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, 2017


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

For the transition period from ___________ to ___________

Commission File Number 001-31539

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 and posted on its corporate Web site, 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 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 (Do not check if a smaller reporting company)		Smaller reporting company o

		Emerging growth company o

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

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

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 26, 2017, the registrant had 111,258,225 shares of common stock, $0.01 par value, outstanding.

SM ENERGY COMPANY

TABLE OF CONTENTS



Part I.	FINANCIAL INFORMATION		PAGE

	Item 1.	Financial Statements (Unaudited)

		Condensed Consolidated Balance Sheets March 31, 2017, and December 31, 2016	3

		Condensed Consolidated Statements of Operations Three Months Ended March 31, 2017, and 2016	4

		Condensed Consolidated Statements of Comprehensive Income (Loss) Three Months Ended March 31, 2017, and 2016	5

		Condensed Consolidated Statement of Stockholders’ Equity Three Months Ended March 31, 2017	6

		Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 2017, and 2016	7

		Notes to Condensed Consolidated Financial Statements	9

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk (included within the content of Item 2)	44

	Item 4.	Controls and Procedures	44

Part II.	OTHER INFORMATION

	Item 1.	Legal Proceedings	45

	Item 1A.	Risk Factors	45

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

	Item 6.	Exhibits	47

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share amounts)



	March 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	659,147		$	9,372
Accounts receivable	108,368			151,950
Derivative asset	73,978			54,521
Prepaid expenses and other	8,053			8,799
Total current assets	849,546			224,642

Property and equipment (successful efforts method):
Proved oil and gas properties	4,803,068			5,700,418
Less - accumulated depletion, depreciation, and amortization	(2,589,204		)	(2,836,532		)
Unproved oil and gas properties	2,483,601			2,471,947
Wells in progress	186,707			235,147
Oil and gas properties held for sale, net	455,943			372,621
Other property and equipment, net of accumulated depreciation of $44,662 and $42,882, respectively	110,005			137,753
Total property and equipment, net	5,450,120			6,081,354

Noncurrent assets:
Derivative asset	84,195			67,575
Other noncurrent assets	15,847			19,940
Total other noncurrent assets	100,042			87,515
Total Assets	$	6,399,708		$	6,393,511

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	299,676		$	299,708
Derivative liability	53,809			115,464
Total current liabilities	353,485			415,172

Noncurrent liabilities:
Revolving credit facility	—			—
Senior Notes, net of unamortized deferred financing costs	2,765,714			2,766,719
Senior Convertible Notes, net of unamortized discount and deferred financing costs	132,889			130,856
Asset retirement obligation	83,160			96,134
Asset retirement obligation associated with oil and gas properties held for sale	16,056			26,241
Deferred income taxes	304,331			315,672
Derivative liability	81,306			98,340
Other noncurrent liabilities	47,252			47,244
Total noncurrent liabilities	3,430,708			3,481,206

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,258,225 and 111,257,500 shares, respectively	1,113			1,113
Additional paid-in capital	1,723,010			1,716,556
Retained earnings	906,515			794,020
Accumulated other comprehensive loss	(15,123		)	(14,556		)
Total stockholders’ equity	2,615,515			2,497,133
Total Liabilities and Stockholders’ Equity	$	6,399,708		$	6,393,511

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 amounts)



	For the Three Months Ended March 31,
	2017			2016
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	333,198		$	211,823
Net gain (loss) on divestiture activity	37,463			(69,021		)
Other operating revenues	2,077			274
Total operating revenues and other income	372,738			143,076

Operating expenses:
Oil, gas, and NGL production expense	138,046			144,543
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	137,812			214,207
Exploration	11,978			15,273
Impairment of proved properties	—			269,785
Abandonment and impairment of unproved properties	—			2,311
General and administrative	29,224			32,238
Net derivative gain	(114,774		)	(14,228		)
Other operating expenses	4,859			5,672
Total operating expenses	207,145			669,801

Income (loss) from operations	165,593			(526,725		)

Non-operating income (expense):
Interest expense	(46,953		)	(31,088		)
Gain (loss) on extinguishment of debt	(35		)	15,722
Other, net	335			6

Income (loss) before income taxes	118,940			(542,085		)
Income tax (expense) benefit	(44,506		)	194,875

Net income (loss)	$	74,434		$	(347,210	)

Basic weighted-average common shares outstanding	111,258			68,077
Diluted weighted-average common shares outstanding	111,329			68,077
Basic net income (loss) per common share	$	0.67		$	(5.10	)
Diluted net income (loss) per common share	$	0.67		$	(5.10	)
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,
	For the Three Months Ended March 31,
	2017			2016
Net income (loss)	$	74,434		$	(347,210	)
Other comprehensive loss, net of tax:
Pension liability adjustment	(567		)	(236		)
Total other comprehensive loss, net of tax	(567		)	(236		)
Total comprehensive income (loss)	$	73,867		$	(347,446	)

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (UNAUDITED)

(in thousands, except share amounts)



				Additional Paid-in Capital						Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
	Common Stock						Retained Earnings
	Shares	Amount					Retained Earnings
Balances, December 31, 2016	111,257,500	$	1,113	$	1,716,556		$	794,020		$	(14,556	)	$	2,497,133
Net income	—	—		—			74,434			—			74,434
Other comprehensive loss	—	—		—			—			(567		)	(567		)
Dividends declared, $ 0.05 per share	—	—		—			(5,563		)	—			(5,563		)
Issuance of common stock upon vesting of restricted stock units, net of shares used for tax withholdings	725	—		(11		)	—			—			(11		)
Stock-based compensation expense	—	—		5,455			—			—			5,455
Cumulative effect of accounting change ⁽¹⁾	—	—		1,108			43,624			—			44,732
Other	—	—		(98		)	—			—			(98		)
Balances, March 31, 2017	111,258,225	$	1,113	$	1,723,010		$	906,515		$	(15,123	)	$	2,615,515

____________________________________________


⁽¹⁾	Refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards.

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,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	74,434		$	(347,210	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (gain) loss on divestiture activity	(37,463		)	69,021
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	137,812			214,207
Impairment of proved properties	—			269,785
Abandonment and impairment of unproved properties	—			2,311
Stock-based compensation expense	5,455			6,868
Net derivative gain	(114,774		)	(14,228		)
Derivative settlement gain	7			147,028
Amortization of discount and deferred financing costs	4,946			(920		)
Non-cash (gain) loss on extinguishment of debt, net	22			(15,722		)
Deferred income taxes	33,225			(195,039		)
Plugging and abandonment	(1,191		)	(604		)
Other, net	4,567			(1,151		)
Changes in current assets and liabilities:
Accounts receivable	30,407			26,922
Prepaid expenses and other	178			4,984
Accounts payable and accrued expenses	(5,497		)	(52,294		)
Accrued derivative settlements	2,838			4,318
Net cash provided by operating activities	134,966			118,276

Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	744,333			1,206
Capital expenditures	(154,401		)	(176,370		)
Acquisition of proved and unproved oil and gas properties	(75,105		)	(15,044		)
Other, net	2,486			885
Net cash provided by (used in) investing activities	517,313			(189,323		)

Cash flows from financing activities:
Proceeds from credit facility	397,500			317,000
Repayment of credit facility	(397,500		)	(226,000		)
Cash paid to repurchase Senior Notes	(2,344		)	(19,917		)
Other, net	(160		)	(3		)
Net cash provided by (used in) financing activities	(2,504		)	71,080

Net change in cash and cash equivalents	649,775			33
Cash and cash equivalents at beginning of period	9,372			18
Cash and cash equivalents at end of period	$	659,147		$	51

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) (Continued)

(in thousands)

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



	For the Three Months Ended March 31,
	2017			2016
Supplemental Cash Flow Information:
Operating Activities:
Cash paid for interest, net of capitalized interest	$	(42,872	)	$	(24,453	)
Net cash refunded for income taxes	$	15		$	4,689
Investing Activities:
Changes in capital expenditure accruals and other	$	27,214		$	20,643

Supplemental Non-Cash Investing Activities:
Fair value of properties exchanged	$	24,544		$	733

Supplemental Non-Cash Financing Activities:
Dividends declared, but not paid	$	5,563		$	3,404

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 - The Company and Business

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.

Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and 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 consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 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, 2017, and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in its 2016 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the 2016 Form 10-K.

Recently Issued Accounting Standards

Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based payment arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the various applicable amendments as summarized below:

•

ASU 2016-09 requires all future excess tax benefits and deficiencies related to share-based payment arrangements to be recognized as income tax benefit or expense as discrete events in the period in which they occur. The Company adopted this amendment under a modified retrospective transition method, which resulted in a $44.3 million cumulative-effect adjustment to retained earnings as of January 1, 2017, with a corresponding deferred tax asset recorded for previously unrecognized excess tax benefits. Consequentially, the Company’s diluted share count calculation changed prospectively beginning in the period ended March 31, 2017. Any future excess tax benefits and deficiencies are now being excluded from the assumed proceeds calculated under the treasury stock method for share-based payment arrangements. Lastly, this amendment requires companies to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity, which the Company applied prospectively beginning in the period ended March 31, 2017. There are no periods presented that would require reclassification of cash flows had the Company elected to apply this amendment retrospectively.

•

ASU 2016-09 allows entities to elect whether to account for forfeitures of share-based payment awards by recognizing forfeitures of awards as they occur or by estimating the number of awards expected to be forfeited. This amendment is to be applied using a modified retrospective transition method. Upon adopting ASU 2016-09, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur effective January 1, 2017. This change in accounting policy resulted in a net $0.7 million cumulative-effect adjustment to retained earnings as of January 1, 2017, to adjust for actual forfeitures versus the previously estimated forfeiture rate. The corresponding impacts were an increase in additional paid-in capital and a decrease in deferred tax assets.

