nine months ended September 30, 2017 averaged 30,331 BOED, an increase of 172% over average production of 11,133 BOED in the nine months ended September 30, 2016. From September 30, 2016 to September 30, 2017, our well count increased by 91 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% increase in production and the 20% increase in average sales prices resulted in a significant increase in revenues.

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

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

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

~~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 thenine months ended September 30, 2017, we experienceddecreasedproduction expense compared to thenine months ended September 30, 2016primarily due to significantly less expense related to environmental remediation and regulatory compliance projects during 2017 and theconsolidation of our operations into a more central geographic operating area. This decrease was partially offset by transportation and gathering charges resulting from new gathering agreements. Unit operating costs benefited from larger volumes of early production on the 87 horizontal wells turned to sales during thenine months ended September 30, 2017in addition to the production on wells turned to sales after thethirdquarter of2016.~~

~~Production taxes~~ - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $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. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 9.4% and 3.7% for the nine months ended September 30, 2017 and 2016, respectively. During the nine months ended September 30, 2017, the Company adjusted its estimates for production taxes to reflect a significant increase in new production. As discussed in Note 1, during the nine months ended September 30, 2016, the Company reduced its estimate for ad valorem taxes, resulting in an approximate $3.6 million reduction to our production taxes.

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

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

DD&A expense per BOE $ 8.86
$ 10.82

For the nine months ended September 30, 2017, DD&A was $8.86 per BOE compared to $10.82 per BOE for the nine months ended September 30, 2016. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool that primarily occurred during the first half of 2016 and the increase in our total proved reserves. These impacts were partially offset by recent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determined the depletion rate.

~~Full cost ceiling impairment~~ - During the 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,
(in thousands) 2017 2016
G&A costs incurred $ 32,018
$ 27,944
Capitalized costs (7,729 ) (4,745 )
Total G&A $ 24,289
$ 23,199

Non-Cash G&A $ 8,390
$ 7,285
Cash G&A 15,899
15,914
Total G&A $ 24,289
$ 23,199

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

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $24.3 million for the third quarter of 2017 were 5% higher than G&A for the same period of 2016. This increase is primarily due to a 32% increase in employee headcount from 89 at September 30, 2016 to 117 at September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity and contract services during 2017.

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

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the nine months ended September 30, 2016 to the nine months ended September 30, 2017 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

~~Commodity derivatives~~ ~~- As more fully described in Item 1. Financial Statements – Note 8,~~ ~~Commodity Derivative Instruments,~~ we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the nine months ended September 30, 2017, we realized a cash 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, we recorded an unrealized gain of $2.4 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the nine months ended September 30, 2016,2018, we reported an unrealized loss of ~~$6.5~~$12.1 million. Unrealized ~~gains and~~ losses are non-cash items.

Income taxes - We reported noincome tax expense of $36.3 million for the six months ended June 30, 2019 as compared to $9.2 million of income tax expense for the ~~nine months ended September 30, 2017 or the~~comparable prior year period. ~~As explained in more detail in~~The effective tax rate for the ~~"-Income taxes" section above, during the nine~~six months ended ~~September~~June 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 and 2016, the effective tax rate2018 differed from the statutory ~~rate~~rates 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~~revolving 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 six months ended June 30, 2019, our cash provided by operating activities of $301.6 million exceeded the $276.1 million spent on drilling and completion 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, including midstream availability, 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~~June 30, ~~2017,~~2019, we had cash and cash equivalents of ~~$21.3~~$27.8 million, ~~$80.0~~$550.0 million outstanding on our 2025 Senior Notes, and a ~~$150.0~~$165.0 million balance outstanding ~~balance~~ under our revolving credit facility. Our sources and (uses) of funds for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 are summarized below (in thousands):


	Nine Months Ended September 30,						Six Months Ended June 30,
	2017			2016			2019			2018
Net cash provided by operations	$	142,817		$	33,193		$	301,583		$	235,762
Capital expenditures	(383,483		)	(582,149		)	(304,545		)	(255,712		)
Net cash provided by other investing activities	95,265			5,979			12,802			766
Net cash (used in) provided by equity financing activities	(517		)	542,901
Net cash provided by (used in) equity financing activities							(1,126		)	3,025
Net cash provided by (used in) debt financing activities	148,628			(2,666		)	(30,484		)	22,857
Net increase (decrease) in cash and equivalents	$	2,710		$	(2,742	)
Net increase (decrease) in cash and cash equivalents							$	(21,770	)	$	6,698

Net cash provided by operating activities was ~~$142.8~~$301.6 million and ~~$33.2~~$235.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016, respectively.~~2018, respectively. The increase in cash from operating activities reflects the ~~increase~~growth in ~~realized commodity prices and~~our production.

Net cash provided by other investing activities was $95.3 million and $6.0 million for the nine months ended September 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017, we received proceeds from the sale of oil and gas properties and other of $77.0 million, and $18.2 million was released from an escrow account relating to an acquisition. For the nine months ended September 30, 2016, we received proceeds from the sale of oil and gas properties of $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.

