Edgar Filing: SM Energy Co

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation or organization)		41-0518430 (I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 1200, Denver, Colorado (Address of principal executive offices)		80203 (Zip Code)

(303) 861-8140

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required 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 þ No o

Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted 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 such files). Yes þ No o

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



Large accelerated filer þ		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o

		Emerging growth company o

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

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

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



Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common stock, $0.01 par value	SM	New York Stock Exchange

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

As of April 25, 2019, the registrant had 112,244,545 shares of common stock outstanding.

TABLE OF CONTENTS



ITEM		PAGE
	PART I	3

ITEM 1.	FINANCIAL STATEMENTS (unaudited)	3

	Condensed Consolidated Balance Sheets March 31, 2019, and December 31, 2018	3

	Condensed Consolidated Statements of Operations Three Months Ended March 31, 2019, and 2018	4

	Condensed Consolidated Statements of Comprehensive Income (Loss) Three Months Ended March 31, 2019, and 2018	5

	Condensed Consolidated Statements of Stockholders’ Equity Three Months Ended March 31, 2019, and 2018	6

	Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 2019, and 2018	7

	Notes to Condensed Consolidated Financial Statements	8

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	23

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (included within the content of Item 2)	39

ITEM 4.	CONTROLS AND PROCEDURES	39

	PART II	41

ITEM 1.	LEGAL PROCEEDINGS	41

ITEM 1A.	RISK FACTORS	41

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	41

ITEM 6.	EXHIBITS	42

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share data)



	March 31, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	14		$	77,965
Accounts receivable	145,299			167,536
Derivative assets	67,567			175,130
Prepaid expenses and other	8,454			8,632
Total current assets	221,334			429,263
Property and equipment (successful efforts method):
Proved oil and gas properties	7,578,976			7,278,362
Accumulated depletion, depreciation, and amortization	(3,586,650		)	(3,417,953		)
Unproved oil and gas properties	1,529,825			1,581,401
Wells in progress	345,507			295,529
Properties held for sale, net	—			5,280
Other property and equipment, net of accumulated depreciation of $59,720 and $57,102, respectively	86,732			88,546
Total property and equipment, net	5,954,390			5,831,165
Noncurrent assets:
Derivative assets	27,202			58,499
Other noncurrent assets	83,692			33,935
Total noncurrent assets	110,894			92,434
Total assets	$	6,286,618		$	6,352,862
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	426,550		$	403,199
Derivative liabilities	95,269			62,853
Other current liabilities	23,523			—
Total current liabilities	545,342			466,052
Noncurrent liabilities:
Revolving credit facility	46,500			—
Senior Notes, net of unamortized deferred financing costs	2,449,588			2,448,439
Senior Convertible Notes, net of unamortized discount and deferred financing costs	150,199			147,894
Asset retirement obligations	94,026			91,859
Deferred income taxes	176,348			223,278
Derivative liabilities	13,332			12,496
Other noncurrent liabilities	68,058			42,522
Total noncurrent liabilities	2,998,051			2,966,488

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,244,545 and 112,241,966 shares, respectively	1,122			1,122
Additional paid-in capital	1,771,558			1,765,738
Retained earnings	982,662			1,165,842
Accumulated other comprehensive loss	(12,117		)	(12,380		)
Total stockholders’ equity	2,743,225			2,920,322
Total liabilities and stockholders’ equity	$	6,286,618		$	6,352,862

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share data)



	For the Three Months Ended March 31,
	2019			2018

Operating revenues and other income:
Oil, gas, and NGL production revenue	$	340,476		$	382,886
Net gain on divestiture activity	61			385,369
Other operating revenues	393			1,340
Total operating revenues and other income	340,930			769,595
Operating expenses:
Oil, gas, and NGL production expense	121,305			120,879
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	177,746			130,473
Exploration	11,348			13,727
Abandonment and impairment of unproved properties	6,338			5,625
General and administrative	32,086			27,682
Net derivative loss	177,081			7,529
Other operating expenses, net	335			4,612
Total operating expenses	526,239			310,527
Income (loss) from operations	(185,309		)	459,068
Interest expense	(37,980		)	(43,085		)
Other non-operating income (expense), net	(317		)	409
Income (loss) before income taxes	(223,606		)	416,392
Income tax (expense) benefit	46,038			(98,991		)
Net income (loss)	$	(177,568	)	$	317,401

Basic weighted-average common shares outstanding	112,252			111,696
Diluted weighted-average common shares outstanding	112,252			112,879
Basic net income (loss) per common share	$	(1.58	)	$	2.84
Diluted net income (loss) per common share	$	(1.58	)	$	2.81
Dividends per common share	$	0.05		$	0.05

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(in thousands)



	For the Three Months Ended March 31,
	2019			2018
Net income (loss)	$	(177,568	)	$	317,401
Other comprehensive income, net of tax:
Pension liability adjustment	263			260
Total other comprehensive income, net of tax	263			260
Total comprehensive income (loss)	$	(177,305	)	$	317,661

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)

(in thousands, except share data and dividends per share)



				Additional Paid-in Capital						Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Common Stock						Retained Earnings
	Shares	Amount					Retained Earnings
Balances, December 31, 2018	112,241,966	$	1,122	$	1,765,738		$	1,165,842		$	(12,380	)	$	2,920,322
Net loss	—	—		—			(177,568		)	—			(177,568		)
Other comprehensive income	—	—		—			—			263			263
Cash dividends declared, $0.05 per share	—	—		—			(5,612		)	—			(5,612		)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	2,579	—		(18		)	—			—			(18		)
Stock-based compensation expense	—	—		5,838			—			—			5,838
Balances, March 31, 2019	112,244,545	$	1,122	$	1,771,558		$	982,662		$	(12,117	)	$	2,743,225

