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EX-32.1 - EXHIBIT 32.1 - SM Energy Cosm-321906certifications331.htm
EX-31.2 - EXHIBIT 31.2 - SM Energy Cosm-312certificationwpursel.htm
EX-31.1 - EXHIBIT 31.1 - SM Energy Cosm-311certificationjottoso.htm
EX-12.1 - EXHIBIT 12.1 - SM Energy Coexhibit121-ratioofearnings.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

OR

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

For the transition period from ___________ to ___________

Commission File Number 001-31539
smelogohoriz4c1200204.jpg
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
 
41-0518430
(I.R.S. Employer
Identification No.)
1775 Sherman Street, Suite 1200, Denver, Colorado
(Address of principal executive offices)
 
80203
(Zip Code)
(303) 861-8140
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
 
Accelerated filer o
 
 
 
Non-accelerated filer o  
(Do not check if a smaller reporting company)
 
Smaller reporting company o
 
 
 
Emerging growth company o 
 
 
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
As of April 25, 2018, the registrant had 111,687,016 shares of common stock, $0.01 par value, outstanding.



1


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 data)
 
March 31,
2018
 
December 31,
2017
 ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
643,337

 
$
313,943

Accounts receivable
192,562

 
160,154

Derivative assets
77,296

 
64,266

Prepaid expenses and other
9,997

 
10,752

Total current assets
923,192

 
549,115

Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
5,824,014

 
6,139,379

Accumulated depletion, depreciation, and amortization
(2,893,674
)
 
(3,171,575
)
Unproved oil and gas properties
1,986,070

 
2,047,203

Wells in progress
405,549

 
321,347

Oil and gas properties held for sale, net
234,618

 
111,700

Other property and equipment, net of accumulated depreciation of $52,483 and $49,985, respectively
112,972

 
106,738

Total property and equipment, net
5,669,549

 
5,554,792

Noncurrent assets:
 
 
 
Derivative assets
35,128

 
40,362

Other noncurrent assets
32,119

 
32,507

Total noncurrent assets
67,247

 
72,869

Total assets
$
6,659,988

 
$
6,176,776

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
468,108

 
$
386,630

Derivative liabilities
181,068

 
172,582

Total current liabilities
649,176

 
559,212

Noncurrent liabilities:
 
 
 
Revolving credit facility

 

Senior Notes, net of unamortized deferred financing costs
2,770,979

 
2,769,663

Senior Convertible Notes, net of unamortized discount and deferred financing costs
141,269

 
139,107

Asset retirement obligations
85,407

 
103,026

Asset retirement obligations associated with oil and gas properties held for sale
23,139

 
11,369

Deferred income taxes
178,423

 
79,989

Derivative liabilities
53,712

 
71,402

Other noncurrent liabilities
45,786

 
48,400

Total noncurrent liabilities
3,298,715

 
3,222,956

 
 
 
 
Commitments and contingencies (note 6)


 


 
 
 
 
Stockholders equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,687,016 and 111,687,016 shares, respectively
1,117

 
1,117

Additional paid-in capital
1,747,035

 
1,741,623

Retained earnings (1)
980,444

 
665,657

Accumulated other comprehensive loss (1)
(16,499
)
 
(13,789
)
Total stockholders equity
2,712,097

 
2,394,608

Total liabilities and stockholders equity
$
6,659,988

 
$
6,176,776

____________________________________________
(1) The Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. Please refer to Note 1 - Summary of Significant Accounting Policies for further detail.
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 data)
 
For the Three Months Ended 
 March 31,
 
2018
 
2017
 
 
 
(as adjusted)
Operating revenues and other income:
 
 
 
Oil, gas, and NGL production revenue
$
382,886

 
$
333,198

Net gain on divestiture activity
385,369

 
37,463

Other operating revenues
1,340

 
2,077

Total operating revenues and other income
769,595


372,738

Operating expenses:





Oil, gas, and NGL production expense
120,879

 
138,046

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
130,473

 
137,812

Exploration
13,727

 
11,817

Abandonment and impairment of unproved properties
5,625

 

General and administrative
27,682

 
28,817

Net derivative (gain) loss
7,529

 
(114,774
)
Other operating expenses
4,612

 
4,859

Total operating expenses
310,527


206,577

Income from operations
459,068


166,161

Interest expense
(43,085
)
 
(46,953
)
Loss on extinguishment of debt

 
(35
)
Other non-operating income (expense), net
409

 
(233
)
Income before income taxes
416,392


118,940

Income tax expense
(98,991
)
 
(44,506
)
Net income
$
317,401


$
74,434

 





Basic weighted-average common shares outstanding
111,696

 
111,258

Diluted weighted-average common shares outstanding
112,879

 
111,329

Basic net income per common share
$
2.84

 
$
0.67

Diluted net income per common share
$
2.81

 
$
0.67

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,
 
 
2018
 
2017
Net income
$
317,401

 
$
74,434

Other comprehensive income (loss), net of tax:
 
 
 
Pension liability adjustment
260

 
(567
)
Total other comprehensive income (loss), net of tax
260

 
(567
)
Total comprehensive income
$
317,661

 
$
73,867

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,
 
2018
 
2017
 
 
 
(as adjusted)
Cash flows from operating activities:
 
 
 
Net income
$
317,401

 
$
74,434

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Net gain on divestiture activity
(385,369
)
 
(37,463
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
130,473

 
137,812

Abandonment and impairment of unproved properties
5,625

 

Stock-based compensation expense
5,412

 
5,455

Net derivative (gain) loss
7,529

 
(114,774
)
Derivative settlement gain (loss)
(24,528
)
 
7

Amortization of debt discount and deferred financing costs
3,866

 
4,946

Loss on extinguishment of debt

 
35

Deferred income taxes
98,366

 
33,225

Other, net
(2,527
)
 
3,376

Changes in current assets and liabilities:
 
 
 
Accounts receivable
(4,464
)
 
30,407

Prepaid expenses and other
755

 
178

Accounts payable and accrued expenses
(8,825
)
 
(5,497
)
Accrued derivative settlements
(3,579
)
 
2,838

Net cash provided by operating activities
140,135

 
134,979

 
 
 
 
Cash flows from investing activities:
 
 
 
Net proceeds from the sale of oil and gas properties
490,780

 
744,333

Capital expenditures
(301,521
)
 
(154,401
)
Acquisition of proved and unproved oil and gas properties

 
(75,105
)
Net cash provided by investing activities
189,259

 
514,827

 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from credit facility

 
397,500

Repayment of credit facility

 
(397,500
)
Cash paid to repurchase Senior Notes

 
(2,344
)
Cash paid for extinguishment of debt

 
(13
)
Other, net

 
(160
)
Net cash used in financing activities

 
(2,517
)
 
