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EX-31.2 - EXHIBIT 31.2 - SM Energy Cosm-312certificationwpursel.htm
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EX-12.1 - EXHIBIT 12.1 - SM Energy Coexhibit121-ratioofearnings.htm



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2016
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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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

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 27, 2016, the registrant had 68,078,567 shares of common stock, $0.01 par value, outstanding.



1


SM ENERGY COMPANY
TABLE OF CONTENTS

PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2


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,
2016
 
December 31,
2015
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
51

 
$
18

Accounts receivable
111,141

 
134,124

Derivative asset
281,596

 
367,710

Prepaid expenses and other
12,850

 
17,137

Total current assets
405,638

 
518,989

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
6,994,150

 
7,606,405

Less - accumulated depletion, depreciation, and amortization
(3,385,234
)
 
(3,481,836
)
Unproved oil and gas properties
231,060

 
284,538

Wells in progress
466,403

 
387,432

Oil and gas properties held for sale, net of accumulated depletion, depreciation, and amortization of $288,592 and $0, respectively
152,725

 
641

Other property and equipment, net of accumulated depreciation of $34,699 and $32,956, respectively
144,675

 
153,100

Total property and equipment, net
4,603,779

 
4,950,280

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
160,732

 
120,701

Other noncurrent assets
36,907

 
31,673

Total other noncurrent assets
197,639

 
152,374

Total Assets
$
5,207,056

 
$
5,621,643

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
293,796

 
$
302,517

Derivative liability
8,211

 
8

Other current liabilities
1,150

 

Total current liabilities
303,157

 
302,525

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
293,000

 
202,000

Senior Notes, net of unamortized deferred financing costs (note 5)
2,271,472

 
2,315,970

Asset retirement obligation
105,329

 
137,284

Asset retirement obligation associated with oil and gas properties held for sale
33,862

 
241

Net Profits Plan liability
6,351

 
7,611

Deferred income taxes
563,105

 
758,279

Derivative liability
78,514

 

Other noncurrent liabilities
43,850

 
45,332

Total noncurrent liabilities
3,395,483

 
3,466,717

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 68,077,546 and 68,075,700, respectively
681

 
681

Additional paid-in capital
312,473

 
305,607

Retained earnings
1,208,900

 
1,559,515

Accumulated other comprehensive loss
(13,638
)
 
(13,402
)
Total stockholders’ equity
1,508,416

 
1,852,401

Total Liabilities and Stockholders’ Equity
$
5,207,056

 
$
5,621,643

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

3



SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)

 
For the Three Months Ended March 31,
 
2016
 
2015
Operating revenues:
 
 
 
Oil, gas, and NGL production revenue
$
211,823


$
393,315

Net loss on divestiture activity (note 3)
(69,021
)
 
(35,802
)
Other operating revenues
274

 
8,421

Total operating revenues and other income
143,076


365,934







Operating expenses:





Oil, gas, and NGL production expense
144,543

 
196,151

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
214,207

 
217,401

Exploration
15,273

 
37,407

Impairment of proved properties
269,785

 
55,526

Abandonment and impairment of unproved properties
2,311

 
11,627

General and administrative
32,238

 
43,639

Change in Net Profits Plan liability
(1,260
)

(4,334
)
Derivative gain
(14,228
)
 
(154,167
)
Other operating expenses
6,932

 
17,119

Total operating expenses
669,801


420,369







Loss from operations
(526,725
)

(54,435
)






Non-operating income (expense):





Interest income
6

 
571

Interest expense
(31,088
)

(32,647
)
Gain on extinguishment of debt
15,722

 







Loss before income taxes
(542,085
)

(86,511
)
Income tax benefit
194,875

 
33,453







Net loss
$
(347,210
)

$
(53,058
)






Basic weighted-average common shares outstanding
68,077

 
67,463







Diluted weighted-average common shares outstanding
68,077

 
67,463







Basic net loss per common share
$
(5.10
)

$
(0.79
)






Diluted net loss per common share
$
(5.10
)

$
(0.79
)






Dividends per common share
$
0.05


$
0.05


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

4


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(in thousands)
 
For the Three Months Ended March 31,
 
 
2016
 
2015
 
 
 
 
Net loss
$
(347,210
)
 
$
(53,058
)
Other comprehensive loss, net of tax:
 
 
 
Pension liability adjustment
(236
)
 
(176
)
Total other comprehensive loss, net of tax
(236
)
 
(176
)
Total comprehensive loss
$
(347,446
)
 
$
(53,234
)

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

5


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)

 
For the Three Months Ended March 31,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(347,210
)
 
$
(53,058
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Net loss on divestiture activity
69,021

 
35,802

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
214,207

 
217,401

Exploratory dry hole expense
(19
)
 
16,275

Impairment of proved properties
269,785

 
55,526

Abandonment and impairment of unproved properties
2,311

 
11,627

Stock-based compensation expense
6,868

 
6,024

Change in Net Profits Plan liability
(1,260
)
 
(4,334
)
Derivative gain
(14,228
)
 
(154,167
)
Derivative settlement gain
147,028

 
161,229

Amortization of deferred financing costs
(920
)
 
1,957

Non-cash gain on extinguishment of debt, net
(15,722
)
 

Deferred income taxes
(195,039
)
 
(33,727
)
Plugging and abandonment
(604
)
 
(2,425
)
Other, net
128

 
1,496

Changes in current assets and liabilities:
 
 
 
Accounts receivable
26,922

 
69,527

Refundable income taxes
5,085

 
(544
)
Prepaid expenses and other
(101
)
 
1,825

Accounts payable and accrued expenses
(52,294
)
 
(45,416
)
Accrued derivative settlements
4,318

 
(1,096
)
Net cash provided by operating activities
118,276

 
283,922

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
1,206

 
21,573

Capital expenditures
(176,370
)
 
(544,965
)
Acquisition of proved and unproved oil and gas properties
(15,044
)
 
(10,069
)
Other, net
885

 
(997
)
Net cash used in investing activities
(189,323
)
 
(534,458
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
317,000

 
560,000

Repayment of credit facility
(226,000
)
 
(309,500
)
Cash paid to repurchase Senior Notes
(19,917
)
 

Other, net
(3
)
 
(62
)
Net cash provided by financing activities
71,080

 
250,438

 
 
 
 
Net change in cash and cash equivalents
33

 
(98
)
Cash and cash equivalents at beginning of period
18

 
120

Cash and cash equivalents at end of period
$
51

 
$
22

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

6


SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)

Supplemental schedule of additional cash flow information and non-cash activities:
 
For the Three Months Ended March 31,
 
2016
 
2015
 
(in thousands)
Cash paid for interest, net of capitalized interest
$
24,453

 
$
34,059

 
 
 
 
Net cash (refunded) paid for income taxes
$
(4,689
)
 
$
94


Dividends of approximately $3.4 million were declared by the Company’s Board of Directors, but not paid, as of March 31, 2016, and 2015.
    