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 April 2019, the borrowing base was increased from~~$225~~ $650 millionto~~$400~~ $700 million, and our elected commitment amount was increased to $550 million from $500 million. As of~~September~~ June 30, ~~2017,~~2019, there was a~~$150.0~~ $165.0 million~~outstanding~~ principal balance outstanding and~~$0.5 million~~in noletters of credit outstanding, leaving$~~249.5~~385.0 millionavailable to us for future borrowings. The next semi-annual redetermination is scheduled for~~April 2018.~~November 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 than1.0to ~~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% and began accruing on June 14, 2016.~~6.25%. Interest is payable on June 151 and December 151 of each year.

The 2025 Senior Notes were issued pursuant to an indenture dated as of ~~June 14, 2016~~November 29, 2017 (the "Indenture") and will be guaranteed on a senior unsecured basis by ~~any~~the Company’s existing and future subsidiaries ~~of the Company~~ that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes at the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100.0% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109.00% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

Revolver. 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.

Capital Expenditures

Capital expenditures for drilling and completion activities totaled ~~$159.5~~$202.1 million and ~~$383.0~~$231.2 million for the ~~three and nine~~six months ended ~~September~~June 30, ~~2017,~~2019 and 2018, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):

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

Acquisitions of oil and gas properties and leasehold* 56,835
89,677
Capitalized interest, capitalized G&A, and other 5,718
17,514
Accrual basis capital expenditures** $ 222,085
$ 490,219



	Six Months Ended June 30,
	2019		2018
Capital expenditures for drilling and completion activities	$	202,119	$	231,196
Acquisitions of oil and gas properties and leasehold¹	219		16,402
Capitalized interest, capitalized G&A, and other	32,489		26,753
Accrual basis capital expenditures²	$	234,827	$	274,351

*¹Acquisitions of oil and gas properties and leasehold reflects the full purchase price of ~~our various~~the relevant acquisitions, ~~which includes~~including non-cash additions for liabilities assumed in the transaction such as asset retirement obligations.

**²Capital 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~~six months ended ~~September~~June 30, ~~2017,~~2019, we drilled 8759 operated horizontal wells and ~~completed 87~~turned 58 operated horizontal ~~wells.~~ wells to sales. As of~~September~~ June 30, ~~2017,~~2019, the Company had 12 gross (11 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the third quarter. As of June 30, 2019, we are the operator o~~f 46~~of 122 gross ~~(36~~(115 net) h~~orizontal~~horizontal wells in progress. All of the wells in progress. at June 30, 2019 are scheduled to commence production before December 31, 2020. All of our drilling and completion activity was funded through cash flows from operations.

For the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, we ~~have~~ participated in ~~123~~47 gross ~~(23~~(5 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.~~2019.

We anticipate that our ~~2017~~full-year 2019 capital expenditures, including operated drilling and completion ~~capital expenditures for operated wells~~costs, limited leasehold acquisition costs and selected non-operated drilling and completion costs, will be ~~approximately $360~~between $425 million ~~for the year.~~and $450 million. However, should commodity prices and/or economic conditions change, we can reduce or accelerate (subject to midstream constraints) 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~~June 30, ~~2017,~~2019, we had open positions covering~~1.3~~2.9 millionbarrels of oil and~~8,984 MMcf~~11.0 Bcf 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~~six months ended ~~September~~June 30, ~~2017,~~2019, we reported an unrealized commodity activity ~~gain~~loss of ~~$2.4~~$22.8 million. Unrealized ~~gains~~losses are non-cash items. We also reported a realized ~~loss~~gain of ~~$26.0 thousand,~~$8.2 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~~June 30, ~~2017,~~2019, we estimated that the fair value of our various commodity derivative contracts was a net ~~liability~~asset of ~~$1.2~~$12.1 million. See Item 1. Financial Statements – Note 9, 8, Fair Value Measurements, for a description of the methods we use to estimate the fair values of commodity derivative instruments.

Non-GAAP Financial ~~Measures~~Measure

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~~(in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016			2019			2018			2019			2018
Adjusted EBITDA:
Net income (loss)	$	43,848		$	(19,241	)	$	91,664		$	(224,490	)
Net income													$	54,468		$	49,624		$	104,219		$	115,420
Depreciation, depletion, and accretion	33,740			9,635			73,396			33,001			58,027			41,877			118,945			78,958
Full cost ceiling impairment	—			25,453			—			215,223
Stock-based compensation expense													3,142			3,146			6,825			5,942
Mark-to-market of commodity derivative contracts:
Total loss on commodity derivatives contracts													(8,285		)	14,294			14,628			20,075
Cash settlements on commodity derivative contracts													3,089			(4,566		)	7,715			(6,121		)
Cash premiums paid for commodity derivative contracts													(658		)	—			(977		)	—
Interest income													(92		)	(5		)	(161		)	(14		)
Income tax expense	—			5			—			106			18,237			3,347			36,271			9,158
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		$	127,928		$	107,717		$	287,465		$	223,418

