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, ~~2018~~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: ~~242,600,829~~243,473,491 outstanding shares of common stock as of ~~October~~July 29, ~~2018.~~2019.

SRC ENERGY INC.

Index



		Page
Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

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

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

	Condensed Consolidated Statements of Cash Flows for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~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	2221

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3837

Item 4.	Controls and Procedures	3938

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings	4039

Item 1A.	Risk Factors	4039

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4139

Item 3.	Defaults of Senior Securities	4139

Item 4.	Mine Safety Disclosures	4139

Item 5.	Other Information	4139

Item 6.	Exhibits	4240

SIGNATURES		4341

SRC ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands, except share data)


ASSETS	September 30, 2018		December 31, 2017			June 30, 2019		December 31, 2018
Current assets:
Cash and cash equivalents	$	19,236	$	48,772		$	27,839	$	49,609
Accounts receivable:
Oil, natural gas, and NGL sales	110,912		86,013			80,510		100,973
Trade	29,559		18,134			21,961		39,415
Commodity derivative assets						12,061		34,906
Other current assets	11,996		7,116			7,257		7,537
Total current assets	171,703		160,035			149,628		232,440

Property and equipment:
Oil and gas properties, full cost method:
Proved properties, net of accumulated depletion	1,364,116		970,584			1,775,675		1,545,445
Wells in progress	244,206		106,269			175,400		227,262
Unproved properties and land, not subject to depletion	748,695		793,669			667,678		740,453
Oil and gas properties, net	2,357,017		1,870,522			2,618,753		2,513,160
Other property and equipment, net	5,902		6,054			4,881		5,540
Total property and equipment, net	2,362,919		1,876,576			2,623,634		2,518,700
Goodwill	40,711		40,711
Other assets	3,599		2,242			11,824		3,574
Total assets	$	2,578,932	$	2,079,564		$	2,785,086	$	2,754,714

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	171,951	$	74,672		$	76,648	$	150,010
Revenue payable	82,670		64,111			95,838		97,030
Production taxes payable	77,115		52,413			81,905		95,099
Asset retirement obligations	2,771		3,246			10,608		11,694
Commodity derivative liabilities	18,570		7,865
Total current liabilities	353,077		202,307			264,999		353,833

Revolving credit facility	115,000		—			165,000		195,000
Notes payable, net of issuance costs	539,050		538,186			539,977		539,360
Commodity derivative liabilities	1,671		—
Asset retirement obligations	48,951		28,376			38,609		40,052
Deferred taxes	18,076		—			74,238		37,967
Other liabilities	2,308		2,261			4,646		2,210
Total liabilities	1,078,133		771,130			1,087,469		1,168,422

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, 400,000,000 and 300,000,000 shares authorized: 242,572,199 and 241,365,522 shares issued and outstanding as of September 30, 2018 and December 31, 2017, respectively	243		241
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	1,488,588		1,474,273			1,499,213		1,492,107
Retained earnings (deficit)	11,968		(166,080		)
Retained earnings						198,161		93,942
Total shareholders' equity	1,500,799		1,308,434			1,697,617		1,586,292

Total liabilities and shareholders' equity	$	2,578,932	$	2,079,564		$	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,					Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017			2018			2017		2019		2018			2019			2018
Oil, natural gas, and NGL revenues	$	160,978		$	103,593		$	455,298		$	222,419	$	162,602	$	147,087		$	352,057		$	294,320

Expenses:
Lease operating expenses	10,360			4,316			29,868			13,008		13,230		11,612			30,590			19,508
Transportation and gathering	1,994			838			5,729			1,136		4,664		1,880			8,718			3,735
Production taxes	12,824			10,083			41,325			21,013		13,185		15,058			20,271			28,501
Depreciation, depletion, and accretion	45,188			33,740			124,146			73,396		58,027		41,877			118,945			78,958
Unused commitment charge	—			—			—			669
General and administrative	10,685			8,484			29,691			24,289		9,243		9,406			18,712			19,006
Total expenses	81,051			57,461			230,759			133,511		98,349		79,833			197,236			149,708

Operating income	79,927			46,132			224,539			88,908		64,253		67,254			154,821			144,612

Other income (expense):
Commodity derivatives gain (loss)	(8,529		)	(2,383		)	(28,604		)	2,324
Commodity derivative gain (loss)												8,285		(14,294		)	(14,628		)	(20,075		)
Interest expense, net of amounts capitalized	—			—			—			—		—		—			—			—
Interest income	23			16			37			47		92		5			161			14
Other income	125			83			152			385		75		6			136			27
Total other income (expense)	(8,381		)	(2,284		)	(28,415		)	2,756		8,452		(14,283		)	(14,331		)	(20,034		)

Income before income taxes	71,546			43,848			196,124			91,664		72,705		52,971			140,490			124,578

Income tax expense	8,918			—			18,076			—		18,237		3,347			36,271			9,158
Net income	$	62,628		$	43,848		$	178,048		$	91,664	$	54,468	$	49,624		$	104,219		$	115,420

Net income per common share:
Basic	$	0.26		$	0.22		$	0.74		$	0.46	$	0.22	$	0.20		$	0.43		$	0.48
Diluted	$	0.26		$	0.22		$	0.73		$	0.46	$	0.22	$	0.20		$	0.43		$	0.47

Weighted-average shares outstanding:
Basic	242,536,781			200,881,447			242,184,348			200,807,436		243,404,917		242,255,724			243,348,141			242,005,211
Diluted	243,560,046			201,460,915			243,207,058			201,326,129		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,						Six Months Ended June 30,
	2018			2017			2019			2018
Cash flows from operating activities:
Net income	$	178,048		$	91,664		$	104,219		$	115,420
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and accretion	124,146			73,396			118,945			78,958
Settlement of asset retirement obligation	(5,234		)	(4,077		)
Settlement of asset retirement obligations							(4,476		)	(4,089		)
Provision for deferred taxes	18,076			—			36,271			9,158
Stock-based compensation expense	9,347			8,390			6,825			5,942
Mark-to-market of commodity derivative contracts:
Total loss (gain) on commodity derivatives contracts	28,604			(2,324		)
Total loss on commodity derivatives contracts							14,628			20,075
Cash settlements on commodity derivative contracts	(13,263		)	778			7,715			(6,121		)
Cash premiums paid for commodity derivative contracts							(977		)	—
Changes in operating assets and liabilities	3,830			(25,010		)	18,433			16,419
Net cash provided by operating activities	343,554			142,817			301,583			235,762

Cash flows from investing activities:
Acquisition of oil and gas properties and leaseholds	(129,069		)	(62,562		)
Acquisition of oil and gas properties and leaseholds, net of post-closing adjustments							116			(16,402		)
Capital expenditures for drilling and completion activities	(331,702		)	(305,636		)	(276,095		)	(213,906		)
Other capital expenditures	(26,439		)	(11,198		)	(28,262		)	(23,823		)
Acquisition of land and other property and equipment	(2,914		)	(4,058		)	(304		)	(1,581		)
Proceeds from sales of oil and gas properties and other	1,233			77,017			12,802			766
Net cash used in investing activities	(488,891		)	(306,437		)	(291,743		)	(254,946		)

Cash flows from financing activities:
Proceeds from the employee exercise of stock options	4,302			114			—			4,192
Payment of employee payroll taxes in connection with shares withheld	(1,106		)	(631		)	(1,126		)	(1,010		)
Proceeds from the revolving credit facility	115,000			170,000			—			25,000
Principal repayments on the revolving credit facility	—			(20,000		)	(30,000		)	—
Fees on debt and equity issuances and revolving credit facility amendments	(2,173		)	(1,372		)	(379		)	(2,165		)
Capital lease payments	(222		)	—			(105		)	(135		)
Net cash provided by financing activities	115,801			148,111
Net cash provided by (used in) financing activities							(31,610		)	25,882

Net decrease in cash, cash equivalents, and restricted cash	(29,536		)	(15,509		)
Net increase (decrease) in cash and cash equivalents							(21,770		)	6,698

Cash, cash equivalents, and restricted cash at beginning of period	48,772			36,834
Cash and cash equivalents at beginning of period							49,609			48,772

Cash, cash equivalents, and restricted cash at end of period	$	19,236		$	21,325
Cash and cash equivalents at end of period							$	27,839		$	55,470