As of March 31, 2016, and 2015, $117.8 million and $318.0 million, respectively, of accrued capital expenditures were included in accounts payable and accrued expenses in the Company’s condensed consolidated balance sheets. These oil and gas property additions are reflected in net cash used in investing activities in the periods during which the payables are settled.

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

7


SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 - The Company and Business

SM Energy Company (“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, 2015 (the “2015 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 subsequent events after the balance sheet date of March 31, 2016, through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current period 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 2015 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 2015 Form 10-K.

Recently Issued Accounting Standards

Effective January 1, 2016, the Company adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU clarifies the consolidation reporting guidance in GAAP. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This ASU changes the accounting for leases. This guidance is to be applied using a modified retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which was issued in May 2014 (“ASU 2014-09”). Further, in April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU also amends ASU 2014-09 and is related to the identification of performance obligations and accounting for licenses. The effective date and transition requirements for both of these amendments to ASU 2014-09 are the same as those of ASU 2014-09, which was deferred for one year by ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim period within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the provisions of each of these standards and assessing their impact on the Company’s financial statements and disclosures.

8



In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This ASU makes targeted amendments to the accounting for employee share-based payments. This guidance is to be applied using various transition methods such as full retrospective, modified retrospective, and prospective based on the criteria for the specific amendments as outlined in the guidance. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted, as long as all of the amendments are adopted in the same period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

Other than as disclosed above or in the 2015 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, 2016, and through the filing date of this report.

Note 3 – 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 costs to sell. Any subsequent decreases to the estimated fair value less costs to sell impact the measurement of assets held for sale.

As of March 31, 2016, the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $152.7 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consists of certain non-core assets in each of the Company’s operating regions. A corresponding asset retirement obligation liability of $33.9 million is separately presented. Certain of these assets were written down by $68.3 million to reflect fair value, less estimated costs to sell, upon reclassification to assets held for sale, as of March 31, 2016. The Company is actively marketing its assets held for sale and expects to close the transactions prior to December 31, 2016. During the quarter ended March 31, 2015, the Company recorded write-downs to fair value less estimated costs to sell, of $30.0 million for certain of its Mid-Continent region assets held for sale as of March 31, 2015.

The write-downs to fair value less estimated costs to sell, are reflected in the net loss on divestiture activity line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”).

The Company determined that these planned asset sales do not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.
 

9


Note 4 - Income Taxes

The income tax benefit recorded for each of the three months ended March 31, 2016, and 2015, differs from the amounts that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, research and development (“R&D”) credits, and other permanent differences. The quarterly rate can also be affected by the proportional effects of forecasted net income or loss as of each period end presented.

The provision for income taxes consists of the following:

 
For the Three Months Ended March 31,
 
2016
 
2015
 
(in thousands)
Current portion of income tax expense (benefit):
 
 
 
Federal
$

 
$

State
164

 
274

Deferred portion of income tax benefit
(195,039
)
 
(33,727
)
Total income tax benefit
$
(194,875
)
 
$
(33,453
)
Effective tax rate
35.9
%
 
38.7
%

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 from various state tax jurisdictions. Cumulative effects of state rate changes are reflected in the period legislation is enacted.

The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2007. During the first quarter of 2016, the Company received an expected $4.9 million refund of tax and interest after the Company and the Internal Revenue Service (“IRS”) reached a final agreement on the examination of the Company’s 2007 - 2011 tax years. There were no material adjustments to previously recorded amounts. During the quarter ended September 30, 2015, the IRS initiated an audit of the tax partnership between the Company and Mitsui E&P Texas LP for the 2013 tax year. The Company has a significant investment in the underlying assets of this tax partnership. The Company received notice during the first quarter of 2016 that the IRS concluded the audit with no adjustments.

Note 5 - Long-Term Debt

Revolving Credit Facility

As of March 31, 2016, the Company’s Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), provided for a maximum loan amount of $2.5 billion, a borrowing base of $2.0 billion, and aggregate lender commitments of $1.5 billion. The maturity date is December 10, 2019.

On April 8, 2016, the Company entered into a Sixth Amendment to the Credit Agreement (the Credit Agreement as amended, the “Amended Credit Agreement”) with its lenders. Pursuant to the amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base was reduced to $1.25 billion. This expected reduction was primarily due to the decline in commodity prices resulting in a decrease in the Company’s proved reserves as of December 31, 2015. The next scheduled redetermination date is October 1, 2016. The borrowing base redetermination process considers the value of both the Company’s proved oil and gas properties reflected in the Company’s applicable reserve report and commodity derivative contracts, each as determined by the lender group. The amendment also reduced the current aggregate lender commitments to $1.25 billion, and changed the required percentage of oil and gas properties subject to a mortgage to at least 90 percent of the total PV-9 of the oil and gas properties evaluated in the most recently completed reserve report. Further, the amendment to the Credit Agreement revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below.
 
The Company must comply with certain financial and non-financial covenants under the terms of the Amended Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios. As of March 31, 2016, the Credit Agreement required that as of the last day of each of the Company’s fiscal quarters, the Company’s ratio of total debt to 12-month trailing adjusted EBITDAX, as defined by the Credit Agreement, be not more than 4.0 to 1.0, and that the Company’s adjusted current ratio, as defined by the Credit Agreement, be not less than 1.0 to 1.0. Effective as of April 8, 2016, the

10


total debt to adjusted EBITDAX ratio financial covenant was deleted as part of the amendment of the Credit Agreement. Financial covenants under the Amended Credit Agreement now require as of the last day of each of the Company’s fiscal quarters, the Company’s ratio of senior secured debt to 12-month trailing adjusted EBITDAX, as defined by the Amended Credit Agreement, be not more than 2.75 to 1.0, the adjusted current ratio, as defined by the Amended Credit Agreement, be not less than 1.0 to 1.0, and the ratio of 12-month trailing adjusted EBITDAX to interest expense, as defined by the Amended Credit Agreement, 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, 2016, and under the Amended Credit Agreement through the filing date of this report.