 
 
 
Net change in cash, cash equivalents, and restricted cash (1)
329,394

 
647,289

Cash, cash equivalents, and restricted cash at beginning of period (1)
313,943

 
12,372

Cash, cash equivalents, and restricted cash at end of period (1)
$
643,337

 
$
659,661

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)
(in thousands)
Supplemental schedule of additional cash flow information and non-cash activities:
 
For the Three Months Ended 
 March 31,
 
2018
 
2017
 
 
 
(as adjusted)
Operating activities:
 
 
 
Cash paid for interest, net of capitalized interest
$
(40,060
)
 
$
(42,872
)
Net cash (paid) refunded for income taxes
$
(106
)
 
$
15

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

 
$
27,214

 
 
 
 
Supplemental non-cash investing activities:
 
 
 
Carrying value of properties exchanged
$

 
$
24,544

 
 
 
 
Supplemental non-cash financing activities:
 
 
 
Non-cash loss on extinguishment of debt, net
$

 
$
22

Dividends declared, but not paid
$
5,584

 
$
5,563

____________________________________________
(1) 
Refer to Note 1 - Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying condensed consolidated balance sheets (“accompanying balance sheets”).
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 - Summary of Significant Accounting Policies
Description of Operations
SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report) in onshore North America.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of March 31, 2018, and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements.
Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies to the Company’s 2017 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2017 Form 10-K.
Recently Issued Accounting Standards
Effective December 31, 2017, the Company early adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) and FASB ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows and ASU 2016-18 is intended to clarify guidance on the classification and presentation of restricted cash and restricted cash equivalents in the statement of cash flows. Please refer to Note 1 - Summary of Significant Accounting Policies in the Company’s 2017 Form 10-K for more information.

8


The accompanying condensed consolidated statements of cash flows (“accompanying statements of cash flows”) line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 for the three months ended March 31, 2017, are summarized as follows:
 
For the Three Months Ended March 31, 2017
 
As Reported
 
As Adjusted
 
(in thousands)
Cash flows from operating activities:
 
 
 
Non-cash loss on extinguishment of debt, net
$
22

 
N/A

Loss on extinguishment of debt
N/A

 
$
35

Net cash provided by operating activities
$
134,966

 
$
134,979

 
 
 
 
Cash flows from investing activities:
 
 
 
Other, net
$
2,486

 
N/A

Net cash provided by investing activities
$
517,313

 
$
514,827

 
 
 
 
Cash flows from financing activities:
 
 
 
Cash paid for extinguishment of debt
N/A

 
$
(13
)
Net cash used in financing activities
$
(2,504
)
 
$
(2,517
)
 
 
 
 
Net change in cash and cash equivalents
$
649,775

 
N/A

Net change in cash, cash equivalents, and restricted cash
N/A

 
$
647,289

Cash and cash equivalents at beginning of period
$
9,372

 
N/A

Cash, cash equivalents, and restricted cash at beginning of period
N/A

 
$
12,372

Cash and cash equivalents at end of period
$
659,147

 
N/A

Cash, cash equivalents, and restricted cash at end of period
N/A

 
$
659,661

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets:
 
As of March 31, 2018
 
As of December 31, 2017
 
(in thousands)
Cash and cash equivalents
$
643,337

 
$
313,943

Restricted cash

 

Total cash, cash equivalents, and restricted cash
$
643,337

 
$
313,943

Effective January 1, 2018, the Company adopted FASB ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and all related ASUs (“ASU 2014-09”). Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The Company adopted ASU 2014-09 using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adopting ASU 2014-09, the Company expanded its disclosures to comply with the expanded disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.
Effective January 1, 2018, the Company adopted FASB ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item, outside of operating items, which the Company adopted with retrospective application. In addition, only the service

9


component of the net benefit cost is eligible for capitalization, which the Company adopted with prospective application. Please refer to Note 1 - Summary of Significant Accounting Policies in the Company’s 2017 Form 10-K for more information.
The March 31, 2017, accompanying condensed consolidated statements of operations (“accompanying statements of operations”) line items that were adjusted as a result of the adoption of ASU 2017-07 are summarized as follows:
 
For the Three Months Ended March 31, 2017
 
As Reported
 
As Adjusted
 
(in thousands)
Operating expenses:
 
 
 
Exploration
$
11,978

 
$
11,817

General and administrative
$
29,224

 
$
28,817

Total operating expenses
$
207,145

 
$
206,577

 
 
 
 
Income from operations
$
165,593

 
$
166,161

 
 
 
 
Other non-operating income (expense), net
$
335

 
$
(233
)
Effective January 1, 2018, the Company early adopted ASU No. 2018-02, Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”) by applying the changes in the period of adoption. ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the enactment into law on December 22, 2017 of H.R.1, formally the Tax Cuts and Jobs Act (the “2017 Tax Act”). As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires recognition of right-of-use assets and lease payment liabilities on the balance sheet by lessees for virtually all leases currently classified as operating leases. The Company has established a cross-functional project team and is leveraging external consultants to evaluate the impacts of ASU 2016-02 and other related guidance, which includes an analysis of non-cancelable leases, drilling rig contracts, certain midstream agreements, and other existing arrangements. Further, the Company is also evaluating policies, controls, and processes that will be necessary to support the additional accounting and disclosure requirements. The Company will adopt ASU 2016-02 and other related guidance on January 1, 2019, using the modified retrospective approach. Adoption of this guidance is expected to result in an increase in right-of-use assets and related liabilities on the Company’s consolidated balance sheets, however, the full impact to the Company’s financial statements and related disclosures is still being evaluated.
Other than as disclosed above or in the Company’s 2017 Form 10-K, there are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of March 31, 2018, and through the filing of this report.
Note 2 - Revenue from Contracts with Customers
The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Permian, South Texas & Gulf Coast, and Rocky Mountain regions. During the three months ended March 31, 2018, the Company entered into two definitive agreements to sell substantially all of its producing properties and related assets in its Rocky Mountain region. One transaction closed in the first quarter of 2018 and the second transaction is expected to close in the second quarter of 2018. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions for additional detail. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers.
    