•

ASU 2016-09 allows entities to withhold an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction, without triggering liability classification of the award; however, the Company does not plan on changing its current withholding process as outlined in its share-based award agreements. Related to this amendment, ASU 2016-09 requires entities to present cash payments made to tax authorities on the employees’ behalf for withheld tax shares as a financing activity on the statement of cash flows retrospectively. However, this presentation is already consistent with the Company’s historical and current cash flow presentation of net share settlement from issuance of stock awards, and therefore, there was no impact from this amendment.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) for the recognition of revenue from contracts with customers. Several additional related ASUs have been issued. The Company has established a cross-functional implementation team that is currently evaluating the provisions of each of these standards, analyzing their impact on the Company’s contract portfolio, reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements of these standards to the Company’s revenue contracts, and assessing their potential impact on the Company’s financial statements and disclosures. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which changes the accounting for leases. The Company is currently establishing a cross-functional implementation team to analyze the impact of the standard on the Company’s contract portfolio by reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard. In addition, the Company is working to identify appropriate changes to the Company’s business processes, systems, and controls to support recognition and disclosure under the new standard. The Company currently plans to adopt the guidance on the effective date of January 1, 2019.

In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). This ASU is intended to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost by providing additional guidance on the presentation of net benefit cost on the income statement and on the components eligible for capitalization in assets. As outlined in ASU 2017-07, certain amendments are to be applied using a retrospective method while others are required to be applied using a prospective method. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted as outlined in ASU 2017-07. The Company is currently evaluating the provisions of this guidance and assessing the potential impact on the Company’s financial statements and disclosures and does not intend to early adopt this guidance.

Other than as disclosed above or in the 2016 Form 10-K, there are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and related disclosures that have been issued but not yet adopted by the Company as of March 31, 2017, and through the filing of this report.

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

Divestitures

On March 10, 2017, the Company divested its outside-operated Eagle Ford shale assets, including ownership interest in related midstream assets, for total cash received at closing, net of commissions (referred to throughout this report as “net divestiture proceeds”), of $747.4 million, subject to post-closing adjustments, and recorded a net estimated gain of $398.1 million for the three months ended March 31, 2017. These assets were classified as held for sale as of December 31, 2016.

The following table presents income (loss) before income taxes of the outside-operated Eagle Ford shale assets sold for the three months ended March 31, 2017, and 2016. This divestiture is considered a disposal of a significant asset group.



	For the Three Months Ended March 31,
	2017		2016
	(in thousands)
Income (loss) before income taxes ⁽¹⁾	$	24,324	$	(286,399	)

____________________________________________


⁽¹⁾	Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes included impairment of proved properties expense of approximately $269.6 million for the three months ended March 31, 2016.

Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent changes to the fair value less estimated costs to sell impact the measurement of assets held for sale, with any gain or loss reflected in the net gain (loss) on divestiture activity line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).

As of March 31, 2017, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $455.9 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consisted primarily of the Company’s remaining Williston Basin assets in Divide County, North Dakota (referred to as “Divide County” throughout this report). A corresponding asset retirement obligation liability of $16.1 million was separately presented. The Company expects to close the divestiture of these assets during the second quarter of 2017. These assets were written down by $359.6 million to reflect fair value less estimated costs to sell upon classification as held for sale during the three months ended March 31, 2017.

The following table presents loss before income taxes of the Company’s Divide County assets held for sale for the three months ended March 31, 2017, and 2016:



	For the Three Months Ended March 31,
	2017			2016
	(in thousands)
Loss before income taxes ⁽¹⁾	$	(335,561	)	$	(16,813	)

____________________________________________

⁽¹⁾

Loss before income taxes reflects oil, gas, and NGL production revenue less oil, gas, and NGL production expense and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, loss before income taxes for the three months ended March 31, 2017, included the $359.6 million write-down on these assets held for sale as discussed above, and loss before income taxes for the three months ended March 31, 2016, included $1.6 million of unproved property impairments.

Acquisitions

During the first quarter of 2017, the Company acquired approximately 2,900 net acres of proved and unproved properties in the Midland Basin for $59.6 million, subject to post-closing adjustments. Under authoritative accounting guidance, this transaction was considered an asset acquisition, and therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired.

The Company finalized the 2016 acquisition of Midland Basin properties from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”) during the first quarter of 2017 by paying an additional $7.4 million of cash consideration, resulting in total consideration of $998.4 million paid after final closing adjustments. There were no material changes to the recorded basis of the proved and unproved properties acquired as a result of the final settlement.

Also, during the first quarter of 2017, and subsequent to March 31, 2017, the Company completed trades of properties, primarily unproved, in Howard and Martin Counties, Texas resulting in the Company acquiring approximately 3,020 net acres in exchange for 2,310 net acres. There was no cash consideration for the trade that was completed during the three months ended March 31, 2017, and this trade was recorded at the fair value of the assets surrendered with no gain or loss recognized.

Note 4 - Income Taxes

The income tax (expense) benefit recorded for the three months ended March 31, 2017, and 2016, 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, changes in valuation allowances, excess tax benefits and deficiencies from share-based payment awards, 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, 2017, and 2016, consisted of the following:



	For the Three Months Ended March 31,
	2017			2016
	(in thousands)
Current portion of income tax (expense) benefit:
Federal	$	(7,439	)	$	—
State	(3,842		)	(164		)
Deferred portion of income tax (expense) benefit	(33,225		)	195,039
Income tax (expense) benefit	$	(44,506	)	$	194,875
Effective tax rate	37.4		%	35.9		%

On a year-to-date basis, a change in the Company’s effective tax rate between reported periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income or loss from Company activities among multiple state tax jurisdictions. Cumulative effects of state tax rate changes are reflected in the period that legislation is enacted. As a result of adopting ASU 2016-09, excess tax benefits and deficiencies from share-based payment awards are expected to impact the Company’s effective tax rate between periods. Please refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards.

The change in the current portion of income tax expense relates to the effect of anticipated utilization of carryover net operating losses, deferred expenses, and carryover tax credits. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013, with the exception of its 2003 tax year.

Note 5 - Long-Term Debt

Credit Facility

The Company’s Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019.

On March 31, 2017, the Company entered into a Ninth Amendment to the Credit Agreement (the “Ninth Amendment”) with its lenders. Pursuant to the Ninth Amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were reduced to $925 million. This expected reduction was primarily due to the sale of the Company’s outside-operated Eagle Ford shale assets in the first quarter of 2017 and the decrease in the value of the Company’s proved reserves at December 31, 2016. The borrowing base redetermination process considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report and (b) commodity derivative contracts, each as determined by the Company’s lender group. Additionally, the Ninth Amendment modified the Credit Agreement to allow the Company to enter into derivative contracts for an increased percentage of projected production volumes. As a result of the reduction to the Company’s borrowing base and aggregate lender commitments, the Company recorded approximately $1.1 million of expense related to the acceleration of unamortized deferred financing costs for the three months ended March 31, 2017. The next scheduled redetermination date is October 1, 2017.

The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. Financial covenants under the Credit Agreement require, as of the last day of each of the Company’s fiscal quarters, the Company’s (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0. The Company was in compliance with all financial and non-financial covenants under the Credit Agreement as of March 31, 2017, 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 and presented in Note 5 – Long-Term Debt to the Company’s consolidated financial statements in its 2016 Form 10-K. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table, and Alternate Base Rate and swingline loans accrue interest at the prime rate, plus the applicable margin from the utilization table. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount and are included in interest expense in 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 26, 2017, March 31, 2017, and December 31, 2016:



	As of April 26, 2017		As of March 31, 2017		As of December 31, 2016
	(in thousands)
Credit facility balance ⁽¹⁾	$	—	$	—	$	—
Letters of credit ⁽²⁾	200		200		200
Available borrowing capacity	924,800		924,800		1,164,800
Total aggregate lender commitment amount	$	925,000	$	925,000	$	1,165,000

____________________________________________


⁽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 $4.3 million and $5.9 million as of March 31, 2017, and December 31, 2016, respectively.


⁽²⁾	Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

Senior Notes

The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of March 31, 2017, and December 31, 2016, consisted of the following:



	As of March 31, 2017						As of December 31, 2016
	Principal Amount		Unamortized Deferred Financing Costs		Senior Notes, Net of Unamortized Deferred Financing Costs		Principal Amount		Unamortized Deferred Financing Costs		Senior Notes, Net of Unamortized Deferred Financing Costs
	(in thousands)
6.50% Senior Notes due 2021 ^{(1) (2)}	$	344,611	$	3,176	$	341,435	$	346,955	$	3,372	$	343,583
6.125% Senior Notes due 2022 ⁽²⁾	561,796		6,684		555,112		561,796		6,979		554,817
6.50% Senior Notes due 2023 ⁽²⁾	394,985		4,254		390,731		394,985		4,436		390,549
5.0% Senior Notes due 2024	500,000		6,302		493,698		500,000		6,533		493,467
5.625% Senior Notes due 2025	500,000		7,393		492,607		500,000		7,619		492,381
6.75% Senior Notes due 2026	500,000		7,869		492,131		500,000		8,078		491,922
Total	$	2,801,392	$	35,678	$	2,765,714	$	2,803,736	$	37,017	$	2,766,719

____________________________________________


⁽¹⁾	During the first quarter of 2017, the Company repurchased a total of $2.3 million in aggregate principal amount of 6.50% Senior Notes due 2021 in open market transactions at a slight premium. The Company canceled all of these repurchased Senior Notes upon cash settlement.