Interest and commitment fees are accrued based on a borrowing base utilization grid.  Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at prime plus the applicable margin from the utilization table below.  Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. As of March 31, 2016, interest and commitment fees were accrued based on the borrowing base utilization grid set forth in Note 5 to the Company’s consolidated financial statements in its 2015 Form 10-K. Effective as of April 8, 2016, the revised borrowing base utilization grid under the Amended Credit Agreement is as follows:

Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage
 
<25%
 
≥25% <50%
 
≥50% <75%
 
≥75% <90%
 
≥90%
Eurodollar Loans
 
1.750
%
 
2.000
%
 
2.250
%
 
2.500
%
 
2.750
%
ABR Loans or Swingline Loans
 
0.750
%
 
1.000
%
 
1.250
%
 
1.500
%
 
1.750
%
Commitment Fee Rate
 
0.300
%
 
0.300
%
 
0.350
%
 
0.375
%
 
0.375
%

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Amended Credit Agreement as of April 27, 2016, and under the Credit Agreement as of March 31, 2016, and December 31, 2015:

 
As of April 27, 2016
 
As of March 31, 2016
 
As of December 31, 2015
 
(in thousands)
Credit facility balance (1)
$
294,500

 
$
293,000

 
$
202,000

Letters of credit (2)
$
200

 
$
200

 
$
200

Available borrowing capacity
$
955,300

 
$
1,206,800

 
$
1,297,800

____________________________________________
(1) Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance.
(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

11


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, and 5.625% Senior Notes due 2025 (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, 2016, and December 31, 2015, consisted of the following:

 
As of March 31, 2016
 
As of December 31, 2015
 
Senior Notes
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
Senior Notes
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
(in thousands)
6.50% Senior Notes due 2021
$
346,955

 
$
3,896

 
$
343,059

 
$
350,000

 
$
4,106

 
$
345,894

6.125% Senior Notes due 2022
561,796

 
7,863

 
553,933

 
600,000

 
8,714

 
591,286

6.50% Senior Notes due 2023
394,985

 
4,983

 
390,002

 
400,000

 
5,231

 
394,769

5.0% Senior Notes due 2024
500,000

 
7,224

 
492,776

 
500,000

 
7,455

 
492,545

5.625% Senior Notes due 2025
500,000

 
8,298

 
491,702

 
500,000

 
8,524

 
491,476

Total
$
2,303,736

 
$
32,264

 
$
2,271,472

 
$
2,350,000

 
$
34,030

 
$
2,315,970


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 that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; however, the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company was in compliance with all covenants under its Senior Notes as of March 31, 2016, and through the filing date of this report. All Senior Notes are registered under the Securities Act of 1933, as amended (the “Securities Act”). 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.

During the first quarter of 2016, the Company repurchased a total of $46.3 million in aggregate principal amount of Senior Notes in open market transactions for a settlement amount of $29.9 million, excluding interest. Of the $29.9 million settlement amount, $10.0 million related to transactions that were executed during the first quarter of 2016; however, the cash settlement occurred subsequent to March 31, 2016. The Company recorded a net gain on extinguishment of debt related to the repurchase of a portion of its 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023 of approximately $15.7 million for the quarter ended March 31, 2016. This amount includes a gain of $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $700,000 related to the acceleration of unamortized deferred financing costs. The Company accounted for the repurchases under the extinguishment method of accounting. The Company canceled the repurchased notes upon cash settlement.

Note 6 - Commitments and Contingencies

Commitments

There were no material changes in commitments during the first three months of 2016, except as discussed below. Please refer to Note 6 - Commitments and Contingencies in the Company’s 2015 Form 10-K for additional discussion.

During the first quarter of 2016, the Company renegotiated the terms of certain drilling rig contracts to provide increased flexibility with regard to the timing of activity and payment. For the three months ended March 31, 2016, and 2015, the Company incurred $5.0 million and $3.2 million, respectively, of expense related to the early termination of drilling rig contracts or fees incurred for rigs placed on standby, which are recorded in the other operating expenses line item in the accompanying statements of operations.

During the first quarter of 2016, the Company entered into amendments to certain oil gathering and gas gathering agreements related to its outside-operated Eagle Ford shale assets, neither of which previously had a minimum volume commitment, in order to

12


obtain more favorable rates and terms. Under these amended agreements, as of March 31, 2016, the Company is now committed to deliver 303 Bcf of natural gas and 40 MMBbl of oil through 2034. In the event that the Company delivers no product under these amended agreements, the Company’s aggregate undiscounted deficiency payments would be approximately $351.2 million at March 31, 2016; however, because of the Company’s partial ownership interest in the gathering systems used to provide the services under these agreements, the Company is entitled to receive its share of operating income generated by the systems, and thus would expect to receive approximately $247.9 million if the $351.2 million shortfall payment was required. During the first quarter of 2016, the Company also entered into an amendment to a gas gathering agreement related to its operated Eagle Ford shale assets, which reduced the Company’s volume commitment amount as of December 31, 2015, by 829 Bcf, and reduced the aggregate undiscounted deficiency payments by $118.2 million through 2021. As of March 31, 2016, the Company has total gathering, processing, and transportation throughput commitments with various third parties that require delivery of a minimum amount of 1,624 Bcf of natural gas, 75 MMBbl of crude oil, and 14 MMBbl of natural gas liquids through 2034. If the Company delivers no product, the aggregate undiscounted deficiency payments total approximately $1.1 billion through 2034, prior to considering the $247.9 million of operating income the Company would expect to receive if certain payments were required as outlined above.

As of the filing date of this report, the Company does not expect to incur any material shortfalls with regard to its gathering, processing, and transportation throughput 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.

The Company is subject to routine severance, royalty and joint interest audits from regulatory authorities, non-operators and others, as the case may be, and records accruals for estimated exposure when a claim is deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise from third party interpretations of the Company’s contracts or otherwise affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices that royalty owners are paid for production from their leases, allowable costs under joint interest arrangements, and other matters. As of March 31, 2016, the Company had $4.4 million accrued for estimated exposure related to claims for payment of royalties on certain Federal and Indian leases. Although the Company believes that it has properly estimated its potential exposure with respect to these claims based on various contracts, laws and regulations, administrative rulings, and interpretations thereof, adjustments could be required as new interpretations and regulations arise.

Note 7 - Compensation Plans

Performance Share Units Under the Equity Incentive Compensation Plan

The Company grants performance share units (“PSUs”) to eligible employees as a 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 the 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. Compensation expense for PSUs is recognized within general and administrative and exploration expense over the vesting periods of the respective awards.

Total compensation expense recorded for PSUs for the three months ended March 31, 2016, and 2015, was $2.9 million and $2.3 million, respectively. As of March 31, 2016, there was $15.2 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2018. There have been no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2016.

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. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the award.


13


Total compensation expense recorded for RSUs was $3.2 million and $2.9 million for the three months ended March 31, 2016, and 2015, respectively. As of March 31, 2016, there was $15.4 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2018. There have been no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2016.

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, will 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,
 
2016
 
2015
 
(in thousands)
Service cost
$
1,987

 
$
1,584

Interest cost
624

 
548

Expected return on plan assets that reduces periodic pension cost
(545
)
 
(494
)
Amortization of prior service cost
4

 
4

Amortization of net actuarial loss
372

 
172

Net periodic benefit cost
$
2,442

 
$
1,814


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 and the market-related value of assets are amortized over the average remaining service period of active participants.

Contributions

The Company contributed $4.0 million to the Pension Plans during the three months ended March 31, 2016.

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 common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs and contingent PSUs. The treasury stock method is used to measure the dilutive impact of these stock awards.

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. For additional discussion on PSUs, please refer to Note 7 - Compensation Plans under the heading Performance Share Units Under the Equity Incentive Compensation Plan.