10


The following tables present the disaggregation of oil, gas, and NGL production revenue by product type for each of the Company’s operating regions:
 
For the Three Months Ended March 31, 2018
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Total
 
(in thousands)
Oil, gas, and NGL production revenue:
 
 
 
 
 
 
 
Oil production revenue
$
205,794

 
$
19,583

 
$
35,683

 
$
261,060

Gas production revenue
24,876

 
52,733

 
1,500

 
79,109

NGL production revenue
124

 
41,770

 
823

 
42,717

Total oil, gas, and NGL production revenue
$
230,794

 
$
114,086

 
$
38,006

 
$
382,886

Relative percentage
60
%
 
30
%
 
10
%
 
100
%
 
For the Three Months Ended March 31, 2017
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain
 
Total
 
(in thousands)
Oil, gas, and NGL production revenue:
 
 
 
 
 
 
 
Oil production revenue
$
81,499

 
$
38,864

 
$
47,261

 
$
167,624

Gas production revenue
11,309

 
88,201

 
1,641

 
101,151

NGL production revenue
147

 
63,357

 
919

 
64,423

Total oil, gas, and NGL production revenue
$
92,955

 
$
190,422

 
$
49,821

 
$
333,198

Relative percentage
28
%
 
57
%
 
15
%
 
100
%
The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has four general categories under which oil, gas, and NGL production revenue is generated. Each of the Company’s operating regions generate production revenue from a combination of some or all of the four different contract types summarized below:
1)
The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.
2)
The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue in the table above and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.
3)
The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.

11


4)
The Company has certain midstream processing arrangements where unprocessed gas is delivered to the inlet of the midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the processed NGLs and residue gas and remits the proceeds to the Company from the sale of the products to third-party customers. In these arrangements, control transfers at the tailgate of the midstream processing facility for both products. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.
Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”) relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells the Company has an ownership interest in. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are generally received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within accounts receivable on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of March 31, 2018, and December 31, 2017, were $97.1 million and $96.6 million, respectively. As of March 31, 2018, only an immaterial balance remained related to accounts receivable from customers that were outstanding as of December 31, 2017. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, NYMEX, OPIS and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized for the three months ended March 31, 2018, that related to performance obligations satisfied in prior reporting periods was immaterial.
Note 3 - Divestitures, Assets Held for Sale, and Acquisitions
Divestitures
On March 26, 2018, the Company divested approximately 112,000 net acres of its Powder River Basin assets (the “PRB Divestiture”), for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $490.8 million, subject to final purchase price adjustments, and recorded an estimated net gain of $409.2 million for the three months ended March 31, 2018. These assets were classified as held for sale as of December 31, 2017.
On March 10, 2017, the Company closed the divestiture of its outside-operated Eagle Ford shale assets, including ownership interest in related midstream assets, for net divestiture proceeds received at closing, of $747.4 million and net divestiture proceeds of $744.1 million after final purchase price adjustments. The Company recorded a net estimated gain of $398.1 million for the three months ended March 31, 2017, and a final net gain of $396.8 million related to these divested assets for the year ended December 31, 2017.

12


Assets Held for Sale
Assets are classified as held for sale when the Company commits to a plan to sell the assets and it is probable the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. When assets no longer meet the criteria of assets held for sale, they are measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense that would have been recognized, or the fair value at the date they are reclassified to assets held for use. Any gain or loss recognized on assets held for sale or on assets held for sale that are subsequently reclassified to assets held for use is reflected in the net gain on divestiture activity line item in the accompanying statements of operations.
As of March 31, 2018, the accompanying balance sheets present $234.6 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consist of the Company’s remaining assets in the Williston Basin located in Divide County, North Dakota (“Divide County”), and the Company’s third-party operated assets, known as Halff East, located in Upton County, Texas. A corresponding asset retirement obligation liability of $23.1 million is separately presented for these assets held for sale. Certain assets held for sale were written down by $24.1 million to reflect fair value less estimated costs to sell upon classification as held for sale during the three months ended March 31, 2018.
The Company has entered into definitive agreements for the sale of its Divide County assets (the “Divide County Divestiture”) and its Halff East assets in the Midland Basin (the “Halff East Divestiture”) for a total gross purchase price of $292.3 million, subject to certain price adjustments. The Company expects both of these divestitures to close during the second quarter of 2018. These closings are subject to the satisfaction of customary closing conditions, and there can be no assurance that either transaction will close on time or at all.
The following table presents loss before income taxes for the three months ended March 31, 2018, and 2017, for the Company’s Divide County assets held for sale as of March 31, 2018, which are considered a significant asset group.
 
For the Three Months Ended March 31,
 
2018
 
2017
 
(in thousands)
Loss before income taxes (1)
$
(11,497
)
 
$
(332,719
)
____________________________________________
(1) 
Loss before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, and impairment expense.
As of March 31, 2017, the Company had certain assets in its Rocky Mountain region classified as held for sale. These assets were written down by $359.6 million to reflect fair value less estimated costs to sell upon classification as held for sale during the three months ended March 31, 2017.
Acquisitions
Subsequent to March 31, 2018, the Company acquired approximately 760 net acres of unproved properties in Martin County, Texas, for $24.6 million. Under authoritative accounting guidance, this transaction was considered an asset acquisition. Therefore, the properties will be recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs will be capitalized as a component of the cost of the assets acquired.

13


Note 4 - Income Taxes
The income tax expense recorded for the three months ended March 31, 2018, and 2017, differs from the amounts that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes primarily due to the effect of state income taxes, excess tax benefits and deficiencies from share-based payment awards, changes in valuation allowances, and accumulated impacts of other smaller permanent differences. The quarterly rate can also be affected by the proportional impacts of forecasted net income or loss as of each period end presented.
The provision for income taxes for the three months ended March 31, 2018, and 2017, consisted of the following:
 
For the Three Months Ended 
 March 31,
 
2018
 
2017
 
(in thousands)
Current portion of income tax expense:
 
 
 
Federal
$

 
$
(7,439
)
State
(625
)
 
(3,842
)
Deferred portion of income tax expense
(98,366
)
 
(33,225
)
Income tax expense
$
(98,991
)
 