				Additional Paid-in Capital						Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Common Stock						Retained Earnings
	Shares	Amount					Retained Earnings
Balances, December 31, 2017	111,687,016	$	1,117	$	1,741,623		$	665,657		$	(13,789	)	$	2,394,608
Net income	—	—		—			317,401			—			317,401
Other comprehensive income	—	—		—			—			260			260
Cash dividends declared, $0.05 per share	—	—		—			(5,584		)	—			(5,584		)
Stock-based compensation expense	—	—		5,412			—			—			5,412
Cumulative effect of accounting change	—	—		—			2,969			(2,969		)	—
Other	—	—		—			1			(1		)	—
Balances, March 31, 2018	111,687,016	$	1,117	$	1,747,035		$	980,444		$	(16,499	)	$	2,712,097

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)



	For the Three Months Ended March 31,
	2019			2018

Cash flows from operating activities:
Net income (loss)	$	(177,568	)	$	317,401
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net gain on divestiture activity	(61		)	(385,369		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	177,746			130,473
Abandonment and impairment of unproved properties	6,338			5,625
Stock-based compensation expense	5,838			5,412
Net derivative loss	177,081			7,529
Derivative settlement loss	(4,969		)	(24,528		)
Amortization of debt discount and deferred financing costs	3,789			3,866
Deferred income taxes	(47,003		)	98,366
Other, net	(2,530		)	(2,527		)
Net change in working capital	(20,159		)	(16,113		)
Net cash provided by operating activities	118,502			140,135

Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	6,114			490,780
Capital expenditures	(249,340		)	(301,521		)
Other, net	291			—
Net cash provided by (used in) investing activities	(242,935		)	189,259

Cash flows from financing activities:
Proceeds from credit facility	172,000			—
Repayment of credit facility	(125,500		)	—
Other, net	(18		)	—
Net cash provided by financing activities	46,482			—

Net change in cash, cash equivalents, and restricted cash	(77,951		)	329,394
Cash, cash equivalents, and restricted cash at beginning of period	77,965			313,943
Cash, cash equivalents, and restricted cash at end of period	$	14		$	643,337

Supplemental schedule of additional cash flow information and non-cash activities:

Operating activities:
Cash paid for interest, net of capitalized interest	$	(39,957	)	$	(40,060	)

Investing activities:
Changes in capital expenditure accruals and other	$	62,185		$	60,299

Supplemental non-cash investing activities:
Carrying value of properties exchanged	$	65,788		$	—

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

SM ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

Description of Operations

SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report) in onshore North America.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of March 31, 2019, and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying unaudited condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2018 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2018 Form 10-K.

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective 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 the Company has implemented in connection with the adoption of ASU 2016-02, include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources.

Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for additional discussion.

Other than as disclosed in the 2018 Form 10-K, there are no ASUs that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of March 31, 2019, and through the filing of this report.

Note 2 - Revenue from Contracts with Customers

The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Permian and South Texas & Gulf Coast regions. As a result of divestiture activity in the first half of 2018, there has been no production revenue from the Rocky Mountain region after the second quarter of 2018. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) is reflective of the revenue generated from contracts with customers.

The table below presents oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three months ended March 31, 2019, and 2018:



	Permian						South Texas & Gulf Coast						Rocky Mountain						Total
	Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2019			2018			2019			2018			2019			2018
	(in thousands)
Oil production revenue	$	225,247		$	205,794		$	13,814		$	19,583		$	—		$	35,683		$	239,061		$	261,060
Gas production revenue	15,592			24,876			49,521			52,733			—			1,500			65,113			79,109
NGL production revenue	21			124			36,281			41,770			—			823			36,302			42,717
Total	$	240,860		$	230,794		$	99,616		$	114,086		$	—		$	38,006		$	340,476		$	382,886
Relative percentage	71		%	60		%	29		%	30		%	—		%	10		%	100		%	100		%

____________________________________________

Note: Amounts may not calculate due to rounding.

The Company recognizes oil, gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are embedded in the price and effectively recorded as a reduction of oil, gas, and NGL production revenue. Please refer to Note 2 - Revenue from Contracts with Customers in the 2018 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL production revenue is generated.

Significant judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of March 31, 2019, and December 31, 2018, were $109.4 million and $107.2 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized during the three months ended March 31, 2019, that related to performance obligations satisfied in prior reporting periods, was immaterial.

Note 3 - Divestitures, Assets Held for Sale, and Acquisitions

Divestitures

On March 26, 2018, the Company divested approximately 112,000 net acres of its Powder River Basin assets (the “PRB Divestiture”) for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $490.8 million, and recorded an estimated net gain of $409.2 million for the three months ended March 31, 2018. After final purchase price adjustments, the Company received net divestiture proceeds of $492.2 million, and recorded a final net gain of $410.6 million related to these divested assets for the year ended December 31, 2018.

During the first quarter of 2018, the company entered into definitive agreements for the sale of its Divide County assets (the “Divide County Divestiture”) and its Halff East assets in the Midland Basin (the “Halff East Divestiture”). Certain of these assets were written down by $24.1 million during the first quarter of 2018 to reflect fair value less estimated costs to sell upon classification as held for sale. These divestitures were completed during the second quarter of 2018.

Acquisitions

During the first quarter of 2019, the Company completed several non-monetary acreage trades of undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the exchange of approximately 2,000 net acres, with $65.8 million of carrying value attributed to the properties surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized. No such trades occurred during the first quarter of 2018.

