10-Q 1 unt-2018331x10q.htm 10-Q Document

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x] 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
[ ] 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 1-9260]
image2a01a10.jpg
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
73-1283193
(State or other jurisdiction of incorporation)
(I.R.S. Employer Identification No.)
8200 South Unit Drive, Tulsa, Oklahoma
74132
(Address of principal executive offices)
(Zip Code)
(918) 493-7700
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)
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 [x]            No [  ]                                                     
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 [x]            No [  ]                                                     
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. (Check one):
Large accelerated filer [ x ]    Accelerated filer [ ]    Non-accelerated filer (Do not check if a smaller reporting company) [  ]
Smaller reporting company [  ]    Emerging growth company [ ]
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.    [ ]        

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]            No [x]                                                     
As of April 20, 2018, 54,046,361 shares of the issuer's common stock were outstanding.



TABLE OF CONTENTS
 
 
 
Page
Number
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
Item 5.
 
 
 
Item 6.
 
 
 
 

1


Forward-Looking Statements

This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document that addresses activities, events or developments we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the SEC will automatically update and supersede information in this report.
 
These forward-looking statements include, among others, things as:

the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
prices for oil, natural gas liquids (NGLs), and natural gas;
demand for oil, NGLs, and natural gas;
our exploration and drilling prospects;
the estimates of our proved oil, NGLs, and natural gas reserves;
oil, NGLs, and natural gas reserve potential;
development and infill drilling potential;
expansion and other development trends of the oil and natural gas industry;
our business strategy;
our plans to maintain or increase production of oil, NGLs, and natural gas;
the number of gathering systems and processing plants we plan to construct or acquire;
volumes and prices for natural gas gathered and processed;
expansion and growth of our business and operations;
demand for our drilling rigs and drilling rig rates;
our belief that the final outcome of legal proceedings involving us will not materially affect our financial results;
our ability to timely secure third-party services used in completing our wells;
our ability to transport or convey our oil or natural gas production to established pipeline systems;
impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets;
our financial condition and liquidity;
the number of wells our oil and natural gas segment plans to drill or rework during the year;
our intended use of the proceeds from the sale of 50% of the interest we owned in our midstream segment; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.
These statements are based on assumptions and analyses made by us based on our experience and our perception of historical trends, current conditions, and expected future developments, and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to several risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:
the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities we pursue;
demand for our land drilling services;
changes in laws or regulations;
changes in the current geopolitical situation;
risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
risks associated with future weather conditions;
decreases or increases in commodity prices;
putative class action lawsuits that may cause substantial expenditures and divert management's attention; and
other factors, most of which are beyond our control.

2


You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this document to reflect unanticipated events.

3


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
 
March 31,
2018
 
December 31,
2017
 
 
(In thousands except share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
752

 
$
701

Accounts receivable, net of allowance for doubtful accounts of $2,450 at both March 31, 2018 and December 31, 2017, respectively
 
98,506

 
111,512

Materials and supplies
 
455

 
505

Current derivative asset (Note 10)
 
537

 
721

Current income tax receivable
 
61

 

Prepaid expenses and other
 
7,724

 
6,233

Total current assets
 
108,035

 
119,672

Property and equipment:
 
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
 
Proved properties
 
5,762,069

 
5,712,813

Unproved properties not being amortized
 
305,621

 
296,764

Drilling equipment
 
1,601,777

 
1,593,611

Gas gathering and processing equipment
 
731,006

 
726,236

Saltwater disposal systems
 
63,124

 
62,618

Corporate land and building
 
59,080

 
59,080

Transportation equipment
 
29,908

 
29,631

Other
 
56,142

 
53,439

 
 
8,608,727

 
8,534,192

Less accumulated depreciation, depletion, amortization, and impairment
 
6,207,449

 
6,151,450

Net property and equipment
 
2,401,278

 
2,382,742

Goodwill
 
62,808

 
62,808

Other assets
 
27,470

 
16,230

Total assets
 
$
2,599,591

 
$
2,581,452


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

4


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED

 
 
March 31,
2018
 
December 31,
2017
 
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
131,064

 
$
112,648

Accrued liabilities (Note 5)
 
52,964

 
48,523

Current derivative liability (Note 10)
 
12,104

 
7,763

Current portion of other long-term liabilities (Note 6)
 
14,587

 
13,002

Total current liabilities
 
210,719

 
181,936

Long-term debt less debt issuance costs (Note 6)
 
790,522

 
820,276

Non-current derivative liability (Note 10)
 
164

 

Other long-term liabilities (Note 6)
 
104,286

 
100,203

Deferred income taxes
 
136,600

 
133,477

Commitments and contingencies (Note 12)
 

 

Shareholders’ equity:
 
 
 
 
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued
 

 

Common stock, $.20 par value, 175,000,000 shares authorized, 54,046,361 and 52,880,134 shares issued as of March 31, 2018 and December 31, 2017, respectively
 
10,403

 
10,280

Capital in excess of par value
 
541,004

 
535,815

Accumulated other comprehensive income (Note 13)
 
(100
)
 
63

Retained earnings
 
805,993

 
799,402

Total shareholders’ equity
 
1,357,300

 
1,345,560

Total liabilities and shareholders’ equity
 
$
2,599,591

 
$
2,581,452


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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS (UNAUDITED)
 
 
 
Three Months Ended
 
 
March 31,
 
 
2018
 
2017
 
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
Oil and natural gas
 
$
103,099

 
$
87,598

Contract drilling
 
45,989

 
37,185

Gas gathering and processing
 
56,044

 
50,941

Total revenues
 
205,132

 
175,724

Expenses:
 
 
 
 
Operating costs:
 
 
 
 
Oil and natural gas
 
35,962

 
29,204

Contract drilling
 
31,667

 
29,227

Gas gathering and processing
 
41,604

 
37,704

Total operating costs
 
109,233

 
96,135

Depreciation, depletion, and amortization
 
57,066

 
46,932

General and administrative
 
10,762

 
8,954

Gain on disposition of assets
 
(161
)
 
(824
)
Total operating expenses
 
176,900

 
151,197

Income from operations
 
28,232

 
24,527

Other income (expense):
 
 
 
 
Interest, net
 
(10,004
)
 
(9,396
)
Gain (loss) on derivatives
 
(6,762
)
 
14,731

Other, net
 
6

 
3

Total other income (expense)
 
(16,760
)
 
5,338

Income before income taxes
 
11,472

 
29,865

Income tax expense:
 
 
 
 
Deferred
 
3,607

 
13,936

Total income taxes
 
3,607

 
13,936

Net income
 
$
7,865

 
$
15,929

Net income per common share:
 