⁽²⁾

During the first quarter of 2016, the Company repurchased a total of $46.3 million in aggregate principal amount of certain of its Senior Notes in open market transactions for a settlement amount of $29.9 million, excluding interest, of which $19.9 million was paid during the three months ended March 31, 2016, with the remaining $10.0 million settlement amount being accrued at March 31, 2016, and paid in the second quarter of 2016. The Company recorded a net gain on extinguishment of debt of approximately $15.7 million for the three months ended March 31, 2016. This amount includes a gain of approximately $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. The Company canceled all of these repurchased Senior Notes upon cash settlement.

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 covenants as of March 31, 2017, 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

On August 12, 2016, the Company issued $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.

The Senior Convertible Notes mature on July 1, 2021, unless earlier converted. Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under certain circumstances as outlined in the indenture governing the Senior Convertible Notes and in Note 5 – Long-Term Debt to the Company’s consolidated financial statements in its 2016 Form 10-K. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment.

The Company has initially elected a net-settlement method to satisfy its conversion obligation. Under the net-settlement method, upon conversion, the Senior Convertible Notes will be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Senior Convertible Notes were not convertible at the option of holders as of March 31, 2017, 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, 2017, did not exceed the principal amount.

At issuance, the Company recorded $132.3 million as the initial carrying amount of the debt component, which approximated its fair value at issuance, and was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25 percent. The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The debt discount and debt-related issuance costs are amortized to the carrying 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 $2.4 million for the three months ended March 31, 2017.

The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets as of March 31, 2017, and December 31, 2016, consisted of the following:



	As of March 31, 2017			As of December 31, 2016
	(in thousands)
Principal amount of Senior Convertible Notes	$	172,500		$	172,500
Unamortized debt discount	(35,713		)	(37,513		)
Unamortized deferred financing costs	(3,898		)	(4,131		)
Net carrying amount	$	132,889		$	130,856

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of March 31, 2017, and through the filing of this report.

Capped Call Transactions

In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The capped call transactions are generally expected to reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call transactions, there could be dilution or there would not be an offset of such potential cash payments.

Note 6 - Commitments and Contingencies

Commitments

During the first quarter of 2017, the Company completed the divestiture of its outside-operated Eagle Ford shale assets. Upon closing of the sale, the Company is no longer subject to gathering, processing, and transportation throughput commitments totaling 514 Bcf of natural gas, 52 MMBbl of oil, and 13 MMBbl of NGLs, or $501.9 million of the potential undiscounted deficiency payments as of December 31, 2016.

As of March 31, 2017, the Company had total gathering, processing, and transportation throughput commitments with various third parties that require delivery of a minimum amount of 915 Bcf of natural gas, 17 MMBbl of crude oil, and 25 MMBbl of water through 2028. If the Company delivers no product, the aggregate undiscounted deficiency payments total approximately $458.8 million. As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to its remaining gathering, processing, and transportation throughput commitments.

Additionally, the Company entered into drilling rig contracts during the first quarter of 2017, and subsequent to March 31, 2017. As of the filing of this report, the Company’s total drilling rig commitment was $30.1 million; however, if the Company terminated these rig contracts early, penalties of $19.0 million would be incurred instead.

There were no other material changes in commitments during the first quarter of 2017. Please refer to Note 6 - Commitments and Contingencies in the Company’s 2016 Form 10-K for additional discussion of the Company’s commitments.

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 expected results of any pending litigation and claims will not 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 Under the Equity Incentive Compensation Plan

The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0% to 200% of the number of PSUs awarded and is determined based on certain performance criteria over a three-year measurement period. The performance criteria for PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. For the three months ended March 31, 2017, and 2016, total compensation expense recorded for PSUs was $2.5 million and $2.9 million, respectively, within general and administrative and exploration expense. As of March 31, 2017, there was $14.2 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2019. There have been no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2017.

Restricted Stock Units Under the Equity Incentive Compensation Plan

The Company grants restricted stock units (“RSUs”) as part of its long-term equity 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. For the three months ended March 31, 2017, and 2016, total compensation expense recorded for RSUs was $2.5 million and $3.2 million, respectively, within general and administrative expense and exploration expense. As of March 31, 2017, there was $12.9 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2019. There have been no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2017.

Note 8 - Pension Benefits

Pension Plans

The Company has a non-contributory defined benefit pension plan covering substantially all of its employees who joined the Company prior to January 1, 2015, and who meet age and service requirements (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 December 31, 2015. Employees participating in the Pension Plans as of December 31, 2015, continue to earn benefits.

Components of Net Periodic Benefit Cost for the Pension Plans

The following table presents the components of the net periodic benefit cost for the Pension Plans:



	For the Three Months Ended March 31,
	2017			2016
	(in thousands)
Service cost	$	2,050		$	1,987
Interest cost	727			624
Expected return on plan assets that reduces periodic pension cost	(559		)	(545		)
Amortization of prior service cost	4			4
Amortization of net actuarial loss	396			372
Net periodic benefit cost	$	2,618		$	2,442

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.

Contributions

The Company contributed $3.0 million to the Qualified Pension Plan during the three months ended March 31, 2017.

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 adjusted 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 of unvested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method.

PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs.

On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which allows the Company to settle the principal amount of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. However, the Company has not made this a formal legal irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business conditions warrant. 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, 2017, and therefore, had no dilutive impact. In connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions are not reflected in diluted net income per share, nor will they ever be, as they are anti-dilutive. Please refer to Note 5 - Long-Term Debt for additional discussion.

When the Company recognizes a loss from continuing operations, as was the case for three months ended March 31, 2016, 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,
	2017	2016
	(in thousands)
Dilutive	71	—
Anti-dilutive	—	49

The following table sets forth the calculations of basic and diluted earnings per share:



	For the Three Months Ended March 31,
	2017		2016
	(in thousands, except per share amounts)
Net income (loss)	$	74,434	$	(347,210	)
Basic weighted-average common shares outstanding	111,258		68,077
Add: dilutive effect of unvested RSUs and contingent PSUs	71		—
Add: dilutive effect of 1.50% Senior Convertible Notes	—		—
Diluted weighted-average common shares outstanding	111,329		68,077
Basic net income (loss) per common share	$	0.67	$	(5.10	)
Diluted net income (loss) per common share	$	0.67	$	(5.10	)

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, 2017, all derivative counterparties were members of the Company’s credit facility lender group and all contracts were entered into for other-than-trading purposes. The Company’s derivative contracts consist of swap and collar arrangements for oil, gas, and NGLs. 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.

As of March 31, 2017, the Company had commodity derivative contracts outstanding as summarized in the tables below.

Oil Swaps



Contract Period	NYMEX WTI Volumes	Weighted-Average Contract Price
	(MBbls)	(per Bbl)
Second quarter 2017	1,444	$	46.44
Third quarter 2017	1,340	$	46.66
Fourth quarter 2017	1,254	$	46.35
Total	4,038

Oil Collars



Contract Period	NYMEX WTI Volumes	Weighted- Average Floor Price		Weighted- Average Ceiling Price
	(MBbls)	(per Bbl)		(per Bbl)
Second quarter 2017	636	$	45.00	$	54.10
Third quarter 2017	583	$	45.00	$	54.05
Fourth quarter 2017	540	$	45.00	$	54.01
2018	3,343	$	50.00	$	58.55
2019	2,660	$	50.00	$	59.31
Total	7,762

Oil Basis Swaps



Contract Period	Midland-Cushing Volumes	Weighted-Average Contract Price ⁽¹⁾
	(MBbls)	(per Bbl)
2018	2,080	$	(1.27	)
2019	1,588	$	(1.45	)
Total	3,668

____________________________________________


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

Natural Gas Swaps



Contract Period	Sold Volumes	Weighted-Average Contract Price		Purchased Volumes ⁽¹⁾		Weighted- Average Contract Price		Net Volumes
	(BBtu)	(per MMBtu)		(BBtu)		(per MMBtu)		(BBtu)
Second quarter 2017	26,205	$	3.98	—		$	—	26,205
Third quarter 2017	23,657	$	4.01	—		$	—	23,657
Fourth quarter 2017	22,001	$	3.98	—		$	—	22,001
2018	75,778	$	3.54	(30,606	)	$	4.27	45,172
2019	32,016	$	4.02	(24,415	)	$	4.34	7,601
Total ⁽²⁾	179,657			(55,021	)			124,636

____________________________________________

⁽¹⁾

During 2016, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No other cash or other consideration was included as part of the restructuring.


⁽²⁾	Total net volumes of natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (95%), and IF NNG Ventura (3%).

NGL Swaps



	OPIS Purity Ethane 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
	(MBbls)	(per Bbl)		(MBbls)	(per Bbl)		(MBbls)	(per Bbl)		(MBbls)	(per Bbl)		(MBbls)	(per Bbl)
Second quarter 2017	787	$	8.86	634	$	21.90	182	$	32.53	157	$	33.38	249	$	48.47
Third quarter 2017	736	$	9.14	588	$	21.91	163	$	32.42	140	$	33.28	222	$	48.43
Fourth quarter 2017	692	$	9.10	550	$	21.91	149	$	32.34	128	$	33.23	203	$	48.41
2018	2,434	$	10.18	1,442	$	22.86	138	$	35.41	119	$	35.44	189	$	49.40
2019	2,176	$	11.95	—	$	—	—	$	—	—	$	—	—	$	—
2020	539	$	11.13	—	$	—	—	$	—	—	$	—	—	$	—
Total	7,364			3,214			632			544			863

Summary of Oil, Gas, and NGL Derivative Contracts Entered Into Subsequent to March 31, 2017

Subsequent to March 31, 2017, and through April 26, 2017, the Company entered into various derivative commodity contracts as summarized in the tables below.