Note 4 - Income Taxes

The income tax (expense) benefit recorded for the three months ended March 31, 2019, and 2018, differs from the amounts that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes primarily due to the effect of state income taxes, excess tax benefits and deficiencies from share-based payment awards, limitations on the compensation of certain covered individuals, changes in valuation allowances, and accumulated impacts of other smaller permanent differences. The quarterly rate can also be affected by the proportional impacts of forecasted net income or loss as of each period end presented.

The provision for income taxes for the three months ended March 31, 2019, and 2018, consisted of the following:



	For the Three Months Ended March 31,
	2019			2018
	(in thousands)
Current portion of income tax (expense) benefit:
Federal	$	—		$	—
State	(965		)	(625		)
Deferred portion of income tax (expense) benefit	47,003			(98,366		)
Income tax (expense) benefit	$	46,038		$	(98,991	)
Effective tax rate	20.6		%	23.8		%

The change in the Company’s effective tax rate for the periods presented in the table above generally reflects differences in its estimated highest marginal state tax rate due to changes in the composition of income or loss from Company activities, including divestitures, among multiple state tax jurisdictions. Future periods are not expected to reflect these differences as the Company’s current activities are occurring predominately in Texas. For years before 2015, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

Note 5 - Long-Term Debt

Credit Agreement

As of March 31, 2019, the Company’s Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) provided for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, an initial borrowing base of $1.5 billion, and initial aggregate lender commitments totaling $1.0 billion, which were unchanged from December 31, 2018. On April 18, 2019, the Company entered into the First Amendment to the Credit Agreement (the “First Amendment”) with its lenders. Pursuant to the First Amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were increased to $1.6 billion and $1.2 billion, respectively. The borrowing base increase was primarily driven by the increased value of the Company’s estimated proved reserves at December 31, 2018. The next scheduled borrowing base redetermination date is October 1, 2019.

The Credit Agreement is scheduled to mature on September 28, 2023. The maturity date could, however, occur earlier on August 16, 2022, if the Company has not completed certain repurchase, redemption, or refinancing activities associated with its 6.125% Senior Notes due 2022 (“2022 Senior Notes”), as outlined in the Credit Agreement. Please refer to Note 5 - Long-Term Debt in the 2018 Form 10-K for additional detail on the terms of the Company’s Credit Agreement.

The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement and was in compliance with all such covenants as of March 31, 2019, and through the filing of this report.

Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Credit Agreement as presented in Note 5 - Long-Term Debt in the Company’s 2018 Form 10-K. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations.

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of April 25, 2019, March 31, 2019, and December 31, 2018:



	As of April 25, 2019		As of March 31, 2019		As of December 31, 2018
	(in thousands)
Credit facility balance ⁽¹⁾	$	40,000	$	46,500	$	—
Letters of credit ⁽²⁾	—		—		200
Available borrowing capacity	1,160,000		953,500		999,800
Total aggregate lender commitment amount	$	1,200,000	$	1,000,000	$	1,000,000

____________________________________________


⁽¹⁾	Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.0 million and $6.4 million as of March 31, 2019, and December 31, 2018, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.


⁽²⁾	Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018, was released during the quarter ended March 31, 2019.

Senior Notes

As of March 31, 2019, the Company’s Senior Notes consisted of 6.125% Senior Notes due 2022, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, 6.75% Senior Notes due 2026, and 6.625% Senior Notes due 2027 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of March 31, 2019, and December 31, 2018, consisted of the following:



	As of March 31, 2019						As of December 31, 2018
	Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net of Unamortized Deferred Financing Costs		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net of Unamortized Deferred Financing Costs
	(in thousands)
6.125% Senior Notes due 2022	$	476,796	$	3,671	$	473,125	$	476,796	$	3,921	$	472,875
5.0% Senior Notes due 2024	500,000		4,457		495,543		500,000		4,688		495,312
5.625% Senior Notes due 2025	500,000		5,582		494,418		500,000		5,808		494,192
6.75% Senior Notes due 2026	500,000		6,198		493,802		500,000		6,407		493,593
6.625% Senior Notes due 2027	500,000		7,300		492,700		500,000		7,533		492,467
Total	$	2,476,796	$	27,208	$	2,449,588	$	2,476,796	$	28,357	$	2,448,439

The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes and was in compliance with all such covenants as of March 31, 2019, and through the filing of this report. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.

Senior Convertible Notes

The Company’s Senior Convertible Notes consist of $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. Please refer to Note 5 - Long-Term Debt in the 2018 Form 10-K for additional detail on the Company’s Senior Convertible Notes and associated capped call transactions.

The Senior Convertible Notes were not convertible at the option of holders as of March 31, 2019, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of March 31, 2019, did not exceed the principal amount. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.7 million and $2.6 million for the three months ended March 31, 2019, and 2018, respectively.

There have been no changes to the initial net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets since issuance. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of March 31, 2019, and December 31, 2018, consisted of the following:



	As of March 31, 2019			As of December 31, 2018
	(in thousands)
Principal amount of Senior Convertible Notes	$	172,500		$	172,500
Unamortized debt discount	(20,238		)	(22,313		)
Unamortized deferred financing costs	(2,063		)	(2,293		)
Senior Convertible Notes, net of unamortized discount and deferred financing costs	$	150,199		$	147,894

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all such covenants as of March 31, 2019, and through the filing of this report.

Capitalized Interest

Capitalized interest costs for the Company for the three months ended March 31, 2019, and 2018, were $4.9 million and $4.5 million, respectively. The amount of interest the Company capitalizes generally fluctuates based on its capital program and the timing and amount of costs associated with capital projects that are considered in progress.

Note 6 - Commitments and Contingencies

Commitments

Other than those items discussed below, there have been no changes in commitments through the filing of this report that differ materially from those disclosed in the 2018 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the 2018 Form 10-K for additional discussion of the Company’s commitments.