$
(44,506
)
Effective tax rate
23.8
%
 
37.4
%
The enactment of the 2017 Tax Act on December 22, 2017, reduced the Company’s federal tax rate for 2018 and future years from 35 percent to 21 percent. Although the Company believes it has properly analyzed the tax accounting impacts of the 2017 Tax Act, it will continue to monitor provisions with discrete rate impacts, such as the limitation on executive compensation for subsequent events and guidance within the one year measurement period. There are no new estimates or finalized income tax items associated with the 2017 Tax Act included in income tax expense for the three months ended March 31, 2018.
On a year-to-date basis, a change in the Company’s effective tax rate between reporting periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income or loss from Company activities among multiple state tax jurisdictions. Cumulative effects of state tax rate changes are reflected in the period legislation is enacted. However, state rate differences between reported periods were not significant. Excess tax benefits and deficiencies from share-based payment awards impact the Company’s effective tax rate between periods.
In 2017, the Company re-evaluated various factors affecting deferred tax assets related to net operating losses and tax credits, and determined utilization would be appropriate. The change in the current portion of income tax expense between periods reflects the effect of this determination. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013.
Note 5 - Long-Term Debt
Credit Agreement
The Company’s Fifth Amended and Restated Credit Agreement, as amended, (the “Credit Agreement”) provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019. As of March 31, 2018, the Company’s borrowing base and aggregate lender commitments were $925 million, which were unchanged from December 31, 2017. Subsequent to March 31, 2018, as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were increased to $1.4 billion and $1.0 billion, respectively. The increase in the borrowing base was primarily driven by the increased value of the Company’s estimated proved reserves at December 31, 2017. The next scheduled redetermination date is October 1, 2018.
The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement and was in compliance with all such covenants as of March 31, 2018, and through the filing of this report.
Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Credit Agreement as presented in Note 5 - Long-Term Debt in the Company’s 2017 Form 10-K.  Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and Alternate Base Rate and swingline loans accrue interest at the prime rate, plus the applicable margin from the utilization grid.  Commitment fees are accrued on the

14


unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in interest expense in the accompanying statements of operations.
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of April 25, 2018, March 31, 2018, and December 31, 2017:
 
As of April 25, 2018
 
As of March 31, 2018
 
As of December 31, 2017
 
(in thousands)
Credit facility balance (1)
$

 
$

 
$

Letters of credit (2)
200

 
200

 
200

Available borrowing capacity
999,800

 
924,800

 
924,800

Total aggregate lender commitment amount
$
1,000,000

 
$
925,000

 
$
925,000

____________________________________________
(1) 
Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $2.7 million and $3.1 million as of March 31, 2018, and December 31, 2017, respectively.
(2) 
Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
Senior Notes
The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of March 31, 2018, and December 31, 2017, consisted of the following:
 
As of March 31, 2018
 
As of December 31, 2017
 
Principal Amount
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
Principal Amount
 
Unamortized Deferred Financing Costs
 
Senior Notes, Net of Unamortized Deferred Financing Costs
 
(in thousands)
6.50% Senior Notes due 2021
$
344,611

 
$
2,483

 
$
342,128

 
$
344,611

 
$
2,656

 
$
341,955

6.125% Senior Notes due 2022
561,796

 
5,505

 
556,291

 
561,796

 
5,800

 
555,996

6.50% Senior Notes due 2023
394,985

 
3,525

 
391,460

 
394,985

 
3,707

 
391,278

5.0% Senior Notes due 2024
500,000

 
5,380

 
494,620

 
500,000

 
5,610

 
494,390

5.625% Senior Notes due 2025
500,000

 
6,487

 
493,513

 
500,000

 
6,714

 
493,286

6.75% Senior Notes due 2026
500,000

 
7,033

 
492,967

 
500,000

 
7,242

 
492,758

Total
$
2,801,392

 
$
30,413

 
$
2,770,979

 
$
2,801,392

 
$
31,729

 
$
2,769,663

The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes.  The Company is subject to certain covenants under the indentures governing the Senior Notes and was in compliance with all such covenants as of March 31, 2018, and through the filing of this report. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.

15


Senior Convertible Notes
The Company’s Senior Convertible Notes consist of $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. Please refer to Note 5 - Long-Term Debt in the Company’s 2017 Form 10-K for additional detail on the Company’s Senior Convertible Notes and associated capped call transactions.
The Senior Convertible Notes were not convertible at the option of holders as of March 31, 2018, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of March 31, 2018, did not exceed the principal amount. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.6 million and $2.4 million for the three months ended March 31, 2018, and 2017, respectively.
There have been no changes to the initial net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets. The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets as of March 31, 2018, and December 31, 2017, consisted of the following:
 
As of March 31, 2018
 
As of December 31, 2017
 
(in thousands)
Principal amount of Senior Convertible Notes
$
172,500

 
$
172,500

Unamortized debt discount
(28,251
)
 
(30,183
)
Unamortized deferred financing costs
(2,980
)
 
(3,210
)
Net carrying amount
$
141,269

 
$
139,107

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all such covenants as of March 31, 2018, and through the filing of this report.
Note 6 - Commitments and Contingencies
Commitments
As of March 31, 2018, the Company had total gathering, processing, transportation throughput, and purchase commitments with various third parties that require delivery of a minimum quantity of 18 MMBbl of oil, 769 Bcf of gas, and 23 MMBbl of produced water through 2028 and a minimum purchase quantity of 10 MMBbl of water by 2022. If the Company fails to deliver or purchase any product, as applicable, the aggregate undiscounted future deficiency payments as of March 31, 2018, would total approximately $461.5 million. As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to these commitments.
The Company entered into new and amended drilling rig and completion contracts during the first three months of 2018 and subsequent to March 31, 2018. As of the filing of this report, the Company’s drilling rig and completion contract commitments totaled $158.3 million; however, if the Company terminated these contracts immediately, it would incur penalties of $40.6 million.
Additionally, as of March 31, 2018, the Company had fixed price contracts with various third parties to purchase electricity through 2027 for a total of $31.7 million. As of the filing of this report, the Company expects to meet these purchase commitments.
There were no other material changes in commitments during the first three months of 2018. Please refer to Note 6 - Commitments and Contingencies in the Company’s 2017 Form 10-K for additional discussion of the Company’s commitments.

16


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 results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.
Note 7 - Compensation Plans
Performance Share Units
The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity incentive compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three-year measurement period. The performance criteria for PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. 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 was $2.4 million and $2.5 million for the three months ended March 31, 2018, and 2017, respectively. As of March 31, 2018, there was $15.6 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2020. There have been no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2018.
 
 
 
 
Employee Restricted Stock Units
The Company grants restricted stock units (“RSUs”) to eligible employees as part of its long-term equity incentive compensation program. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards.
Total compensation expense recorded for employee RSUs was $2.7 million and $2.5 million for the three months ended March 31, 2018, and 2017, respectively. As of March 31, 2018, there was $16.2 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2020. There have been no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2018.
 
 
 
 
Note 8 - Pension Benefits
Pension Plans
The Company has a non-contributory defined benefit pension plan covering employees 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”). Effective as of January 1, 2016, the Company froze the Pension Plans to new participants, and employees eligible to participate in the Pension Plans prior to them being frozen will continue to earn benefits.