14


When the Company recognizes a loss from continuing operations, as was the case for the three months ended March 31, 2016, and 2015, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. For the three months ended March 31, 2016, and 2015, weighted-average anti-dilutive securities related to unvested RSUs and contingent PSUs totaled approximately 49,000 and 452,000 shares, respectively.

The following table sets forth the calculations of basic and diluted earnings per share:
 
For the Three Months Ended March 31,
 
2016
 
2015
 
(in thousands, except per share amounts)
Net loss
$
(347,210
)
 
$
(53,058
)
Basic weighted-average common shares outstanding
68,077

 
67,463

Add: dilutive effect of unvested RSUs and contingent PSUs

 

Diluted weighted-average common shares outstanding
68,077

 
67,463

Basic net loss per common share
$
(5.10
)
 
$
(0.79
)
Diluted net loss per common share
$
(5.10
)
 
$
(0.79
)

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. All contracts are 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, 2016, the Company had commodity derivative contracts outstanding through the second quarter of 2020 as summarized in the tables below. During the three months ended March 31, 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 cash or other consideration was included as part of the restructuring. The net result of buying fixed price volumes in 2018 and 2019 is that the Company does not have any protection against natural gas price volatility in those years.

Subsequent to March 31, 2016, the Company entered into derivative fixed price swap contracts through the fourth quarter of 2018 for a total of 37.9 million MMBtu of gas production with contract prices ranging from $2.36 to $3.19 per MMBtu, as well as a derivative fixed price swap contract through the fourth quarter of 2017 for 1.0 million Bbls of oil production with a contract price of $47.15 per Bbl. Additionally, subsequent to March 31, 2016, the Company entered into derivative collar contracts through the fourth quarter of 2017 for a total of 2.7 million Bbls of oil production with contract floor prices ranging from $40.00 to $45.00 per Bbl and contract ceiling prices ranging from $50.35 to $52.85 per Bbl.


15


The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of March 31, 2016:

Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(Bbls)
 
(per Bbl)
Second quarter 2016
 
1,752,000

 
$
86.73

Third quarter 2016
 
1,840,000

 
$
71.80

Fourth quarter 2016
 
1,399,000

 
$
67.73

2017
 
2,035,000

 
$
44.84

All oil swaps
 
7,026,000

 
 

Natural Gas Swaps
Contract Period
 
Sold
Volumes
 
Weighted-Average
 Contract Price
 
Purchased Volumes
 
Weighted- Average Contract Price
 
Net
Volumes
 
 
(MMBtu)
 
(per MMBtu)
 
(MMBtu)
 
(per MMBtu)
 
(MMBtu)
Second quarter 2016
 
20,780,000

 
$
3.40

 

 
$

 
20,780,000

Third quarter 2016
 
18,830,000

 
$
3.38

 

 
$

 
18,830,000

Fourth quarter 2016
 
18,988,000

 
$
3.69

 

 
$

 
18,988,000

2017
 
85,019,000

 
$
4.09

 

 
$

 
85,019,000

2018
 
30,606,000

 
$
4.27

 
(30,606,000
)
 
$
4.27

 

2019
 
24,415,000

 
$
4.34

 
(24,415,000
)
 
$
4.34

 

All gas swaps*
 
198,638,000

 
 
 
(55,021,000
)
 
 
 
143,617,000


*Total net volumes of natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (97%), and IF NNG Ventura (1%).


16


NGL Swaps
 
 
OPIS Purity Ethane Mont Belvieu
 
OPIS Propane Mont Belvieu Non-TET
 
OPIS Normal Butane Mont Belvieu Non-TET
 
OPS Isobutane 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
 
 
(Bbls)
(per Bbl)
 
(Bbls)
(per Bbl)
 
(Bbls)
(per Bbl)
 
(Bbls)
(per Bbl)
Second quarter 2016
 
828,000

$
8.28

 
949,000

$
19.64

 
208,000

$
24.02

 
174,000

$
24.68

Third quarter 2016
 
751,000

$
8.70

 
863,000

$
19.03

 
186,000

$
21.86

 
155,000

$
22.42

Fourth quarter 2016
 
687,000

$
8.71

 
792,000

$
18.53

 
170,000

$
21.86

 
141,000

$
22.42

2017
 
3,062,000

$
8.92

 

$

 

$

 

$

2018
 
2,435,000

$
10.18

 

$

 

$

 

$

2019
 
1,200,000

$
10.92

 

$

 

$

 

$

2020
 
539,000

$
11.13

 

$

 

$

 

$

Total NGL swaps
 
9,502,000

 
 
2,604,000

 
 
564,000

 
 
470,000

 

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 $355.6 million as of March 31, 2016, and a net asset of $488.4 million as of December 31, 2015.

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

 
As of March 31, 2016
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
281,596

 
Current liabilities
 
$
8,211

Commodity contracts
Noncurrent assets
 
160,732

 
Noncurrent liabilities
 
78,514

Derivatives not designated as hedging instruments
 
 
$
442,328

 
 
 
$
86,725


 
As of December 31, 2015
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet
 Classification
 
Fair Value
 
Balance Sheet
 Classification
 
Fair Value
 
(in thousands)
Commodity contracts
Current assets
 
$
367,710

 
Current liabilities
 
$
8

Commodity contracts
Noncurrent assets
 
120,701

 
Noncurrent liabilities
 

Derivatives not designated as hedging instruments
 
 
$
488,411

 
 
 
$
8


Offsetting of Derivative Assets and Liabilities

As of March 31, 2016, and December 31, 2015, 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.  


17


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, 2016
 
December 31, 2015
 
March 31, 2016
 
December 31, 2015
 
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
 
$
442,328

 
$
488,411

 
$
(86,725
)
 
$
(8
)
Amounts not offset in the accompanying balance sheets
 
(86,725
)
 
(8
)
 
86,725

 
8

Net amounts
 
$
355,603

 
$
488,403

 
$

 
$

    
The following table summarizes the components of the derivative gain presented in the accompanying statements of operations:
 
For the Three Months Ended March 31,
 
2016
 
2015
 
(in thousands)
Derivative settlement gain:
 
 
 
Oil contracts
$
(99,992
)
 
$
(106,214
)
Gas contracts
(41,053
)
 
(34,232
)
NGL contracts
(5,983
)
 
(20,783
)
Total derivative settlement gain
$
(147,028
)

$
(161,229
)
 
 
 
 
Total derivative (gain) loss:
 
 
 
Oil contracts
$
(10,432
)
 
$
(73,860
)
Gas contracts
(24,023
)
 
(82,339
)
NGL contracts
20,227

 
2,032

Total derivative gain
$
(14,228
)

$
(154,167
)


Credit Related Contingent Features

As of March 31, 2016, and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. On or before June 10, 2016, the Company is obligated to mortgage additional assets so that the Company’s obligations under the Amended Credit Agreement and derivative contracts are secured by 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 recently approved reserve report.