Delivery and Purchase Commitments. Subsequent to March 31, 2019, the Company executed an amendment to its existing sand sourcing agreement that created certain commitments and potential penalties which will vary based on the amount of actual sand the Company uses in well completions occurring in a particular area. This amended sand sourcing agreement expires on December 31, 2023. As of the filing of this report, potential penalties under this sand sourcing agreement range from zero to $10.0 million. The Company does not expect to incur penalties with regard to this agreement.

Drilling Rig and Completion Service Contracts. The Company entered into new and amended drilling rig and well completion service contracts during the first three months of 2019, and subsequent to March 31, 2019. As of the filing of this report, the Company’s drilling rig and completion service contract commitments totaled $105.3 million. If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $50.0 million in early termination fees. Excluded from these amounts are variable commitments and penalties determined by the number of completion crews the Company has in operation in a particular area under a completion service arrangement. As of the filing of this report, potential penalties under this completion service arrangement, which expires on December 31, 2023, range from zero to a maximum of $15.7 million. The Company does not expect to incur penalties with regard to its drilling rig and completion service contracts.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Note 7 - Compensation Plans

Performance Share Units

The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity incentive compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three-year performance period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Company’s Equity Incentive Compensation Plan (“Equity Plan”).

PSUs are subject to a combination of market, performance, and service vesting criteria. Awards with a market criteria component are based on annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of the Company’s peer group for the performance period. Compensation expense for market-based PSUs is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards.

Awards with a performance criteria component are based on relative debt adjusted per share cash flow growth (“DACFG”) compared with DACFG, as calculated by the Company, of its peer group that is evaluated over the three-year performance period. Compensation expense for performance-based PSUs will be evaluated on a quarterly basis and may be adjusted as the number of units expected to vest increases or decreases.

Total compensation expense recorded for PSUs was $2.8 million and $2.4 million for the three months ended March 31, 2019, and 2018, respectively. As of March 31, 2019, there was $15.9 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2021. There have been no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2019.

Employee Restricted Stock Units

The Company grants restricted stock units (“RSUs”) to eligible persons as part of its long-term equity incentive compensation program. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. RSUs granted to employees generally vest one-third on each anniversary date of the grant over a three-year vesting period or upon other triggering events as set forth in the Company’s Equity Plan.

Total compensation expense recorded for employee RSUs was $2.7 million for each of the three months ended March 31, 2019, and 2018. As of March 31, 2019, there was $16.4 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2021. There have been no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2019.

Note 8 - Pension Benefits

Pension Plans

The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen will continue to earn benefits.

Components of Net Periodic Benefit Cost for the Pension Plans



	For the Three Months Ended March 31,
	2019			2018
	(in thousands)
Components of net periodic benefit cost:
Service cost	$	1,683		$	1,660
Interest cost	656			673
Expected return on plan assets that reduces periodic pension benefit cost	(466		)	(561		)
Amortization of prior service cost	4			4
Amortization of net actuarial loss	332			324
Net periodic benefit cost	$	2,209		$	2,100

Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. The service cost component of net periodic benefit cost for the Pension Plans is presented as an operating expense within the general and administrative and exploration expense line items on the accompanying statements of operations while the other components of net periodic benefit cost for the Pension Plans are presented as non-operating expenses within the other non-operating income (expense), net line item on the accompanying statements of operations.

Contributions

The Company contributed $4.3 million to the Qualified Pension Plan during the three months ended March 31, 2019.

Note 9 - Earnings Per Share

Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the three months ended March 31, 2019, and 2018, and therefore the Senior Convertible Notes had no dilutive impact. Please refer to Note 9 - Earnings Per Share in the 2018 Form 10-K for additional detail on these potentially dilutive securities.

When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average dilutive and anti-dilutive securities for the periods presented:



	For the Three Months Ended March 31,
	2019	2018
	(in thousands)
Dilutive	—	1,183
Anti-dilutive	781	—

The following table sets forth the calculations of basic and diluted net income (loss) per common share:



	For the Three Months Ended March 31,
	2019			2018
	(in thousands, except per share data)
Net income (loss)	$	(177,568	)	$	317,401

Basic weighted-average common shares outstanding	112,252			111,696
Dilutive effect of non-vested RSUs and contingent PSUs	—			1,183
Dilutive effect of Senior Convertible Notes	—			—
Diluted weighted-average common shares outstanding	112,252			112,879

Basic net income (loss) per common share	$	(1.58	)	$	2.84
Diluted net income (loss) per common share	$	(1.58	)	$	2.81

Note 10 - Derivative Financial Instruments

Summary of Oil, Gas, and NGL Derivative Contracts in Place

The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of March 31, 2019, all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas production, and swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices.

As of March 31, 2019, the Company had commodity derivative contracts outstanding through the fourth quarter of 2022 as summarized in the tables below.

Oil Swaps



Contract Period	NYMEX WTI Volumes	Weighted-Average Contract Price
	(MBbl)	(per Bbl)
Second quarter 2019	575	$	55.52
Third quarter 2019	1,217	$	61.41
Fourth quarter 2019	1,115	$	59.97
2020	2,491	$	65.68
Total	5,398

Oil Collars



Contract Period	NYMEX WTI Volumes	Weighted-Average Floor Price		Weighted-Average Ceiling Price
	(MBbl)	(per Bbl)		(per Bbl)
Second quarter 2019	3,034	$	52.39	$	64.32
Third quarter 2019	2,547	$	49.50	$	62.64
Fourth quarter 2019	3,168	$	50.54	$	62.49
2020	3,405	$	55.00	$	63.00
Total	12,154

Oil Basis Swaps



Contract Period	WTI Midland-NYMEX WTI Volumes	Weighted-Average Contract Price ⁽¹⁾			NYMEX WTI-ICE Brent Volumes	Weighted-Average Contract Price ⁽²⁾
	(MBbl)	(per Bbl)			(MBbl)	(per Bbl)
Second quarter 2019	2,571	$	(4.49	)	—	$	—
Third quarter 2019	3,291	$	(2.86	)	—	$	—
Fourth quarter 2019	3,338	$	(2.87	)	—	$	—
2020	11,601	$	(1.03	)	2,750	$	(8.03	)
2021	3,707	$	0.33		3,650	$	(7.86	)
2022	—	$	—		3,650	$	(7.78	)
Total	24,508				10,050

____________________________________________


⁽¹⁾	Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).


