UNIT CORP - FORM 10-Q - November 3, 2016

Attached files

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EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER UNDER RULE 13A 14(A) - UNIT CORP	unt-20160930xex311.htm
EX-32 - CERTIFICATION OF CEO AND CFO UNDER RULE 13A -14(A) - UNIT CORP	unt-20160930xex32.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER UNDER RULE 13A 14(A) - UNIT CORP	unt-20160930xex312.htm

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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 September 30, 2016

[ ] 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]

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [x] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]

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 October 21, 2016, 51,486,818 shares of the issuer's common stock were outstanding.

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TABLE OF CONTENTS



		Page Number
	PART I. Financial Information

Item 1.	Financial Statements (Unaudited)

	Unaudited Condensed Consolidated Balance Sheets September 30, 2016 and December 31, 2015	4

	Unaudited Condensed Consolidated Statements of Operations Three and Nine Months Ended September 30, 2016 and 2015	6

	Unaudited Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2016 and 2015	7

	Notes to Unaudited Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	50

Item 4.	Controls and Procedures	51

	PART II. Other Information

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 3.	Defaults Upon Senior Securities	52

Item 4.	Mine Safety Disclosures	52

Item 5.	Other Information	52

Item 6.	Exhibits	53

Signatures		54

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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 in the future, 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 in the future 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 our legal proceedings 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; and


•	our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may be required to record in future periods.

These statements are based on assumptions and analyses made by us in light of 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;


•	our ability to successfully implement our pending technology conversion process relating to our financial and operational information systems; and


•	other factors, most of which are beyond our control.

You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim any current intention to update forward-looking information and to release publicly the results of any future revisions we may

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make to forward-looking statements to reflect events or circumstances after the date of this document to reflect unanticipated events.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



	September 30, 2016		December 31, 2015
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	913	$	835
Accounts receivable, net of allowance for doubtful accounts of $5,174 and $5,199 at September 30, 2016 and December 31, 2015, respectively	71,955		79,941
Materials and supplies	3,334		3,565
Current derivative asset (Note 10)	—		10,186
Current income tax receivable	366		21,002
Current deferred tax asset	8,361		14,206
Assets held for sale	—		615
Prepaid expenses and other	8,717		9,908
Total current assets	93,646		140,258
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	5,434,782		5,401,618
Unproved properties not being amortized	322,992		337,099
Drilling equipment	1,568,053		1,567,560
Gas gathering and processing equipment	700,170		689,063
Saltwater disposal systems	60,554		60,316
Corporate land and building	58,767		49,890
Transportation equipment	33,168		40,072
Other	47,282		45,489
	8,225,768		8,191,107
Less accumulated depreciation, depletion, amortization, and impairment	5,915,369		5,609,980
Net property and equipment	2,310,399		2,581,127
Goodwill	62,808		62,808
Non-current derivative asset (Note 10)	177		968
Other assets	14,161		14,681
Total assets	$	2,481,191	$	2,799,842

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - CONTINUED



	September 30, 2016		December 31, 2015
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	56,375	$	87,413
Accrued liabilities (Note 5)	57,719		46,918
Current derivative liability (Note 10)	5,552		—
Current portion of other long-term liabilities (Note 6)	16,342		16,560
Total current liabilities	135,988		150,891
Long-term debt less debt issuance costs (Note 6)	854,583		918,995
Non-current derivative liability (Note 10)	265		285
Other long-term liabilities (Note 6)	103,657		140,341
Deferred income taxes	197,122		275,750
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, 51,496,833 and 50,413,101 shares issued as of September 30, 2016 and December 31, 2015, respectively	10,016		9,831
Capital in excess of par value	499,689		486,571
Retained earnings	679,871		817,178
Total shareholders’ equity	1,189,576		1,313,580
Total liabilities and shareholders’ equity	$	2,481,191	$	2,799,842