17


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,
 
2018
 
2017
 
(in thousands)
Service cost
$
1,660

 
$
2,050

Interest cost
673

 
727

Expected return on plan assets that reduces periodic pension benefit cost
(561
)
 
(559
)
Amortization of prior service cost
4

 
4

Amortization of net actuarial loss
324

 
396

Net periodic benefit cost
$
2,100

 
$
2,618

Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. As a result of the adoption of ASU 2017-07, the service cost component of net periodic benefit cost for the Pension Plans is presented as an operating expense within the general and administrative and exploration expense line items on the accompanying statements of operations while the other components of net periodic benefit cost for the Pension Plans are presented as non-operating expenses within the other non-operating income (expense), net line item on the accompanying statements of operations. Please refer to Note 1 - Summary of Significant Accounting Policies for further detail.
Contributions
The Company contributed $4.1 million to the Qualified Pension Plan during the three months ended March 31, 2018.

18


Note 9 - Earnings Per Share
Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the three months ended March 31, 2018, and 2017, and therefore the Senior Convertible Notes had no dilutive impact. Please refer to Note 1 - Summary of Significant Accounting Policies in the Company’s 2017 Form 10-K for additional detail on these potentially dilutive securities.
The following table sets forth the calculations of basic and diluted net income per common share:
 
For the Three Months Ended 
 March 31,
 
2018
 
2017
 
(in thousands, except per share data)
Net income
$
317,401

 
$
74,434

 
 
 
 
Basic weighted-average common shares outstanding
111,696

 
111,258

Dilutive effect of non-vested RSUs and contingent PSUs
1,183

 
71

Dilutive effect of Senior Convertible Notes

 

Diluted weighted-average common shares outstanding
112,879

 
111,329

 
 
 
 
Basic net income per common share
$
2.84

 
$
0.67

Diluted net income per common share
$
2.81

 
$
0.67

Note 10 - Derivative Financial Instruments
Summary of Oil, Gas, and NGL Derivative Contracts in Place
The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of March 31, 2018, all derivative counterparties were members of the Company’s credit facility lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas, and swap arrangements for 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.

19


As of March 31, 2018, the Company had commodity derivative contracts outstanding as summarized in the tables below:
Oil Swaps


Contract Period
 
NYMEX WTI Volumes
 
Weighted-Average
 Contract Price
 
 
(MBbl)
 
(per Bbl)
Second quarter 2018
 
1,534

 
$
49.57

Third quarter 2018
 
1,769

 
$
49.77

Fourth quarter 2018
 
1,894

 
$
49.87

2019
 
1,940

 
$
50.70

Total
 
7,137

 
 
Oil Collars
Contract Period
 
NYMEX WTI
 Volumes
 
Weighted-
Average Floor
 Price
 
Weighted-
Average Ceiling
 Price
 
 
(MBbl)
 
(per Bbl)
 
(per Bbl)
Second quarter 2018
 
1,459

 
$
50.00

 
$
59.03

Third quarter 2018
 
1,948

 
$
50.00

 
$
58.61

Fourth quarter 2018
 
2,222

 
$
50.00

 
$
58.44

2019
 
5,908

 
$
47.65

 
$
59.19

Total
 
11,537

 
 
 
 
Oil Basis Swaps


Contract Period
 
Midland-Cushing Volumes
 
Weighted-Average
 Contract Price (1)
 
 
(MBbl)
 
(per Bbl)
Second quarter 2018
 
2,392

 
$
(1.03
)
Third quarter 2018
 
3,018

 
$
(1.06
)
Fourth quarter 2018
 
3,327

 
$
(1.08
)
2019
 
5,788

 
$
(1.09
)
Total
 
14,525

 
 
____________________________________________
(1)  
Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma.
Gas Swaps
Contract Period
 
Sold
Volumes
 
Weighted-Average
 Contract Price
 
Purchased Volumes
 
Weighted-Average Contract Price
 
Net
Volumes
 
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
 
(per MMBtu)
 
(BBtu)
Second quarter 2018
 
23,507

 
$
3.31

 
(7,795
)
 
$
4.24

 
15,712

Third quarter 2018
 
24,627

 
$
3.29

 
(7,480
)
 
$
4.23

 
17,147

Fourth quarter 2018
 
25,856

 
$
3.29

 
(7,210
)
 
$
4.27

 
18,646

2019
 
41,394

 
$
3.76

 
(24,415
)
 
$
4.34

 
16,979

Total (1)
 
115,384

 
 
 
(46,900
)
 
 
 
68,484

____________________________________________
(1) 
Total net volumes of gas swaps are comprised 100% of IF HSC.

20


NGL Swaps
 
 
OPIS Purity Ethane Mont Belvieu
 
OPIS Propane Mont Belvieu Non-TET
 
OPIS Normal Butane Mont Belvieu Non-TET
 
OPIS Isobutane Mont Belvieu Non-TET
 
OPIS Natural Gasoline Mont Belvieu Non-TET
Contract Period
 
Volumes
Weighted-Average
 Contract Price
 
Volumes
Weighted-Average
Contract Price
 
Volumes
Weighted-Average
Contract Price
 
Volumes
Weighted-Average
Contract Price
 
Volumes
Weighted-Average
Contract Price
 
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
 
(MBbl)
(per Bbl)
Second quarter 2018
 
915

$
10.87

 
554

$
24.94

 
84

$
35.69

 
66

$
35.07

 
175

$
50.99

Third quarter 2018
 
1,033

$
10.99

 
610

$
24.27

 
93

$
35.70

 
70

$
35.07

 
202

$
51.13

Fourth quarter 2018
 
1,146

$
11.18

 
671

$
24.39

 
102

$
35.70

 
76

$
35.07

 
208

$
50.99

2019
 
3,533

$
12.31

 
1,503

$
27.83

 
154

$
35.64

 
117

$
35.70

 
197

$
50.93

2020
 
539

$
11.13

 

$

 

$

 

$

 

$

Total
 
7,166

 
 
3,338

 
 
433

 
 
329

 
 
782

 
Commodity Derivative Contracts Entered Into After March 31, 2018
Subsequent to March 31, 2018, the Company entered into various derivative contracts, as summarized below:
NYMEX WTI costless collar contracts for 2019 for a total of 2.1 MMBbl of oil production with contract floor prices ranging from $50.00 per Bbl to $55.00 per Bbl and contract ceiling prices ranging from $66.60 per Bbl to $68.62 per Bbl;
fixed price Midland-Cushing basis swap contract for 2019 for a total of 0.5 MMBbl of oil production at a contract price of ($3.80) per Bbl;
fixed price Midland-Cushing basis swap contracts for 2020 for a total of 2.3 MMBbl of oil production at contract prices ranging from ($0.80) per Bbl to ($0.97) per Bbl; and
IF HSC costless collar contracts for 2019 for a total of 14,242 BBtu of gas production with contract floor prices of $2.50 per MMBtu and contract ceiling prices ranging from $2.83 per MMBtu to $2.84 per MMBtu.
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 liability of $122.4 million as of March 31, 2018, and a net liability of $139.4 million as of December 31, 2017.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:
 