⁽²⁾	Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).

Gas Swaps



Contract Period	IF HSC Volumes	Weighted-Average Contract Price		WAHA Volumes	Weighted-Average Contract Price
	(BBtu)	(per MMBtu)		(BBtu)	(per MMBtu)
Second quarter 2019	11,177	$	2.82	4,546	$	0.70
Third quarter 2019	14,102	$	2.84	4,340	$	1.30
Fourth quarter 2019	14,433	$	2.88	2,962	$	1.75
2020	9,123	$	2.98	2,060	$	2.20
Total ⁽¹⁾	48,835			13,908

____________________________________________


⁽¹⁾	The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of March 31, 2019, total volumes for gas swaps are comprised of 78 percent IF HSC, 12 percent GD Waha, and 10 percent IF Waha.

Gas Collars



Contract Period	IF HSC Volumes	Weighted-Average Floor Price		Weighted-Average Ceiling Price
	(BBtu)	(per MMBtu)		(per MMBtu)
Second quarter 2019	4,358	$	2.50	$	2.83
Third quarter 2019	5,066	$	2.50	$	2.83
Fourth quarter 2019	4,818	$	2.50	$	2.83
Total	14,242

NGL Swaps



	OPIS Ethane Purity Mont Belvieu			OPIS Propane Mont Belvieu Non-TET			OPIS Normal Butane Mont Belvieu Non-TET			OPIS Isobutane Mont Belvieu Non-TET			OPIS Natural Gasoline Mont Belvieu Non-TET
Contract Period	Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price		Volumes	Weighted-Average Contract Price
	(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)		(MBbl)	(per Bbl)
Second quarter 2019	877	$	12.29	561	$	31.32	38	$	35.64	29	$	35.70	49	$	50.93
Third quarter 2019	907	$	12.34	637	$	31.29	39	$	35.64	30	$	35.70	50	$	50.93
Fourth quarter 2019	896	$	12.36	651	$	31.64	39	$	35.64	29	$	35.70	50	$	50.93
2020	711	$	11.38	—	$	—	—	$	—	—	$	—	—	$	—
Total	3,391			1,849			116			88			149

Commodity Derivative Contracts Entered Into Subsequent to March 31, 2019

Subsequent to March 31, 2019, the Company entered into various commodity derivative contracts, as summarized below:


•	fixed price NYMEX WTI oil swap contracts through the second quarter of 2020 for a total of 1.6 MMBbl of oil production at a weighted-average contract price of $61.49 per Bbl;


•	NYMEX WTI costless collar contracts through the third quarter of 2020 for a total of 1.7 MMBbl of oil production with a weighted-average contract floor price of $55.00 per Bbl and a weighted-average contract ceiling price of $65.07 per Bbl; and


•	fixed price OPIS Propane Mont Belvieu Non-TET swap contracts through the fourth quarter of 2020 for a total of 0.6 MMBbl of propane production at a contract price of $28.10 per Bbl.

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the commodity derivative contracts was a net liability of $13.8 million at March 31, 2019, and a net asset of $158.3 million at December 31, 2018.

The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:



	As of March 31, 2019		As of December 31, 2018
	(in thousands)
Derivative assets:
Current assets	$	67,567	$	175,130
Noncurrent assets	27,202		58,499
Total derivative assets	$	94,769	$	233,629
Derivative liabilities:
Current liabilities	$	95,269	$	62,853
Noncurrent liabilities	13,332		12,496
Total derivative liabilities	$	108,601	$	75,349

Offsetting of Derivative Assets and Liabilities

As of March 31, 2019, and December 31, 2018, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have 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 not offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:



	Derivative Assets						Derivative Liabilities
	As of						As of
	March 31, 2019			December 31, 2018			March 31, 2019			December 31, 2018
	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	94,769		$	233,629		$	(108,601	)	$	(75,349	)
Amounts not offset in the accompanying balance sheets	(52,882		)	(56,041		)	52,882			56,041
Net amounts	$	41,887		$	177,588		$	(55,719	)	$	(19,308	)

The following table summarizes the components of the net derivative loss line item presented in the accompanying statements of operations:



	For the Three Months Ended March 31,
	2019			2018
	(in thousands)
Derivative settlement (gain) loss:
Oil contracts	$	1,369		$	20,748
Gas contracts	4,134			(6,410		)
NGL contracts	(534		)	10,190
Total derivative settlement loss	$	4,969		$	24,528

Net derivative (gain) loss:
Oil contracts	$	185,797		$	13,966
Gas contracts	(6,113		)	9,990
NGL contracts	(2,603		)	(16,427		)
Total net derivative loss	$	177,081		$	7,529

Credit Related Contingent Features

As of March 31, 2019, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

Note 11 - Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:


•	Level 1 – quoted prices in active markets for identical assets or liabilities


•	Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable


•	Level 3 – significant inputs to the valuation model are unobservable

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of March 31, 2019:



	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	94,769	$	—
Liabilities:
Derivatives ⁽¹⁾	$	—	$	108,601	$	—

__________________________________________


⁽¹⁾	This represents a financial asset or liability that is measured at fair value on a recurring basis.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2018:



	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	233,629	$	—
Liabilities:
Derivatives⁽¹⁾	$	—	$	75,349	$	—

____________________________________________


⁽¹⁾	This represents a financial asset or liability that is measured at fair value on a recurring basis.