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	78,854		$	96,619		$	206,318		$	309,944
Contract drilling	25,819			65,022			88,786			215,114
Gas gathering and processing	48,735			50,752			132,793			156,881
Total revenues	153,408			212,393			427,897			681,939
Expenses:
Oil and natural gas:
Operating costs	26,014			38,688			92,691			129,871
Depreciation, depletion, and amortization	27,135			57,159			89,378			202,378
Impairment of oil and natural gas properties (Note 2)	49,443			329,924			161,563			1,141,053
Contract drilling:
Operating costs	19,137			35,486			66,489			123,717
Depreciation	11,318			14,255			34,431			42,533
Impairment of contract drilling equipment (Note 3)	—			—			—			8,314
Gas gathering and processing:
Operating costs	35,738			40,314			99,185			125,081
Depreciation and amortization	11,436			10,976			34,410			32,518
General and administrative	8,932			7,643			26,029			26,637
(Gain) loss on disposition of assets	(154		)	7,230			(823		)	6,270
Total operating expenses	188,999			541,675			603,353			1,838,372
Loss from operations	(35,591		)	(329,282		)	(175,456		)	(1,156,433		)
Other income (expense):
Interest, net	(10,002		)	(8,286		)	(30,225		)	(23,482		)
Gain (loss) on derivatives	6,969			8,250			(4,774		)	12,917
Other, net	3			16			(11		)	38
Total other income (expense)	(3,030		)	(20		)	(35,010		)	(10,527		)
Loss before income taxes	(38,621		)	(329,302		)	(210,466		)	(1,166,960		)
Income tax expense (benefit):
Current	—			(2,584		)	—			(1,716		)
Deferred	(14,599		)	(121,437		)	(73,159		)	(437,220		)
Total income taxes	(14,599		)	(124,021		)	(73,159		)	(438,936		)
Net loss	$	(24,022	)	$	(205,281	)	$	(137,307	)	$	(728,024	)
Net loss per common share:
Basic	$	(0.48	)	$	(4.18	)	$	(2.75	)	$	(14.83	)
Diluted	$	(0.48	)	$	(4.18	)	$	(2.75	)	$	(14.83	)

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	Nine Months Ended
	September 30,
	2016			2015
	(In thousands)
OPERATING ACTIVITIES:
Net loss	$	(137,307	)	$	(728,024	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization	160,023			279,739
Impairments (Notes 2 and 3)	161,563			1,149,367
(Gain) loss on derivatives	4,774			(12,917		)
Cash receipts on derivatives settled	11,735			32,156
Deferred tax benefit	(73,159		)	(437,220		)
(Gain) loss on disposition of assets	(1,100		)	6,270
Employee stock compensation plans	10,664			12,514
Other, net	(3,055		)	1,834
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	759			84,098
Accounts payable	26,940			(4,432		)
Material and supplies	231			(2,114		)
Accrued liabilities	14,073			(363		)
Income taxes	20,636			(4,975		)
Other, net	985			5,549
Net cash provided by operating activities	197,762			381,482
INVESTING ACTIVITIES:
Capital expenditures	(154,558		)	(484,028		)
Proceeds from disposition of assets	46,880			9,838
Other	169			—
Net cash used in investing activities	(107,509		)	(474,190		)
FINANCING ACTIVITIES:
Borrowings under credit agreement	195,700			484,600
Payments under credit agreement	(261,700		)	(388,900		)
Payments on capitalized leases	(2,756		)	(2,648		)
Tax (benefit) expense from stock compensation	(376		)	4
Book overdrafts	(21,043		)	(503		)
Net cash (used in) provided by financing activities	(90,175		)	92,553
Net increase (decrease) in cash and cash equivalents	78			(155		)
Cash and cash equivalents, beginning of period	835			1,049
Cash and cash equivalents, end of period	$	913		$	894



Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	16,650	12,691
Income taxes	—	3,277
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	36,934	116,062
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	29,423	8,558

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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UNIT CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

The accompanying 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 accompanying 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 25, 2016, for the year ended December 31, 2015.