18


Note 11 - Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
Level 1 – quoted prices in active markets for identical assets or liabilities
Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3 – significant inputs to the valuation model are unobservable
The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of March 31, 2016:


Level 1

Level 2

Level 3

(in thousands)
Assets:








Derivatives (1)
$


$
442,328


$

Total property and equipment, net (2)
$


$


$
439,942

Liabilities:








Derivatives (1)
$


$
86,725


$

Net Profits Plan (1)
$


$


$
6,351

____________________________________________
(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 is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2015:

 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$

 
$
488,411

 
$

Total property and equipment, net (2)
$

 
$

 
$
124,813

Liabilities:
 
 
 
 
 
Derivatives (1)
$

 
$
8

 
$

Net Profits Plan (1)
$

 
$

 
$
7,611

____________________________________________
(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.


19


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.

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. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group.

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.

Net Profits Plan

The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability.

The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. A discount rate of 10 percent was used to calculate this liability, and is intended to represent the Company’s best estimate of the present value of expected future payments under the Net Profits Plan.

The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. The Company regularly assesses the current market environment.  The Net Profits Plan liability is determined using price assumptions of five one-year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivative contracts in the relevant periods.  The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets.

If the commodity prices used in the calculation changed by five percent, the liability recorded at March 31, 2016, would differ by approximately $1.0 million. A one percent increase or decrease in the discount rate would result in a change of approximately $250,000. Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated.


20


No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates.
    
The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs:
 
For the Three Months Ended March 31, 2016
 
(in thousands)
Beginning balance
$
7,611

Net decrease in liability (1)
(291
)
Net settlements (1) (2)
(969
)
Transfers in (out) of Level 3

Ending balance
$
6,351


____________________________________________
(1) 
Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.
(2) 
Settlements represent cash payments made or accrued under the Net Profits Plan.

Long-Term Debt
The following table reflects the fair value of the Senior Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of March 31, 2016, or December 31, 2015, as they were recorded at carrying value, net of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt for discussion of the Company’s repurchase of a portion of its Senior Notes during the first quarter of 2016.

 
As of March 31, 2016
 
As of December 31, 2015
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
(in thousands)
6.50% Senior Notes due 2021
$
346,955

 
$
257,399

 
$
350,000

 
$
262,938

6.125% Senior Notes due 2022
561,796

 
410,813

 
600,000

 
440,250

6.50% Senior Notes due 2023
394,985

 
282,414

 
400,000

 
296,000

5.0% Senior Notes due 2024
500,000

 
344,375

 
500,000

 
334,065

5.625% Senior Notes due 2025
500,000

 
347,500

 
500,000

 
326,875

Total Senior Notes
$
2,303,736

 
$
1,642,501

 
$
2,350,000

 
$
1,660,128


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


21


Proved and Unproved Oil and Gas Properties

Total property and equipment, net, measured at fair value within the accompanying balance sheets totaled $439.9 million and $124.8 million as of March 31, 2016, and December 31, 2015, respectively.

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 were estimated to be 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of March 31, 2016, and December 31, 2015. The Company believes the discount rates are representative of current market conditions and take into account 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. The Company recorded impairment of proved properties expense of $269.8 million for the three months ended March 31, 2016, due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows for the Company’s outside-operated Eagle Ford assets, driven by continued commodity price declines between year-end 2015 and March 31, 2016. As of December 31, 2015, certain of the Company’s proved oil and gas properties in each of its operating regions were measured at fair value.

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: future development plans, risk weighted potential resource recovery, and estimated reserve values. The Company recorded abandonment and impairment of unproved properties expense of $2.3 million for the three months ended March 31, 2016, resulting from lease expirations on acreage the Company no longer intended to develop. As of December 31, 2015, certain of the Company’s unproved properties were measured at fair value resulting from lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the decline in commodity prices.
Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. Fair value of other property and equipment is valued using an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. The Company recorded impairment of other property and equipment expense of $49.4 million for the year ended December 31, 2015, on the Company’s gathering system assets in east Texas. These assets were impaired in conjunction with the impairment of the associated proved and unproved properties, which the Company does not intend to develop during an environment of sustained low commodity prices.

Proved properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company estimates acreage value based on the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. For the three months ended March 31, 2016, write-downs to fair value less costs to sell on certain assets held for sale totaled $68.3 million. These write-downs are included within the net loss on divestiture activity line item on the accompanying statements of operations. Please refer to Note 3 – Assets Held for Sale. There were no assets held for sale recorded at fair value as of December 31, 2015 as the carrying value was below the estimated fair value less costs to sell.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.


22


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

This management’s discussion and analysis contains forward-looking statements. Refer to Cautionary Information About Forward-Looking Statements at the end of this item for an explanation of 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. Our strategic objective is to profitably build our ownership and operatorship of North American oil, gas, and NGL producing assets that have high operating margins and significant opportunities for additional economic investment. We pursue growth opportunities through both exploration and acquisitions, and we seek to maximize the value of our assets through industry leading technology application and outstanding operational execution. We focus on achieving high full-cycle economic returns on our investments and maintaining a simple, strong balance sheet through a conservative approach to leverage.

We currently focus our capital investments on our development positions in the Eagle Ford shale, Bakken/Three Forks, and Permian Basin resource plays. We also have a delineation and exploration program in the Powder River Basin.

In the first quarter of 2016, we had the following financial and operational results:

Average net daily production for the three months ended March 31, 2016, was 45.3 MBbls of oil, 392.2 MMcf of gas, and 36.8 MBbls of NGLs, for a quarterly equivalent daily production rate of 147.5 MBOE, compared with 186.4 MBOE for the same period in 2015. Please see additional discussion below under Production Results.

We recorded a net loss of $347.2 million, or $5.10 per diluted share, for the three months ended March 31, 2016, compared to a net loss of $53.1 million, or $0.79 per diluted share, for the three months ended March 31, 2015. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2016, and 2015, below for additional discussion regarding the components of net loss.
 
Costs incurred for oil and gas property acquisitions and exploration and development activities for the three months ended March 31, 2016, totaled $227.4 million. The majority of our drilling and completion costs incurred during this period were in our Eagle Ford shale, Bakken/Three Forks, and Permian Basin programs. Total costs incurred for the same period in 2015 were $499.7 million. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital program.

Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2016, was $182.3 million, compared to $311.9 million for the same period in 2015. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net loss and net cash provided by operating activities to adjusted EBITDAX.

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. We sell the majority of our gas under contracts using first-of-the-month index pricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day the gas is produced.  For assets where high BTU gas is sold at the wellhead, we also receive additional value for the higher energy content contained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPIS daily settlement prices, adjusted for processing, transportation, and location differentials. Our oil is sold using the calendar month average of the NYMEX WTI daily contract settlement prices during the month of production, adjusted for quality, transportation, American Petroleum Institute (“API”) gravity, and location differentials. 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.