 
 
 
Basic
 
$
0.15

 
$
0.32

Diluted
 
$
0.15

 
$
0.31


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


6


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three Months Ended
 
March 31,
 
2018
 
2017
 
(In thousands)
Net income
$
7,865

 
$
15,929

Other comprehensive income, net of taxes:
 
 
 
Unrealized loss on securities, net of tax of ($58) and $0
(176
)
 

Comprehensive income
$
7,689

 
$
15,929


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


7


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Three Months Ended
 
 
March 31,
 
 
2018
 
2017
 
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
 
Net income
 
$
7,865

 
$
15,929

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, and amortization
 
57,066

 
46,932

Amortization of debt issuance costs and debt discount (Note 6)
 
546

 
536

(Gain) loss on derivatives
 
6,762

 
(14,731
)
Cash payments on derivatives settled, net
 
(2,073
)
 
(1,159
)
Deferred tax expense
 
3,607

 
13,936

Gain on disposition of assets
 
(161
)
 
(824
)
Stock compensation plans
 
6,609

 
3,704

Contract assets and liabilities, net (Note 2)
 
(1,192
)
 

Other, net
 
937

 
626

Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
 
Accounts receivable
 
8,005

 
(1,900
)
Accounts payable
 
(55,638
)
 
(7,735
)
Material and supplies
 
50

 
73

Accrued liabilities
 
6,757

 
9,832

Other, net
 
(494
)
 
433

Net cash provided by operating activities
 
38,646

 
65,652

INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(45,327
)
 
(37,636
)
Producing properties and other acquisitions
 

 
(7,508
)
Proceeds from disposition of assets
 
22,084

 
16,116

Net cash used in investing activities
 
(23,243
)
 
(29,028
)
FINANCING ACTIVITIES:
 
 
 
 
Borrowings under credit agreement
 
67,400

 
49,700

Payments under credit agreement
 
(97,700
)
 
(60,500
)
Payments on capitalized leases
 
(946
)
 
(946
)
Book overdrafts
 
15,894

 
(17,301
)
Net cash used in financing activities
 
(15,352
)
 
(29,047
)
Net increase in cash and cash equivalents
 
51

 
7,577

Cash and cash equivalents, beginning of period
 
701

 
893

Cash and cash equivalents, end of period
 
$
752

 
$
8,470

Supplemental disclosure of cash flow information:
 
 
 
 
Cash paid during the year for:
 
 
 
 
Interest paid (net of capitalized)
 
(1,731
)
 
(2,389
)
Income taxes
 

 

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
 
(58,160
)
 
(11,401
)
Non-cash (addition) reduction to oil and natural gas properties related to asset retirement obligations
 
6,340

 
912

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

8


UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The unaudited condensed consolidated financial statements in this report include the accounts of Unit Corporation and all its subsidiaries and affiliates and have been prepared under the rules and regulations of the SEC. The terms “company,” “Unit,” “we,” “our,” “us,” or like terms refer to Unit Corporation, a Delaware corporation, and one or more of its subsidiaries and affiliates, except as otherwise indicated or as the context otherwise requires.

The condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Form 10-K, filed February 27, 2018, for the year ended December 31, 2017.

In the opinion of our management, the unaudited condensed consolidated financial statements contain all normal recurring adjustments (including the elimination of all intercompany transactions) necessary to fairly state:

Balance Sheets at March 31, 2018 and December 31, 2017;
Income Statements for the three months ended March 31, 2018 and 2017;
Statements of Comprehensive Income for the three months ended March 31, 2018 and 2017; and
Statements of Cash Flows for the three months ended March 31, 2018 and 2017.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and notes. Actual results may differ from those estimates. Results for the three months ended March 31, 2018 and 2017 are not necessarily indicative of the results to be realized for the full year of 2018, or that we realized for the full year of 2017.

Accounting Changes - Recent Accounting Pronouncements - Adopted

As of January 1, 2018, the company adopted ASU 2018-02 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This standard is explained further in Note 8 - New Accounting Pronouncements. We adopted this amendment early and it did not have a material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and now we are using 24.5%. The change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 13 - Equity.

Also, as of January 1, 2018, the company adopted ASU 2014-09 Revenue from Contracts with Customers - Topic 606 (ASC 606) and all later amendments that modified ASC 606. The new revenue standard is explained further in Note 8 - New Accounting Pronouncements. The company has elected to apply the standard on the modified retrospective approach method to contracts not completed as of January 1, 2018, where the cumulative effect upon adoption, which only impacted our mid-stream segment is recognized as an adjustment to opening retained earnings at January 1, 2018. This adjustment related to the timing of revenue recognition for certain demand fees. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605.

The additional disclosures required by the ASU have been included in Note 2 – Revenue from Contracts with Customers.

NOTE 2 – REVENUE FROM CONTRACTS WITH CUSTOMERS

The company’s revenue streams are reported under three segments: oil and natural gas, contract drilling, and mid-stream. This is our disaggregation of revenue and how our segment revenue is reported (as reflected in Note 14 - Industry Segment Information). Revenue from the oil and natural gas segment is derived from sales of our oil and natural gas production. Revenue from the contract drilling segment is derived by contracting with upstream companies to drill an agreed-on number of wells or provide drilling rigs and services over an agreed-on period of time. Revenue from the mid-stream segment is derived from gathering, transporting, and processing natural gas production and selling those commodities. The company sells its hydrocarbons (from the oil and natural gas and mid-stream segments) to midstream and downstream oil and gas companies.

9


We satisfy performance obligation for each contract as follows: for the contract drilling and mid-stream contracts, we satisfy the performance obligation over the agreed-on time period within the contracts, and for oil and natural gas contracts, we satisfy the performance obligation with each delivery of volumes. For oil and natural gas contracts, as it is more feasible, we account for these deliveries on a monthly basis. Per the contracts for all segments, customers pay for the services/goods received on a monthly basis within an agreed on number of days following the end of the month. Besides the mid-stream demand fees discussed further below, there were no other contract assets or liabilities.

Oil and Natural Gas Contracts, Revenues, Implementation Impact to Retained Earnings, and Performance Obligations

Typical types of revenue contracts signed are Oil Sales Contracts, Gas Purchase Agreements, North American Energy Standards Board (NAESB) Contracts, Gas Gathering and Processing Agreements, and revenues earned as the non-operated party with the operator serving as an agent on our behalf under our Joint Operating Agreements. Contract term can range from single month to extended term contracts spanning a decade or more; some include evergreen provisions. Revenues from sales are recognized when the customer obtains control of the company’s product. For sales to other midstream and downstream oil and gas companies, this would occur at a point in time, typically on delivery to the customer. Sales generated from our non-operated interest are recorded based on the information obtained from the operator. On adoption of the standard, no adjustment to opening retained earnings was required.