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


•	Balance Sheets at September 30, 2016 and December 31, 2015;


•	Statements of Operations for the three and nine months ended September 30, 2016 and 2015; and


•	Statements of Cash Flows for the nine months ended September 30, 2016 and 2015.

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 accompanying notes. Actual results may differ from those estimates. Results for the nine months ended September 30, 2016 and 2015 are not necessarily indicative of the results to be realized for the full year of 2016, or that we realized for the full year of 2015.

Certain amounts in the accompanying unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. There was no impact to consolidated net income (loss) or shareholders' equity.

NOTE 2 – OIL AND NATURAL GAS PROPERTIES

Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the unescalated 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible.

During each quarter for the nine months ended September 30, 2015, the 12-month average commodity prices decreased, resulting in a non-cash ceiling test write-down of $400.6 million pre-tax ($249.4 million, net of tax), $410.5 million pre-tax ($255.6 million, net of tax), and $329.9 million pre-tax ($205.4 million, net of tax) for the first, second, and third quarters, respectively.

During each quarter for the nine months ended September 30, 2016, the 12-month average commodity prices decreased, resulting in a non-cash ceiling test write-down of $37.8 million pre-tax ($23.5 million, net of tax), $74.3 million pre-tax ($46.3 million, net of tax), and $49.4 million pre-tax ($30.8 million, net of tax) for the first, second, and third quarters, respectively.

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NOTE 3 – DIVESTITURES

Oil and Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for $43.6 million during the first nine months of 2016, compared to $0.2 million during the first nine months of 2015. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

Contract Drilling

During the second quarter of 2015, we recorded a write-down of approximately $8.3 million pre-tax on drilling equipment being held for sale. During the third quarter of 2015, we sold 30 drilling rigs and other drilling equipment at auction. The proceeds from that sale, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax.

NOTE 4 – LOSS PER SHARE

Information related to the calculation of loss per share follows:



	Loss (Numerator)			Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended September 30, 2016
Basic loss per common share	$	(24,022	)	50,081	$	(0.48	)
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	—			—	—
Diluted loss per common share	$	(24,022	)	50,081	$	(0.48	)
For the three months ended September 30, 2015
Basic loss per common share	$	(205,281	)	49,155	$	(4.18	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(205,281	)	49,155	$	(4.18	)

Due to the net loss for the three months ended September 30, 2016, approximately 546,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the above loss per share calculation. For the three months ended September 30, 2015, approximately 296,000 weighted average shares were excluded.

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
	September 30,
	2016		2015
Stock options and SARs	240,270		261,270
Average exercise price	$	49.29	$	50.34

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	Loss (Numerator)			Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the nine months ended September 30, 2016
Basic loss per common share	$	(137,307	)	50,012	$	(2.75	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(137,307	)	50,012	$	(2.75	)
For the nine months ended September 30, 2015
Basic loss per common share	$	(728,024	)	49,094	$	(14.83	)
Effect of dilutive stock options, restricted stock, and SARs	—			—	—
Diluted loss per common share	$	(728,024	)	49,094	$	(14.83	)

Because of the net loss for the nine months ended September 30, 2016, approximately 424,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and excluded from the above loss per share calculation. For the nine months ended September 30, 2015, approximately 204,000 weighted average shares were excluded.



	Nine Months Ended
	September 30,
	2016		2015
Stock options and SARs	240,270		261,270
Average exercise price	$	49.29	$	50.34

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:



	September 30, 2016		December 31, 2015
	(In thousands)
Interest payable	$	17,247	$	6,321
Lease operating expenses	12,751		17,220
Taxes	10,717		3,767
Employee costs	11,718		12,641
Third-party credits	2,831		3,326
Derivative settlements	26		—
Other	2,429		3,643
Total accrued liabilities	$	57,719	$	46,918

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

Long-Term Debt

Our long-term debt consisted of the following as of the dates indicated:



	September 30, 2016			December 31, 2015
	(In thousands)
Credit agreement with an average interest rate of 2.5% and 2.6% at September 30, 2016 and December 31, 2015, respectively	$	215,000		$	281,000
6.625% senior subordinated notes due 2021	650,000			650,000
Total principal amount	865,000			931,000
Less: unamortized discount	(2,941		)	(3,338		)
Less: debt issuance costs, net	(7,476		)	(8,667		)
Total long-term debt	$	854,583		$	918,995

Credit Agreement. On April 8, 2016, we amended our Senior Credit Agreement (credit agreement) scheduled to mature on April 10, 2020. The amount we can borrow is 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 the maximum credit agreement amount of $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. The fee varies based on the amount borrowed as a percentage of the amount 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. With the new amendment, we 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 midstream 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. The October 2016 redetermination did not result in any changes. 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 may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable 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%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At September 30, 2016, we had $215.0 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.

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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 quarter ending thereafter, 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 September 30, 2016, we were in compliance with the covenants in the credit agreement.

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 will 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 the issuance of 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.

On and after May 15, 2016, we may redeem all or, from time to time, 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, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, 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 September 30, 2016.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	September 30, 2016		December 31, 2015
	(In thousands)
Asset retirement obligation (ARO) liability	$	71,021	$	98,297
Capital lease obligations	19,818		22,466
Workers’ compensation	15,185		16,551
Separation benefit plans	5,289		9,886
Deferred compensation plan	4,470		4,244
Gas balancing liability	3,806		5,047
Other	410		410
	119,999		156,901
Less current portion	16,342		16,560
Total other long-term liabilities	$	103,657	$	140,341

Estimated annual principal payments under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning October 1, 2016 (and through 2021) are $16.3 million, $44.7 million, $9.4 million, $223.9 million, and $656.7 million, respectively.

Capital Leases

During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital lease obligations of $3.7 million is included in current portion of other long-term liabilities and the non-current portion of $16.2 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2016. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $8.1 million and $2.1 million, respectively at September 30, 2016. Annual payments, net of maintenance and interest, average $4.0 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 fair market value at that time.

Future payments required under the capital leases at September 30, 2016:



	Amount
Ending September 30,	(In thousands)
2017	$	6,168
2018	6,168
2019	6,168
2020	6,168
2021	5,311
Total future payments	29,983
Less payments related to:
Maintenance	8,106
Interest	2,059
Present value of future minimum payments	$	19,818

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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 of 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:



	Nine Months Ended
	September 30,
	2016			2015
	(In thousands)
ARO liability, January 1:	$	98,297		$	100,567
Accretion of discount	2,147			2,599
Liability incurred	311			6,505
Liability settled	(874		)	(1,933		)
Liability sold ⁽¹⁾	(10,758		)	(249		)
Revision of estimates ⁽²⁾	(18,102		)	(12,881		)
ARO liability, September 30:	71,021			94,608
Less current portion	3,498			3,481
Total long-term ARO	$	67,523		$	91,127

_______________________


(1)	We sold our interest in approximately 1,270 non-core wells to unaffiliated third-parties during the first nine months of 2016.


(2)	Plugging liability estimates were revised in both 2016 and 2015 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

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. The FASB issued ASU 2016-15, to address diversity in how certain transactions are presented and classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. We do not believe this ASU will have a material impact on our financial statements.

Compensation—Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB has issued ASU 2016-09. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments primarily impact classification within the statement of cash flows between financial and operating activities. We do not believe the amendments will have a material impact on our financial statements.

Leases. The FASB has issued ASU 2016-02. Under the new guidance, lessees will be required 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 is an asset that represents the lessee's right to use a specified asset for the lease term. Lessor accounting is largely unchanged. For public companies, the amendments are effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of evaluating the impact these amendments will have on our financial statements.

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments will require

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current deferred tax assets to be combined with noncurrent deferred tax assets. We do not believe the amendments will have a material impact on our financial statements.

Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The FASB has issued ASU 2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We have maintained debt issuance costs associated with our credit agreement as an asset and amortize these fees over the life of the credit agreement. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. We have adopted these amendments during the first quarter of 2016. Previously, debt issuance costs associated with the Notes was classified as a long-term asset on the balance sheet, but with ASU 2015-03, it is presented as a direct deduction from the carrying amount of the recognized debt liability.

Presentation of Financial Statements-Going Concern: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The FASB has issued ASU 2014-15. This is intended to define management's responsibility to evaluate whether there is substantial doubt about an organization's ability to continue as a going concern and to provide related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company's ability to continue as a going concern within one year from the date financial statements are issued. The amendments are effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. Early application is permitted for annual or interim reporting periods for which the financial statements have not previously been issued. We will begin performing the assessments and making any disclosures, if applicable, beginning at the end of fiscal year 2016.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This guidance affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance in certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This ASU rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities— Oil and Gas, effective upon the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are in the process of evaluating the impact this guidance will have on our financial statements.

NOTE 9 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In millions)
Recognized stock compensation expense	$	1.9	$	2.1	$	7.2	$	11.2
Capitalized stock compensation cost for our oil and natural gas properties	0.4		0.7		1.6		2.6
Tax benefit on stock based compensation	0.7		0.8		2.7		4.2

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The remaining unrecognized compensation cost related to unvested awards at September 30, 2016 is approximately $8.6 million, of which $1.3 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.7 of a year.

The 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) as well as to non-employee directors. A total of 4,500,000 shares of the company's common stock is 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."

We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2016 or 2015. We did not grant any restricted stock awards during either of the three month periods ending September 30, 2016 or 2015. The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the nine month periods ending September 30, 2016 and 2015:



	Nine Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2015
	Time Vested			Performance Vested			Time Vested			Performance Vested
Shares granted:
Employees	486,578			152,373			576,361			148,081
Non-employee directors	90,000			—			25,848			—
	576,578			152,373			602,209			148,081
Estimated fair value (in millions):⁽¹⁾
Employees	$	2.6		$	0.8		$	18.5		$	5.1
Non-employee directors	0.9			—			0.9			—
	$	3.5		$	0.8		$	19.4		$	5.1
Percentage of shares granted expected to be distributed:
Employees	94		%	89		%	94		%	3		%
Non-employee directors	100		%	N/A			100		%	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 nine months of 2016 and 2015 are being recognized over a three year vesting period. During the first quarter of 2016, there were two different 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 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 based on the company's achievement of cash flow to total assets performance measurement each year and will range from 0% to 200%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2016 awards for the first nine months of 2016 was $1.3 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

We have entered into 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 September 30, 2016, our derivative transactions were comprised of the following 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.

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•	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.

•

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 occurring before maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives in our Unaudited Condensed Consolidated Statements of Operations.

At September 30, 2016, we had the following derivatives outstanding:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Oct’16 – Dec’16	Natural gas – swap	45,000 MMBtu/day	$2.596	IF – NYMEX (HH)
Jan’17 – Dec'17	Natural gas – swap	60,000 MMBtu/day	$2.960	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – swap	10,000 MMBtu/day	$3.025	IF – NYMEX (HH)
Jan’17 – Dec'17	Natural gas – basis swap	20,000 MMBtu/day	$(0.215)	IF – NYMEX (HH)
Jan’18 – Dec'18	Natural gas – basis swap	10,000 MMBtu/day	$(0.208)	IF – NYMEX (HH)
Oct’16 – Dec'16	Natural gas – collar	42,000 MMBtu/day	$2.40 - $2.88	IF – NYMEX (HH)
Jan’17 – Oct'17	Natural gas – collar	20,000 MMBtu/day	$2.88 - $3.10	IF – NYMEX (HH)
Oct’16 – Dec'16	Natural gas – three-way collar	13,500 MMBtu/day	$2.70 - $2.20 - $3.26	IF – NYMEX (HH)
Jan’17 – Dec'17	Natural gas – three-way collar	15,000 MMBtu/day	$2.50 - $2.00 - $3.32	IF – NYMEX (HH)
Oct’16 – Dec'16	Crude oil – collar	1,450 Bbl/day	$47.50 - $56.40	WTI – NYMEX
Oct’16 – Dec'16	Crude oil – three-way collar	700 Bbl/day	$46.50 - $35.00 - $57.00	WTI – NYMEX
Oct'16 – Dec'16	Crude oil – three-way collar ⁽¹⁾	700 Bbl/day	$47.50 - $35.00 - $63.50	WTI – NYMEX
Jan’17 – Dec'17	Crude oil – three-way collar	1,750 Bbl/day	$50.00 - $39.10 - $61.67	WTI – NYMEX