Supplemental Cash Flow Information (See Note 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. 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. The Company’s common stock is listed and traded on the NYSE American under the 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, ~~2017~~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, ~~2017~~2018 as filed with the SEC on February ~~21, 2018.~~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, ~~2017.~~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 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	2018	2017	2018	2017	2019	2018	2019	2018
Company A	23%	30%	13%	27%	28%	*	26%	*
Company B	21%	27%	19%	26%	20%	17%	21%	17%
Company C	14%	13%	28%	15%	16%	32%	18%	17%
Company D	14%	*	11%	*	11%	19%	10%	33%
Company E	14%	*	16%	*	*	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 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, 2018 December 31, 2017
Company A 23% 26%
Company B 16% 16%
Company C 14% 23%
Company D 14% *
Company E * 11%

* less than 10%

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

Recently Adopted Accounting Pronouncements:

In ~~May 2014,~~February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") ~~2014-09, “Revenue from Contracts~~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 recognize right-of-use (“ROU”) 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 ~~Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue~~such classification affecting the pattern and classification of expense recognition ~~standard designed to depict~~in the ~~transfer~~consolidated statements of ~~goods or services to a customer in an amount that reflects~~operations and presentation within the consideration the entity expects to receive in exchange for those goods or services. 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 usestatements of either the full or modified retrospective transition method, and the standard became effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period. cash flows.

The Company adopted ~~the guidance~~ASC 842 on January 1, 2019 using the modified retrospective ~~method~~method. The 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 the ~~effective date~~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 one year, (b) for all existing asset classes that 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, which among other things allows the Company to 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 under the previous leasing guidance, that existed or expired before adoption of 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 the accompanying condensed consolidated balance sheets as a result of the additional ROU assets and related lease liabilities. Upon adoption on January 1, ~~2018. The~~2019, the Company ~~did not record a cumulative-effect adjustment~~recognized approximately $2.4 million in ROU assets and $4.3 million in liabilities for its operating leases. There was no cumulative effect to ~~the opening balance of~~ retained earnings ~~as no adjustment was necessary. The~~upon the adoption of ~~the Revenue ASUs did not impact net income or cash flows.~~this guidance. See Note 14 for the new disclosures required by ~~the Revenue ASUs.~~ASC 842.

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

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

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

Change in estimate: 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, the credit for ad valorem taxes was 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, which increased our operating income for the three months ended March 31, 2019 by a corresponding amount, or $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, 2018 December 31, 2017
Oil and gas properties, full cost method:
Costs of proved properties:
Producing and non-producing $ 2,148,278
$ 1,629,789
Less, accumulated depletion and full cost ceiling impairments (784,162 ) (659,205 )
Subtotal, proved properties, net 1,364,116
970,584

Costs of wells in progress 244,206
106,269

Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs 739,303
786,469
Land 9,392
7,200
Subtotal, unproved properties and land 748,695
793,669

Costs of other property and equipment:
Other property and equipment 9,462
8,134
Less, accumulated depreciation (3,560 ) (2,080 )
Subtotal, other property and equipment, net 5,902
6,054

Total property and equipment, net $ 2,362,919
$ 1,876,576

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At ~~September~~June 30, ~~2018~~2019 and ~~2017,~~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 impairments were 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,
2018 2017 2018 2017
Capitalized overhead $ 3,129
$ 2,518
$ 9,522
$ 7,729

~~3. Acquisitions~~

~~September 2018 Acquisition and Swap~~

In September 2018, the Company completed the purchase of vertical and horizontal wells in the Greeley-Crescent development area in Weld County, Colorado for $64.1 million in cash and the assumption of certain liabilities for a total purchase price of $96.8 million. This purchase was contemplated as part of the GCII Acquisition discussed below in "‑December 2017 Acquisition." The effective date of this part of the transaction was September 1, 2018. The transaction was accounted for as an asset acquisition under ASC 805, ~~Business Combinations, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of September 27, 2018.~~

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

~~August 2018 Acquisition~~

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

~~December 2017 Acquisition~~

In December 2017, the Company completed the purchase of approximately 30,200 net acres and the associated non-operated production in the Greeley-Crescent development area in Weld County, Colorado for $576.4 million in cash and the assumption of certain liabilities for a total purchase price of $577.5 million ("GCII Acquisition"). The purchase price has been allocated as $60.8 million to proved oil and gas properties and $516.7 million to unproved oil and gas properties. The effective date of this part of the transaction was November 1, 2017. The transaction was accounted for as an asset acquisition under ASC 805, ~~Business Combinations, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of December 15, 2017.~~


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,
2018 2017 2018 2017
Depletion of oil and gas properties $ 44,230
$ 32,944
$ 121,259
$ 71,389
Depreciation and accretion 958
796
2,887
2,007
Total DD&A Expense $ 45,188
$ 33,740
$ 124,146
$ 73,396

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


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, remediate the well, and 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, 2018
Asset retirement obligations, December 31, 2017 $ 31,622
Obligations incurred with development activities 1,488
Obligations assumed with acquisitions 26,150
Accretion expense 1,406
Obligations discharged with asset retirements and divestitures (8,944 )
Asset retirement obligation, September 30, 2018 $ 51,722
Less, current portion (2,771 )
Long-term portion $ 48,951


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 Restated Credit Agreement provides a revolving credit facility (sometimes referred to as the "Revolver") and a $25 million swingline facility with a maturity date of April 2, 2023. The Revolver is available for working capital for exploration and production operations, acquisitions of oil and gas properties, and general corporate purposes and to support letters of credit. At ~~September~~June 30, ~~2018,~~2019, the terms of the Revolver provided for up to $1.5 billion in borrowings, an aggregate elected commitment of ~~$450~~$550 million, and a borrowing base limitation of ~~$550~~$700 million. As of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, the outstanding principal balance was ~~$115.0~~$165.0 million and ~~nil,~~$195.0 million, respectively. At ~~September~~June 30, 2019 and December 31, 2018, the Company had no letters of credit issued.

In October 2018, the lenders under the Revolver completed their semi-annual redetermination of our borrowing base. The borrowing base was increased from $550 million to $650 million, and we increased our aggregate elected commitment from $450 million to $500 million.

Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the ~~nine~~six months ended ~~September~~June 30, ~~2018 and 2017~~2019 was ~~4.0% and 3.3%, respectively.~~4.4%.

Certain of the Company’s assets, including substantially all of its producing wells and developed oil and gas leases, have been designated as collateral under the Restated Credit Agreement. The 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 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 the projected production from proved developed producing or total proved reserves as reflected in the most recently completed reserve report.

~~Furthermore, the Restated Credit Agreement 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 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 last day of any fiscal quarter or (b) permit its ratio of current assets to current liabilities, each as defined in the agreement, to be less than 1.0 to 1.0 as of the last day of any fiscal quarter. As of ~~September~~June 30, ~~2018,~~2019, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.


7.6.	Notes Payable

2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of 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 December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% ~~and began accruing on November 29, 2017.~~. Interest is payable on June 1 and December 1 of each ~~year, beginning on June 1, 2018.~~year. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017. ~~The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions.~~ The associated expenses and underwriting discounts and commissions are amortized using the effective interest method at an effective interest rate of 6.6%.~~The net proceeds were used to fund the GCII Acquisition as discussed further in Note~~ ~~3, to repay our previously outstanding senior notes due 2021, and to pay off the outstanding Revolver balance~~.

At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the principal amount plus an Applicable Premium (as defined in the Indenture) and accrued and unpaid interest. On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes ~~(104.688% for 2020, 103.125% for 2021,~~ ~~101.563%for 2022,~~ ~~and 100% for 2023 and thereafter,~~ during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to~~35%of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to106.25% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.~~

The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications. 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 June 30, 2019, none of the Company's subsidiaries met the criteria in the Indenture to be considered a guarantor of the 2025 Senior Notes.

As of~~September~~June 30, ~~2018,~~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.