Oil Collars



Contract Period	NYMEX WTI Volumes	Weighted- Average Floor Price		Weighted- Average Ceiling Price
	(MBbls)	(per Bbl)		(per Bbl)
Fourth quarter 2017	546	$	50.00	$	58.08
2018	1,687	$	50.00	$	57.12
2019	468	$	50.00	$	56.20
Total	2,701

Oil Basis Swaps



Contract Period	Midland-Cushing Volumes	Weighted-Average Contract Price ⁽¹⁾
	(MBbls)	(per Bbl)
Third quarter 2017	566	$	(1.62	)
Fourth quarter 2017	1,403	$	(1.55	)
2018	3,584	$	(1.50	)
2019	2,375	$	(1.45	)
Total	7,928

____________________________________________


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

Natural Gas Swaps



Contract Period	IF HSC Volumes	Weighted-Average Contract Price
	(BBtu)	(per MMBtu)
2018	17,236	$	2.87
2019	9,378	$	2.88
Total	26,614

NGL Swaps



	OPIS Purity Ethane 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
	(MBbls)	(per Bbl)		(MBbls)	(per Bbl)		(MBbls)	(per Bbl)		(MBbls)	(per Bbl)		(MBbls)	(per Bbl)
Second quarter 2017	105	$	10.97	—	$	—	—	$	—	—	$	—	—	$	—
Third quarter 2017	170	$	10.98	—	$	—	—	$	—	—	$	—	—	$	—
Fourth quarter 2017	274	$	11.04	—	$	—	—	$	—	—	$	—	—	$	—
2018	1,157	$	12.23	345	$	26.04	87	$	31.71	69	$	30.35	116	$	47.36
Total	1,706			345			87			69			116

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 fair value of the commodity derivative contracts was a net asset of $23.1 million as of March 31, 2017, and a net liability of $91.7 million as of December 31, 2016.

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:



	As of March 31, 2017
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Commodity contracts	Current assets	$	73,978	Current liabilities	$	53,809
Commodity contracts	Noncurrent assets	84,195		Noncurrent liabilities	81,306
Derivatives not designated as hedging instruments		$	158,173		$	135,115



	As of December 31, 2016
	Derivative Assets			Derivative Liabilities
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in thousands)
Commodity contracts	Current assets	$	54,521	Current liabilities	$	115,464
Commodity contracts	Noncurrent assets	67,575		Noncurrent liabilities	98,340
Derivatives not designated as hedging instruments		$	122,096		$	213,804

Offsetting of Derivative Assets and Liabilities

As of March 31, 2017, and December 31, 2016, 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 derivative contracts:



	Derivative Assets						Derivative Liabilities
	As of						As of
Offsetting of Derivative Assets and Liabilities	March 31, 2017			December 31, 2016			March 31, 2017			December 31, 2016
	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	158,173		$	122,096		$	(135,115	)	$	(213,804	)
Amounts not offset in the accompanying balance sheets	(88,952		)	(118,080		)	88,952			118,080
Net amounts	$	69,221		$	4,016		$	(46,163	)	$	(95,724	)

The following table summarizes the components of the net derivative gain presented in the accompanying statements of operations:



	For the Three Months Ended March 31,
	2017			2016
	(in thousands)
Derivative settlement (gain) loss:
Oil contracts	$	9,084		$	(99,992	)
Gas contracts	(17,506		)	(41,053		)
NGL contracts	8,415			(5,983		)
Total derivative settlement gain	$	(7	)	$	(147,028	)

Total net derivative (gain) loss:
Oil contracts	$	(49,590	)	$	(10,432	)
Gas contracts	(44,468		)	(24,023		)
NGL contracts	(20,716		)	20,227
Total net derivative gain	$	(114,774	)	$	(14,228	)

Credit Related Contingent Features

As of March 31, 2017, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. Under the Credit Agreement and derivative contracts, the Company is required to secure mortgages on assets having a value equal to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report.

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 summarizes 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, 2017:



	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	158,173	$	—
Total property and equipment, net ⁽²⁾	$	—	$	—	$	443,772
Liabilities:
Derivatives ⁽¹⁾	$	—	$	135,115	$	—

____________________________________________


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


⁽²⁾	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

The following table summarizes 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, 2016:



	Level 1		Level 2		Level 3
	(in thousands)
Assets:
Derivatives ⁽¹⁾	$	—	$	122,096	$	—
Total property and equipment, net ⁽²⁾	$	—	$	—	$	88,205
Liabilities:
Derivatives ⁽¹⁾	$	—	$	213,804	$	—

____________________________________________


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


⁽²⁾	This represents a non-financial asset that is measured at fair value on a nonrecurring 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 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.

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group.

Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date.

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments.

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

Property and equipment, net measured at fair value within the accompanying balance sheets totaled $443.8 million as of March 31, 2017, and related to assets held for sale as further discussed below. Property and equipment, net measured at fair value totaled $88.2 million as of December 31, 2016, and related primarily to downward performance reserve revisions on the Company’s Powder River Basin assets at year-end.

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 the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. The calculation of the discount rates are based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of March 31, 2017, and December 31, 2016. The Company believes the discount rates are representative of current market conditions and consider estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. There were no impairments on proved properties during the three months ended March 31, 2017. For the three months ended March 31, 2016, the Company recorded $269.8 million of proved property impairments related primarily to the Company’s outside-operated Eagle Ford shale assets and the decline in expected reserve cash flows driven by commodity price declines during the first quarter of 2016.

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. There were no material abandonments or impairments of unproved properties during the three months ended March 31, 2017, or 2016.

Oil and gas properties held for sale. Proved and unproved properties and other property and equipment classified as held for sale, including the 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, or by recent, comparable market transactions. If an estimated selling price is not available, the Company utilizes the various income 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 (loss) on divestiture activity line item in the accompanying statements of operations. For the three months ended March 31, 2017, write-downs to fair value less estimated costs to sell on the Divide County assets held for sale totaled $359.6 million. For the three months ended March 31, 2016, write-downs to fair value less estimated costs to sell on certain assets held for sale totaled $68.3 million. Certain of these assets were subsequently sold in the third quarter of 2016 for a small net gain due to successful marketing efforts. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion.

Long-Term Debt

The following table reflects the fair value of the Senior Notes and Senior Convertible Notes 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, 2017, or December 31, 2016, 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, 2017				As of December 31, 2016
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(in thousands)
6.50% Senior Notes due 2021	$	344,611	$	353,657	$	346,955	$	354,546
6.125% Senior Notes due 2022	$	561,796	$	572,330	$	561,796	$	570,925
6.50% Senior Notes due 2023	$	394,985	$	403,378	$	394,985	$	403,134
5.0% Senior Notes due 2024	$	500,000	$	472,500	$	500,000	$	475,975
5.625% Senior Notes due 2025	$	500,000	$	479,550	$	500,000	$	485,000
6.75% Senior Notes due 2026	$	500,000	$	503,750	$	500,000	$	516,565
1.50% Senior Convertible Notes due 2021	$	172,500	$	171,355	$	172,500	$	202,189

The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating and based on prevailing market rates.

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

This discussion includes 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, Highlights, and Outlook

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. We currently have development positions in the Midland Basin, Eagle Ford shale, and Bakken/Three Forks resource plays. Our strategic objective is to become a premier operator of top tier assets. During 2016, and continuing into 2017, we cored up our portfolio through proved and unproved property acquisitions in the Midland Basin. We were able to accomplish this through the divestiture of non-core assets and successful financing transactions. We plan to continue coring up our portfolio so we can concentrate on our highest return programs and provide value through accelerated development activity. Our Midland Basin and Eagle Ford shale assets have high operating margins and significant opportunities for additional economic investment. 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 prospective drilling opportunities, which we believe provide for long-term production and reserves growth. We focus on achieving high full-cycle economic returns on our investments and maintaining a simple, strong balance sheet.

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 2017, as well as the fourth and first quarters of 2016:



	For the Three Months Ended
	March 31, 2017			December 31, 2016			March 31, 2016
Crude Oil (per Bbl):
Average NYMEX contract monthly price	$	51.91		$	49.29		$	33.41
Realized price, before the effect of derivative settlements	$	47.55		$	43.58		$	25.67
Effect of oil derivative settlements	$	(2.58	)	$	5.38		$	24.27

Natural Gas:
Average NYMEX monthly settle price (per MMBtu)	$	3.32		$	2.98		$	1.96
Realized price, before the effect of derivative settlements (per Mcf)	$	2.98		$	2.86		$	1.87
Effect of natural gas derivative settlements (per Mcf)	$	0.52		$	0.35		$	1.15

NGLs (per Bbl):
Average OPIS price ⁽¹⁾	$	26.74		$	24.11		$	15.99
Realized price, before the effect of derivative settlements	$	22.06		$	20.02		$	11.76
Effect of NGL derivative settlements	$	(2.88	)	$	(3.10	)	$	1.78

____________________________________________


⁽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, gas, 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 all regions of the world as well as the relative strength of the dollar compared to other currencies. Oil markets continue to be unstable due to over-supply, large inventory balances, and uncertainty in global demand. The increase in oil prices at the end of 2016 was primarily attributable to the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC exporting countries agreeing to cut production. While participating countries have largely adhered to agreed upon production cuts, uncertainty remains concerning whether these cuts will be sustained. Drilling activity in the United States has increased in recent months, putting continued downward pressure on oil prices in the near term.

There has been improvement in natural gas pricing over the last year, largely as a result of demand growth from gas fired power generation and both LNG exports and exports to Mexico exceeding prior expectations. We expect prices to remain near current levels in the near term as drilling rigs in operation have increased in recent months leading to increased supply, which we expect will be offset by continued demand growth from LNG exports and exports to Mexico. We also expect prices to fluctuate with changes in demand resulting from the weather.

NGL prices have also improved over the last year due to oil and natural gas price recovery. We expect NGL prices to remain near current levels through 2017, as we expect increased demand from export and petrochemical markets to be offset by increased drilling activity.