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

Please refer to Note 10 - Derivative Financial Instruments and to Note 11 - Fair Value Measurements in the 2018 Form 10-K for more information regarding the Company’s derivative instruments.

Proved and Unproved Oil and Gas Properties and Other Property and Equipment

Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique to measure the fair value of proved properties through the application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management.

Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. During the three months ended March 31, 2019, and 2018, the Company recorded $6.3 million and $5.6 million, respectively, in abandonment and impairment of unproved properties expense related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks.

Properties held for sale. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain on divestiture activity line item in the accompanying statements of operations.

There were $5.3 million of assets held for sale that were recorded at fair value less estimated costs to sell as of December 31, 2018. There were no assets held for sale as of March 31, 2019. For the three months ended March 31, 2018, write-downs to fair value less estimated costs to sell on assets held for sale totaled $24.1 million. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions above and in the 2018 Form 10-K for more information regarding the Company’s oil and gas properties held for sale.

Please refer to Note 1 – Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the 2018 Form 10-K for more information regarding the Company’s approach in determining fair value of its properties.

Long-Term Debt

The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of March 31, 2019, or December 31, 2018, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion.



	As of March 31, 2019				As of December 31, 2018
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(in thousands)
6.125% Senior Notes due 2022	$	476,796	$	477,988	$	476,796	$	452,336
5.0% Senior Notes due 2024	$	500,000	$	464,685	$	500,000	$	439,265
5.625% Senior Notes due 2025	$	500,000	$	464,820	$	500,000	$	436,460
6.75% Senior Notes due 2026	$	500,000	$	481,875	$	500,000	$	448,305
6.625% Senior Notes due 2027	$	500,000	$	476,205	$	500,000	$	442,500
1.50% Senior Convertible Notes due 2021	$	172,500	$	163,013	$	172,500	$	158,614

Note 12 - Leases

Effective January 1, 2019, the Company adopted Topic 842, which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of March 31, 2019, the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 will not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases.

As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance.

The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 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, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include:


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

•

Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which early termination options are reasonably certain to be exercised.

Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, well completion agreements, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately seven years. The weighted-average lease term remaining for these leases is 3.2 years. Certain leases also contain optional extension periods that allow for terms to be extended for up to an additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement.

Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to Note 1 – Summary of Significant Accounting Policies in the Company’s 2018 Form 10-K for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs.

For the three months ended March 31, 2019, total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were $175.3 million. This total does not reflect amounts that may be reimbursed by other third-parties in the normal course of business, such as non-operating working interest owners. Components of the Company’s total lease cost, whether capitalized or expensed, for the three months ended March 31, 2019, were as follows:



	For the Three Months Ended March 31, 2019
	(in thousands)
Operating lease cost	$	8,979
Short-term lease cost ⁽¹⁾	134,917
Variable lease cost ⁽²⁾	31,408
Total lease cost ⁽³⁾	$	175,304

____________________________________________

⁽¹⁾

Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.

⁽²⁾

Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs and completion crews, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.


⁽³⁾	Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.

Other information related to the Company’s leases for the three months ended March 31, 2019, was as follows:



	For the Three Months Ended March 31, 2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	9,134
Right-of-use assets obtained in exchange for new operating lease liabilities	$	12,191

Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of March 31, 2019, were as follows:



	As of March 31, 2019
	(in thousands)
2019 (remaining after March 31, 2019)	$	21,217
2020	16,384
2021	11,074
2022	5,123
2023	3,316
Thereafter	3,721
Total Lease payments	$	60,835
Less: Imputed interest ⁽¹⁾	(6,339		)
Total	$	54,496

____________________________________________


⁽¹⁾	The weighted-average discount rate used to determine the operating lease liability as of March 31, 2019 was 6.6 percent.

Amounts recorded on the Company’s accompanying balance sheets for operating leases as of March 31, 2019, were as follows:



	As of March 31, 2019
	(in thousands)
Other noncurrent assets	$	51,448

Other current liabilities	$	23,523
Other noncurrent liabilities	$	30,973

As of March 31, 2019, the Company had an additional long-term operating lease arrangement for a drilling rig that commenced service in April 2019 for approximately $7.8 million with a lease term of 14 months. This agreement is not reflected in the amounts above as the commencement date was subsequent to March 31, 2019.

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

The following discussion includes certain forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements at the end of this item for important information about these types of statements.

Overview of the Company

General Overview

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America, with operations currently focused in the state of Texas. Our strategic objective is to be a premier operator of top tier assets. We seek to maximize the value of our assets by applying industry leading technology and outstanding operational execution. Our portfolio is comprised of unconventional resource prospects with expanding prospective drilling opportunities, which we believe provides for long-term production and reserves growth. We are focused on generating strong full-cycle economic returns on our investments and maintaining a strong balance sheet.

Regional Overview

Our Permian region is comprised of approximately 80,000 net acres in the Midland Basin located in western Texas (“Midland Basin”). Operations in the Midland Basin are primarily focused on developing the Lower Spraberry and Wolfcamp A and B intervals on our RockStar acreage in Howard and Martin Counties, Texas, and Lower and Middle Spraberry and Wolfcamp A and B intervals on our Sweetie Peck acreage in Upton and Midland Counties, Texas. We are also actively evaluating and testing additional intervals within our RockStar position, including the Middle Spraberry, Wolfcamp D, and Dean formations.