Certain costs as either a deduction from revenue or an expense is determined based on when control of the commodity transfers to the customer, which would affect our total revenue recognized, but will not affect gross profit. For example, gathering, processing and transportation costs that are included as part of the contract price with the customer upon transfer of control of the commodity are included in the transaction price, while costs incurred while we are in control of the commodity represent operating costs. The following table summarizes the impact of the adoption of ASC 606 on revenue and operating costs, as the change did not impact income from operations or net income for the three months ended March 31, 2018:
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Oil and natural gas revenues
 
$
103,099

 
$
(3,169
)
 
$
106,268

Oil and natural gas operating costs
 
35,962

 
(3,169
)
 
39,131

Gross profit
 
$
67,137

 
$

 
$
67,137


Our performance obligation for all contracts is the delivery of oil and gas volumes to the customer. Typically the contract will establish a period of time (for example, a month or a year); however, each delivery can be considered separately identifiable as each delivery provides benefits to the customer on its own. For feasibility, as accounting for a monthly performance obligation is not materially different than identifying a more granular performance obligation, we conclude this performance obligation is satisfied monthly. We typically receive payment within a set number of days following the end of the month and includes payment for all deliveries in that month. Depending on contract circumstances, judgment could be required to determine when the transfer of control occurs. Generally, depending of the facts and circumstances, we consider the transfer of control of the asset in a commodity sale to occur at the point the commodity transfers to our final purchaser.

The majority of the consideration received for oil and gas sales is variable. Most of our contracts state the consideration is calculated by multiplying a variable quantity by an agreed-on index price less deductions related to gathering, transportation, fractionation, and related fuel charges. There are also instances where the consideration is quantity multiplied by a weighted average sales price. These different pricing tools can change the perception of when control transfers; however, when analyzed with other control factors, typically the accounting conclusion is the same for both pricing methods. In these instances, the variable consideration is partially constrained. In addition, all variable consideration is settled at the end of the month; therefore, whether the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to each reporting period. An estimation and allocation of transaction price and future obligations are not required.

Contract Drilling Contracts, Revenues, Implementation impact to retained earnings, and Performance Obligations

The contract drilling contracts we use primarily are industry standard IADC contracts 2003 and 2013. Contract terms can range from six months to two or more years or can be based on terms to drill a specific number of wells. These allocation rules in ASC 606 are referred to as the series guidance which states that a contract may contain a single performance obligation

10


composed of a series of distinct goods or services if 1) each distinct good or service is substantially the same and would meet the criteria to be a performance obligation satisfied over time and 2) each distinct good or service is measured using the same method as it relates to the satisfaction of the overall performance obligation. The company determined that the delivery of drilling services is within the scope of the series guidance as both criteria noted above are met. Specifically, 1) each distinct increment of service (i.e. hour available to drill) that the driller promises to transfer represents a performance obligation that would meet the criteria for recognizing revenue over time, and 2) the driller would use the same method for measuring progress toward satisfaction of the performance obligation for each distinct increment of service in the series. At inception, the total transaction price will be estimated to include any applicable fixed consideration, unconstrained variable consideration (estimated day rate mobilization and demobilization revenue, estimated operating day rate revenue to be earned over the contract term, expected bonuses (if material and can be reasonably estimated without significant reversal), and penalties (if material and can be reasonably estimated without significant reversal)). Allocation rules under the new standard will allow the company to recognize revenues associated with contract drilling contacts in materially the same manner as under the previous revenue accounting standard. A contract liability will be recorded for consideration received before the corresponding transfer of services. Such liabilities will generally only arise in relation to upfront mobilization fees which are paid in advance and are allocated/recognized over the entire performance obligation. Such balances will be amortized over the recognition period based on the same method of measure used for revenue. On adoption of the standard, no adjustment to opening retained earnings was required.

Our performance obligation for all contracts is to drill the agreed-on number of wells or drill over an agreed-on period of time as stated in the contract. Mobilization and demobilization activities associated with a drilling contract are not considered to be distinct within the context of the contract and therefore, any associated revenue is allocated to the overall performance obligation of drilling services and recognized ratably over the initial term of the related drilling contract. It typically takes from 10 to 90 days to complete drilling a well; therefore, depending on the number of wells under a contract, the contract term could be up to two years. Most of the drilling contracts are for less than one year. As the customer simultaneously received and consumes the benefits provided by the company’s performance, and the company’s performance enhances an asset that the customer controls, the performance obligation to drill the well occurs over time. We typically receive payment within a set number of days following the end of the month and includes payment for all services performed that month (calculated on an hourly basis). The company satisfies its overall performance obligation when the well included in the contract is drilled to an agreed-upon depth or by a set date.

All consideration received for contract drilling contracts is variable, excluding termination fees, which we concluded will not be applicable to our current contracts as of the reporting date. The consideration is calculated by multiplying a variable quantity (number of days/hours) by an agreed-on daily price (for the daily rate, mobilization and demobilization revenue). Other revenue items per the contract include bonus/penalty revenue, reimbursable revenue, drilling fluid rates, and early termination fees. All variable consideration is not constrained but is settled at the end of the month; therefore, whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known prior to each reporting period excluding certain bonuses/penalties which might be based on activity that occurs over the entire term of the contract. We have evaluated the mobilization and de-mobilization charges on outstanding contracts, however, the impact to the financial statements was immaterial. As of March 31, 2018, we had 32 contract drilling contracts (six long-term) for a duration of two to fourteen months.

Per the new guidance in relation to disclosures regarding remaining performance obligations, there is a practical expedient for contracts that have an original expected duration of one year or less (ASC 606-10-50-14) and for contracts where the entity can recognize revenue as invoiced (ASC 606-10-55-18). The majority of contract drilling contracts have an original term of less than one year; however, there are a few contracts with a longer duration that are not material.

Mid-stream Contracts Revenues, and Implementation impact to retained earnings, and Performance Obligations

Revenues are generated from the fees earned for gas gathering and processing services provided to a customer. Typical types of revenue contracts signed are Gas Gathering and Processing agreements. Contract terms can range from single month to extended term contracts spanning a decade or more, some include evergreen provisions. Fees for mid-stream services (gathering, transportation, processing) are performance obligations and meet the criteria of over time recognition which could be considered a series of distinct performance obligations that represents one overall performance obligation of gas gathering and processing services.