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 26, 2017, and March 31, 2017:



	As of April 26, 2017		As of March 31, 2017
NYMEX WTI oil (per Bbl)	$	50.58	$	51.64
NYMEX Henry Hub gas (per MMBtu)	$	3.39	$	3.36
OPIS NGLs (per Bbl)	$	24.69	$	24.84

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 derivatives is driven by the amount of debt on our balance sheet, the level 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 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 prices while also setting a price floor for a portion of our oil production. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and the caption titled Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

First Quarter 2017 Highlights and Outlook for the Remainder of 2017

Our priorities for 2017 are to:


•	demonstrate the value of our 2016 and 2017 acquisitions in the Midland Basin;


•	generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;


•	successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and


•	reduce our outstanding debt.

Our capital program for 2017, excluding acquisitions, is expected to be approximately $875 million. By concentrating our capital on the highest return programs and operating at strong performance levels, we expect to generate higher company-wide margins and cash flow growth while creating value for our stockholders. We successfully closed the sale of our outside-operated Eagle Ford shale assets in the first quarter of 2017 for net divestiture proceeds of $747.4 million. Additionally, we began marketing our Divide County assets, which we expect to sell by mid-year. We plan to use these divestiture proceeds to support the funding of our 2017 and 2018 capital programs. If market conditions are favorable, we may use a portion of the divestiture proceeds to pay down outstanding debt; however, the amount and timing is uncertain. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our 2017 capital program.

Operational Activities. In our Midland Basin program, we began 2017 operating four drilling rigs and added two drilling rigs during the first quarter of 2017, one of which is drilling vertical test wells. We placed a seventh drilling rig into operation in mid-April 2017. Of these seven drilling rigs, five are focused on delineating and developing the Lower and Middle Spraberry and Wolfcamp A and B shale intervals on our acreage position in Howard and Martin Counties, Texas, and the other two drilling rigs remain focused on developing the Wolfcamp and Spraberry shale intervals on our Sweetie Peck property in Upton County, Texas. We expect approximately 80 percent of our 2017 capital program to be dedicated to our Midland Basin program.

During the first quarter of 2017, we acquired approximately 2,900 net acres in Howard County, Texas for $59.6 million, subject to post-closing adjustments, and completed an acreage trade of approximately 760 net acres in Howard County, Texas. Additionally, subsequent to March 31, 2017, we completed another asset trade, primarily leasehold interests, in Howard and Martin Counties, Texas, whereby we received approximately 2,260 net acres in exchange for transferring approximately 1,550 net acres. These trades provide us the opportunity to drill longer lateral wells and increase our working interest in existing drilling units.

In our Eagle Ford shale program, we began running one drilling rig during the first quarter of 2017. We plan to add another drilling rig in the third quarter of 2017, and are focused on reducing our drilled but not completed well count and meeting lease obligations. We expect 20 percent of our 2017 capital program to be dedicated to our Eagle Ford shale program.

In our Powder River Basin program, we continued running one drilling rig during the first quarter of 2017 under an acquisition and development funding agreement with a third party, pursuant to which the third party is carrying our drilling and completion costs.

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 $281.5 million for the three months ended March 31, 2017, and were incurred primarily in our Midland Basin and operated Eagle Ford shale programs. Of our total costs incurred for the three months ended March 31, 2017, $85.8 million relates to property acquisitions, primarily unproved, in Howard County, Texas. Included in this acquisition amount is the fair value attributed to the properties surrendered in the non-monetary acreage trade completed during the first quarter of 2017, as discussed above.

Drilling and Completion Activity. The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs during the first quarter of 2017:



	Midland Basin				Eagle Ford Shale				Bakken/Three Forks ⁽¹⁾		Total
	Gross		Net		Gross		Net		Gross	Net	Gross		Net
Wells drilled but not completed at December 31, 2016	17		17		47		47		20	17	84		81
Wells drilled	19		19		5		5		—	—	24		24
Wells completed	(16	)	(16	)	(17	)	(17	)	—	—	(33	)	(33	)
Wells drilled but not completed at March 31, 2017	20		20		35		35		20	17	75		72

_________________________________________


⁽¹⁾	During the first quarter of 2017, we announced plans to sell our Divide County assets.

Production Results. The table below provides a regional breakdown of our production for the first quarter of 2017:



	Permian		South Texas & Gulf Coast		Rocky Mountain		Total
Oil (MMBbl)	1.6		0.9		1.0		3.5
Gas (Bcf)	2.9		30.0		1.0		33.9
NGLs (MMBbl)	—		2.9		—		2.9
Equivalent (MMBOE)	2.1		8.8		1.2		12.1
Avg. daily equivalents (MBOE/d)	23.4		97.6		13.4		134.4
Relative percentage	17	%	73	%	10	%	100	%

____________________________________________

Note: Amounts may not calculate due to rounding.

Production on an equivalent basis decreased 10 percent for the three months ended March 31, 2017, compared with the same period in 2016, primarily as a result of the divestitures of properties across our regions in the last half of 2016 and the first quarter of 2017, specifically our Raven/Bear Den and outside-operated Eagle Ford shale assets. Please refer to A 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, 2017, and 2016 below for additional discussion on production.

Financial Results. In the first quarter of 2017, we had the following financial results:

•

We recorded net income of $74.4 million, or $0.67 per diluted share, for the three months ended March 31, 2017, compared with a net loss of $347.2 million, or $5.10 per diluted share, for the three months ended March 31, 2016. Net income for the three months ended March 31, 2017, was driven largely by a net gain of $398.1 million recorded on the sale of our outside-operated Eagle Ford shale assets and a net derivative gain of $114.8 million, mostly offset by a $359.6 million write-down to estimated fair value less costs to sell on our Divide County assets held for sale. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2017, and 2016 below for additional discussion regarding the components of net income (loss) for each period.


•	We had net cash provided by operating activities of $135.0 million for the three months ended March 31, 2017, compared with $118.3 million for the same period in 2016. Please refer to Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2017, and 2016 below for additional discussion.

•

Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2017, was $172.2 million, compared with $182.3 million for the same period in 2016. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX.

•

On March 31, 2017, pursuant to the Ninth Amendment to our Credit Agreement, our borrowing base and aggregate lender commitments were reduced to $925 million during the regularly scheduled semi-annual redetermination and as a result of closing the sale of our outside-operated Eagle Ford shale assets. Please refer to Note 5 - Long-Term Debt in Part I, Item I of this report for additional discussion.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information. A detailed discussion follows.



	For the Three Months Ended
	March 31,		December 31,			September 30,			June 30,
	2017		2016			2016			2016
	(in millions, except for production data)
Production (MMBOE)	12.1		13.4			14.2			14.3
Oil, gas, and NGL production revenue	$	333.2	$	346.3		$	329.2		$	291.1
Oil, gas, and NGL production expense	$	138.0	$	151.9		$	152.5		$	148.6
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	137.8	$	171.6		$	194.0		$	211.0
Exploration	$	12.0	$	23.7		$	13.5		$	13.2
General and administrative	$	29.2	$	33.3		$	32.7		$	28.2
Net income (loss)	$	74.4	$	(200.9	)	$	(40.9	)	$	(168.7	)

____________________________________________

Note: Amounts may not calculate due to rounding.

Selected Performance Metrics



	For the Three Months Ended
	March 31,			December 31,			September 30,			June 30,
	2017			2016			2016			2016
Average net daily production equivalent (MBOE per day)	134.4			145.6			153.9			157.2
Lease operating expense (per BOE)	$	3.82		$	3.67		$	3.29		$	3.31
Transportation costs (per BOE)	$	5.88		$	6.39		$	6.24		$	5.95
Production taxes as a percent of oil, gas, and NGL production revenue	4.2		%	4.3		%	4.5		%	4.6		%
Ad valorem tax expense (per BOE)	$	0.55		$	0.17		$	0.21		$	0.19
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)	$	11.39		$	12.81		$	13.70		$	14.75
General and administrative (per BOE)	$	2.42		$	2.49		$	2.31		$	1.97

____________________________________________

Note: Amounts may not calculate due to rounding.

A 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
	2017		2016			Amount Change Between Periods			Percent Change Between Periods
Net production volumes⁽¹⁾
Oil (MMBbl)	3.5		4.1			(0.6		)	(14	)%
Gas (Bcf)	33.9		35.7			(1.8		)	(5	)%
NGLs (MMBbl)	2.9		3.3			(0.4		)	(13	)%
Equivalent (MMBOE)	12.1		13.4			(1.3		)	(10	)%
Average net daily production⁽¹⁾
Oil (MBbl per day)	39.2		45.3			(6.1		)	(13	)%
Gas (MMcf per day)	376.6		392.2			(15.6		)	(4	)%
NGLs (MBbl per day)	32.5		36.8			(4.4		)	(12	)%
Equivalent (MBOE per day)	134.4		147.5			(13.1		)	(9	)%
Oil, gas, and NGL production revenue (in millions)
Oil production revenue	$	167.6	$	105.8		$	61.8		58	%
Gas production revenue	101.2		66.6			34.6			52	%
NGL production revenue	64.4		39.4			25.0			63	%
Total	$	333.2	$	211.8		$	121.4		57	%
Oil, gas, and NGL production expense (in millions)
Lease operating expense	$	46.1	$	50.8		$	(4.7	)	(9	)%
Transportation costs	71.1		81.3			(10.2		)	(13	)%
Production taxes	14.1		8.9			5.2			58	%
Ad valorem tax expense	6.7		3.5			3.2			91	%
Total	$	138.0	$	144.5		$	(6.5	)	(4	)%
Realized price (before the effect of derivative settlements)
Oil (per Bbl)	$	47.55	$	25.67		$	21.88		85	%
Gas (per Mcf)	$	2.98	$	1.87		$	1.11		59	%
NGLs (per Bbl)	$	22.06	$	11.76		$	10.30		88	%
Per BOE	$	27.55	$	15.78		$	11.77		75	%
Per BOE data ⁽¹⁾
Production costs:
Lease operating expense	$	3.82	$	3.79		$	0.03		1	%
Transportation costs	$	5.88	$	6.06		$	(0.18	)	(3	)%
Production taxes	$	1.17	$	0.66		$	0.51		77	%
Ad valorem tax expense	$	0.55	$	0.27		$	0.28		104	%
General and administrative	$	2.42	$	2.40		$	0.02		1	%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	11.39	$	15.96		$	(4.57	)	(29	)%
Derivative settlement gain ⁽²⁾	$	—	$	10.96		$	(10.96	)	(100	)%
Earnings per share information
Basic net income (loss) per common share	$	0.67	$	(5.10	)	$	5.77		113	%
Diluted net income (loss) per common share	$	0.67	$	(5.10	)	$	5.77		113	%
Basic weighted-average common shares outstanding (in thousands)	111,258		68,077			43,181			63	%
Diluted weighted-average common shares outstanding (in thousands)	111,329		68,077			43,252			64	%

______________________________________


⁽¹⁾	Amount and percentage changes may not calculate due to rounding.