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 seven counterparties. Five of the counterparties are lenders in the Restated Credit Agreement. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying condensed consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses 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, ~~2018~~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

Volumes
(Bbls per day)

Weighted-Average
Floor Price
Weighted-Average Ceiling Price
Crude Oil - NYMEX WTI
Oct 1, 2018 - Dec 31, 2018 Collar 10,000
$ 43.63
$ 61.29
Jan 1, 2019 - Dec 31, 2019 Collar 6,000
$ 55.00
$ 74.31

Settlement Period
Derivative
Instrument

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

Settlement Period
Derivative
Instrument

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

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

Jan 1, 2019 - Dec 31, 2019 Swap 2,000
$ 37.52

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

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

Offsetting of Derivative Assets and Liabilities

As of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017,~~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, 2018								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	$	1,740	$	(1,740	)	$	—	Current assets	$	15,749	$	(3,688	)	$	12,061
Commodity derivative contracts	Noncurrent assets	1,078		(1,078		)	—		Noncurrent assets	—		—			—
Commodity derivative contracts	Current liabilities	20,310		(1,740		)	18,570		Current liabilities	3,688		(3,688		)	—
Commodity derivative contracts	Noncurrent liabilities	$	2,749	$	(1,078	)	$	1,671	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, 2017
Underlying
Balance Sheet
Location
Gross Amounts of Recognized Assets and Liabilities
Gross Amounts Offset in the
Balance Sheet

Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
Commodity derivative contracts Current assets $ 1,960
$ (1,960 ) $ —
Commodity derivative contracts Noncurrent assets —
—
—
Commodity derivative contracts Current liabilities 9,825
(1,960 ) 7,865
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,
2018 2017 2018 2017
Realized gain (loss) on commodity derivatives $ (8,273 ) $ 116
$ (16,228 ) $ (26 )
Unrealized gain (loss) on commodity derivatives (256 ) (2,499 ) (12,376 ) 2,350
Total gain (loss) $ (8,529 ) $ (2,383 ) $ (28,604 ) $ 2,324

Realized gains and losses represent the monthly settlement of derivative contracts at their scheduled maturity date, 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,
2018 2017 2018 2017
Monthly settlement $ (8,273 ) $ 376
$ (16,228 ) $ 927
Previously incurred premiums attributable to settled commodity contracts —
(260 ) —
(953 )
Total realized loss $ (8,273 ) $ 116
$ (16,228 ) $ (26 )

~~Credit Related~~Credit-Related Contingent Features

As of ~~September~~June 30, ~~2018, five~~2019, all of the ~~seven~~ counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the ~~credit facility~~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 sixth and seventh counterparties, which are not lenders under the credit facility, is unsecured and does not require the posting of collateral.~~


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 or valuation models.

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

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

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

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 by level within the fair value hierarchy (in thousands):


	Fair Value Measurements at September 30, 2018								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	$	—	$	20,241	$	—	$	20,241	$	—	$	—	$	—	$	—



	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, 2017
Level 1 Level 2 Level 3 Total
Financial assets and liabilities:
Commodity derivative asset $ —
$ —
$ —
$ —
Commodity derivative liability $ —
$ 7,865
$ —
$ 7,865

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At ~~September~~June 30, ~~2018,~~2019, derivative instruments utilized by the Company consist of 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, accounts receivable, and accounts payable are representative of their fair values due to their ~~short-~~

~~term~~short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the notes payable is estimated to be ~~$514.3~~$499.1 million at ~~September~~June 30, ~~2018.~~2019. The Company determined the fair value of its notes payable at ~~September~~June 30, ~~2018~~2019 by using observable market-based information for these debt instruments. The Company has classified the notes payable as Level 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,
2018 2017 2018 2017
Revolving bank credit facility $ 376
$ 1,016
$ 461
$ 1,286
Notes payable 8,593
1,800
25,781
5,400
Amortization of issuance costs and other 905
1,090
2,905
2,267
Less: interest capitalized (9,874 ) (3,906 ) (29,147 ) (8,953 )
Interest expense, net of amounts capitalized $ —
$ —
$ —
$ —


~~11.~~10.	~~Equity and~~ Stock-Based Compensation

~~Equity~~

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

~~Stock-Based Compensation~~

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant-date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting period"). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's 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, ~~2018,~~2019, there were 10,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which ~~4,251,410~~1,164,414 shares were available for future grant. The shares available for future grant exclude ~~1,555,263~~1,973,768 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards meet the 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,
2018 2017 2018 2017
Stock options $ 1,072
$ 1,277
$ 3,470
$ 3,825
Performance-vested stock units 1,187
807
3,216
2,130
Restricted stock units and stock bonus shares 1,771
1,386
4,507
3,779
Total stock-based compensation $ 4,030
$ 3,470
$ 11,193
$ 9,734
Less: stock-based compensation capitalized (625 ) (440 ) (1,846 ) (1,344 )
Total stock-based compensation expensed $ 3,405
$ 3,030
$ 9,347
$ 8,390

Stock options

No stock options were granted during the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 or ~~2017.~~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, 2017 5,636,834
$ 9.38
7.0 years $ 4,806
Granted —
—

Exercised (823,883 ) 5.36
4,611
Expired (23,400 ) 11.27

Forfeited (104,917 ) 9.57

Outstanding, September 30, 2018 4,684,634
$ 10.07
6.6 years $ 2,505
Outstanding, Exercisable at September 30, 2018 3,142,430
$ 10.25
6.4 years $ 1,452

The following table summarizes information about issued and outstanding stock options as of ~~September~~June 30, ~~2018:~~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 35,000
$ 3.31
3.8 years 35,000
$ 3.31
3.8 years
$5.00 - $6.99 723,800
6.30
6.7 years 389,200
6.27
5.9 years
$7.00 - $10.99 1,362,334
9.42
6.7 years 864,830
9.49
6.4 years
$11.00 - $13.46 2,563,500
11.58
6.7 years 1,853,400
11.57
6.6 years
Total 4,684,634
$ 10.07
6.6 years 3,142,430
$ 10.25
6.4 years

The estimated unrecognized compensation cost from stock options not vested as of ~~September~~June 30, ~~2018,~~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) $ 5,685
Remaining vesting phase 1.8 years

Restricted stock units and stock bonus awards

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

The following table summarizes activity for restricted stock units and stock bonus awards for the ~~nine~~six months ended ~~September~~June 30, ~~2018:~~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, 2017 1,087,386
$ 8.89
Granted 747,168
9.35
Vested (439,945 ) 8.77
Forfeited (54,111 ) 9.56
Not vested, September 30, 2018 1,340,498
$ 9.16

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of ~~September~~June 30, ~~2018,~~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) $ 9,075
Remaining vesting phase 2.0 years

Performance-vested stock units

The Company ~~grants two~~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 ~~September~~June 30, ~~2018, 281,872~~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 ~~TSR~~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 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,
2018 2017
Weighted-average expected term 2.8 years
2.9 years
Weighted-average expected volatility 52 % 59 %
Weighted-average risk-free rate 2.41 % 1.34 %

~~The fair value of the TSR PSUs granted during the nine months ended September 30, 2018 and 2017 was $4.2 million and $5.1 million, respectively.~~ As of ~~September~~June 30, ~~2018,~~2019, unrecognized compensation cost for TSR PSUs was ~~$6.0~~$7.7 million and will be amortized through ~~2020. A summary of the status and~~2021. The following table summarizes activity offor TSR PSUs ~~is presented in~~for 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, 2017	951,884	$	9.44
Not vested, December 31, 2018				780,028	$	11.73
Granted	321,507	13.11		918,842	5.74
Vested	—	—		—	—
Forfeited	—	—		—	—
Not vested, September 30, 2018	1,273,391	$	10.36
Not vested, June 30, 2019				1,698,870	$	8.49

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.~~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,		Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017	2019	2018	2019	2018
Weighted-average shares outstanding — basic	242,536,781	200,881,447	242,184,348	200,807,436	243,404,917	242,255,724	243,348,141	242,005,211
Potentially dilutive common shares from:
Stock options	230,067	415,524	332,953	412,902	13,719	421,316	12,611	387,634
TSR PSUs ¹	411,738	—	336,882	—	277,364	1,372,019	209,431	1,223,542
Restricted stock units and stock bonus shares	381,460	163,944	352,875	105,791	434,245	415,717	139,732	338,286
Weighted-average shares outstanding — diluted	243,560,046	201,460,915	243,207,058	201,326,129	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 September 30,		Nine Months Ended September 30,		Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017	2019	2018	2019	2018
Potentially dilutive common shares from:
Stock options ¹	3,456,300	4,726,500	3,438,167	4,756,500	4,556,834	3,353,700	4,556,834	3,564,617
TSR PSUs ^1,2	160,754	951,884	160,754	951,884	773,954	—	1,233,375	—
Goal-Based PSUs ^2,3	281,872	—	281,872	—	274,898	281,872	274,898	281,872
Restricted stock units and stock bonus shares ¹	13,907	308,094	13,907	497,806	695,353	2,772	704,948	10,005
Total	3,912,833	5,986,478	3,894,700	6,206,190	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.