11


On adoption of the standard, an adjustment to opening retained earnings was made in the amount of $1.7 million ($1.3 million, net of tax). This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Balance Sheet:
 
 
Balance at December 31, 2017
 
Adjustments due to ASC 606
 
Balance at January 1, 2018
 
 
(In thousands)
Assets:
 
 
 
 
 
 
Other assets
 
$
16,230

 
$
10,798

 
$
27,028

Liabilities and shareholders' equity:
 
 
 
 
 
 
Current portion of other long-term liabilities
 
13,002

 
2,748

 
15,750

Other long-term liabilities
 
100,203

 
9,737

 
109,940

Deferred income taxes
 
133,477

 
(413
)
 
133,064

Retained earnings
 
799,402

 
(1,274
)
 
798,128


The following impact of these demand fees to the Unaudited Condensed Consolidated Balance Sheet on at March 31, 2018:
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Assets:

 
 
 
 
 
 
Prepaid expenses and other
 
$
7,724

 
$
50

 
$
7,674

Other assets
 
27,470

 
11,397

 
16,073

Liabilities and shareholders' equity:

 
 
 
 
 
 
Current portion of other long-term liabilities
 
14,587

 
2,824

 
11,763

Other long-term liabilities
 
104,286

 
9,118

 
95,168

Deferred income taxes

 
136,600

 
(121
)
 
136,479

Retained earnings

 
805,993

 
(374
)
 
805,619


This adjustment related to the timing of revenue recognized on certain demand fees and had the following impact to the Unaudited Condensed Consolidated Income Statement for the three months ended March 31, 2018:
 
 
As Reported
 
Adjustments due to ASC 606
 
Amounts without the Adoption of ASC 606
 
 
(In thousands)
Gas gathering and processing revenues
 
$
56,044

 
$
1,192

 
$
54,852

Deferred income tax expense
 
3,607

 
292

 
3,315

Net income
 
7,865

 
900

 
6,965


The only fixed consideration related to mid-stream consideration is the demand fee which is calculated by multiplying an agreed-on price by a fixed number of volumes per month over a specified term in the contract.


12


Included below is the additional fixed revenue the company will earn over the remaining term of the contracts and excludes all variable consideration to be earned with the associated contract.
Contract
Remaining Term of Contract
April - December 2018
2019
2020
2021
2022
Total Remaining Impact to Revenue
 
 
(In thousands)
 
Demand fee contracts
4-5 years
$
3,777

$
2,632

$
(3,781
)
$
(3,507
)
$
1,374

$
495


Before the implementation of ASC 606, we recognized the entire demand fee as the fee was payable the first five years after the effective date, not the entire term of the contract. However, as the demand fee does not specifically relate to a distinct performance obligation, the amount should be recognized over the life of the contract. Therefore, the demand fee already recognized for $1.7 million ($1.3 million, net of tax) was adjusted to retained earnings as of January 1, 2018, and will be recognized over the remaining term of the contract. As this amount is fixed consideration, recognition of the remaining portion will be stable. For the first three months of March 31, 2018, $1.2 million was recognized in revenue for these demand fees.

Besides the demand fee, there were no other contract assets or liabilities (see above for the balance sheet line items where they are reported.)
 
 
March 31, 2018
 
January 1, 2018
 
Change
 
 
(In thousands)
Contract assets

 
$
11,447

 
$
10,798

 
$
649

Contract liabilities

 
11,942

 
12,485

 
(543
)
Contract liabilities, net
 
$
(495
)
 
$
(1,687
)
 
$
1,192


Our performance obligations for all contracts is to gather, transport, or process an agreed-on number of volumes as stated in the contract. Typically the contract will establish a period of time over which the company will perform the mid-stream services. Certain contracts also include an agreed-on quantity (or an agreed-on minimum quantity) of volumes that the company will deliver or service. The term under mid-stream service contracts is typically five to ten years. Under service contracts, as the customer simultaneously receives and consumes the benefits provided by the entity’s performance as the entity performs, the performance obligation to gather, transport, or process occurs over time. We typically receive payment within a set number of days following the end of the month and includes payment for all services performed that month. The company satisfies its overall performance obligation at the end of the contract term.

Most of the consideration received for mid-stream service contracts is variable. The consideration is calculated by multiplying a variable quantity (number of volumes) by an agreed-on price per MCF (commodity fee and the gathering fee). One fixed component of revenue is calculated by multiplying an agreed-on price by a certain volume commitment (MCF per day). Other revenue items may include shortfall fees. All variable consideration is settled at the end of the month; therefore, whether or not the variability is constrained does not affect accounting for revenue under ASC 606 as the variability is known before each reporting period. However, this excludes the shortfall fee as this fee could be based on a set number of volumes over the course of more than one month.

Per the new guidance related to disclosures for remaining performance obligations, there is a practical expedient for contracts that have an original expected duration of one year or less (ASC 606-10-50-14). There is also a practical expedient for “variable consideration [that] is allocated entirely to a wholly unsatisfied performance obligation… that forms part of a single performance obligation… for which the criteria in paragraph 606-10-32-40 have been met” (ASC 606-10-50-14A). As stated previously, the contract term for mid-stream services is typically longer than one year. However, based on the guidance at 606-10-32-40, we determined some of the variable payment in mid-stream service agreements specifically relates to the entity’s efforts to satisfy the performance obligation and that “allocating the variable amount entirely to the distinct good or service is consistent with the allocation objective in paragraph 606-10-32-28.” Therefore, the practical expedient relates to this variable consideration: the commodity fee and the gathering fee. The last time we received a shortfall fee was in 2016 and the amount was immaterial to total mid-stream revenues. These terms have historically been limited in our contracts.

We calculate revenue earned from the variable consideration related to mid-stream services by multiplying the number of volumes serviced times an agreed-on price. Therefore, the variable portion of this consideration is due to the change in

13


volumes. This variability is resolved at the end of each month as the company will know the number of volumes serviced under each contract and payment is received monthly. The mid-stream gathering service contracts remaining are for a duration of less than one year to 15 years.

While long term service contracts are in place as of the reporting date, due to the variable volumes an estimation and allocation of transaction price and future obligations are not required.