23


The following table summarizes commodity price data, as well as the effects of derivative settlements, for the first quarter of 2016, as well as the fourth and first quarters of 2015:

 
For the Three Months Ended
 
March 31, 2016
 
December 31, 2015
 
March 31, 2015
Crude Oil (per Bbl):
 
 
 
 
 
Average NYMEX price
$
33.41

 
$
42.02

 
$
48.49

Realized price, before the effect of derivative settlements
$
25.67

 
$
34.93

 
$
38.56

Oil derivative settlement gain
$
24.27

 
$
20.88

 
$
20.33

 
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Average NYMEX price (per MMBtu)
$
1.96

 
$
2.11

 
$
2.87

Realized price, before the effect of derivative settlements (per Mcf)
$
1.87

 
$
2.19

 
$
2.76

Natural gas derivative settlement gain (per Mcf)
$
1.15

 
$
0.77

 
$
0.75

 
 
 
 
 
 
NGLs (per Bbl): (1)
 
 
 
 
 
Average OPIS price
$
15.99

 
$
18.48

 
$
21.53

Realized price, before the effect of derivative settlements
$
11.76

 
$
14.99

 
$
16.67

NGL derivative settlement gain
$
1.78

 
$
0.61

 
$
5.33

____________________________________________
(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.

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. 

We expect future prices for oil, gas, and NGLs 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 oil producing regions of the world, particularly the Middle East, and the relative strength of the U.S. dollar compared to other currencies.  In late 2015, the U.S. lifted its ban on the export of crude oil, which we expect will help balance supply and demand within North America. Crude oil prices continued to decline into 2016 primarily due to slower global economic growth combined with excess global supply before improving slightly in March 2016. We expect this imbalance between supply and demand to remain throughout 2016, keeping crude oil prices at levels below their five-year average. Gas prices also continued to deteriorate during the first quarter of 2016, as the United States experienced a warmer than normal winter. Supply remains in excess of demand for natural gas, resulting in higher levels of gas in storage compared to the five-year average.  NGL prices remained under downward pressure during the first quarter of 2016, primarily due to the drop in oil and gas prices and high inventory levels. Prices for certain NGL components, specifically propane, began to rebound late in the first quarter of 2016 as a result of a decrease in inventory levels.  In response to lower oil, gas, and NGL prices, industry participants continued to cut capital spending in the first quarter of 2016 as compared to 2015 levels. We expect the lower capital spending by industry participants to eventually result in a decrease in supply, which should drive commodity prices higher for all products.

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 27, 2016, and March 31, 2016:

 
As of April 27, 2016
 
As of March 31, 2016
NYMEX WTI oil (per Bbl)
$
47.53

 
$
41.89

NYMEX Henry Hub gas (per MMBtu)
$
2.64

 
$
2.44

OPIS NGLs (per Bbl)
$
20.95

 
$
18.77


24


Derivative Activity
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 and gas prices while also setting a price floor for a portion of our 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 2016 Highlights and Outlook for the Remainder of 2016
Operational Activities. Our goal during 2016 is to maintain a strong balance sheet and preserve liquidity in the current commodity price environment while improving our portfolio and holding quality acreage positions. We expect to incur capital expenditures below adjusted EBITDAX in order to minimize any impact to our total debt. We believe this focus on our liquidity will best preserve our balance sheet and will give us the flexibility to adapt as industry conditions change.
We expect our capital program for 2016 to be approximately $705 million, of which we plan to invest approximately 85 percent in drilling and completion activities with the focus on our core development programs in the Bakken/Three Forks, Permian Basin, and Eagle Ford shale. We plan to continue our focus on conducting safe operations even as we pursue cost saving measures throughout our business.
In our operated Eagle Ford shale program, we began 2016 operating three drilling rigs and dropped two operated drilling rigs during the first quarter of 2016. We expect to drop the remaining operated drilling rig during the third quarter of 2016, and plan to utilize one frac crew through the third quarter of 2016. In 2016, we plan to focus the majority of our investment on wells that were drilled but uncompleted at year-end 2015 and to meet lease obligations. As of March 31, 2016, in our operated Eagle Ford program, we had drilled but not completed 81 gross and net wells. We drilled seven gross and net wells during the first quarter of 2016.
In our outside-operated Eagle Ford shale program, we expect the operator will further slow its pace of development in 2016.
In our Bakken/Three Forks program, we began 2016 operating two drilling rigs. We expect to drop one drilling rig during the second quarter of 2016, and run one drilling rig for the remainder of 2016. As of March 31, 2016, in our operated Bakken/Three Forks program, we had drilled but not completed 52 gross wells (45 net). We drilled ten gross wells (nine net) during the first quarter of 2016.
In our Permian Basin development program, we began operating one drilling rig in early 2016 and expect to increase to two drilling rigs during the second quarter of 2016. Our focus will be on developing the Wolfcamp and Spraberry shale intervals on our Sweetie Peck property in Upton County, Texas. As of March 31, 2016, in our Permian program, we had drilled but not completed eight gross and net wells. We drilled three gross and net wells during the first quarter of 2016.
We have curtailed activity in our delineation and exploration programs to focus on preserving our more prospective acreage. We dropped our last operated drilling rig in our Powder River Basin program in mid-February 2016.
We will continue to evaluate our rig count throughout the remainder of 2016 as we respond to commodity price changes and reduced costs. Please refer to Overview of Liquidity and Capital Resources below for additional discussion concerning how we intend to fund our 2016 capital program.

25


Production Results. The table below provides a regional breakdown of our production for the first quarter of 2016:
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Permian
 
Total (1)
 
 
 
 
 
 
 
 
Oil (MMBbl)
1.5

 
2.2

 
0.4

 
4.1

Gas (Bcf)
32.0

 
2.6

 
1.1

 
35.7

NGLs (MMBbl)
3.3

 
0.1

 

 
3.3

Equivalent (MMBOE)
10.1

 
2.7

 
0.6

 
13.4

Avg. daily equivalents (MBOE/d)
111.3

 
30.1

 
6.1

 
147.5

Relative percentage
76
%
 
20
%
 
4
%
 
100
%
____________________________________________
(1) Amounts may not calculate due to rounding.

Production decreased for the three months ended March 31, 2016, compared to the same period in 2015, driven by the divestiture of properties in our Mid-Continent region in the second quarter of 2015, as well as a reduction in our drilling and completion activity. In our operated Eagle Ford shale, Bakken/Three Forks, and Permian Basin programs for the three months ended March 31, 2016, we completed two gross and net wells, five gross wells (four net), and four gross and net wells, respectively. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2016, and 2015 and A three-month overview of selected production and financial information, including trends below for additional discussion on production.