Our South Texas & Gulf Coast region is primarily comprised of approximately 163,000 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are primarily focused on developing the Eagle Ford shale formation and testing additional intervals, including the Austin Chalk formation.

First Quarter 2019 Highlights and Outlook for the Remainder of 2019

We remain focused on maximizing the returns and increasing the value of our top tier investment opportunities across our Midland Basin and South Texas positions. We expect to do this through exploration, acquisitions, and further development optimization. These assets provide significant production growth potential and strong returns that we believe will increase internally generated cash flows, which will support our priorities of improving our credit metrics and maintaining strong financial flexibility.

Our capital program for 2019, excluding acquisitions, is expected to range from $1.00 billion to $1.07 billion. Our program is concentrated on developing our top tier assets in the Midland Basin and South Texas, with the majority of our 2019 capital expected to be allocated to our Midland Basin program. Planned drilling and completion activity in our South Texas program continues to be partially funded by a third-party as part of a joint development agreement, which was extended into 2019 to include 12 additional wells. We expect that all 12 of these wells will be completed in 2019. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on our 2019 capital program.

Financial and Operational Results. During the first quarter of 2019, we had the following financial and operational results:

•

Average net daily production for the three months ended March 31, 2019, was 118.7 MBOE, compared with 112.7 MBOE for the same period in 2018. The increase in total production was driven by our Midland Basin assets, which had a 34 percent increase in production volumes in the first quarter of 2019 compared to the same period in 2018. Average net daily production for the first quarter of 2018 also included 8.5 MBOE from our Rocky Mountain region, which we divested of in the second quarter of 2018. Please refer to Three-Month Overview of Selected Production and Financial Information, Including Trends below for additional discussion on production.

•

Net cash provided by operating activities was $118.5 million for the three months ended March 31, 2019, compared with $140.1 million for the same period in 2018. The decrease in net cash provided by operating activities for the three months ended March 31, 2019, was primarily the result of a 16 percent decrease in our realized price per BOE before the effects of derivative settlements, which led to an 11 percent decrease in oil, gas, and NGL production revenue. Partially offsetting the decrease was a realized settlement loss on derivatives of $5.0 million during the first quarter of 2019, compared to a realized settlement loss of $24.5 million during the same period in 2018. Please refer to Overview of Liquidity and Capital Resources below for additional discussion of our sources and uses of cash.

•

We recorded a net loss of $177.6 million, or $1.58 per diluted share, for the three months ended March 31, 2019, compared with net income of $317.4 million, or $2.81 per diluted share, for the same period in 2018. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2019, and 2018 below for additional discussion regarding the components of net income (loss) for each of the periods presented.

•

Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2019, was $186.5 million, compared with $210.2 million for the same period in 2018. The decrease in the first quarter of 2019 compared to the same period in 2018 was primarily the result of an 11 percent decrease in oil, gas, and NGL production revenue. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities.

Operational Activities. In our Midland Basin program, we averaged five drilling rigs and three completion crews during the first quarter of 2019. We ended the first quarter of 2019 with five drilling rigs and four completion crews, and added a sixth drilling rig in April 2019. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals. For the full year 2019, we expect to average six drilling rigs and three completion crews in the Midland Basin, and expect to allocate approximately 80 percent of our drilling and completion capital to our Midland Basin program.

During the first quarter of 2019, we completed several non-monetary acreage trades of primarily undeveloped properties in the Midland Basin, resulting in the exchange of approximately 2,000 net acres, with $65.8 million of carrying value attributed to the properties we surrendered. Acreage trades continue to increase our working interest in existing drilling units and are yielding an increasingly contiguous acreage position that will allow for longer lateral completions. There was no gain or loss recognized in connection with these trades.

In our South Texas program, we averaged two drilling rigs and two completion crews during the first quarter of 2019. Drilling and completion activities in South Texas continue to focus on developing the Eagle Ford shale and testing additional intervals, including the Austin Chalk formation. Certain drilling and completion activities in the northern portion of our South Texas acreage position continue to be partially funded by a third-party as part of a joint development agreement. For the full year 2019, we anticipate averaging one to two drilling rigs and one completion crew in South Texas and expect to allocate approximately 20 percent of our drilling and completion capital to this program.

The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three months ended March 31, 2019:



	Permian				South Texas & Gulf Coast				Total
	Gross		Net		Gross		Net		Gross		Net
Wells drilled but not completed at December 31, 2018	61		55		29		23		90		78
Wells drilled	31		28		8		7		39		35
Wells completed	(30	)	(27	)	(2	)	(2	)	(32	)	(29	)
Other ⁽¹⁾	—		—		(1	)	—		(1	)	—
Wells drilled but not completed at March 31, 2019	62		56		34		28		96		84

____________________________________________


⁽¹⁾	Includes adjustments related to normal business activities, including wells that were previously drilled but that we no longer intend to complete and working interest changes for existing drilled but not completed wells.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $322.0 million for the three months ended March 31, 2019, and were incurred in our Midland Basin and South Texas programs.

Production Results. The table below presents our production by product type for each of our operating regions for the three months ended March 31, 2019, and 2018:



	Permian				South Texas & Gulf Coast				Rocky Mountain ⁽¹⁾				Total
	Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,				Three Months Ended March 31,
	2019		2018		2019		2018		2019		2018		2019		2018
Production:
Oil (MMBbl)	4.5		3.3		0.3		0.4		—		0.6		4.8		4.3
Gas (Bcf)	6.9		5.6		17.0		18.7		—		0.9		23.9		25.2
NGLs (MMBbl)	—		—		1.9		1.6		—		—		1.9		1.7
Equivalent (MMBOE)	5.7		4.3		5.0		5.1		—		0.8		10.7		10.1
Avg. daily equivalents (MBOE/d)	63.3		47.3		55.5		56.9		—		8.5		118.7		112.7
Relative percentage	53	%	42	%	47	%	50	%	—	%	8	%	100	%	100	%

____________________________________________

Note: Amounts may not calculate due to rounding.