~~13.~~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.

~~During~~The effective combined U.S. federal and state income tax rates for the three and six months ended ~~March 31,~~June 30, 2019 were 25% and 26%, respectively. For the three and six months ended June 30, 2018, the Company concluded it is more likely than not it will realize the benefits of its net deferred tax assets by the end of 2018 as a result of current year ordinary income. This conclusion was based upon the Company’s projection of cumulative positive net income for the three-year period ended December 31, 2018. The release of the valuation allowance is reflected in the Company’s estimated annual effective tax rate since the realization of the Company’s deferred tax assets is supported by current year ordinary income. The Company is projecting a net deferred tax liability with a full release of its beginning valuation allowance by the end of 2018.

rates were 6% and 7%, respectively. The effective tax rates for the three and ~~nine~~six months ended ~~September~~June 30, 2019 differed from the statutory rate primarily due to state income taxes, non-deductible expenses, and tax deficiencies recognized in connection with the vesting of stock awards. The 2018 ~~were 12% and 9%, respectively. For the three and nine months ended September 30, 2017, the effective tax~~ rates ~~were nil. The effective tax rates for the three and nine months ended September 30, 2018 and 2017~~ differed from the statutory rates due primarily to the release of valuation allowances previously recorded against deferred tax assets.

As of ~~September~~June 30, ~~2018,~~2019, we had no liability for unrecognized tax benefits. The Company believes that there are no new items 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, ~~2018.~~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, ~~2018,~~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. As of ~~September~~June 30, ~~2018,~~2019, the Company believes it will be able to generate sufficient future ~~taxable~~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.

~~14.~~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 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

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

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:

~~Natural Gas and NGLs Sales~~

~~Under our natural gas processing contracts, we deliver natural gas to~~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 ~~midstream processing entity at~~yield curve analysis that factors in certain assumptions, including the ~~wellhead or the inlet~~term of the ~~midstream processing entity’s system. The midstream processing entity gathers~~lease and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. For these contracts, we have concluded that the midstream processing entity is our customer. We recognize natural gas and NGL revenues based on the net amountcredit rating of the ~~proceeds received from~~Company at lease commencement.

Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the ~~midstream processing.~~

~~Oil Sales~~

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

~~We sell oil production at~~lease term when recognizing a ROU asset and corresponding lease liability. When determining the ~~wellhead~~lease term, options available to extend or early terminate the arrangement are evaluated and ~~collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue~~included when ~~control transfers~~it is reasonably certain these options will be exercised. There are no available options to ~~the purchaser at the wellhead at the net price received.~~

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

~~Transaction Price Allocated to Remaining Performance Obligations~~

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

~~For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states~~ the Company is ~~not required~~reasonably certain to ~~disclose~~exercise.

Currently, the ~~transaction price allocated~~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 residual value guarantee for our vehicle leases. Certain leases also contain optional extension periods that allow for lease terms to ~~remaining performance obligations if~~be extended for up to an additional 5 years.

Costs associated with the ~~variable consideration~~Company’s operating leases are either expensed or capitalized depending on how the underlying asset is ~~allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes~~utilized. For example, costs associated with drilling rigs are ~~wholly unsatisfied and disclosure~~capitalized as part of the ~~transaction price allocated~~development of the Company’s oil and gas properties. Refer to ~~remaining performance obligations is not required.~~

~~Contract Balances~~

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

~~Prior-Period Performance Obligations~~

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


15.	Other Commitments and Contingencies

Oil Commitments

The Company has entered into firm sales agreements for its oil production with four counterparties. Deliveries under ~~three of~~ the sales agreements have commenced. ~~Deliveries under the fourth agreement are expected to commence in the first quarter of 2019.~~ Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments, ~~over the next five years,~~ excluding the contingent commitment described below, are as follows:



Year ending December 31, 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 2018 1,072
2019 5,167
2020 4,003
2021 1,672
2022 —
Thereafter —
Total 11,914

During the ~~third~~second quarter of ~~2018,~~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 plant ("Mewbourn 3") as well as the expansion of a related gathering system. Starting~~plants in August ~~2018, Mewbourn 3 was complete and in service. Our share of the commitment requires 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years.~~

2018. The second agreement includes an additional 300 MMcf per day processing plant ("O'Connor 2"), including up to 100 MMcf per day of bypass, as well as the expansion of a related gathering system. Construction of the plant is ~~underway~~currently being commissioned and is expected to be placed fully into service induring the ~~second~~third quarter of 2019. ~~Our share~~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 ~~an additional~~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 and 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 contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment.~~ If we are unable to fulfill all of our contractual obligations and our obligations are not sufficiently reduced by the collective volumes delivered by other producers, we may be required to pay penalties or damages pursuant to these agreements. During the ~~third~~second quarter of ~~2018,~~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, this cannot be guaranteed.~~obligations. We are also required for the first three years of the 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.

Litigation

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

~~Office leases~~

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

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

~~Vehicle Leases~~

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

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

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

Less: Amount representing interest (92 )
Present value of net minimum lease payments ^*
$ 543

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


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: 2018 2017
Interest paid $ 17,701
$ 4,796

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

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


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

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of ~~September~~June 30, ~~2018~~2019 and its results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017.~~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, ~~2017~~2018 filed with the SEC on February ~~21, 2018.~~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.

~~Proposition 112~~

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

Overview

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

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

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately ~~85%~~90% of our proved developed reserves and anticipate operating 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,
	2017		2016		2015		2015		2014		2013		2018		2017		2016		2015
Average NYMEX prices
Oil (per Bbl)	$	50.93	$	43.20	$	48.73	$	60.65	$	100.39	$	94.58	$	64.94	$	50.93	$	43.20	$	48.73
Natural gas (per Mcf)	$	3.00	$	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,						Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017			2019			2018			2019			2018
Oil (NYMEX-WTI)
Average NYMEX Price	$	69.76		$	48.18		$	66.89		$	49.44		$	59.78		$	68.03		$	57.31		$	65.46
Realized Price *	63.48			41.89			60.13			41.73			52.75			61.22			50.32			58.48
Differential *	$	(6.28	)	$	(6.29	)	$	(6.76	)	$	(7.71	)	$	(7.03	)	$	(6.81	)	$	(6.99	)	$	(6.98	)

Natural Gas (NYMEX-Henry Hub)
Average NYMEX Price	$	2.90		$	2.99		$	2.90		$	3.03		$	2.64		$	2.80		$	2.89		$	2.90
Realized Price	1.79			2.35			1.84			2.39
Differential	$	(1.11	)	$	(0.64	)	$	(1.06	)	$	(0.64	)
Realized Price *													1.58			1.64			2.04			1.87
Differential *													$	(1.06	)	$	(1.16	)	$	(0.85	)	$	(1.03	)

NGL Realized Price	$	19.93		$	17.32		$	18.91		$	15.49		$	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 and continuing through the current period,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.

Our revenues, results of operations, profitability, future growth, and carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil, natural gas, and NGL production. There has been significant volatility in the price of oil and natural gas since mid-2014. During the nine months ended September 30, 2018, the NYMEX-WTI oil price ranged from a high of $77.41 per Bbl on June 27, 2018 to a low of $59.20 per Bbl on February 9, 2018, and the NYMEX-Henry Hub natural gas price ranged from a low of $2.55 per MMBtu on February 12, 2018 to a high of $3.63 per MMBtu on January 29, 2018. As reflected in published data, the price for WTI oil settled at $60.46 per Bbl on December 29, 2017. Comparably, the price of oil settled at $73.16 per Bbl on Friday, September 28, 2018, an increase of 21% from December 29, 2017. NYMEX-Henry Hub natural gas traded at $2.95 per Mcf on December 29, 2017, but increased approximately 2% as of September 28, 2018 to $3.01. While we use NYMEX-Henry Hub to calculate our natural gas differentials, our natural gas sales tend to trend ~~more~~ closely with Colorado Interstate Gas – Rocky Mountains as published in Inside FERC’s Gas Market Report, published by Platts ("CIG"). Average CIG prices for the ~~third quarter of 2018 increased to $2.18 from $1.83 in the~~ second quarter of ~~2018, and~~2019 decreased to $1.95 from $2.95 in the first quarter of 2019, resulting in the basis difference for CIG to NYMEX-Henry Hub ~~decreased~~increasing from ~~$0.97~~$0.20 to ~~$0.72.~~$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, ~~2018,~~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.

Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of ~~September~~June 30, ~~2018:~~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

628

602

146

774

646

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

364

338

310

674

397

433

409

321

754

466

In addition to the producing wells summarized in the preceding table, as of ~~September~~June 30, ~~2018,~~2019, we were the operator of 77122 gross ~~(66~~(115 net) horizontal wells in ~~progress, which excludes 30 gross (23 net) wells for which we have only set surface casings.~~progress. As of ~~September~~June 30, ~~2018,~~2019, we are participating in 2939 gross (9(5 net) non-operated horizontal wells in progress.

As we develop our acreage through horizontal drilling, we have an active program for the remediation and reclamation

of the vast majority of the operated vertical wellbores. During the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we ~~plugged 146~~reclaimed 58 wells and returned the associated acreage to the property owners.

~~Production~~

For the three months ended September 30, 2018, our average daily production increased to 49,165 BOED as compared to 40,378 BOED for the three months ended September 30, 2017. During the first nine months of 2018, our average net daily production was 47,416 BOED. By comparison, during the nine months ended September 30, 2017, our average production rate was 30,331 BOED. As of September 30, 2018, over 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, and acquisitions of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:

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

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

~~Use the latest technology to maximize returns and improve hydrocarbon recovery.~~ Our development objective for individual well optimization is to drill and complete wells with lateral lengths of mostly 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.

~~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 governing 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 permit.

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

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

~~Control and reduce emissions from our production facilities~~. We place high importance on achieving compliance with all applicable air quality rules and regulations and reducing emissions continues to be a top environmental priority. To minimize these emissions, we employ best management practices such as using available direct pipeline take-away access and pneumatic actuated instrument devices and working with suppliers to deploy diesel engines that meet the U.S. Environmental Protection Agency Tier 4 standand. We also control emissions and minimize flaring of gas by recovering natural gas and actively pursuing sufficient take-away capacity for associated produced gas and the use of vapor recovery equipment. We continue to 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).

~~Significant Developments~~

~~Acquisitions and Trade~~

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

~~Revolving Credit Facility~~

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 attractive well-level rates of return. Should commodity prices weaken or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move

higher 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, ~~2018,~~2019, we drilled 8959 operated horizontal wells and turned 5458 operated horizontal wells to sales. As of ~~September~~June 30, ~~2018,~~2019, the Company had 912 gross (8(11 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the ~~fourth~~third quarter. As of ~~September~~June 30, ~~2018,~~2019, we are the operator of 77122 gross ~~(66~~(115 net) horizontal wells in ~~progress, which excludes~~30~~gross (23net) horizontal wells for which we have only set surface casings. The majority~~progress. All of this activity was funded through cash flows from operations. For ~~2018~~2019 as a whole, we expect to drill ~~118~~99 gross ~~(101~~(90 net) operated horizontal wells and complete approximately ~~127~~68 gross ~~(112~~(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, ~~2018,~~2019, we participated in the completion of328gross (6(0.4net) non-operated horizontal wells. As of~~September~~June 30, ~~2018,~~2019, we are participating in2939gross (9(5net) non-operated 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 aggregate volumes currently shut-in are approximately 25,000 BOED with an approximate 33% oil cut. This volume and oil cut is 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 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 year and into 2020.

Legislative Matters

New legislation governing oil and gas development in 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

NYMEX-WTI oil traded at$~~60.46~~45.15per Bbl onDecember ~~29, 2017,~~28, 2018, but ~~has since~~increasedapproximately~~21%~~29%as of~~September~~June 28, ~~2018~~2019to$~~73.16.~~58.20. NYMEX-Henry Hub natural gas traded at$~~2.95~~3.25per Mcf onDecember ~~29, 2017,~~28, 2018, but~~increased~~declinedapproximately2%26%as of~~September~~June 28, ~~2018~~2019to$~~3.01.~~2.42. Although NYMEX-WTI oil prices ~~have~~ increased over the first half in ~~2018,~~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, 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) cause us to allow leases to expire based upon the value of potential oil and natural gas reserves in relation to the costs of exploration, (v) result in marginally productive oil and natural gas wells being ~~abandoned~~shut-in as non-commercial, and (vi) cause ceiling test impairments.

We continually focus on managing drilling and completion costs through a combination of well design optimization, reductions in the average days to drill, and employment of current technological advancements. This focus on cost management helps support well-level economics under varying oil and natural gas pricing environments.

~~Midstream~~Multiple midstream companies that operate ~~the~~ natural gas processing facilities and gathering pipelines in the Wattenberg Field continue to make significant capital investments to increase the capacity of their systems. ~~From~~Until such time ~~to time,~~that these facilities are operational, our production has been, and ~~may~~most likely will continue to be, adversely impacted by ~~the~~a lack of available processing capacity, resulting in high natural gas gathering line pressures. Second and third quarter 2018 results were impacted by this lack of spare gas processing capacity, which resulted in persistently high line pressures and the inability to maintain consistent production flows. Further exacerbating the midstream constraints were above average temperatures in Colorado in June and continuing into July as well as unplanned shutdowns of natural gas processing facilities. As a result, many of the Company's wells could not be produced consistently, and the Company was unable to turn recently completed wells to sales as desired. capacity.

To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream ishas 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 support the expansion of natural gas gathering and processing capacity through agreements that impose baseline and incremental volume commitments, which we are currently exceeding. ~~The initial plans included a new~~DCP Midstream's second expansion under this arrangement is the O'Connor processing complex, which is currently being expanded by 200 MMcf per day of processing ~~plant ("Mewbourn 3"), and~~capacity along with the ~~expansion of a related gathering system, which became operational in August 2018. Through the same framework, all of the parties agreed~~ability to ~~a development plan to add another 300~~bypass an incremental 100 MMcf per ~~day plant ("O'Connor 2"), including~~day. This processing expansion is expected to be placed in service during the third quarter of 2019. DCP Midstream has also recently announced an offload agreement with Western Midstream Partners, LP for up to ~~100~~225 MMcf per day of ~~bypass, that is expected to be~~incremental processing capacity in ~~service in the second quarter of 2019. In addition,~~2020 at Western’s facility. Further, DCP Midstream has ~~announced~~secured the land and permits for the development of ~~a third plant~~another facility ("Bighorn"), ~~which~~where DCP Midstream could ~~have~~add processing capacity of up to 1 Bcf per day, including ~~bypass,~~bypass.

As a result of the 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 pace 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 bring back one completion crew in the third quarter of 2019. We will be utilizing an ~~in-service date after 2019.~~electric fleet upon the crew's return to service. In our continuing effort to reduce our emissions, we 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 these gathering lines have several benefits, including a) reduced need to use trucks, thereby reducing truck traffic and noise in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site storage capacity, resulting in lower production location facility costs, and d) generally improved community relations. As these gathering lines ~~are currently being~~continue to be expanded, we have experienced and ~~expect to~~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. 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."

For~~2018,~~2019, we expect to drill ~~118~~99 gross operated horizontal wells ~~(89~~ (59 of which were drilled through ~~September~~June 30, ~~2018)~~ 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 $580~~be between $425 million ~~($408.3~~ and $450 million ~~of which was incurred through September 30, 2018)~~ and ~~that it should~~will lead to ~~a significant~~an increase in production and associated proved developed producing reserves. ~~We currently~~Our current estimate is that full-year ~~2018~~2019 production will average ~~approximately 50,000~~between 63,000 BOED and 66,000 BOED with ~~the~~oil ~~mix being approximately~~making up 42% to 45% of production.

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

Results of Operations

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

For the three months ended ~~September~~June 30, ~~2018~~2019 compared to the three months ended ~~September~~June 30, ~~2017~~2018

For the three months ended ~~September~~June 30, ~~2018,~~2019, we reported net income of ~~$62.6~~$54.5 million compared to net income of ~~$43.8~~$49.6 million during the three months ended ~~September~~June 30, ~~2017.~~2018. Net income per basic and diluted share was ~~$0.26~~$0.22 for the three months ended ~~September~~June 30, ~~2018~~2019 compared to net income per basic and diluted share of ~~$0.22~~$0.20 for the three months ended ~~September~~June 30, ~~2017.~~2018.