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:
 
For the Three Months Ended March 31, 2016
 
(in millions)
Development costs
$
178.2

Exploration costs
32.6

Acquisitions
 
Proved properties
2.2

Unproved properties (1)
14.4

Total, including asset retirement obligations (2)
$
227.4

____________________________________________
(1) Includes $14.0 million of unproved properties acquired as part of proved property acquisitions for the three months ended March 31, 2016. The remaining amount is leasing activity.
(2) Includes amounts relating to estimated asset retirement obligations of $870,000 and capitalized interest of $5.1 million for the three months ended March 31, 2016.

The majority of costs incurred for oil and gas producing activities during the first quarter of 2016 were in the development of our Bakken/Three Forks, Permian Basin, and Eagle Ford shale programs. Please refer to Production Results above for discussion on completion activity during the first quarter 2016, in addition to First Quarter 2016 Highlights and Outlook for the Remainder of 2016 above for discussion on wells that have been drilled, but not completed as of March 31, 2016. Additionally, please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our capital expenditure program.

Subsequent Events. Subsequent to March 31, 2016, we entered into the Amended Credit Agreement with our lenders. Pursuant to the Amended Credit Agreement, and as part of the regular, semi-annual redetermination process, our borrowing base and our lender commitments were decreased to $1.25 billion. The amendment to the Credit Agreement also modified our borrowing base utilization grid, debt covenants, and required percentage of oil and gas properties subject to a mortgage and title requirements, as well as certain covenants concerning prepayments, voluntary redemptions of debt, and repurchases of common stock. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
    


26


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,
 
2016
 
2015
 
2015
 
2015
 
(in millions, except for production data)
Production (MMBOE)
13.4

 
14.9

 
16.1

 
16.5

Oil, gas, and NGL production revenue
$
211.8

 
$
298.7

 
$
366.6

 
$
441.3

Oil, gas, and NGL production expense
$
144.5

 
$
169.2


$
184.6

 
$
173.7

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
214.2

 
$
240.0

 
$
243.9

 
$
219.7

Exploration
$
15.3

 
$
37.9

 
$
19.7

 
$
25.5

General and administrative
$
32.2

 
$
33.6

 
$
37.8

 
$
42.6

Net income (loss)
$
(347.2
)
 
$
(340.3
)
 
$
3.1

 
$
(57.5
)
____________________________________________
Note: Amounts may not calculate due to rounding.

Selected Performance Metrics:

 
For the Three Months Ended
 
March 31,
 
December 31,
 
September 30,
 
June 30,
 
2016
 
2015
 
2015
 
2015
Average net daily production equivalent (MBOE/d)
147.5

 
162.1

 
174.5

 
181.0

Lease operating expense (per BOE)
$
3.79

 
$
3.85

 
$
3.86

 
$
3.26

Transportation costs (per BOE)
$
6.06

 
$
6.10

 
$
6.27

 
$
5.64

Production taxes as a percent of oil, gas, and NGL production revenue
4.2
%
 
5.1
%
 
4.2
%
 
5.2
%
Ad valorem tax expense (per BOE)
$
0.27

 
$
0.38

 
$
0.40

 
$
0.25

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
$
15.96

 
$
16.10

 
$
15.19

 
$
13.34

General and administrative (per BOE)
$
2.40

 
$
2.26

 
$
2.35

 
$
2.59

____________________________________________
Note: Amounts may not calculate due to rounding.

27


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
 
2016
 
2015
 
Net production volumes (1)
 
 
 
 
 
 
 
Oil (MMBbl)
4.1

 
5.2

 
(1.1)

 
(21
)%
Gas (Bcf)
35.7

 
45.9

 
(10.2
)
 
(22
)%
NGLs (MMBbl)
3.3

 
3.9

 
(0.6)

 
(14
)%
Equivalent (MMBOE)
13.4

 
16.8

 
(3.4)

 
(20
)%
Average net daily production (1)
 
 
 
 
 
 
 
Oil (MBbl per day)
45.3

 
58.1

 
(12.8
)
 
(22
)%
Gas (MMcf per day)
392.2

 
510.3

 
(118.1
)
 
(23
)%
NGLs (MBbl per day)
36.8

 
43.3

 
(6.5
)
 
(15
)%
Equivalent (MBOE per day)
147.5

 
186.4

 
(39.0
)
 
(21
)%
Oil, gas, and NGL production revenue (in millions)
 
 
 
 
 
 
Oil production revenue
$
105.8

 
$
201.5

 
$
(95.7
)
 
(47
)%
Gas production revenue
66.6

 
126.8

 
(60.2
)
 
(47
)%
NGL production revenue
39.4

 
65.0

 
(25.6
)
 
(39
)%
Total
$
211.8

 
$
393.3

 
$
(181.5
)
 
(46
)%
Oil, gas, and NGL production expense (in millions)
 
 
 
 
 
 
Lease operating expense
$
50.8

 
$
66.5

 
$
(15.7
)
 
(24
)%
Transportation costs
81.3

 
102.1

 
(20.8
)
 
(20
)%
Production taxes
8.9

 
18.8

 
(9.9
)
 
(53
)%
Ad valorem tax expense
3.5

 
8.8

 
(5.3
)
 
(60
)%
Total (1)
$
144.5

 
$
196.2

 
$
(51.6
)
 
(26
)%
Realized price (before the effect of derivative settlements)
 
 
 
 
 
 
 
Oil (per Bbl)
$
25.67

 
$
38.56

 
$
(12.89
)
 
(33
)%
Gas (per Mcf)
$
1.87

 
$
2.76

 
$
(0.89
)
 
(32
)%
NGLs (per Bbl)
$
11.76

 
$
16.67

 
$
(4.91
)
 
(29
)%
Per BOE
$
15.78

 
$
23.44

 
$
(7.66
)
 
(33
)%
Per BOE Data (1)
 
 
 
 
 
 
 
Production costs:
 
 
 
 
 
 
 
Lease operating expense
$
3.79

 
$
3.96

 
$
(0.17
)
 
(4
)%
Transportation costs
$
6.06

 
$
6.08

 
$
(0.02
)
 
 %
Production taxes
$
0.66

 
$
1.12

 
$
(0.46
)
 
(41
)%
Ad valorem tax expense
$
0.27

 
$
0.52

 
$
(0.25
)
 
(48
)%
General and administrative
$
2.40

 
$
2.60

 
$
(0.20
)
 
(8
)%
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
15.96

 
$
12.96

 
$
3.00

 
23
 %
Derivative settlement gain (2)
$
10.96

 
$
9.61

 
$
1.35

 
14
 %
 
 
 
 
 
 
 
 
Earnings per share information
 
 
 
 
 
 
 
Basic net loss per common share
$
(5.10
)
 
$
(0.79
)
 
$
(4.31
)
 
546
 %
Diluted net loss per common share
$
(5.10
)
 
$
(0.79
)
 
$
(4.31
)
 
546
 %
Basic weighted-average common shares outstanding (in thousands)
68,077

 
67,463

 
614

 
1
 %
Diluted weighted-average common shares outstanding (in thousands)
68,077

 
67,463

 
614

 
1
 %
____________________________________________
(1) Amount and percentage changes may not calculate due to rounding.
(2) Derivative settlements for the three months ended March 31, 2016, and 2015, respectively, are included within the derivative gain line item in the accompanying statements of operations.