_______________________


(1)	We pay our counterparty a premium, which can be and is being deferred until settlement.

After September 30, 2016, we entered into the following derivative transactions:



Term	Commodity	Contracted Volume	Weighted Average Fixed Price	Contracted Market
Oct’16 – Dec'16	Crude oil – collar	2,000 Bbl/day	$48.00 - $53.15	WTI – NYMEX
Jan’17 – Dec'17	Crude oil – three-way collar	2,000 Bbl/day	$49.60 - $40.00 - $60.38	WTI – NYMEX
Jan’17 – Mar'17	Natural gas – swap	10,000 MMBtu/day	$3.550	IF – NYMEX (HH)

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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	September 30, 2016		December 31, 2015
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	—	$	10,186
Long-term	Non-current derivative asset	177		968
Total derivative assets		$	177	$	11,154



		Derivative Liabilities
		Fair Value
	Balance Sheet Location	September 30, 2016		December 31, 2015
		(In thousands)
Commodity derivatives:
Current	Current derivative liability	$	5,552	$	—
Long-term	Non-current derivative liability	265		285
Total derivative liabilities		$	5,817	$	285

All of 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 Statements of Operations for the three months ended September 30:



Derivatives Instruments	Location of Gain Recognized in Income on Derivative	Amount of Gain Recognized in Income on Derivative
		2016		2015
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	6,969	$	8,250
Total		$	6,969	$	8,250

_______________________


(1)	Amounts settled during the 2016 and 2015 periods include a loss of $0.5 million and a gain of $11.1 million, respectively.

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30:



Derivatives Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		2016			2015
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives ⁽¹⁾	$	(4,774	)	$	12,917
Total		$	(4,774	)	$	12,917

_______________________


(1)	Amounts settled during the 2016 and 2015 periods include gains of $11.7 million and $32.2 million, respectively.

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NOTE 11 – FAIR VALUE MEASUREMENTS

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of 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 which are 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:



	September 30, 2016
	Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	1,206		$	714		$	(1,743	)	$	177
Liabilities	(4,719		)	(2,841		)	1,743			(5,817		)
	$	(3,513	)	$	(2,127	)	$	—		$	(5,640	)



	December 31, 2015
	Level 2			Level 3			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	2,794		$	10,145		$	(1,785	)	$	11,154
Liabilities	(1,019		)	(1,051		)	1,785			(285		)
	$	1,775		$	9,094		$	—		$	10,869

All of 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 September 30, 2016.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

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.

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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 tables are reconciliations of our level 3 fair value measurements:



	Net Derivatives
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(In thousands)
Beginning of period	$	(4,761	)	$	207		$	9,094		$	3,355
Total gains or losses (realized and unrealized):
Included in earnings ⁽¹⁾	3,077			4,436			(3,257		)	5,324
Settlements	(443		)	(2,161		)	(7,964		)	(6,197		)
End of period	$	(2,127	)	$	2,482		$	(2,127	)	$	2,482
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets still held at end of period	$	2,634		$	2,275		$	(11,221	)	$	(873	)

_______________________


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

The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2016:



Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil collars	$	174		Discounted cash flow	Forward commodity price curve	$0.17 - $2.60
Oil three-way collars	$	533		Discounted cash flow	Forward commodity price curve	$0.00 - $5.82
Natural gas collar	$	(1,730	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.69
Natural gas three-way collars	$	(1,104	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.40

_______________________


(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.