NOTE 3 – DIVESTITURES

Oil and Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for $21.7 million during the first three months of 2018, compared to $14.8 million during the first three months of 2017. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

NOTE 4 – EARNINGS PER SHARE

Information related to the calculation of earnings per share follows:
 
 
Earnings
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the three months ended March 31, 2018
 
 
 
 
 
 
Basic earnings per common share
 
$
7,865

 
51,730

 
$
0.15

Effect of dilutive stock options and restricted stock
 

 
542

 

Diluted earnings per common share
 
$
7,865

 
52,272

 
$
0.15

For the three months ended March 31, 2017
 
 
 
 
 
 
Basic earnings per common share
 
$
15,929

 
50,293

 
$
0.32

Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)
 

 
568

 
(0.01
)
Diluted earnings per common share
 
$
15,929

 
50,861

 
$
0.31


The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
 
Three Months Ended
 
 
March 31,
 
 
2018
 
2017
Stock options and SARs
 
87,500

 
199,755

Average exercise price
 
$
51.34

 
$
48.79



14


NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
 
 
March 31,
2018
 
December 31,
2017
 
 
(In thousands)
Interest payable
 
$
17,560

 
$
6,745

Lease operating expenses
 
11,570

 
11,819

Employee costs
 
9,754

 
19,521

Taxes
 
4,139

 
3,404

Third-party credits
 
2,051

 
2,240

Derivative settlements
 
1,527

 

Other
 
6,363

 
4,794

Total accrued liabilities
 
$
52,964

 
$
48,523

 
NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

Our long-term debt as of the dates indicated consisted of the following:
 
 
March 31,
2018
 
December 31,
2017
 
 
(In thousands)
Credit agreement with an average interest rate of 3.8% and 3.4% at March 31, 2018 and December 31, 2017, respectively
 
$
147,700

 
$
178,000

6.625% senior subordinated notes due 2021
 
650,000

 
650,000

Total principal amount
 
797,700

 
828,000

Less: unamortized discount
 
(2,085
)
 
(2,234
)
Less: debt issuance costs, net
 
(5,093
)
 
(5,490
)
Total long-term debt
 
$
790,522

 
$
820,276


Credit Agreement. On April 2, 2018, we amended our Senior Credit Agreement (credit agreement) scheduled to mature on April 10, 2020. The details of this amendment are discussed in Note 15 — Subsequent Events.

Before the amendment and through March 31, 2018, the amount we could borrow was the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million. Our borrowing base and elected commitment was $475.0 million. We were charged a commitment fee of 0.50% on the amount available but not borrowed. That fee varied based on the amount borrowed as a percentage of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. Under the credit agreement, we have pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our mid-stream affiliate, Superior Pipeline Company, L.L.C.

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement could be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the LIBOR base for the term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00% plus a margin. Interest is payable at the end of each month and the principal may be repaid in whole or in part at

15


any time, without a premium or penalty. At March 31, 2018, we had $147.7 million of outstanding borrowings under our credit agreement.

We can use borrowings for financing general working capital requirements for (a) exploration, development, production, and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services and acquisition of contract drilling equipment, and (e) general corporate purposes.

The credit agreement prohibits, among other things:

the payment of dividends (other than stock dividends) during any fiscal year over 30% of our consolidated net income for the preceding fiscal year;
the incurrence of additional debt with certain limited exceptions; and
the creation or existence of mortgages or liens, other than those in the ordinary course of business and with certain limited exceptions, on any of our properties, except in favor of our lenders.

The credit agreement also requires that we have at the end of each quarter:

a current ratio (as defined in the credit agreement) of not less than 1 to 1.

Through the quarter ending March 31, 2019, the credit agreement also requires that we have at the end of each quarter:

a senior indebtedness ratio of senior indebtedness to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four quarters of no greater than 2.75 to 1.

Beginning with the quarter ending June 30, 2019, and for each following quarter, the credit agreement requires:

a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1.

As of March 31, 2018, we were in compliance with the credit agreement covenants.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior subordinated notes (the Notes) outstanding. Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each year. The Notes mature on May 15, 2021. In issuing the Notes, we incurred fees of $14.7 million that are being amortized as debt issuance cost over the life of the Notes.

The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture dated as of January 7, 2013, between us, the Guarantors, and the Trustee (as supplemented, the 2011 Indenture), establishing the terms of and providing for issuing the Notes. The Guarantors are most of our direct and indirect subsidiaries. The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes
(registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

We may redeem all or, occasionally, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants including those that limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of March 31, 2018.

16


Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
 
March 31,
2018
 
December 31,
2017
 
 
(In thousands)
Asset retirement obligation (ARO) liability
 
$
63,763

 
$
69,444

Capital lease obligations
 
14,277

 
15,224

Workers’ compensation
 
13,049

 
13,340

Contract liability
 
11,942

 

Separation benefit plans
 
7,087

 
6,524

Deferred compensation plan
 
5,472

 
5,390

Gas balancing liability
 
3,283

 
3,283

 
 
118,873

 
113,205

Less current portion
 
14,587

 
13,002

Total other long-term liabilities
 
$
104,286

 
$
100,203


Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive twelve-month periods beginning April 1, 2018 (and through 2023) are $14.6 million, $41.9 million, $156.1 million, $653.2 million, and $2.0 million, respectively.

Capital Leases

In 2014, our mid-stream segment entered into capital lease agreements for 20 compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The $3.9 million current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $10.4 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of March 31, 2018. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $5.4 million and $1.0 million, respectively, at March 31, 2018. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

Future payments required under the capital leases at March 31, 2018:
 
 
Amount
Beginning April 1,
 
(In thousands)
2018
 
$
6,168

2019
 
6,168

2020
 
7,815

2021
 
579

Total future payments
 
20,730

Less payments related to:
 
 
Maintenance
 
5,428

Interest
 
1,025

Present value of future minimum payments
 
$
14,277



17


NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets. Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All our AROs relate to the plugging costs associated with our oil and gas wells.

The following table shows certain information about our AROs for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
 
 
2018
 
2017
 
 
(In thousands)
ARO liability, January 1:
 
$
69,444

 
$
70,170

Accretion of discount
 
659

 
785

Liability incurred
 
118

 
658

Liability settled
 
(1,626
)
 
(630
)
Liability sold
 
(81
)
 
(432
)
Revision of estimates (1)
 
(4,751
)

(508
)
ARO liability, March 31:
 
63,763

 
70,043

Less current portion
 
1,477

 
3,243

Total long-term ARO
 
$
62,286

 
$
66,800

_______________________ 
(1)
Plugging liability estimates were revised in both 2018 and 2017 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. This amendment will not have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. The amendment will require lessees to recognize at the commencement date a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. In January 2018, the FASB issued ASU 2018-01, "Leases - Land Easement practical expedient for Transition to Topic 842", which provides clarifying guidance regarding land easements and adds practical expedients. For public companies, the amendment is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard will not apply to leases of mineral rights. We have begun the identification of leases and impact assessment within the scope of the guidance. Our evaluation of the impact of the new guidance on our financial statements in on-going.