 
As of March 31, 2018
 
As of December 31, 2017
 
 
(in thousands)
Derivative assets:
 
 
 
 
Current assets
 
$
77,296

 
$
64,266

Noncurrent assets
 
35,128

 
40,362

Total derivative assets
 
$
112,424

 
$
104,628

Derivative liabilities:
 
 
 
 
Current liabilities
 
$
181,068

 
$
172,582

Noncurrent liabilities
 
53,712

 
71,402

Total derivative liabilities
 
$
234,780

 
$
243,984


21


Offsetting of Derivative Assets and Liabilities
As of March 31, 2018, and December 31, 2017, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.
The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts:
 
 
Derivative Assets
 
Derivative Liabilities
 
 
As of
 
As of
 
 
March 31, 
 2018
 
December 31, 2017
 
March 31, 
 2018
 
December 31, 2017
 
 
(in thousands)
Gross amounts presented in the accompanying balance sheets
 
$
112,424

 
$
104,628

 
$
(234,780
)
 
$
(243,984
)
Amounts not offset in the accompanying balance sheets
 
(100,617
)
 
(100,035
)
 
100,617

 
100,035

Net amounts
 
$
11,807

 
$
4,593

 
$
(134,163
)
 
$
(143,949
)
The following table summarizes the components of the net derivative (gain) loss presented in the accompanying statements of operations:
 
 
For the Three Months Ended 
 March 31,
 
 
2018
 
2017
 
(in thousands)
Derivative settlement (gain) loss:
 
 
 
 
Oil contracts
 
$
20,748

 
$
9,084

Gas contracts
 
(6,410
)
 
(17,506
)
NGL contracts
 
10,190

 
8,415

Total derivative settlement (gain) loss
 
$
24,528

 
$
(7
)
 
 
 
 
 
Net derivative (gain) loss:
 
 
 
 
Oil contracts
 
$
13,966

 
$
(49,590
)
Gas contracts
 
9,990

 
(44,468
)
NGL contracts
 
(16,427
)
 
(20,716
)
Total net derivative (gain) loss
 
$
7,529

 
$
(114,774
)
Credit Related Contingent Features
As of March 31, 2018, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. Under the Credit Agreement and derivative contracts, the Company is required to secure mortgages on assets having a value equal to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report.

22


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, 2018:

Level 1

Level 2

Level 3

(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$

 
$
112,424

 
$

Total property and equipment, net (2)
$

 
$

 
$
192,000

Liabilities:
 
 
 
 
 
Derivatives (1)
$

 
$
234,780

 
$

__________________________________________
(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, 2017:
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Assets:
 
 
 
 
 
Derivatives (1)
$

 
$
104,628

 
$

Liabilities:
 
 
 
 
 
Derivatives (1)
$

 
$
243,984

 
$

____________________________________________
(1) 
This represents a financial asset or liability that is measured at fair value on a recurring basis.
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

23


Derivatives
The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.
Please refer to Note 10 - Derivative Financial Instruments and to Note 11 - Fair Value Measurements in the Company’s 2017 Form 10-K for more information regarding the Company’s derivative instruments.
Proved and Unproved Oil and Gas Properties and Other Property and Equipment
Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows 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 is based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir-specific weightings of future estimated proved and unproved cash flows as of March 31, 2018, and December 31, 2017. The Company believes the discount rates are representative of current market conditions and considers 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 pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. There were no impairments of proved properties during the three months ended March 31, 2018, or 2017.
Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable.  Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. During the three months ended March 31, 2018, the Company recorded $5.6 million in abandonment and impairment of unproved properties expense related to lease expirations. There was no abandonment and impairment of unproved properties expense recorded during the three months ended March 31, 2017.
Oil and gas properties held for sale. Proved and unproved oil and gas properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain on divestiture activity line item in the accompanying statements of operations.
For the three months ended March 31, 2018, and 2017, write-downs to fair value less estimated costs to sell on assets held for sale totaled $24.1 million and $359.6 million, respectively. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions in the Company’s 2017 Form 10-K for more information regarding the Company’s oil and gas properties held for sale.

24


Long-Term Debt
The following table reflects the fair value of the Senior Notes and Senior Convertible Notes measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of March 31, 2018, or December 31, 2017, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion.
 