Based on our valuation at September 30, 2016, we determined that risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

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

At September 30, 2016, 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 currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at September 30, 2016 and December 31, 2015 was $215.0 million and $281.0 million, respectively. This debt would be classified as Level 2.

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The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015 were $639.6 million and $638.0 million, respectively. We estimate the fair value of these Notes using quoted marked prices at September 30, 2016 and December 31, 2015 were $557.8 million and $455.5 million, respectively. These 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 – 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 development, acquisition, 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.

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The following table provides certain information about the operations of each of our segments:



	Three Months Ended September 30, 2016
	Oil and Natural Gas			Contract Drilling			Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	78,854		$	—		$	—	$	—		$	—		$	78,854
Contract drilling	—			25,819			—		—			—			25,819
Gas gathering and processing	—			—			63,090		—			(14,355		)	48,735
Total revenues	78,854			25,819			63,090		—			(14,355		)	153,408
Expenses:
Oil and natural gas:
Operating costs	27,710			—			—		—			(1,696		)	26,014
Depreciation, depletion, and amortization	27,135			—			—		—			—			27,135
Impairment of oil and natural gas properties	49,443			—			—		—			—			49,443
Contract drilling:
Operating costs	—			19,137			—		—			—			19,137
Depreciation	—			11,318			—		—			—			11,318
Gas gathering and processing:
Operating costs	—			—			48,397		—			(12,659		)	35,738
Depreciation and amortization	—			—			11,436		—			—			11,436
Total expenses	104,288			30,455			59,833		—			(14,355		)	180,221
Total operating income (loss) ⁽¹⁾	(25,434		)	(4,636		)	3,257		—			—			(26,813		)
General and administrative expense	—			—			—		(8,932		)	—			(8,932		)
Gain on disposition of assets	—			151			—		3			—			154
Gain on derivatives	—			—			—		6,969			—			6,969
Interest expense, net	—			—			—		(10,002		)	—			(10,002		)
Other	—			—			—		3			—			3
Income (loss) before income taxes	$	(25,434	)	$	(4,485	)	$	3,257	$	(11,959	)	$	—		$	(38,621	)

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

Table of Contents



	Three Months Ended September 30, 2015
	Oil and Natural Gas			Contract Drilling			Mid-stream		Other			Eliminations			Total Consolidated
	(In thousands)
Revenues:
Oil and natural gas	$	96,619		$	—		$	—	$	—		$	—		$	96,619
Contract drilling	—			68,426			—		—			(3,404		)	65,022
Gas gathering and processing	—			—			66,836		—			(16,084		)	50,752
Total revenues	96,619			68,426			66,836		—			(19,488		)	212,393
Expenses:
Oil and natural gas:
Operating costs	39,942			—			—		—			(1,254		)	38,688
Depreciation, depletion, and amortization	57,159			—			—		—			—			57,159
Impairment of oil and natural gas properties	329,924			—			—		—			—			329,924
Contract drilling:
Operating costs	—			38,671			—		—			(3,185		)	35,486
Depreciation	—			14,255			—		—			—			14,255
Impairment of contract drilling properties	—			—			—		—			—			—
Gas gathering and processing:
Operating costs	—			—			55,136		—			(14,822		)	40,314
Depreciation and amortization	—			—			10,976		—			—			10,976
Total expenses	427,025			52,926			66,112		—			(19,261		)	526,802
Total operating income (loss)⁽¹⁾	(330,406		)	15,500			724		—			(227		)	(314,409		)
General and administrative expense	—			—			—		(7,643		)	—			(7,643		)
Loss on disposition of assets	—			(7,230		)	—		—			—			(7,230		)
Gain on derivatives	—			—			—		8,250			—			8,250
Interest expense, net	—			—			—		(8,286		)	—			(8,286		)
Other	—			—			—		16			—			16
Income (loss) before income taxes	$	(330,406	)	$