Adopted Standards

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The FASB issued ASU 2018-02, an amendment which provides financial statement preparers with an option to reclassify stranded tax effects within AOCI to retained earnings caused by the Tax Cuts and Jobs Act of 2017. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. Organizations should apply the proposed amendments either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. We adopted this amendment early and it did not have a material effect to our financial statements. We previously used 37.75% to calculate the tax effect on AOCI and now we are using 24.5%. The change is reflected in our Unaudited Condensed Consolidated Statements of Comprehensive Income and in Note 13 - Equity.

18


Revenue from Contracts with Customers. Effective January 1, 2018, the company adopted ASC 606. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The guidance in this update supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. Under the standard, 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. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The company applied the five step method outlined in the ASU to all revenue streams in the scope of ASC 606 and elected the modified retrospective approach method. Under that approach the cumulative effect on adoption is recognized as an adjustment to opening retained earnings at January 1, 2018. Only our mid-stream segment was affected. This adjustment related to the timing of revenue on certain demand fees. Both our oil and natural gas and contract drilling segments had no retained earnings adjustment. Comparative prior periods have not been adjusted and continue to be reported under ASC 605.

The additional disclosures required by ASC 606 have been included in Note 2 – Revenue from Contracts with Customers.

Our internal control framework did not materially change, but the existing internal controls have been modified to consider our new revenue recognition policy effective January 1, 2018. As we implement the new standard, we have added internal controls to ensure that we adequately evaluate new contracts under the five-step model under ASU 2014-09.

NOTE 9 –STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
 
Three Months Ended
 
 
March 31,
 
 
2018
 
2017
 
 
(In millions)
Recognized stock compensation expense
 
$
4.6

 
$
2.6

Capitalized stock compensation cost for our oil and natural gas properties
 
1.3

 
0.4

Tax benefit on stock based compensation
 
1.1

 
1.0


The remaining unrecognized compensation cost related to unvested awards at March 31, 2018 is approximately $27.4 million, of which $3.5 million is anticipated to be capitalized. The weighted average period over which this cost will be recognized is one year.

Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) and to non-employee directors. 7,230,000 shares of the company's common stock are authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options."


19


We granted no SARs or stock options during either of the three-month periods ending March 31, 2018 or 2017. This table shows the fair value of restricted stock awards granted to employees and non-employee directors during the periods indicated:
 
 
Three Months Ended
 
Three Months Ended
 
 
March 31, 2018
 
March 31, 2017
 
 
Time
Vested
 
Performance Vested
 
Time
Vested
 
Performance Vested
Shares granted:
 
 
 
 
 
 
 
 
Employees
 
839,498

 
362,070

 
461,799

 
152,373

Non-employee directors
 

 

 

 

 
 
839,498

 
362,070

 
461,799

 
152,373

Estimated fair value (in millions):(1)
 
 
 
 
 
 
 
 
Employees
 
$
16.1

 
$
7.3

 
$
11.4

 
$
4.0

Non-employee directors
 

 

 

 

 
 
$
16.1

 
$
7.3

 
$
11.4

 
$
4.0

Percentage of shares granted expected to be distributed:
 
 
 
 
 
 
 
 
Employees
 
95
%
 
63
%
 
94
%
 
105
%
Non-employee directors
 
N/A

 
N/A

 
N/A

 
N/A

_______________________
(1)
Represents 100% of the grant date fair value. (We recognize the grant date fair value minus estimated forfeitures.)

The time vested restricted stock awards granted during the first three months of 2018 and 2017 are being recognized over a three-year vesting period. During the the first quarter of 2018 and 2017, there were two performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures (TSR) at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three-year vesting period subject to the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected TSR performance criteria at March 31, 2018, the participants are estimated to receive 27% of the 2018, 93% of the 2017, and 164% of the 2016 performance based shares. The CFTA performance measurement at March 31, 2018 was assessed to vest at target or 100%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2018 awards for the first three months of 2018 was $1.1 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

We have signed various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of March 31, 2018, our derivative transactions comprised these hedges:

Swaps. We receive or pay a fixed price for the commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Basis Swaps. We receive or pay the NYMEX settlement value plus or minus a fixed delivery point price for the commodity and pay or receive the published index price at the specified delivery point. We use basis swaps to hedge the price risk between NYMEX and its physical delivery points.

Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.


20


Three-way collars. A three-way collar contains a fixed floor price (long put), fixed subfloor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, we receive the ceiling strike price and pay the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the subfloor price, we receive the floor strike price and pay the market price. If the market price is below the subfloor price, we receive the market price plus the difference between the floor and subfloor strike prices and pay the market price.

We have documented policies and procedures to monitor and control the use of derivative transactions. We do not engage in derivative transactions for speculative purposes. Any changes in the fair value of our derivative transactions before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Income Statements.

At March 31, 2018, these derivatives were outstanding:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Apr’18 – Sep'18
 
Natural gas – swap
 
40,000 MMBtu/day
 
$2.985
 
IF – NYMEX (HH)
Oct'18
 
Natural gas – swap
 
30,000 MMBtu/day
 
$3.005
 
IF – NYMEX (HH)
Nov’18 – Dec'18
 
Natural gas – swap
 
20,000 MMBtu/day
 
$3.013
 
IF – NYMEX (HH)
Apr'18 – Oct'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.190)
 
NGPL TEXOK
Apr'18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.678)
 
PEPL
Apr’18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.568)
 
NGPL MIDCON
Nov’18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Jan'19 – Dec'19
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.728)
 
PEPL
Jan'19 – Dec'19
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.625)
 
NGL MIDCON
Jan'19 – Dec'19
 
Natural gas – basis swap
 
30,000 MMBtu/day
 
$(0.265)
 
NGPL TEXOK
Jan'20 – Dec'20
 
Natural gas – basis swap
 
20,000 MMBtu/day
 
$(0.280)
 
NGPL TEXOK
Apr'18 – Sep'18
 
Natural gas – collar
 
30,000 MMBtu/day
 
$2.67 - $2.97
 
IF – NYMEX (HH)
Apr'18 – Dec'18
 
Natural gas – three-way collar
 
20,000 MMBtu/day
 
$3.00 - $2.50 - $3.51
 
IF – NYMEX (HH)
Apr'18 – Dec'18
 
Crude oil – swap
 
4,000 Bbl/day
 
$53.52
 
WTI – NYMEX
Apr'18 – Dec'18
 
Crude oil – three-way collar
 
2,000 Bbl/day
 
$47.50 - $37.50 - $56.08
 
WTI – NYMEX
Apr'18 – Sep'18
 
NGLs – swap (1)
 
1,500 Bbl/day
 
$32.14
 
OPIS – Mont Belvieu
_______________________
(1)
Type of NGLs involved is propane.