28


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 daily production for the three months ended March 31, 2016, decreased 21 percent, compared with the same period in 2015, due to the sale of our Mid-Continent assets during the second quarter of 2015, which produced 11.1 MBOE per day during the first quarter 2015, and our reduced drilling and completion activity throughout 2015 and into 2016. Overall, we expect our production to be relatively flat on a quarterly basis for the remainder of 2016, resulting in an overall decrease in production for the full-year 2016 compared to the full-year 2015. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2016, and 2015 below for additional discussion.

Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized price on a per BOE basis for the three months ended March 31, 2016, decreased 33 percent compared to the same period in 2015 as a result of lower commodity prices.

Lease operating expense (“LOE”) on a per BOE basis for the three months ended March 31, 2016, decreased four percent compared to the same period in 2015, due to our recurring LOE declining at a faster rate than production. This decrease was a result of divesting our Mid-Continent assets in the second quarter of 2015 and also a result of service providers lowering costs in light of the weak commodity price environment. Our LOE is comprised of recurring LOE and workover expense. 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 the full-year 2016, we expect LOE on a per BOE basis to be flat to slightly lower than full-year 2015.

Transportation expense on a per BOE basis was flat for the three months ended March 31, 2016, compared to the same period in 2015 as the decline in absolute transportation expense was in-line with the decline in production volumes. We generally expect transportation costs to trend with production; therefore, we expect transportation costs on a per BOE basis to be relatively flat throughout 2016.

Production taxes on a per BOE basis for the three months ended March 31, 2016, decreased 41 percent compared to the same period in 2015. This decrease was driven largely by the decrease in production revenues, as well as a decrease in our company-wide production tax rate as a result of divesting our Mid-Continent properties in the second quarter of 2015. We generally expect absolute production tax expense to trend with oil, gas, and NGL production revenue. Product mix, the location of production, and incentives to encourage oil and gas development can all impact or change the amount of production tax we recognize.

Ad valorem tax expense on a per BOE basis for the three months ended March 31, 2016, decreased 48 percent compared to the same period in 2015. The decrease in ad valorem tax expense on a per BOE basis for the three months ended March 31, 2016, is primarily due to the lower valuation of properties subject to ad valorem taxes in 2016 as a result of declining commodity prices. We expect ad valorem tax expense to fluctuate throughout the year on an absolute and on a per BOE basis as valuations and county tax rates are finalized, with an overall decrease on a per BOE basis when comparing full-year 2016 to full-year 2015.

General and administrative (“G&A”) expense on a per BOE basis for the three months ended March 31, 2016, decreased eight percent compared to the same period in 2015, as our absolute G&A expense decreased at a faster rate than the decrease in production volumes. Absolute G&A expense decreased in the first quarter of 2016 compared to the same period in 2015 primarily due to lower headcount in 2016 than in 2015, and the exit and disposal costs incurred during the first quarter of 2015 relating to the closure of our Tulsa, Oklahoma office. Overall, we expect G&A expense on a per BOE basis to be lower in 2016 compared to 2015, based on the factors impacting the quarterly decline discussed herein.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis for the three months ended March 31, 2016, increased 23 percent compared to the same period in 2015. Our DD&A rate can fluctuate as a result of impairments, planned and closed divestitures, and changes in the mix of our production and the underlying proved reserve volumes. The decrease in commodity prices resulted in a decrease in proved reserve volumes and consequently an increased DD&A rate in the first quarter of 2016. We expect DD&A expense on a per BOE basis to decrease for the remainder of 2016 due to reductions in the cost basis to be depleted as a result of proved properties that were impaired at March 31, 2016. Additionally, at the end of the first quarter of 2016, we began marketing for sale certain non-core assets in each of our operating regions, which will reduce DD&A expense on a per BOE basis as these assets are held for sale and therefore no DD&A expense will be recorded for these assets. If commodity prices remain at current levels or decline further, downward revisions of proved reserves due to commodity price impacts may be significant and increase our DD&A rate, offsetting our expected decrease. An increase in commodity prices could lead to upward revisions to proved reserves and thus further lower our DD&A rate.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2016, and 2015 below for additional discussion on operating expenses.

29


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 loss per common share calculations. For the three months ended March 31, 2016, and 2015, we recorded a loss from continuing operations and all potentially dilutive shares were anti-dilutive and excluded from the calculation of diluted net loss per common share.

Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2016, and 2015

Oil, gas, and NGL production, revenue, and 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, 2016, and 2015:

 
Average Net Daily Production
Decrease
 
Production Revenue Decrease
 
Production Costs
Decrease
 
(MBOE/d)
 
(in millions)
 
(in millions)
South Texas & Gulf Coast
(25.3
)
 
$
(117.6
)
 
$
(31.7
)
Rocky Mountain

 
(33.6
)
 
(5.1
)
Permian
(2.6
)
 
(15.2
)
 
(7.8
)
Mid-Continent (1)
(11.1
)
 
(15.1
)
 
(7.0
)
Total
(39.0
)
 
$
(181.5
)
 
$
(51.6
)
____________________________________________
(1) We divested our Mid-Continent assets in the second quarter of 2015.

Our 20 percent decrease in net equivalent production volumes combined with a 33 percent decrease in realized prices on a per BOE basis, resulted in a 46 percent decrease in oil, gas, and NGL production revenue between the two periods.

Total production costs decreased 26 percent for the three months ended March 31, 2016, compared with the same period of 2015, primarily due to a 20 percent decrease in net equivalent production volumes as a result of reduced activity and the divestiture of our Mid-Continent assets in the second quarter of 2015, lower service provider costs, and decreased production taxes due to lower commodity prices.

Please refer to A three-month overview of selected production and financial information, including trends above for realized prices received before the effects of derivative settlements for the three months ended March 31, 2016, and 2015, and discussion of trends on a per BOE basis. We expect our realized prices to trend with commodity prices.

Net loss on divestiture activity

The following table presents our net loss on divestiture activity for the periods presented:

 
For the Three Months Ended March 31,
 
2016
 
2015
 
(in millions)
Net loss on divestiture activity
$
(69.0
)
 
$
(35.8
)

The net loss on divestiture activity recorded for the three months ended March 31, 2016, is largely due to the write-down to fair value of certain assets held for sale. Similarly, the net loss on divestiture activity for the three months ended March 31, 2015, was largely a result of the write-down to fair value of certain assets held for sale in our Mid-Continent region. Please refer to Note 3 – Assets Held for Sale in Part I, Item 1 of this report for additional discussion.

 




30


Other operating revenues

The following table presents our other operating revenues for the periods presented:
 
For the Three Months Ended March 31,
 
2016
 
2015
 
(in millions)
Other operating revenues
$
0.3