⁽²⁾	Derivative settlements for the three months ended March 31, 2017, and 2016, respectively, are included within the net derivative gain line item in the accompanying statements of operations.

We present per BOE information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis. Average net daily production for the three months ended March 31, 2017, decreased nine percent compared with the same period in 2016 primarily as a result of the divestitures of properties across our regions in the last half of 2016 and the first quarter of 2017, specifically our Raven/Bear Den and outside-operated Eagle Ford shale assets. We anticipate a further decrease in production upon the expected divestiture of our Divide County assets later in the year; however, as we ramp up our Midland Basin development program, we expect production to increase and begin offsetting this decline. Overall, we expect a decrease in production for full-year 2017 compared with full-year 2016. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2017, and 2016 below for additional discussion.

Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized price before the effects of derivative settlements on a per BOE basis for the three months ended March 31, 2017, increased 75 percent compared with the same period in 2016. Commodity prices were at recent historic lows in early 2016 and began to improve in the last half of 2016 and are holding relatively flat in the first quarter of 2017. For the three months ended March 31, 2017, we had a minimal gain on the settlement of our derivative contracts, which resulted in no gain on a per BOE basis. This compares with a gain of $10.96 per BOE for the three months ended March 31, 2016.

Lease operating expense (“LOE”) on a per BOE basis increased slightly for the three months ended March 31, 2017, compared with the same period in 2016. We experience volatility in our LOE as a result of the impact industry activity has on service provider costs and seasonality in workover expense. For 2017, we generally expect LOE on a per BOE basis to be relatively flat compared with 2016. We expect that any increase in service provider costs resulting from increased development activity in the Midland Basin will be offset by the executed and planned divestitures of our higher cost Williston Basin properties.

Transportation expense on a per BOE basis decreased slightly for the three months ended March 31, 2017, compared with the same period in 2016 primarily as a result of selling our outside-operated Eagle Ford shale assets in early March 2017. In general, we expect transportation costs on a per BOE basis to decrease further in 2017 with the sale of our outside-operated Eagle Ford shale assets and as our Midland Basin assets become a larger portion of our production mix. The majority of our Midland Basin production is sold at the wellhead under current contracts, and therefore, there is minimal transportation expense separately recorded on the accompanying statements of operations.

Production taxes on a per BOE basis increased 77 percent for the three months ended March 31, 2017, compared with the same period in 2016 in line with the increase in our realized price before the effect of derivative settlements, as there was no change in our production tax rate of 4.2 percent period-over-period. We generally expect production tax expense to trend with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax we recognize. For 2017, we generally expect our production tax rate to decrease year-over-year as a result of our closed and anticipated divestitures; however, we expect an increase in production taxes on a per BOE basis in line with improved commodity prices.

Ad valorem tax expense on a per BOE basis increased 104 percent for the three months ended March 31, 2017, compared with the same period in 2016 primarily as a result of changes in our asset and production base. The majority of our ad valorem tax expense is related to our Texas properties. Since we have acquired producing properties in Texas and divested properties in our Rocky Mountain region, we expect ad valorem tax expense on an absolute and per BOE basis to increase in 2017. Additionally, we expect an increase in commodity price assumptions used in 2017 property tax valuations.

General and administrative (“G&A”) expense on a per BOE basis increased slightly for the three months ended March 31, 2017, compared with the same period in 2016. The decrease in absolute G&A expense was in line with the decrease in production volumes. We expect G&A expense on an absolute basis to remain relatively flat in 2017 compared with 2016 as reduced headcount in 2016 is expected to be offset by headcount changes resulting from recent and anticipated acquisition and divestiture activity and an expected increase in base and short-term incentive compensation. However, we expect an overall increase in G&A expense on a per BOE basis in 2017 due to the decrease in production volumes.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis decreased 29 percent for the three months ended March 31, 2017, compared with the same period in 2016, as a result of divested assets and the impact of assets held for sale, specifically our outside-operated Eagle Ford shale assets that were held for sale prior to being sold in March 2017 and our Divide County assets which we classified as held for sale during the first quarter of 2017. These assets were not depleted while classified as held for sale. Our DD&A rate fluctuates as a result of impairments, planned and closed divestitures, and changes in the mix of our production and the underlying proved reserve volumes. In general, we expect DD&A expense on a per BOE basis to decrease in 2017 due to selling our higher cost Raven/Bear Den assets in late 2016 and assets held for sale impacts.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2017, and 2016 below for additional discussion on operating expenses.

Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for discussion on the types of shares included in our basic and diluted net income (loss) per common share calculations. Our basic and diluted weighted-average share count increased for the three months ended March 31, 2017, compared with the same period in 2016 due to the public and private equity offerings of our common stock made in the last half of 2016. Additionally, we recorded net income for the three months ended March 31, 2017, and therefore, our unvested RSUs and contingent PSUs were dilutive for this period.

Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2017, and 2016

Oil, gas, and NGL production, production revenues, and production costs

The following table presents the regional changes in our oil, gas, and NGL production, production revenues, and production costs between the three months ended March 31, 2017, and 2016:



	Average Net Daily Production Increase (Decrease)		Production Revenues Increase (Decrease)			Production Costs Increase (Decrease)
	(MBOE/d)		(in millions)			(in millions)
Permian	17.3		$	79.3		$	16.3
South Texas & Gulf Coast	(13.7	)	$	52.1		$	(6.3	)
Rocky Mountain	(16.7	)	$	(10.0	)	$	(16.5	)
Total	(13.1	)	$	121.4		$	(6.5	)

The 10 percent decrease in net equivalent production volumes primarily due to recent divestitures was partially offset by a 75 percent increase in realized prices on a per BOE basis resulting in a 57 percent increase in oil, gas, and NGL production revenues between the three months ended March 31, 2017, and 2016. This decrease in net equivalent production volumes, as well as the changes in costs on a per BOE basis discussed above, resulted in a four percent decrease in total production costs for the three months ended March 31, 2017, compared with the same period in 2016. Offsetting the decrease in production volumes and costs in our South Texas & Gulf Coast and Rocky Mountain regions due to recent divestitures is an increase in production volumes, revenues, and costs in our Permian region due to increased drilling and completion activity in our Midland Basin development program. Please refer to A Three-Month Overview of Selected Production and Financial Information, Including Trends above for discussion of trends on a per BOE basis.

Net gain (loss) on divestiture activity



	For the Three Months Ended March 31,
	2017		2016
	(in millions)
Net gain (loss) on divestiture activity	$	37.5	$	(69.0	)

The net gain on divestiture activity for the three months ended March 31, 2017, was a result of the $398.1 million net gain recorded on the sale of our outside-operated Eagle Ford shale assets, partially offset by a write-down to fair value less estimated selling costs recorded on the Divide County assets held for sale. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part I, Item 1 of this report for additional discussion. The net loss on divestiture activity for the three months ended March 31, 2016, was largely due to the write-down to fair value less estimated selling costs recorded on certain assets held for sale that were sold in the third quarter of 2016.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion



	For the Three Months Ended March 31,
	2017		2016
	(in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	$	137.8	$	214.2

DD&A expense decreased 36 percent for the three months ended March 31, 2017, compared with the same period in 2016 due to the decline in our production volumes and the impact of assets sold and assets held for sale. Please refer to the section A Three-Month Overview of Selected Production and Financial Information, Including Trends above for further discussion of DD&A expense on a per BOE basis.

Exploration



	For the Three Months Ended March 31,
	2017		2016
	(in millions)
Exploration	$	12.0	$	15.3

Exploration expense for the three months ended March 31, 2017, decreased 22 percent compared with the same period in 2016 due to reduced overhead costs as a result of lower headcount. Overall, we expect our geological and geophysical and exploration overhead expenses to be higher for full-year 2017 than full-year 2016 as we focus on testing and delineating our recently acquired Midland Basin acreage.

Impairment of proved properties and abandonment and impairment of unproved properties



	For the Three Months Ended March 31,
	2017		2016
	(in millions)
Impairment of proved properties	$	—	$	269.8
Abandonment and impairment of unproved properties	$	—	$	2.3

There were no proved or unproved property impairments recorded for the three months ended March 31, 2017. Proved property impairments recorded for the three months ended March 31, 2016, were a result of continued commodity price declines, largely impacting proved properties in our outside-operated Eagle Ford shale program. These assets were recently sold for a significant gain due to a recovery in commodity prices and successful marketing efforts. Please refer to the caption Net gain (loss) on divestiture activity above. Unproved property impairments recorded for the three months ended March 31, 2016, were due to lease expirations on acreage we no longer intended to develop.