⁽¹⁾	We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.

For the three months ended March 31, 2019, production on an equivalent basis increased five percent compared with the same period in 2018. This increase in overall production volumes was driven by our Permian region, which had a 34 percent increase in production volumes for the three months ended March 31, 2019, compared with the same period in 2018. Increased production volumes from our Permian region were partially offset as a result of the divestiture of our remaining producing assets in the Rocky Mountain region in the first half of 2018.

Please refer to Three-Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2019, and 2018 below for additional discussion on production.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the first quarter of 2019 as well as the fourth and first quarters of 2018:



	For the Three Months Ended
	March 31, 2019			December 31, 2018			March 31, 2018
Oil (per Bbl):
Average NYMEX contract monthly price	$	54.90		$	58.81		$	62.87
Realized price, before the effect of derivative settlements	$	49.47		$	49.29		$	61.25
Effect of oil derivative settlements	$	(0.28	)	$	(1.35	)	$	(4.86	)
Gas:
Average NYMEX monthly settle price (per MMBtu)	$	3.15		$	3.64		$	3.00
Realized price, before the effect of derivative settlements (per Mcf)	$	2.73		$	3.71		$	3.14
Effect of gas derivative settlements (per Mcf)	$	(0.18	)	$	(0.70	)	$	0.25
NGLs (per Bbl):
Average OPIS price ⁽¹⁾	$	26.28		$	29.91		$	30.87
Realized price, before the effect of derivative settlements	$	19.39		$	24.01		$	25.53
Effect of NGL derivative settlements	$	0.28		$	(4.65	)	$	(6.09	)

____________________________________________


⁽¹⁾	Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

We expect future prices for oil and NGLs to continue to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. We expect oil prices to remain volatile due to uncertainty in global supply and demand. We expect NGL prices to continue to benefit from increased demand from export and petrochemical markets, but these benefits could be partially or completely offset by increased drilling activity in areas containing liquid-rich gas capable of yielding additional NGL volumes.

We expect gas prices to remain near current levels in the near term due to the abundance of supply relative to demand. Demand from increased liquefied natural gas (“LNG”) exports and gas exports to Mexico are expected to help alleviate oversupply.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of April 25, 2019, and March 31, 2019:



	As of April 25, 2019		As of March 31, 2019
NYMEX WTI oil (per Bbl)	$	64.37	$	60.21
NYMEX Henry Hub gas (per MMBtu)	$	2.70	$	2.85
OPIS NGLs (per Bbl)	$	27.46	$	25.81

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives. The amount of our production covered by derivative instruments is driven by the amount of debt on our balance sheet, the magnitude of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity contracts. With our current derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and location differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil and gas production.

Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended March 31, 2019, and the immediately preceding three quarters. A detailed discussion follows.



	For the Three Months Ended
	March 31,			December 31,		September 30,			June 30,
	2019			2018		2018			2018
	(in millions)
Production (MMBOE)	10.7			11.3		12.0			10.5
Oil, gas, and NGL production revenue	$	340.5		$	392.5	$	458.4		$	402.6
Oil, gas, and NGL production expense	$	121.3		$	121.5	$	127.6		$	117.4
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	177.7		$	182.0	$	201.1		$	151.8
Exploration	$	11.3		$	14.3	$	13.1		$	14.1
General and administrative	$	32.1		$	30.4	$	29.5		$	28.9
Net income (loss)	$	(177.6	)	$	309.7	$	(135.9	)	$	17.2

____________________________________________

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics



	For the Three Months Ended
	March 31,			December 31,			September 30,			June 30,
	2019			2018			2018			2018
Average net daily production equivalent (MBOE per day)	118.7			122.8			130.2			115.2
Lease operating expense (per BOE)	$	5.20		$	4.98		$	4.41		$	4.66
Transportation costs (per BOE)	$	4.08		$	4.19		$	4.20		$	4.47
Production taxes as a percent of oil, gas, and NGL production revenue	4.1		%	3.4		%	4.1		%	4.3		%
Ad valorem tax expense (per BOE)	$	0.76		$	0.39		$	0.45		$	0.41
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	16.63		$	16.10		$	16.78		$	14.48
General and administrative (per BOE)	$	3.00		$	2.69		$	2.46		$	2.76

____________________________________________

Note: Amounts may not calculate due to rounding.

Three-Month Overview of Selected Production and Financial Information, Including Trends



	For the Three Months Ended March 31,				Amount Change Between Periods		Percent Change Between Periods
	2019		2018		Amount Change Between Periods		Percent Change Between Periods
Net production volumes:⁽¹⁾
Oil (MMBbl)	4.8		4.3		0.6		13	%
Gas (Bcf)	23.9		25.2		(1.3	)	(5	)%
NGLs (MMBbl)	1.9		1.7		0.2		12	%
Equivalent (MMBOE)	10.7		10.1		0.6		5	%
Average net daily production:⁽¹⁾
Oil (MBbl per day)	53.7		47.4		6.3		13	%
Gas (MMcf per day)	265.5		280.2		(14.8	)	(5	)%
NGLs (MBbl per day)	20.8		18.6		2.2		12	%
Equivalent (MBOE per day)	118.7		112.7		6.0		5	%
Oil, gas, and NGL production revenue (in millions): ⁽¹⁾
Oil production revenue	$	239.1	$	261.1