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~~20, 2019 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 planned capacity expansion projects, future ~~differentials, future~~production (including production relative to volume ~~commitments,~~commitments) and reserves, covenant compliance, and the ~~closing~~implementation and ~~effect~~effects of ~~proposed transactions.~~SB19-181 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~~2018 filed with the SEC on February ~~23, 2017~~20, 2019 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;

~~declines~~the effects of, changes in ~~oil~~ and ~~natural~~ ~~gas~~ ~~prices;~~

the costs of compliance with federal, state, and local regulations applicable to our business, including those related to hydraulic stimulation and SB19-181;

operating hazards that adversely affect our ability to conduct business;

uncertainties in the estimates of proved reserves;

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

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

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

our ability to obtain adequate financing;

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

incurrence of ceiling test write-downs;

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

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

~~the~~ strength and financial resources of our competitors;

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

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

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

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

our ability to market our production;

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

~~the~~ effect of environmental liabilities;

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

changes in U.S. tax laws;

our ability to satisfy our contractual obligations and commitments;

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

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

the geographic concentration of our principal properties;

our ability to protect critical data and technology systems;

the availability of water for use in our operations; and

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


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of natural gas prices, as approximately ~~71%~~81% and ~~69%~~79% of our revenue during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, respectively, was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a ~~$8.6~~$12.2 million and ~~$18.3~~$27.0 million change in revenues during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, respectively,~~2019, respectively; a $0.25 per Mcf change in our realized natural gas price would have resulted in a ~~$1.9~~$3.0 million and ~~$4.3~~$5.8 million change in our natural gas revenues for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, respectively,~~2019, respectively; and a $5 per barrel change in our realized NGL price would have resulted in a ~~$3.8~~$5.6 million and ~~$8.8~~$10.8 million change in our NGL revenues for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, respectively.

During the three months ended ~~September~~June 30, ~~2017,~~2019, the average price of oil was higher than it was in the first quarter of 2019 whereas the average prices for natural gas and NGLs ~~increased relative to the third quarter of 2016.~~were lower. 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 onon 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~~June 30, ~~2017,~~2019, we had open oil and natural gas derivatives in a net ~~liability~~ assetposition with a fair value of ~~$1.2~~$12.1 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~~$12.1 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~~$9.4 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~~June 30, ~~2017,~~2019, we had$~~150~~165.0 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 ~~nine~~three and six months ended ~~September~~June 30, ~~2017,~~2019, we incurred interest ~~at an annualized rate~~expense of ~~3.3%. We~~$2.1 million and $4.3 million on our revolving credit facility. 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~~six months ended ~~September~~June 30, ~~2017~~2019 would have changed by ~~$0.3~~approximately $0.5 million and ~~$0.4~~$1.0 million, respectively.

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

Counterparty Risk - As described in ~~"- Commodity~~"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~~decreased slightly during the ~~third~~second quarter of ~~2017~~2019 as the amounts due to us from counterparties ~~has increased.~~decreased.


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

PART II


Item 1.	Legal Proceedings

~~Except as disclosed in Note 14 to the accompanying condensed consolidated financial statements, during~~During the quarter ended June 30, 2019, 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.~~20, 2019. 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.~~20, 2019. This information should be considered carefully together with other information in this report and other reports and materials that we file with the SEC.


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

Purchases of equity securities by the Company

Period Total Number of Shares Purchased Average Price Paid per Share
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
April 1, 2019 - April 30, 2019 ⁽¹⁾	24,609	$	5.12
May 1, 2019 - May 31, 2019 ⁽¹⁾	22,860	5.23
June 1, 2019 - June 30, 2019 ⁽¹⁾	996	$	4.71
Total	48,465

(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~~Performance-Vested Stock Unit Agreement (2019) *
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		XBRLInstance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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.~~July, 2019.



	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	)



	Nine Months Ended September 30, 2017
Asset retirement obligations, December 31, 2016	$	16,458
Obligations incurred with development activities	2,782
Obligations assumed with acquisitions	23,521
Accretion expense	981
Obligations discharged with asset retirements and divestitures	(7,023		)
Asset retirement obligation, September 30, 2017	$	36,719
Less, current portion	(2,738		)
Long-term portion	$	33,981



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



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



	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



Unrecognized compensation cost (in thousands)	$	11,101
Remaining vesting phase	2.5 years



Year ending December 31,		Oil
Year ending December 31,		(MBbls)
Remainder of 2017		1,072
2018		4,942
2019		5,167
2020		4,003
2021		1,672
Thereafter		—
Total		16,856



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



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

Acquisitions of oil and gas properties and leasehold*	56,835		89,677
Capitalized interest, capitalized G&A, and other	5,718		17,514
Accrual basis capital expenditures**	$	222,085	$	490,219