As of March 31, 2018
 
As of December 31, 2017
 
Principal Amount
 
Fair Value
 
Principal Amount
 
Fair Value
 
(in thousands)
6.50% Senior Notes due 2021
$
344,611

 
$
347,626

 
$
344,611

 
$
351,682

6.125% Senior Notes due 2022
$
561,796

 
$
563,200

 
$
561,796

 
$
571,627

6.50% Senior Notes due 2023
$
394,985

 
$
394,124

 
$
394,985

 
$
403,434

5.0% Senior Notes due 2024
$
500,000

 
$
466,750

 
$
500,000

 
$
483,440

5.625% Senior Notes due 2025
$
500,000

 
$
473,750

 
$
500,000

 
$
494,355

6.75% Senior Notes due 2026
$
500,000

 
$
497,500

 
$
500,000

 
$
516,350

1.50% Senior Convertible Notes due 2021
$
172,500

 
$
164,091

 
$
172,500

 
$
168,291


25


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements at the end of this item for important information about these types of statements.
Overview of the Company
General Overview
We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in onshore North America. We currently have producing assets and significant acreage positions in the Midland Basin and Eagle Ford shale plays in Texas, and expect to complete the sale of our remaining position in North Dakota by the end of the second quarter of 2018. Our strategic objective is to be a premier operator of top tier assets. We seek to maximize the value of our assets by applying industry leading technology and outstanding operational execution. Our portfolio is comprised of unconventional resource prospects with expanding prospective drilling opportunities, which we believe provide for long-term production and reserves growth. We are focused on achieving high full-cycle economic returns on our investments and maintaining a strong balance sheet.
Outlook for 2018
Our priorities for 2018, as set at the beginning of the year, are to:
continue generating high margin returns from top tier projects that drive cash flow growth;
core up our portfolio to focus on assets that generate the highest returns; and
improve our credit metrics and maintain strong financial flexibility.
With respect to our 2018 priorities, we are focused on continuing to demonstrate the significant value of our Midland Basin assets and coring up this position in order to maximize our long-term growth. Our operational execution thus far in our Midland Basin program continues to yield stronger than expected well results, which has been key to increasing oil production, both on an absolute and relative basis. Increasing oil production and improved realized prices for oil in the first quarter of 2018 have led to improved operating margins and positive cash flow growth.
We successfully closed our previously announced PRB Divestiture in the first quarter of 2018, for net divestiture proceeds at closing of $490.8 million, subject to final purchase price adjustments. We also began marketing our non-core Bakken/Three Forks assets in Divide County, North Dakota and third-party operated Halff East assets in Upton County, Texas. We have entered into definitive agreements for the sale of these properties for a total gross purchase price of $292.3 million, subject to certain price adjustments. We expect both of these divestitures to close in the second quarter of 2018. Proceeds received from our PRB Divestiture, and expected proceeds from our Halff East Divestiture and Divide County Divestiture, provide us with significant liquidity. We plan to use these proceeds to fund our Midland Basin and Eagle Ford shale capital programs, and for general corporate purposes, including debt reduction. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions in Part I, Item 1 of this report for additional discussion.
Our capital program for 2018, excluding acquisitions, is expected to be approximately $1.27 billion, of which approximately 80 percent will be invested in drilling and completion activities. We plan to allocate the majority of our 2018 capital to our Midland Basin program, which generates the highest margins and returns in our portfolio. Planned drilling and completion activity in the Eagle Ford shale will be partially funded by a third party as part of our previously announced joint venture agreement. By concentrating our capital on the highest return programs and operating at strong performance levels, we believe we will generate higher company-wide margins, while also creating greater cash flow growth and value creation for our stockholders. Please refer to Overview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our 2018 capital program.
Financial Results
We recorded net income of $317.4 million, or $2.81 per diluted share, for the three months ended March 31, 2018, compared with net income of $74.4 million, or $0.67 per diluted share, for the same period in 2017. Net income for the three months ended March 31, 2018, was driven largely by a net estimated gain of $409.2 million recorded upon

26


closing the PRB Divestiture. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2018, and 2017 below for additional discussion regarding the components of net income for each period presented.
We had net cash provided by operating activities of $140.1 million for the three months ended March 31, 2018, compared with $135.0 million for the same period in 2017. Please refer to Overview of Liquidity and Capital Resources below for additional discussion of our sources and uses of cash.
Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2018, was $210.2 million, compared with $172.0 million for the same period in 2017. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations of our net income and net cash provided by operating activities to adjusted EBITDAX.
Operational Activities
In our Midland Basin program, we operated nine drilling rigs and five completion crews for the majority of the first quarter of 2018. For the full year 2018, we anticipate our Midland Basin program will average approximately eight operated drilling rigs and four completion crews. During the first quarter of 2018, our operations continued to focus on delineating and developing the Lower Spraberry and Wolfcamp A and B shale intervals on our RockStar acreage in Howard and Martin Counties, Texas, and our Sweetie Peck acreage in Upton and Midland Counties, Texas. We expect to allocate approximately 86 percent of our budgeted 2018 drilling and completion capital to our Midland Basin program.
Subsequent to March 31, 2018, we expanded our core RockStar acreage position by acquiring approximately 760 contiguous net acres of unproved properties in Martin County, Texas, for cash consideration of $24.6 million. Further, as discussed above, we expect to close on the sale of our non-core third-party operated Halff East assets during the second quarter of 2018.
In our operated Eagle Ford shale program, we operated two drilling rigs and averaged one completion crew during the first quarter of 2018. For the full year 2018, we anticipate our Eagle Ford shale program will operate approximately one to two drilling rigs and one completion crew. Drilling and completion activities related to our previously announced joint venture agreement in a focused portion of our Eagle Ford North area continued throughout the first quarter of 2018. We expect the remaining wells associated with this joint venture to be drilled and completed in 2018, with little capital investment required on our part. We plan to allocate approximately 14 percent of our budgeted 2018 drilling and completion capital to our Eagle Ford shale program.
During the first quarter of 2018, we successfully closed on the sale of our previously announced PRB Divestiture for net divestiture proceeds of $490.8 million, subject to final purchase price adjustments. In addition, we also announced that we entered into a definitive agreement for the sale of our remaining Bakken/Three Forks assets in Divide County, North Dakota, which we expect to close in the second quarter of 2018, subject to customary closing conditions.
The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs during the first quarter of 2018:
 
Midland Basin
 
Eagle Ford Shale
 
Bakken/Three Forks (1)
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells drilled but not completed at December 31, 2017
49

 
41

 
33

 
30

 
18

 
15

 
100

 
86

Wells drilled
35

 
33

 
11

 
8

 

 

 
46

 
41

Wells completed
(22
)
 
(17
)
 
(5
)
 
(5
)
 

 

 
(27
)
 
(22
)
Other (2)

 
1

 

 

 

 

 

 
1

Wells drilled but not completed at March 31, 2018
62

 
58

 
39

 
33

 
18

 
15

 
119

 
106

____________________________________________
(1) 
We have entered into a definitive agreement to sell our remaining Bakken/Three Forks assets in Divide County, North Dakota, which we expect to close in the second quarter of 2018, subject to customary closing conditions.
(2) 
Reflects net working interest changes resulting from normal business operations.

27


Production Results
The table below provides a regional breakdown of our production for the first quarter of 2018:
 
Permian
 
South Texas & Gulf Coast
 
Rocky Mountain (1)
 
Total
Production:
 
 
 
 
 
 
 
Oil (MMBbl)
3.3

 
0.4

 
0.6

 
4.3

Gas (Bcf)
5.6

 
18.7

 
0.9

 
25.2

NGLs (MMBbl)

 
1.6

 

 
1.7

Equivalent (MMBOE)
4.3

 
5.1

 
0.8

 
10.1

Avg. daily equivalents (MBOE/d)
47.3

 
56.9

 
8.5

 
112.7

Relative percentage
42
%
 
50
%
 
8
%
 
100
%
____________________________________________
Note: Amounts may not calculate due to rounding.
(1)  
During the first quarter of 2018, we closed the PRB Divestiture and entered into a definitive agreement to sell our Divide County assets, which we expect to close in the second quarter of 2018. Upon closing the Divide County Divestiture, we will no longer have meaningful production volumes from the Rocky Mountain region.
Production on an equivalent basis decreased 16 percent for the three months ended March 31, 2018, compared with the same period in 2017. Production declines were primarily a result of the divestiture of our outside-operated Eagle Ford shale assets, which occurred in the first quarter of 2017, and declining production from our retained operated Eagle Ford shale assets as a result of reduced capital investment. A significant portion of these production declines were offset by increased production from our Permian region, which increased 102 percent in the first quarter of 2018 compared with the same period in 2017. Please refer to A Three-Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2018, and 2017 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, totaled $372.2 million for the three months ended March 31, 2018, and were incurred primarily in our Midland Basin and operated Eagle Ford shale programs.