Oil, Natural Gas, and NGL Production and Revenues - For the three months ended ~~September~~June 30, ~~2018,~~2019, we recorded total oil, natural gas, and NGL revenues of ~~$161.0~~$162.6 million compared to ~~$103.6~~$147.1 million for the three months ended ~~September~~June 30, ~~2017,~~2018, an increase of ~~$57.4~~$15.5 million or ~~55%~~11%. The following table summarizes key production and revenue statistics:


	Three Months Ended September 30,				Percentage		Three Months Ended June 30,				Percentage
	2018		2017		Change		2019		2018		Change
Production:
Oil (MBbls) ¹	1,915		1,726		11	%	2,441		1,846		32	%
Natural Gas (MMcf) ²	9,471		7,412		28	%	11,905		8,987		32	%
NGLs (MBbls) ¹	1,030		753		37	%	1,111		992		12	%
MBOE ³	4,523		3,714		22	%	5,536		4,336		28	%
BOED ⁴	49,165		40,378		22	%	60,833		47,646		28	%

Revenues (in thousands):
Oil	$	123,540	$	73,144	69	%	$	132,098	$	114,857	15	%
Natural Gas	16,908		17,402		(3	)%	20,069		14,714		36	%
NGLs	20,530		13,047		57	%	10,435		17,516		(40	)%
	$	160,978	$	103,593	55	%	$	162,602	$	147,087	11	%
Average sales price:
Oil ⁵	$	63.48	$	41.89	52	%	$	52.75	$	61.22	(14	)%
Natural Gas	1.79		2.35		(24	)%
Natural Gas ⁵							1.58		1.64		(4	)%
NGLs	19.93		17.32		15	%	9.39		17.65		(47	)%
BOE ⁵	$	35.15	$	27.66	27	%	$	28.53	$	33.50	(15	)%

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

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

³"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.

⁴"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, ~~2018~~2019 averaged ~~49,165~~60,833 BOED, an increase of ~~22%~~28% over average production of ~~40,378~~47,646 BOED in the three months ended ~~September~~June 30, ~~2017.~~2018. From ~~September~~June 30, ~~2017~~2018 to ~~September~~June 30, ~~2018,~~2019, our well count increased by ~~170~~165 net horizontal wells, growing our reserves and daily production totals. The ~~22%~~28% increase in production ~~and~~resulted in an increase in revenues which was partially offset by the ~~27% increase~~15% decrease in average sales ~~prices resulted in a significant increase in revenues.~~prices.

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,
	2018		2017		2019		2018
Production costs	$	10,181	$	4,223	$	12,963	$	11,433
Workover	179		93		267		179
Total LOE	$	10,360	$	4,316	$	13,230	$	11,612

Per BOE:
Production costs	$	2.25	$	1.14	$	2.34	$	2.64
Workover	0.04		0.03		0.05		0.04
Total LOE	$	2.29	$	1.17	$	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, 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, ~~2018,~~2019, we experienced increased production expense compared to the three months ended ~~September~~June 30, ~~2017~~2018 due to ~~a 45%~~an increase in net operated wells. In addition, elevated line pressures temporarily drove operating costs on a per unit basis higher in the third quarter of 2018 as the Company incurred incremental costs without the typical benefit of flush production from its new wells.

Transportation and gathering - Transportation and gathering ~~was $2.0~~costs were $4.7 million, or ~~$0.44~~$0.84 per BOE, for the three months ended ~~September~~June 30, ~~2018~~2019, compared to ~~$0.8~~$1.9 million, or ~~$0.23~~$0.43 per BOE, for the three months ended ~~September~~June 30, ~~2017.~~2018. Coinciding with the ~~increasing~~increase in its production in ~~2018,~~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. Production taxes were ~~$12.8~~$13.2 million, or ~~$2.83~~$2.38 per BOE, for the three months ended ~~September~~June 30, ~~2018,~~2019, compared to ~~$10.1~~$15.1 million, or ~~$2.71~~$3.47 per BOE, during the three months ended ~~September~~June 30, ~~2017. Taxes tend to increase or decrease primarily based on the value of production sold.~~2018. As a percentage of revenues, production taxes were ~~8.0%~~8.1% and ~~9.7%~~10.2% for the three months ended ~~September~~June 30, 2019 and 2018, ~~and 2017,~~ respectively.

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


	Three Months Ended September 30,				Three Months Ended June 30,
(in thousands)	2018		2017		2019		2018
Depletion of oil and gas properties	$	44,230	$	32,944	$	56,597	$	40,927
Depreciation and accretion	958		796		1,430		950
Total DD&A	$	45,188	$	33,740	$	58,027	$	41,877

DD&A expense per BOE	$	9.99	$	9.08	$	10.48	$	9.66

For the three months ended ~~September~~June 30, ~~2018,~~2019, DD&A was ~~$9.99~~$10.48 per BOE compared to ~~$9.08~~$9.66 per BOE for the three months ended ~~September~~June 30, ~~2017~~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.

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) 2018 2017
G&A costs incurred $ 13,836
$ 11,002
Capitalized costs (3,151 ) (2,518 )
Total G&A $ 10,685
$ 8,484

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

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



	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 ~~$10.7~~$9.2 million for the ~~third~~second quarter of ~~2018~~2019 were ~~26% higher~~2% lower than G&A for the same period of ~~2017. This increase is primarily due to~~ a ~~25% increase in employee headcount from 117 at September 30, 2017 to 146 at September 30,~~ 2018. ~~Additionally, G&A for the three months ended September 30, 2018 was elevated by expenses incurred in support of Colorado oil and gas legislative activities.~~

Our G&A expense for the three months ended ~~September~~June 30, ~~2018~~2019 includes stock-based compensation of ~~$3.4~~$3.1 million compared to ~~$3.0~~$3.1 million for the three months ended ~~September~~June 30, ~~2017.~~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 months ended September 30, 2017 to the three months ended September 30, 2018 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivative gains (losses) - As more fully described in 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 months ended ~~September~~June 30, ~~2018,~~2019, we realized a settlement ~~loss~~gain of ~~$8.3~~$3.3 million. For the prior comparable period, we realized a settlement~~gain~~lossof$~~0.1 million, net of previously incurred premiums attributable to the settled commodity contracts.~~5.9 million.

In addition, for the three months ended ~~September~~June 30, ~~2018,~~2019, we recorded an unrealized ~~loss~~gain of ~~$0.3~~$5.0 million to recognize the mark-to-market change in fair value of our commodity contracts. InBy comparison, in the three months ended ~~September~~June 30, ~~2017,~~2018, we reported an unrealized loss of ~~$2.5~~$8.4 million. Unrealized gains and losses are non-cash items.

Income taxes - As more fully described in Item 1. Financial Statements – Note ~~13,~~ 12, Income Taxes, we reported income tax expense of ~~$8.9~~$18.2 million for the three months ended ~~September~~June 30, ~~2018~~2019 as compared to ~~no income tax expense~~$3.3 million for the comparable prior year period. The effective tax ~~rates~~rate for the three ~~and nine~~ months ended ~~September~~June 30, 2018 ~~and 2017~~ differed from the statutory rates due primarily to the release of valuation allowances previously recorded against deferred tax assets.

For the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018

For the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we reported net income of ~~$178.0~~$104.2 million compared to net income of ~~$91.7~~$115.4 million during the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018. Net income per basic and diluted share was ~~$0.74 and $0.73, respectively,~~$0.43 for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 compared to net income per basic and diluted share of ~~$0.46~~$0.48 and $0.47, respectively, for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018.