After March 31, 2018, the following derivative was entered into:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Jan'19 – Dec'19
 
Crude oil – three-way collar
 
1,000 Bbl/day
 
$55.00 - $45.00 - $70.25
 
WTI – NYMEX
Jan'20 – Dec'20
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.265)
 
NGPL TEXOK

21


The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
 
 
 
 
Derivative Assets
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
March 31,
2018
 
December 31,
2017
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative asset
 
$
537

 
$
721

Long-term
 
Non-current derivative asset
 

 

Total derivative assets
 
 
 
$
537

 
$
721


 
 
 
 
Derivative Liabilities
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
March 31,
2018
 
December 31,
2017
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative liability
 
$
12,104

 
$
7,763

Long-term
 
Non-current derivative liability
 
164

 

Total derivative liabilities
 
 
 
$
12,268

 
$
7,763


All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Income Statements for the three months ended March 31:
Derivatives Instruments
 
Location of Gain (Loss) Recognized in
Income on Derivative
 
Amount of Gain 
(Loss) Recognized in Income on Derivative
 
 
 
 
2018
 
2017
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain (loss) on derivatives (1)
 
$
(6,762
)
 
$
14,731

Total
 
 
 
$
(6,762
)
 
$
14,731

_______________________
(1)
Amounts settled during the 2018 and 2017 periods include net payments of $2.1 million and $1.2 million, respectively.

NOTE 11 – FAIR VALUE MEASUREMENTS

The estimated fair value of our available-for-sale securities, reflected on our Unaudited Condensed Consolidated Balance Sheets as Non-current other assets, is based on market quotes. The following is a summary of available-for-sale securities:

 
 
Cost
 
Gross Unrealized Gains
 
Gross Unrealized Losses
 
Estimated Fair Value
 
 
(In thousands)
Equity Securities:
 
 
March 31, 2018
 
$
830

 
$

 
$
132

 
$
698

December 31, 2017
 
$
830

 
$
102

 
$

 
$
932



22


During the second quarter of 2017, we received available-for-sale securities for early termination fees associated with a long-term drilling contract. We will evaluate the marketable of those equity securities to determine if any decline in fair value below cost is other-than-temporary. If a decline in fair value below cost is determined to be other-than-temporary, an impairment charge will be recorded, and a new cost basis established. We will review several factors to determine whether a loss is other-than-temporary. These factors include, but are not limited to, (i) the time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near-term prospects of the issuer, and (iv) our intent and ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value.

Fair value is defined as the amount that would be received from the sale of an asset or paid for transferring a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows:

Level 1—unadjusted quoted prices in active markets for identical assets and liabilities.

Level 2—significant observable pricing inputs other than quoted prices included within level 1 either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data.

Level 3—generally unobservable inputs developed based on the best information available and may include our own internal data.

The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments.

The following tables set forth our recurring fair value measurements:
 
 
March 31, 2018
 
 
Level 1
 
Level 2
 
Level 3
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
 
Assets
 
$

 
$
2,897

 
$
1,294

 
$
(3,654
)
 
$
537

Liabilities
 

 
(11,422
)
 
(4,500
)
 
3,654

 
(12,268
)
Total commodity derivatives
 

 
(8,525
)
 
(3,206
)
 

 
(11,731
)
Equity securities
 
698

 

 

 

 
698

 
 
$
698

 
$
(8,525
)
 
$
(3,206
)
 
$

 
$
(11,033
)
 
 
December 31, 2017
 
 
Level 1
 
Level 2
 
Level 3
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
 
Assets
 
$

 
$
2,137

 
$
3,344

 
$
(4,760
)
 
$
721

Liabilities
 

 
(8,973
)
 
(3,550
)
 
4,760

 
(7,763
)
Total commodity derivatives
 
$

 
$
(6,836
)
 
$
(206
)
 
$

 
$
(7,042
)
Equity securities
 
932

 

 

 

 
932

 
 
$
932

 
$
(6,836
)
 
$
(206
)
 
$

 
$
(6,110
)

All our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of March 31, 2018.

23


We used the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above. There were no transfers between Level 2 and Level 3 financial assets (liabilities).

Level 1 Fair Value Measurements

Equity Securities. We measure the fair values of our available for sale securities based on market quotes.

Level 2 Fair Value Measurements

Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index.

Level 3 Fair Value Measurements

Commodity Derivatives. The fair values of our natural gas and crude oil collars and three-way collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.

The following table is a reconciliation of our level 3 fair value measurements: 
 
 
Net Derivatives
 
 
Three Months Ended
 
 
March 31,
 
 
2018
 
2017
 
 
(In thousands)
Beginning of period
 
$
(206
)
 
$
(7,122
)
Total gains or losses (realized and unrealized):
 
 
 
 
Included in earnings (1)
 
(3,919
)
 
5,903

Settlements
 
919

 
617

End of period
 
$
(3,206
)
 
$
(602
)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period
 
$
(3,000
)
 
$
6,520

_______________________
(1)
Commodity derivatives are reported in the Unaudited Condensed Consolidated Income Statements in gain (loss) on derivatives.

The following table provides quantitative information about our Level 3 unobservable inputs at March 31, 2018:
Commodity (1)
 
Fair Value
 
Valuation Technique
 
Unobservable Input
 
Range
 
 
(In thousands)
 
 
 
 
 
 
Oil three-way collars
 
$
(4,457
)
 
Discounted cash flow
 
Forward commodity price curve
 
$0 - $9.41
Natural gas collar
 
$
(1
)
 
Discounted cash flow
 
Forward commodity price curve
 
$0.01 - $0.12
Natural gas three-way collars
 
$
1,252

 
Discounted cash flow
 
Forward commodity price curve
 
$0 - $0.28
 _______________________
(1)
The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Our valuation at March 31, 2018 reflected that the risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

This disclosure of the estimated fair value of financial instruments is made under accounting guidance for financial instruments. We have determined the estimated fair values by using market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. Using different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.


24


At March 31, 2018, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short-term nature.