We expect proved property impairments to be more likely to occur in periods of declining or depressed commodity prices, and unproved property impairments to fluctuate with the timing of lease expirations, unsuccessful exploration activities, and changing economics associated with volatile commodity prices. Additionally, changes in drilling plans, downward engineering revisions, or unsuccessful exploration efforts may result in proved and unproved property impairments. Any amount of future impairment is difficult to predict, but based on updated commodity price assumptions as of April 26, 2017, we do not expect any material impairments in the second quarter of 2017 due to commodity price impacts.

General and administrative



	For the Three Months Ended March 31,
	2017		2016
	(in millions)
General and administrative	$	29.2	$	32.2

G&A expense decreased nine percent for the three months ended March 31, 2017, compared with the same period in 2016, primarily due to reduced headcount in the last half of 2016. However, we do expect changes in headcount in 2017 resulting from recent and anticipated acquisition and divestiture activity, as well as an increase in base and short-term incentive compensation. Please refer to the section A Three-Month Overview of Selected Production and Financial Information, Including Trends above for further discussion of G&A expense on a per BOE basis.

Net derivative gain



	For the Three Months Ended March 31,
	2017			2016
	(in millions)
Net derivative gain	$	(114.8	)	$	(14.2	)

We recognized a derivative gain of $114.8 million for the three months ended March 31, 2017, which is primarily a result of a $94.3 million mark-to-market gain recorded on contracts remaining as of March 31, 2017, due to a decrease in commodity strip prices from December 31, 2016. For contracts settled during the first quarter of 2017, the fair value was a net liability of $20.5 million at December 31, 2016, and net cash settlements were minimal, resulting in a $20.5 million gain. We recognized a $14.2 million derivative gain for the three months ended March 31, 2016, due to favorable cash settlements on contracts settled in the first quarter of 2016, partially offset by a small mark-to-market loss on remaining contracts as of March 31, 2016. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information.

Other operating expenses



	For the Three Months Ended March 31,
	2017		2016
	(in millions)
Other operating expenses	$	4.9	$	5.7

Other operating expenses for the three months ended March 31, 2017, consisted primarily of losses on materials inventory sales, whereas other operating expenses for the same period in 2016 consisted primarily of drilling rig termination and standby fees.

Gain (loss) on extinguishment of debt



	For the Three Months Ended March 31,
	2017		2016
	(in millions)
Gain (loss) on extinguishment of debt	$	—	$	15.7

During the first quarter of 2016, we recorded a $15.7 million net gain on the early extinguishment of a portion of our Senior Notes, which included approximately $16.4 million associated with the discount realized upon repurchase, slightly offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional information.

Interest expense



	For the Three Months Ended March 31,
	2017			2016
	(in millions)
Interest expense	$	(47.0	)	$	(31.1	)

There was a 51 percent increase in interest expense for the three months ended March 31, 2017, compared with the same period in 2016, primarily due to the additional debt issued in 2016, as presented in Note 5 - Long-Term Debt in Part I, Item I of this report, and an increase in our weighted-average interest rate, as discussed and presented in Overview of Liquidity and Capital Resources.

Income tax (expense) benefit



	For the Three Months Ended March 31,
	2017			2016
	(in millions, except tax rate)
Income tax (expense) benefit	$	(44.5	)	$	194.9
Effective tax rate	37.4		%	35.9		%

The increase in the effective tax rate for the three months ended March 31, 2017, compared with the same period in 2016, resulted from 2017 state apportionment changes due to divesting our outside-operated Eagle Ford shale assets, 2016 valuation allowance increases correlating from various 2016 projected state net operating losses, which decreased the 2016 effective tax rate, versus 2017 valuation allowance decreases resulting from projected utilization of various state net operating losses, which increased the 2017 effective tax rate. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion service commitments to maintain the flexibility to adjust our activity and capital expenditures in periods of prolonged weak commodity prices or to respond should commodity prices recover further.

Sources of Cash

We currently expect our 2017 capital program to be funded by cash flows from operations and proceeds from the divestiture of properties.

Although we anticipate cash flows from these sources will be sufficient to fund our expected 2017 capital program, we may also elect to borrow under our Credit Agreement and/or raise funds through debt or equity financings or from other sources or enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs. See Credit Agreement below for discussion of the recent reduction in our borrowing base. Our borrowing base could be further reduced as a result of lower commodity prices, divestitures of proved properties, or newly issued debt. Decreases in commodity prices have limited our industry’s access to capital markets in recent periods. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our stockholders could be diluted, and these newly-issued securities may have rights, preferences, or privileges senior to those of existing stockholders. Any future downgrades in our credit ratings may make it more difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry.

We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts.

Proposals to reform the Internal Revenue Code of 1986, as amended, which include eliminating or reducing current tax deductions for intangible drilling costs, depreciation of equipment acquisition costs, the domestic production activities deduction, percentage depletion, and other deductions that reduce our taxable income, have been discussed in past years. Although we believe this possibility has decreased with the recent congressional discussions on tax reform, we expect that future legislation eliminating these deductions would reduce net operating cash flows over time, thereby reducing funding available for our exploration and development capital programs, as well as funding available to our peers in the industry for similar programs. If enacted, reductions in available deductions could have a significant adverse effect on drilling in the United States for a number of years.

Credit Agreement

Our Credit Agreement provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019. On March 31, 2017, we entered into a Ninth Amendment to the Credit Agreement. Pursuant to the Ninth Amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and current aggregate lender commitments were decreased to $925 million. This expected decrease was primarily due to the divestiture of our outside-operated Eagle Ford shale properties in the first quarter of 2017. Additionally, as part of the Ninth Amendment, we are now able to enter into derivative contracts for an increased percentage of projected production volumes. We had a zero balance on our credit facility as of March 31, 2017, and as of the filing of this report. We anticipate our borrowing base to be further reduced upon divesting our Divide County assets, which we expect to occur prior to the October 1, 2017, scheduled borrowing base redetermination. No individual bank that is a party to our Credit Agreement represents more than 10 percent of the lender commitments. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

We must comply with certain financial and non-financial covenants under the Credit Agreement, including covenants limiting dividend payments and requiring us to maintain certain financial ratios, as defined by the Credit Agreement. Financial covenants under the Credit Agreement require, as of the last day of each fiscal quarter, our (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of March 31, 2017, and through the filing of this report. Please refer to the caption Non-GAAP Financial Measures below for the calculation of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities to adjusted EBITDAX.

Our daily weighted-average credit facility debt balance was approximately $52.9 million and $252.0 million for the three months ended March 31, 2017, and 2016, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, and the amount of our capital expenditures, including acquisitions, all impact the amount we have borrowed under our credit facility.

Weighted-Average Interest Rates

Our weighted-average interest rates include paid and accrued interest, fees on the unused portion of the credit facility’s aggregate commitment amount, letter of credit fees, the non-cash amortization of deferred financing costs, and the non-cash amortization of the discount related to the Senior Convertible Notes. Our weighted-average borrowing rates include paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the three months ended March 31, 2017, and 2016:



	For the Three Months Ended March 31,
	2017		2016
Weighted-average interest rate	6.6	%	5.9	%
Weighted-average borrowing rate	5.8	%	5.5	%

The increase in our weighted-average interest rate and weighted-average borrowing rate for the three months ended March 31, 2017, compared with the same period in 2016, is largely due to the Senior Convertible Notes and 6.75% Senior Notes due 2026 issued during the third quarter of 2016. Further impacting these rates in 2017 and 2016 is the timing and amount of Senior Notes redemptions, changes in our aggregate lender commitment amount on our credit facility, and the average balance on our credit facility. The rates disclosed in the above table do not reflect amounts associated with the repurchase of Senior Notes, such as the discount realized or premium paid upon repurchase or acceleration of unamortized deferred financing costs expensed upon repurchase. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Uses of Cash

We use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the acquisition, exploration, and development of oil and gas properties are the primary use of our capital resources. For the three months ended March 31, 2017, we spent $229.5 million in capital expenditures and in acquiring proved and unproved oil and gas properties. This amount differs from the costs incurred amount, which is accrual-based and includes asset retirement obligations, geological and geophysical expenses, exploration overhead amounts, and the fair value of assets acquired in a non-monetary trade.

The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing, and financing activities, and our ability to assimilate acquisitions and execute our drilling program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.

We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges for other securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. If market conditions are favorable, we may use a portion of 2017 divestiture proceeds to pay down debt; however, the amount and timing is uncertain. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion of previously repurchased Senior Notes.

As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. We currently do not plan to repurchase any outstanding shares during 2017.

Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2017, and 2016

The following tables present changes in cash flows between the three months ended March 31, 2017, and 2016, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our condensed consolidated statements of cash flows in Part I, Item 1 of this report.

Operating Activities



	For the Three Months Ended March 31,				Amount Change Between Periods		Percent Change Between Periods
	2017		2016		Amount Change Between Periods		Percent Change Between Periods
	(in millions)
Net cash provided by operating activities	$	135.0	$	118.3	$	16.7	14	%

Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, including derivative cash settlements, decreased $21.1 million for the three months ended March 31, 2017, compared with the same period in 2016, as a result of the decline in production volumes, partially offset by a slight increase in our realized price, after the effects of derivative settlements. Interest paid increased $18.4 million for the three months ended March 31, 2017, compared with the same period in 2016 due to the issuance of our 6.75% Senior Notes due 2026 and Senior Convertible Notes in 2016. These decreases in operating cash flow are offset by an $11.7 million decrease in cash paid for LOE, an increase in working capital balances, and a decrease in cash G&A expense and exploration overhead for the three months ended March 31, 2017, compared to the same period in 2016. The decrease in LOE for the three months ended March 31, 2017, compared with the same period in 2016, is being driven by a decrease in production volumes and the sale of our higher cost Raven/Bear Den assets in 2016.

