UNIT CORP - FORM 10-Q - November 4, 2014

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EXCEL - IDEA: XBRL DOCUMENT - UNIT CORP	Financial_Report.xls
EX-15 - LETTER RE: UNAUDITED INTERIM FINANCIAL INFORMATION - UNIT CORP	unt-20140930xex15.htm
EX-31.2 - CERTIFICATION OF CFO UNDER RULE 13A -14(A) - UNIT CORP	unt-2014930xex312.htm
EX-31.1 - CERTIFICATION OF CEO UNDER RULE 13A -14(A) - UNIT CORP	unt-2014930xex311.htm
EX-32 - CERTIFICATION OF CEO AND CFO UNDER RULE 13A -14(A) - UNIT CORP	unt-2014930xex32.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, 2014

[ ] 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.)



7130 South Lewis, Suite 1000, Tulsa, Oklahoma	74136
(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 24, 2014, 49,574,090 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, 2014 and December 31, 2013	3

	Unaudited Condensed Consolidated Statements of Income Three and Nine Months Ended September 30, 2014 and 2013	5

	Unaudited Condensed Consolidated Statements of Comprehensive Income Three and Nine Months Ended September 30, 2014 and 2013	6

	Unaudited Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2014 and 2013	7

	Notes to Unaudited Condensed Consolidated Financial Statements	8

	Report of Independent Registered Public Accounting Firm	23

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	45

Item 4.	Controls and Procedures	46

	PART II. Other Information

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 3.	Defaults Upon Senior Securities	47

Item 4.	Mine Safety Disclosures	47

Item 5.	Other Information	47

Item 6.	Exhibits	48

Signatures		49

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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 that 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 that we file with the SEC in the future will automatically update and supersede information contained in this report.

These forward-looking statements include, among others, such things as:


•	the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;


•	the amount of wells we plan to drill or rework;


•	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 impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;


•	our projected production guidelines for the year;


•	our anticipated capital budgets;


•	the number of wells our oil and natural gas segment plans to drill during the year; and


•	our outlook for the demand of our new drilling rig, the BOSS drilling rig.

These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, and expected future developments, as well as other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to a number of 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 that we pursue;


•	demand for our land drilling services;


•	changes in laws or regulations;


•	decreases or increases in commodity prices; 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 make to forward-looking statements to reflect events or circumstances after the date of this document to reflect the occurrence of 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, 2014		December 31, 2013
	(In thousands except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	895	$	18,593
Accounts receivable, net of allowance for doubtful accounts of $2,292 and $5,342 at September 30, 2014 and at December 31, 2013, respectively	179,464		139,788
Materials and supplies	8,776		10,998
Current derivative asset (Note 9)	4,047		515
Current deferred tax asset	13,585		13,585
Assets held for sale	—		15,621
Prepaid expenses and other	13,360		12,931
Total current assets	220,127		212,031
Property and equipment:
Oil and natural gas properties on the full cost method:
Proved properties	4,696,879		4,235,712
Unproved properties not being amortized	584,270		545,588
Drilling equipment	1,569,202		1,477,093
Gas gathering and processing equipment	606,815		549,422
Transportation equipment	40,402		39,666
Other	107,965		87,435
	7,605,533		6,934,916
Less accumulated depreciation, depletion, amortization, and impairment	3,480,885		3,212,225
Net property and equipment	4,124,648		3,722,691
Debt issuance cost	10,653		11,844
Goodwill	62,808		62,808
Non-current derivative asset (Note 9)	658		—
Other assets	12,917		13,016
Total assets	$	4,431,811	$	4,022,390

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, 2014		December 31, 2013
	(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	237,736	$	154,062
Accrued liabilities (Note 4)	83,930		64,363
Income taxes payable	15,452		7,474
Current derivative liabilities (Note 9)	—		5,561
Current portion of other long-term liabilities (Note 5)	14,221		12,113
Total current liabilities	351,339		243,573
Long-term debt (Note 5)	676,843		645,696
Other long-term liabilities (Note 5)	147,214		158,331
Deferred income taxes	888,915		801,398
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, 49,574,708 and 49,107,004 shares issued, respectively	9,730		9,659
Capital in excess of par value	460,680		445,470
Retained earnings	1,897,090		1,718,263
Total shareholders’ equity	2,367,500		2,173,392
Total liabilities and shareholders’ equity	$	4,431,811	$	4,022,390

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 INCOME (UNAUDITED)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(In thousands except per share amounts)
Revenues:
Oil and natural gas	$	188,471		$	157,320		$	575,176		$	475,728
Contract drilling	120,652			100,647			341,530			313,180
Gas gathering and processing	91,851			75,809			277,687			203,821
Total revenues	400,974			333,776			1,194,393			992,729
Expenses:
Oil and natural gas:
Operating costs	48,841			50,139			133,979			138,171
Depreciation, depletion, and amortization	70,033			56,294			200,958			163,612
Contract drilling:
Operating costs	66,727			58,988			197,025			188,580
Depreciation	22,560			17,402			61,194			52,570
Gas gathering and processing:
Operating costs	78,558			63,098			238,166			172,065
Depreciation and amortization	10,272			8,773			29,972			24,143
General and administrative	10,172			9,936			30,409			28,288
(Gain) loss on disposition of assets	529			(4,345		)	(9,092		)	(7,744		)
Total operating expenses	307,692			260,285			882,611			759,685
Income from operations	93,282			73,491			311,782			233,044
Other income (expense):
Interest, net	(4,280		)	(3,625		)	(12,201		)	(11,777		)
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	19,841			(13,760		)	(9,234		)	(3,340		)
Other	(68		)	(14		)	3			(171		)
Total other income (expense)	15,493			(17,399		)	(21,432		)	(15,288		)
Income before income taxes	108,775			56,092			290,350			217,756
Income tax expense:
Current	5,451			2,111			23,721			6,745
Deferred	35,802			19,749			87,802			77,566
Total income taxes	41,253			21,860			111,523			84,311
Net income	$	67,522		$	34,232		$	178,827		$	133,445
Net income per common share:
Basic	$	1.39		$	0.71		$	3.68		$	2.77
Diluted	$	1.37		$	0.70		$	3.65		$	2.75