Oil, Natural Gas, and NGL Production and Revenues - For the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we recorded total oil, natural gas, and NGL revenues of ~~$455.3~~$352.1 million compared to ~~$222.4~~$294.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, an increase of ~~$232.9~~$57.7 million or ~~105%~~20%. The following table summarizes key production and revenue statistics:


	Nine Months Ended September 30,				Percentage		Six Months Ended June 30,				Percentage
	2018		2017		Change		2019		2018		Change
Production:
Oil (MBbls)	5,802		3,668		58	%	5,408		3,887		39	%
Natural Gas (MMcf)	26,177		17,122		53	%	23,296		16,706		39	%
NGLs (MBbls)	2,780		1,758		58	%	2,165		1,750		24	%
MBOE	12,945		8,280		56	%	11,455		8,422		36	%
BOED	47,416		30,331		56	%	63,288		46,528		36	%

Revenues (in thousands):
Oil	$	354,601	$	154,232	130	%	$	279,178	$	231,061	21	%
Natural Gas	48,139		40,945		18	%	49,173		31,231		57	%
NGLs	52,558		27,242		93	%	23,706		32,028		(26	)%
	$	455,298	$	222,419	105	%	$	352,057	$	294,320	20	%
Average sales price:
Oil	$	60.13	$	41.73	44	%	$	50.32	$	58.48	(14	)%
Natural Gas	1.84		2.39		(23	)%	2.04		1.87		9	%
NGLs	18.91		15.49		22	%	10.95		18.30		(40	)%
BOE	$	34.73	$	26.72	30	%	$	29.97	$	34.50	(13	)%

Net oil, natural gas, and NGL production for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 averaged ~~47,416~~63,288 BOED, an increase of ~~56%~~36% over average production of ~~30,331~~46,528 BOED in the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018. From ~~September~~June 30, ~~2017~~2018 to ~~September~~June 30, ~~2018,~~2019, our well count increased by ~~170~~165 net horizontal wells, growing our reserves and daily production totals. The ~~56%~~36% production resulted in an increase in ~~production and 30% increase~~revenues which was partially offset by the 13% decrease in average sales ~~prices resulted in a significant increase in revenues.~~prices.

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


	Nine Months Ended September 30,				Six Months Ended June 30,
	2018		2017		2019		2018
Production costs	$	29,328	$	12,511	$	30,244	$	19,147
Workover	540		497		346		361
Total LOE	$	29,868	$	13,008	$	30,590	$	19,508

Per BOE:
Production costs	$	2.27	$	1.51	$	2.64	$	2.27
Workover	0.04		0.06		0.03		0.04
Total LOE	$	2.31	$	1.57	$	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 the~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we experiencedincreasedproduction expense compared to the~~nine~~six months ended ~~September~~June 30, ~~2017~~2018primarilydue to ~~a 45%~~an increase in net operated wells. In addition, elevated line pressures temporarily drove operating costs on a unit basis higher in the second and third quarter of 2018 as the Company incurred incremental costs without the typical benefit of flush production from its new wells.

Transportation and gathering - Transportation and gathering ~~was $5.7~~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 ~~nine~~six months ended ~~September~~June 30, ~~2018, compared to $1.1 million, or $0.14 per BOE, for~~2018. Coinciding with the ~~nine months ended September 30, 2017. In~~increase in its production in 2019, the ~~first half of 2017, a majority of the Company's production was delivered to the purchaser at the wellhead whereas, in 2018, the~~

Company has increased the ~~proportion~~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 ~~$41.3~~$20.3 million, or ~~$3.19~~$1.77 per BOE, for the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, compared to ~~$21.0~~$28.5 million, or ~~$2.54~~$3.38 per BOE, for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were ~~9.1%~~5.8% and ~~9.4%~~9.7% for the ~~nine~~six months ended ~~September~~June 30, 2019 and 2018, ~~and 2017, respectively.~~respectively, with the 2019 period reflecting the effect of the change in estimate.

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


	Nine Months Ended September 30,				Six Months Ended June 30,
(in thousands)	2018		2017		2019		2018
Depletion of oil and gas properties	$	121,259	$	71,389	$	116,025	$	77,029
Depreciation and accretion	2,887		2,007		2,920		1,929
Total DD&A	$	124,146	$	73,396	$	118,945	$	78,958

DD&A expense per BOE	$	9.59	$	8.86	$	10.38	$	9.38

For the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, DD&A was ~~$9.59~~$10.38 per BOE compared to ~~$8.86~~$9.38 per BOE for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~ 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:

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

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

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



	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 ~~$29.7~~$18.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 were ~~22% higher~~2% lower than G&A for the same period of ~~2017. This increase is primarily due to a 25% increase in employee headcount from 117 at September 30, 2017 to 146 at September 30,~~ 2018. ~~Additionally,~~Cash G&A for the ~~nine~~six months ended ~~September~~June 30, 2018 was elevated by expenses incurred in support of Colorado oil and gas legislative activities during the ~~third~~second quarter of 2018.

Our G&A expense for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 includes stock-based compensation of ~~$9.3~~$6.8 million compared to ~~$8.4~~$5.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018.

properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 to the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 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, 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 ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we realized a settlement ~~loss~~gain of ~~$16.2~~$8.2 million. For the prior comparable period, we realized a settlement loss of ~~$26.0 thousand,~~$8.0 million, net of previously incurred premiums attributable to the settled commodity contracts.

In addition, for the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we recorded an unrealized loss of ~~$12.4~~$22.8 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, we reported an unrealized ~~gain~~loss of ~~$2.4~~$12.1 million. Unrealized ~~gains and~~ losses are non-cash items.

Income taxes - We reported income tax expense of ~~$18.1~~$36.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 as compared to no$9.2 million of income tax expense for the comparable prior year period. ~~During~~The effective tax rate for the ~~nine~~six months ended ~~September~~June 30, 2018 ~~and 2017, the effective tax rate~~ differed from the statutory ~~rate~~rates due primarily to the release of valuation 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, the sale of equity and debt securities, borrowings under ~~bank~~revolving credit 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 will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. During the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, our cash provided by operating activities of $301.6 million exceeded the $276.1 million spent on drilling and ~~completions expenditures were primarily covered by cash flows from operating~~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. Oil and gas markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.

At ~~September~~June 30, ~~2018,~~2019, we had cash and cash equivalents ~~and restricted cash~~ of ~~$19.2~~$27.8 million, $550.0 million outstanding on our 2025 Senior ~~2025~~ Notes, and a ~~$115.0~~$165.0 million balance outstanding under our revolving credit facility. Our sources and (uses) of funds for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018 are summarized below (in thousands):


	Nine Months Ended September 30,						Six Months Ended June 30,
	2018			2017			2019			2018
Net cash provided by operations	$	343,554		$	142,817		$	301,583		$	235,762
Capital expenditures	(490,124		)	(383,454		)	(304,545		)	(255,712		)
Net cash provided by other investing activities	1,233			77,017			12,802			766
Net cash provided by (used in) equity financing activities	3,039			(517		)	(1,126		)	3,025
Net cash provided by debt financing activities	112,762			148,628
Net increase in cash, cash equivalents, and restricted cash	$	(29,536	)	$	(15,509	)
Net cash provided by (used in) debt financing activities							(30,484		)	22,857
Net increase (decrease) in cash and cash equivalents							$	(21,770	)	$	6,698

Net cash provided by operating activities was ~~$343.6~~$301.6 million and ~~$142.8~~$235.8 million for the ~~nine~~six months ended ~~September~~June 30, 2019 and 2018, ~~and 2017,~~ respectively. The increase in cash from operating activities reflects the ~~increase~~growth in ~~realized commodity prices and~~our production.

N~~et cash provided by other investing activities was$1.2 millionand$77.0 millionfor thenine months endedSeptember 30, 2018and2017, respectively, which were primarily comprised of proceeds from the sale of oil and gas properties and other.~~

Credit Facility

The Revolver has a maturity date of April 2, 2023. The Revolver has a maximum loan commitment of $1.5 billion; however, the maximum amount available to be borrowed at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the least of the aggregate maximum 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.

In ~~October 2018,~~April 2019, the borrowing base was increased from~~$550~~ $650 millionto~~$650 million; however,~~ $700 million, and our elected commitment amount was increased to $550 million from $500 ~~million~~.million. As of~~October 31, 2018,~~ June 30, 2019, there was a ~~$145.0~~ $165.0 million principal balance outstanding andnoletters of credit outstanding, leaving$~~355.0~~385.0 millionavailable to us for future borrowings. The next semi-annual redetermination is scheduled for~~April~~November 2019. Interest on the Revolver accrues at a variable rate. The interest rate pricing grid provides for an escalation in applicable margin based on increased 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 last day of any fiscal quarter or (b) permit its ratio of current assets to current liabilities, each as defined in the agreement, to be less than1.0to 1.0as of the last day of any fiscal quarter.