Investing activities



	For the Three Months Ended March 31,					Amount Change Between Periods		Percent Change Between Periods
	2017		2016			Amount Change Between Periods		Percent Change Between Periods
	(in millions)
Net cash provided by (used in) investing activities	$	517.3	$	(189.3	)	$	706.6	373	%

The increase in cash flow from investing activities for the three months ended March 31, 2017, compared with the same period in 2016 is largely due to divestiture cash proceeds of $744.3 million received in the first quarter of 2017 primarily from the sale of our outside-operated Eagle Ford shale assets and a $22.0 million decrease in capital expenditures, partially offset by a $60.1 million increase in proved and unproved property acquisitions in the Midland Basin during the first quarter of 2017.

Financing activities



	For the Three Months Ended March 31,					Amount Change Between Periods			Percent Change Between Periods
	2017			2016		Amount Change Between Periods			Percent Change Between Periods
	(in millions)
Net cash provided by (used in) financing activities	$	(2.5	)	$	71.1	$	(73.6	)	(104	)%

We had a zero balance on our credit facility as of December 31, 2016, and March 31, 2017. Due to the proceeds received on the sale of our outside-operated Eagle Ford shale assets during the first quarter of 2017, we had a cash balance of $659.1 million as of March 31, 2017. This compares to net borrowings of $91.0 million during the three months ended March 31, 2016. Additionally, during the three months ended March 31, 2016, we paid $19.9 million for the repurchase of a portion of our Senior Notes. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.

Interest Rate Risk

We are exposed to market risk due to the floating interest rate on our revolving credit facility; however, as of March 31, 2017, and through the filing of this report, we had a zero balance on our credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes or fixed-rate Senior Convertible Notes, but can impact their fair market values. As of March 31, 2017, our outstanding fixed-rate debt totaled $3.0 billion. Please refer to Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair value of our Senior Notes and Senior Convertible Notes.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly impact our revenue, overall profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to wide fluctuations in response to changes in supply and demand and other factors. The markets for oil, gas, and NGLs have been volatile, especially over the last several years, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on our production for the three months ended March 31, 2017, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $16.8 million, $10.1 million, and $6.4 million, respectively. If commodity prices had been 10 percent lower, our derivative settlements would have been higher, partially offsetting the decrease in production revenues as discussed in the next paragraph.

We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity prices. The fair value of our commodity derivative contracts are largely determined by estimates of the forward curves of the relevant price indices. For the three months ended March 31, 2017, a 10 percent decrease in the contract settlement prices would have increased our oil, gas, and NGL derivative settlement gain by approximately $8.6 million, $9.3 million, and $4.5 million, respectively.

Off-Balance Sheet Arrangements

As part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions in 2017.

Critical Accounting Policies and Estimates

Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2016 Form 10-K for discussion of our accounting policies and estimates.

New Accounting Pronouncements

Please refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards under Part I, Item 1 of this report for new accounting matters.

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, other non-operating income and expense, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property impairments, non-cash stock-based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, gains and losses on divestitures, gains and losses on extinguishment of debt, and materials inventory impairments and losses on sale. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in Part I, Item 1 of this report. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of senior secured debt to adjusted EBITDAX and a minimum permitted ratio of adjusted EBITDAX to interest, we will be in default, an event that would prevent us from borrowing under our credit facility and would therefore materially limit our sources of liquidity. In addition, if we default under our credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for default.

The following table provides reconciliations of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX for the periods presented:



	For the Three Months Ended March 31,
	2017			2016
	(in thousands)
Net income (loss) (GAAP)	$	74,434		$	(347,210	)
Interest expense	46,953			31,088
Other non-operating income, net	(335		)	(6		)
Income tax expense (benefit)	44,506			(194,875		)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	137,812			214,207
Exploration ⁽¹⁾	10,570			13,611
Impairment of proved properties	—			269,785
Abandonment and impairment of unproved properties	—			2,311
Stock-based compensation expense	5,455			6,868
Net derivative gain	(114,774		)	(14,228		)
Derivative settlement gain	7			147,028
Net (gain) loss on divestiture activity	(37,463		)	69,021
(Gain) loss on extinguishment of debt	35			(15,722		)
Other	4,986			432
Adjusted EBITDAX (Non-GAAP)	172,186			182,310
Interest expense	(46,953		)	(31,088		)
Other non-operating income, net	335			6
Income tax (expense) benefit	(44,506		)	194,875
Exploration ⁽¹⁾	(10,570		)	(13,611		)
Amortization of discount and deferred financing costs	4,946			(920		)
Deferred income taxes	33,225			(195,039		)
Plugging and abandonment	(1,191		)	(604		)
Other, net	(432		)	(1,583		)
Changes in current assets and liabilities	27,926			(16,070		)
Net cash provided by operating activities (GAAP)	$	134,966		$	118,276

____________________________________________

⁽¹⁾ Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

Cautionary Information about Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included in this report that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:


•	the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;


•	our outlook on future oil, gas, and NGL prices, well costs, and service costs;


•	the drilling of wells and other exploration and development activities and plans, as well as possible or expected acquisitions or divestitures;


•	the possible divestiture or farm-down of, or joint venture relating to, certain properties;


•	proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates;


•	future oil, gas, and NGL production estimates;


•	cash flows, anticipated liquidity, and the future repayment of debt;


•	business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and


•	other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Some of these risks are described in the Risk Factors section in Part I, Item 1A of our 2016 Form 10-K, and include such factors as:


•	the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;


•	weakness in economic conditions and uncertainty in financial markets;


•	our ability to replace reserves in order to sustain production;


•	our ability to raise the substantial amount of capital required to develop and/or replace our reserves;


•	our ability to compete against competitors that have greater financial, technical, and human resources;


•	our ability to attract and retain key personnel;


•	the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;


•	the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;


•	the possibility that exploration and development drilling may not result in commercially producible reserves;


•	our limited control over activities on outside-operated properties;


•	our reliance on the skill and expertise of third-party service providers on our operated properties;


•	the possibility that title to properties in which we claim an interest may be defective;


•	our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;


•	the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;


•	the uncertainties associated with enhanced recovery methods;


•	our commodity derivative contracts may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;


•	the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;


•	our ability to deliver required quantities of crude oil, natural gas, natural gas liquids, or water to contractual counterparties;


•	price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;


•	the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;


•	the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;


•	the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and Senior Convertible Notes may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions, or lead to the accelerated payment of our debt;


•	operating and environmental risks and hazards that could result in substantial losses;


•	the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities;


•	our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;


•	complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;


•	the availability and capacity of gathering, transportation, processing, and/or refining facilities;


•	our ability to sell and/or receive market prices for our oil, gas, and NGLs;


•	new technologies may cause our current exploration and drilling methods to become obsolete;


•	the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and


•	litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.

We caution you that forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this report speak as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under Interest Rate Risk and Commodity Price Risk in Item 2 above and is incorporated herein by reference. Please also refer to the information under Interest Rate Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2016 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that is designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls were effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes during the first quarter of 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2016 Form 10-K.

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

The following table provides information about purchases by us or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the quarter ended March 31, 2017, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act:

PURCHASES OF EQUITY SECURITIES BY ISSUER

AND AFFILIATED PURCHASERS



Period	(a) Total Number of Shares Purchased ⁽¹⁾	(b) Weighted Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Program	(d) Maximum Number of Shares that May Yet Be Purchased Under the Program ⁽²⁾
01/01/17 - 01/31/17	108	$	34.40	—	3,072,184
02/01/17 - 02/28/17	66	$	26.99	—	3,072,184
03/01/17 - 03/31/17	205	$	24.39	—	3,072,184
Total:	379	$	27.69	—	3,072,184

____________________________________________


⁽¹⁾	All shares purchased by us in the first quarter of 2017 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying restricted stock units delivered under the terms of grants under our Equity Incentive Compensation Plan.

⁽²⁾

In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to up to 6,000,000 shares as of the effective date of the resolution. Accordingly, as of the filing of this report, we may repurchase up to 3,072,184 shares of common stock on a prospective basis, subject to the approval of our Board of Directors. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time.

Our payment of cash dividends to our stockholders is subject to covenants under the terms of our Credit Agreement that limit our annual dividend payments to no more than $50.0 million per year. We are also subject to certain covenants under the indentures governing our Senior Notes and Senior Convertible Notes that restrict certain payments, including dividends; provided, however, that the first $6.5 million of dividends paid each year are not restricted by these covenants. We do not anticipate that these restrictions will limit our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.

ITEM 6. EXHIBITS

The following exhibits are filed or furnished with or incorporated by reference into this report:



Exhibit Number		Description
2.1*		Membership Interest Purchase Agreement dated January 1, 2017 between SM Energy Company and Venado EF LLC
2.2*		Second Amendment to Membership Interest Purchase Agreement dated March 4, 2017 between SM Energy Company and Venado EF L.P.
3.1		Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
3.2		Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)
10.1		Ninth Amendment to Fifth Amended and Restated Credit Agreement, dated March 31, 2017, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April 3, 2017 and incorporated herein by reference)
12.1*		Computation of Ratio of Earnings to Fixed Charges
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1**		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

_____________________________________



	*	Filed with this report.
	**	Furnished with this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



	SM ENERGY COMPANY

May 3, 2017	By:	/s/ JAVAN D. OTTOSON
		Javan D. Ottoson
		President and Chief Executive Officer
		(Principal Executive Officer)

May 3, 2017	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

May 3, 2017	By:	/s/ MARK T. SOLOMON
		Mark T. Solomon
		Vice President - Controller and Assistant Secretary
		(Principal Accounting Officer)