28


Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effects of derivative settlements, unless otherwise indicated. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, and transportation differentials for these products.
The following table summarizes commodity price data, as well as the effects of derivative settlements, for the first quarter of 2018, as well as the fourth and first quarters of 2017:
 
For the Three Months Ended
 
March 31, 2018
 
December 31, 2017
 
March 31, 2017
Oil (per Bbl):
 
 
 
 
 
Average NYMEX contract monthly price
$
62.87

 
$
55.40

 
$
51.91

Realized price, before the effect of derivative settlements
$
61.25

 
$
53.32

 
$
47.55

Effect of oil derivative settlements
$
(4.86
)
 
$
(4.42
)
 
$
(2.58
)
Gas:
 
 
 
 
 
Average NYMEX monthly settle price (per MMBtu)
$
3.00

 
$
2.93

 
$
3.32

Realized price, before the effect of derivative settlements (per Mcf)
$
3.14

 
$
3.09

 
$
2.98

Effect of gas derivative settlements (per Mcf)
$
0.25

 
$
0.94

 
$
0.52

NGLs (per Bbl):
 
 
 
 
 
Average OPIS price (1)
$
30.87

 
$
32.12

 
$
26.74

Realized price, before the effect of derivative settlements
$
25.53

 
$
26.01

 
$
22.06

Effect of NGL derivative settlements
$
(6.09
)
 
$
(7.17
)
 
$
(2.88
)
____________________________________________
(1)  
Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
We expect future prices for oil, gas, and NGLs to continue to be volatile.  In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. Oil markets have strengthened due to recent inventory drawdowns, but we expect oil prices to remain volatile due to uncertainty in global demand and easy access to new supply such as increases in oil production from United States shale. Oil prices began to increase at the end of 2017 as a result of the Organization of Petroleum Exporting Countries (“OPEC”) and several non-OPEC exporting countries agreeing to maintain previously agreed upon production cuts through 2018.
We expect gas prices to remain near current levels in the near term due to the abundance of supply relative to demand. Demand from increased liquefied natural gas (“LNG”) exports and gas exports to Mexico are expected to help balance supply.
We expect NGL prices to continue to benefit from increased demand from export and petrochemical markets while being offset by increased drilling activity.

29


The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (same product mix as discussed under the table above) as of April 25, 2018, and March 31, 2018:
 
As of April 25, 2018
 
As of March 31, 2018
NYMEX WTI oil (per Bbl)
$
65.98

 
$
63.07

NYMEX Henry Hub gas (per MMBtu)
$
2.88

 
$
2.88

OPIS NGLs (per Bbl)
$
30.23

 
$
29.29

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives.  The amount of our production covered by derivatives is driven by the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and our ability to enter into favorable derivative commodity contracts.  With our current derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil prices while also setting a price floor for a portion of our oil production. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

30


Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended March 31, 2018, and the immediately preceding three quarters. A detailed discussion follows.
 
For the Three Months Ended
 
March 31,
 
December 31,
 
September 30,
 
June 30,
 
2018
 
2017
 
2017
 
2017
 
(in millions)
Production (MMBOE)
10.1

 
10.4

 
10.7

 
11.3

Oil, gas, and NGL production revenue
$
382.9

 
$
341.2

 
$
294.5

 
$
284.9

Oil, gas, and NGL production expense
$
120.9

 
$
122.8

 
$
122.7

 
$
124.4

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
$
130.5

 
$
131.4

 
$
134.6

 
$
153.2

Exploration (1)
$
13.7

 
$
15.8

 
$
14.1

 
$
13.0

General and administrative (1)
$
27.7

 
$
32.7

 
$
27.6

 
$
28.2

Net income (loss)
$
317.4

 
$
(26.3
)
 
$
(89.1
)
 
$
(119.9
)
____________________________________________
Note: Amounts may not calculate due to rounding.
(1) 
Certain prior period amounts have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to Recently Issued Accounting Standards in Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for additional discussion.
Selected Performance Metrics
 
For the Three Months Ended
 
March 31,
 
December 31,
 
September 30,
 
June 30,
 
2018
 
2017
 
2017
 
2017
Average net daily production equivalent (MBOE per day)
112.7

 
112.6

 
116.0

 
124.6

Lease operating expense (per BOE)
$
4.95

 
$
5.10

 
$
4.81

 
$
4.11

Transportation costs (per BOE)
$
4.63

 
$
5.01

 
$
5.24

 
$
5.71

Production taxes as a percent of oil, gas, and NGL production revenue
4.4
%
 
4.3
%
 
4.2
%
 
4.0
%
Ad valorem tax expense (per BOE)
$
0.67

 
$
0.33

 
$
0.29

 
$
0.16

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)
$
12.87

 
$
12.69

 
$
12.61

 
$
13.52

General and administrative (per BOE) (1)
$
2.73

 
$
3.15

 
$
2.58

 
$
2.49

____________________________________________
Note: Amounts may not calculate due to rounding.
(1) 
Certain prior period amounts have been adjusted to conform to the current period presentation on the condensed consolidated financial statements. Please refer to Recently Issued Accounting Standards in Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for additional discussion.

31


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
 
2018
 
2017
 
Net production volumes: (1)
 
 
 
 
 
 
 
Oil (MMBbl)
4.3

 
3.5

 
0.7

 
21
 %
Gas (Bcf)
25.2

 
33.9

 
(8.7
)
 
(26
)%
NGLs (MMBbl)
1.7

 
2.9

 
(1.2
)
 
(43
)%
Equivalent (MMBOE)
10.1

 
12.1

 
(2.0
)
 
(16
)%
Average net daily production: (1)
 
 
 
 
 
 
 
Oil (MBbl per day)
47.4

 
39.2

 
8.2

 
21
 %
Gas (MMcf per day)
280.2

 
376.6

 
(96.4
)
 
(26
)%
NGLs (MBbl per day)
18.6

 
32.5

 
(13.9
)
 
(43
)%
Equivalent (MBOE per day)
112.7

 
134.4

 
(21.7
)
 
(16
)%
Oil, gas, and NGL production revenue (in millions): (1)
 
 
 
 
 
 
 
Oil production revenue
$
261.1

 
$
167.6

 
$
93.4

 
56
 %
Gas production revenue
79.1

 
101.2

 
(22.0
)
 
(22
)%
NGL production revenue
42.7

 
64.4

 
(21.7
)
 
(34
)%
Total oil, gas, and NGL production revenue
$
382.9

 
$
333.2

 
$
49.7

 
15
 %
Oil, gas, and NGL production expense (in millions): (1)
 
 
 
 
 
 
 
Lease operating expense
$
50.2

 
$
46.1

 
$
4.0

 
9
 %
Transportation costs
46.9

 
71.1

 
(24.2
)
 
(34
)%
Production taxes
17.0

 
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