2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes due 2025 (the ~~2025~~"2025 Senior ~~Notes)~~Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% ~~and began accruing on November 29, 2017.~~. Interest is payable on June 1 and December 1 of each ~~year, beginning~~year.

The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 (the "Indenture") and will be guaranteed on ~~June 1, 2018.~~

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

Capital Expenditures

Capital expenditures for drilling and completion activities totaled ~~$408.3~~$202.1 million and ~~$383.0~~$231.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017,~~2018, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):


	Nine Months Ended September 30,				Six Months Ended June 30,
	2018		2017		2019		2018
Capital expenditures for drilling and completion activities	$	408,334	$	383,028	$	202,119	$	231,196
Acquisitions of oil and gas properties and leasehold*	162,081		89,677
Acquisitions of oil and gas properties and leasehold¹					219		16,402
Capitalized interest, capitalized G&A, and other	40,037		17,514		32,489		26,753
Accrual basis capital expenditures**	$	610,452	$	490,219
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.

During the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we drilled 8959 operated horizontal wells and turned 5458 operated horizontal wells to sales. As of ~~September~~June 30, ~~2018,~~2019, the Company had 912 gross (8(11 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the ~~fourth~~third quarter. As of ~~September~~June 30, ~~2018,~~2019, we are the operator of 77122 gross ~~(66~~(115 net) horizontal wells in ~~progress, which excludes 30 gross (23 net) wells for which we have only set surface casings.~~progress. All of the wells in progress at ~~September~~June 30, ~~2018~~2019 are scheduled to commence production before December 31, ~~2019. The majority~~2020. All of ~~this~~our drilling and completion activity was funded through cash flows from operations.

For the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we participated in 6147 gross ~~(14~~(5 net) 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 ~~2018.~~2019.

We anticipate that our full-year ~~2018~~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 $580~~between $425 million ~~($408.3 million of which was incurred through September 30, 2018).~~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.

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 ~~October 23, 2018,~~June 30, 2019, we had open positions covering~~3.1~~2.9 millionbarrels of oil and~~15,380 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, ~~2018,~~2019, we reported an unrealized commodity activity loss of ~~$12.4~~$22.8 million. Unrealized losses are non-cash items. We also reported a realized ~~loss~~gain of ~~$16.2~~$8.2 million, representing the settlement of commodity contracts settled during the period.

At ~~September~~June 30, ~~2018,~~2019, we estimated that the fair value of our various commodity derivative contracts was a net ~~liability~~asset of ~~$20.2~~$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 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 in arriving at adjusted EBITDA. We exclude those items because they can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. Adjusted EBITDA is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, net income. We believe that adjusted EBITDA is widely used in our industry as a measure of operating performance and may also be used by investors to measure our ability to meet debt covenant requirements. However, our definition of adjusted EBITDA may not be fully comparable to measures with similar titles reported by other companies. We define adjusted EBITDA as net income 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,
	2018			2017			2018			2017			2019			2018			2019			2018
Adjusted EBITDA:
Net income	$	62,628		$	43,848		$	178,048		$	91,664		$	54,468		$	49,624		$	104,219		$	115,420
Depreciation, depletion, and accretion	45,188			33,740			124,146			73,396			58,027			41,877			118,945			78,958
Stock-based compensation expense	3,405			3,030			9,347			8,390			3,142			3,146			6,825			5,942
Mark-to-market of commodity derivative contracts:
Total loss (gain) on commodity derivatives contracts	8,529			2,383			28,604			(2,324		)
Total loss on commodity derivatives contracts													(8,285		)	14,294			14,628			20,075
Cash settlements on commodity derivative contracts	(7,142		)	544			(13,263		)	778			3,089			(4,566		)	7,715			(6,121		)
Cash premiums paid for commodity derivative contracts													(658		)	—			(977		)	—
Interest income	(23		)	(16		)	(37		)	(47		)	(92		)	(5		)	(161		)	(14		)
Income tax expense	8,918			—			18,076			—			18,237			3,347			36,271			9,158
Adjusted EBITDA	$	121,503		$	83,529		$	344,921		$	171,857		$	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 ~~21, 2018~~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 ~~the construction and effect of additional midstream infrastructure,~~planned capacity expansion projects, future ~~differentials, future~~production (including production relative to volume ~~commitments,~~commitments) and reserves, covenant compliance, and the ~~potential~~ implementation and effects of ~~Proposition 112~~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, ~~2017~~2018 filed with the SEC on February ~~21, 2018~~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 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 and Proposition 112;~~

our ability to market our production;

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

~~the~~ effect of environmental liabilities;

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

changes in U.S. tax laws;

our ability to satisfy our contractual obligations and commitments;

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

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

the geographic concentration of our principal properties;

our ability to protect critical data and technology systems;

the availability of water for use in our operations; and

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


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of natural gas prices, as approximately ~~77%~~81% and 79% of our revenue during the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019, respectively, was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a ~~$9.6~~$12.2 million and ~~$29.0~~$27.0 million change in revenues during the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, respectively; a $0.25 per Mcf change in our realized natural gas price would have resulted in a ~~$2.4~~$3.0 million and ~~$6.5~~$5.8 million change in our natural gas revenues for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, respectively; and a $5 per barrel change in our realized NGL price would have resulted in a ~~$5.2~~$5.6 million and ~~$13.9~~$10.8 million change in our NGL revenues for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, respectively.

During the three months ended ~~September~~June 30, ~~2018,~~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 second quarter of 2018.~~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, ~~2018,~~2019, we had open oil and natural gas derivatives in a net ~~liability~~ assetposition with a fair value of ~~$20.2~~$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 ~~$16.1~~$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 ~~$7.8~~$9.4 million.

Interest Rate Risk -At ~~September~~June 30, ~~2018,~~2019, we had ~~$115.0~~$165.0 million outstanding under our revolving credit facility. Interest on amounts borrowed under our credit facility accrues at a variable rate, based upon either the Prime Rate or LIBOR plus an applicable margin. During the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we incurred interest expense of ~~$0.4~~$2.1 million and ~~$0.5~~$4.3 million on our revolving credit ~~facility, respectively.~~facility. When we have balances outstanding under the revolving credit facility, we are exposed to interest rate risk if the variable reference rates increase. If interest rates increase, our 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 expense in the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 would have changed by approximately ~~$0.1 million.~~$0.5 million and $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 Price Risk" above, we enter into commodity derivative agreements to mitigate short-term price volatility. These derivative financial instruments present certain counterparty risks. We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows. We do not require collateral or other security to be furnished by counterparties. We seek to manage the counterparty risk associated with these contracts by limiting transactions to well-capitalized, well-established, and well-known 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 ~~2018~~2019 as the amounts due to us from counterparties ~~have 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

During the quarter ended ~~September~~June 30, ~~2018,~~2019, there were no material developments regarding the legal matters, previously described under Item 3, Legal Proceedings, of the Annual Report on Form 10-K filed with the Securities and Exchange Commission on February ~~21, 2018.~~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 ~~21, 2018.~~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.

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

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

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

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

~~increased operating costs,~~

~~greater difficulties in maintaining leases through production,~~

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

~~inability to meet commitments related to our future production.~~

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


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

Purchases of equity securities by the Company

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



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.


Item 5.	Other Information

None.

Item 6. Exhibits



Exhibit Number		Exhibit
10.1		Form of ~~Goal Based~~ 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 **
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 31st day of ~~October, 2018.~~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 (Principal Financial Officer)

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



	Nine Months Ended September 30, 2018
Asset retirement obligations, December 31, 2017	$	31,622
Obligations incurred with development activities	1,488
Obligations assumed with acquisitions	26,150
Accretion expense	1,406
Obligations discharged with asset retirements and divestitures	(8,944		)
Asset retirement obligation, September 30, 2018	$	51,722
Less, current portion	(2,771		)
Long-term portion	$	48,951



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

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

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

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



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



Unrecognized compensation cost (in thousands)	$	5,685
Remaining vesting phase	1.8 years



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



Year ending December 31,		Oil
Year ending December 31,		(MBbls)
Remainder of 2018		1,072
2019		5,167
2020		4,003
2021		1,672
2022		—
Thereafter		—
Total		11,914



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