Based on the borrowing rates available to us for credit agreement debt with similar terms and maturities and considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at March 31, 2018 and December 31, 2017 was $147.7 million and $178.0 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt associated with the Notes, net of unamortized discount and debt issuance costs, reported in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 were $642.8 million and $642.3 million, respectively. We estimate the fair value of the Notes using quoted marked prices at March 31, 2018 and December 31, 2017 was $632.9 million and $649.7 million, respectively. The Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the company’s AROs is presented in Note 7 – Asset Retirement Obligations.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. We also have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $2.7 million, $0.9 million, $0.4 million, and less than $0.1 million in twelve-month periods beginning April 1, 2018 (and through 2021), respectively. Total rent expense incurred was $2.3 million and $2.1 million for the first three months of 2018 and 2017, respectively.

In 2014, our mid-stream segment signed capital lease agreements for 20 compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the four successive twelve-month periods beginning April 1, 2018 (and through the end of 2021) are $6.2 million, $6.2 million, $7.8 million, and $0.6 million. Total maintenance and interest remaining related to these leases are $5.4 million and $1.0 million, respectively at March 31, 2018. Annual payments, net of maintenance and interest, average $4.2 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal. In any one year, these repurchases are limited to 20% of the units outstanding. We had no repurchases in the first quarter of 2018 or 2017.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. Any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees expected to devote significant time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property.

We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well.

For the next twelve months, we have committed to purchase approximately $3.4 million of new drilling rig components.


25


NOTE 13 – EQUITY

At-the-Market (ATM) Common Stock Program 

On April 4, 2017, we signed a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
 
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions we may impose).
 
We do not have to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
 
As of March 31, 2018, we have sold 787,547 shares of our common stock resulting in net proceeds of approximately $18.6 million. No shares were sold in the first quarter of 2018. On May 2, 2018, we terminated this Agreement, the details are discussed in Note 15 — Subsequent Events.

Accumulated Other Comprehensive Income

Components of accumulated other comprehensive income were as follows for the three months ended March 31:
 
 
2018
 
2017
 
 
(In thousands)
Unrealized loss on securities, before tax
 
$
(234
)
 
$

Tax expense
 
58

(1) 

Unrealized loss on securities, net of tax
 
$
(176
)
 
$

_______________________
(1)
Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.

Changes in accumulated other comprehensive income by component, net of tax, for the three months ended March 31 are as follows:
 
 
Net Gains on Equity Securities
 
 
2018
 
2017
 
 
(In thousands)
Balance at December 31, 2017
 
$
63

 
$

Adjustment due to ASU 2018-02
 
13

(1) 

Balance at January 1:
 
76

 

Unrealized loss before reclassifications
 
(176
)
(1) 

Amounts reclassified from accumulated other comprehensive income
 

 

Net current-period other comprehensive income
 
(176
)
 

Balance at March 31:
 
$
(100
)
 
$

_______________________
(1)
Due to the implementation of ASU 2018-02, the tax rate changed from 37.75% to 24.5%.


26


NOTE 14 – INDUSTRY SEGMENT INFORMATION

We have three main business segments offering different products and services within the energy industry:
 
Oil and natural gas,
Contract drilling, and
Mid-stream

Our oil and natural gas segment is engaged in the acquisition, development, and production of oil, NGLs, and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in the buying, selling, gathering, processing, and treating of natural gas and NGLs.

We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. We have no oil and natural gas production outside the United States.

The following tables provide certain information about the operations of each of our segments:
 
 
Three Months Ended March 31, 2018
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues: (1)
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
103,099

 
$

 
$

 
$

 
$

 
$
103,099

Contract drilling
 

 
50,710

 

 

 
(4,721
)
 
45,989

Gas gathering and processing
 

 

 
74,650

 

 
(18,606
)
 
56,044

Total revenues
 
103,099

 
50,710

 
74,650

 

 
(23,327
)
 
205,132

Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
37,152

 

 

 

 
(1,190
)
 
35,962

Contract drilling
 

 
35,954

 

 

 
(4,287
)
 
31,667

Gas gathering and processing
 

 

 
59,020

 

 
(17,416
)
 
41,604

Total operating costs
 
37,152

 
35,954

 
59,020

 

 
(22,893
)
 
109,233

Depreciation, depletion, and amortization
 
30,783

 
13,312

 
11,053

 
1,918

 

 
57,066

Total expenses
 
67,935

 
49,266

 
70,073

 
1,918

 
(22,893
)
 
166,299

Total operating income (loss) (2)
 
35,164

 
1,444

 
4,577

 
(1,918
)
 
(434
)
 
 
General and administrative expense
 

 

 

 
(10,762
)
 

 
(10,762
)
Gain on disposition of assets
 
71

 
26

 
34

 
30

 

 
161

Loss on derivatives
 

 

 

 
(6,762
)
 

 
(6,762
)
Interest expense, net
 

 

 

 
(10,004
)
 

 
(10,004
)
Other
 

 

 

 
6

 

 
6

Income (loss) before income taxes
 
$
35,235

 
$
1,470

 
$
4,611

 
$
(29,410
)
 
$
(434
)
 
$
11,472

_______________________
(1)
The revenues for oil and natural gas occur at a point in time. The revenues for contract drilling and gas gathering and processing occur over time.

(2)
Operating income (loss) is total operating revenues less operating expenses, depreciation, depletion, and amortization and does not include general corporate expenses, gain on disposition of assets, loss on derivatives, interest expense, other income, or income taxes.

27


 
 
Three Months Ended March 31, 2017
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
87,598

 
$

 
$

 
$

 
$

 
$
87,598

Contract drilling
 

 
37,185

 

 

 

 
37,185

Gas gathering and processing
 

 

 
66,464

 

 
(15,523
)
 
50,941

Total revenues
 
87,598

 
37,185

 
66,464

 

 
(15,523
)
 
175,724

Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
30,326

 

 

 

 
(1,122
)
 
29,204

Contract drilling
 

 
29,227

 

 

 

 
29,227

Gas gathering and processing
 

 

 
52,105

 

 
(14,401
)
 
37,704

Total operating costs
 
30,326

 
29,227

 
52,105

 

 
(15,523
)
 
96,135

Depreciation, depletion, and amortization
 
21,526

 
12,847

 
10,818

 
1,741

 

 
46,932

Total expenses
 
51,852

 
42,074

 
62,923

 
1,741

 
(15,523
)
 
143,067

Total operating income (loss)(1)
 
35,746

 
(4,889
)
 
3,541

 
(1,741
)
 

 
 
General and administrative expense
 

 

 

 
(8,954
)
 

 
(8,954
)
Gain on disposition of assets
 
9

 
7

 

 
808

 

 
824

Gain on derivatives
 

 

 

 
14,731

 

 
14,731

Interest expense, net
 

 

 

 
(9,396
)
 

 
(9,396
)
Other
 

 

 

 
3

 

 
3

Income (loss) before income taxes
 
$
35,755

 
$
(4,882