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 COMPREHENSIVE INCOME (UNAUDITED)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
	(In thousands)
Net income	$	67,522	$	34,232		$	178,827	$	133,445
Other comprehensive income (loss), net of taxes:
Change in value of derivative instruments used as cash flow hedges, net of tax of $0, ($3,013), $0, and ($5,517)	—		(4,797		)	—		(8,617		)
Reclassification - derivative settlements, net of tax of $0, $1,240, $0, and $63	—		1,970			—		139
Ineffective portion of derivatives, net of tax of $0, $97, $0, and ($44)	—		155			—		(72		)
Comprehensive income	$	67,522	$	31,560		$	178,827	$	124,895

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,
	2014			2013
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	178,827		$	133,445
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	294,412			242,590
Loss on derivatives	9,234			3,542
Cash payments on derivatives settled	(18,984		)	(1,777		)
Deferred tax expense	87,802			77,566
Gain on disposition of assets	(9,092		)	(7,744		)
Employee stock compensation plans	17,780			16,652
Other, net	5,156			4,263
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable	(47,704		)	1,888
Accounts payable	1,708			320
Material and supplies	2,222			(1,767		)
Accrued liabilities	28,596			31,041
Other, net	(430		)	942
Net cash provided by operating activities	549,527			500,961
INVESTING ACTIVITIES:
Capital expenditures	(686,405		)	(512,574		)
Proceeds from disposition of assets	49,341			89,916
Other	303			—
Net cash used in investing activities	(636,761		)	(422,658		)
FINANCING ACTIVITIES:
Borrowings under credit agreement	395,700			222,500
Payments under credit agreement	(364,900		)	(293,600		)
Payments on capitalized leases	(1,505		)	—
Proceeds from exercise of stock options	926			578
Book overdrafts	39,315			(7,014		)
Net cash provided by (used in) financing activities	69,536			(77,536		)
Net increase (decrease) in cash and cash equivalents	(17,698		)	767
Cash and cash equivalents, beginning of period	18,593			974
Cash and cash equivalents, end of period	$	895		$	1,741



Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest paid (net of capitalized)	(1,340	)	(1,301	)
Income taxes	16,000		7,300
Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment	(42,651	)	(516	)
Non-cash reductions to oil and natural gas properties related to asset retirement obligations	40,516		16,417
Non-cash additions to property, plant, and equipment acquired under capital leases	(28,202	)	—

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, as appropriate, 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 in conjunction with the audited consolidated financial statements and notes included in our Form 10-K, filed February 25, 2014, for the year ended December 31, 2013.

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, 2014 and December 31, 2013;

• Statements of Income for the three and nine months ended September 30, 2014 and 2013;

• Statements of Comprehensive Income for the three and nine months ended September 30, 2014 and 2013; and

• Statements of Cash Flows for the nine months ended September 30, 2014 and 2013.

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, 2014 and 2013 are not necessarily indicative of the results to be realized for the full year in the case of 2014, or that we realized for the full year of 2013.

Certain amounts in the accompanying unaudited condensed consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity.

With respect to the unaudited financial information for the three and nine month periods ended September 30, 2014 and 2013, our auditors, PricewaterhouseCoopers LLP, reported that it applied limited procedures in accordance with professional standards in reviewing that information. Its separate report dated November 4, 2014, which is included in this report, states that it did not audit and it does not express an opinion on that unaudited financial information. Accordingly, the degree of reliance placed on its report should be restricted in light of the limited review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 (Act) for its report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Act.

NOTE 2 – DIVESTITURES

We sold non-core oil and natural gas assets, net of related expenses, for $18.5 million during the first nine months of 2014, compared to $64.4 million during the first nine months of 2013 (of which $57.1 million was due to the sales in the third quarter of 2013 of our interest in certain Bakken properties). Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.

During the first quarter of 2014, we sold four idle 3,000 horsepower drilling rigs to an unaffiliated third-party. These drilling rigs were previously classified as assets held for sale at December 31, 2013. The proceeds of this sale, less costs to sell, exceeded the $16.3 million net book value of the drilling rigs, both in the aggregate and for each drilling rig, resulting in a gain of $9.6 million.

In the second and third quarters of 2013, we sold three 2,000 horsepower electric drilling rigs to unaffiliated third-parties.

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NOTE 3 – EARNINGS PER SHARE

Information related to the calculation of earnings per share follows:



	Income (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the three months ended September 30, 2014
Basic earnings per common share	$	67,522	48,650	$	1.39
Effect of dilutive stock options, restricted stock, and stock appreciation rights (SARs)	—		527	(0.02		)
Diluted earnings per common share	$	67,522	49,177	$	1.37
For the three months ended September 30, 2013
Basic earnings per common share	$	34,232	48,254	$	0.71
Effect of dilutive stock options, restricted stock, and SARs	—		404	(0.01		)
Diluted earnings per common share	$	34,232	48,658	$	0.70

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,
	2014		2013
Stock options and SARs	24,500		149,665
Average exercise price	$	73.26	$	58.41



	Income (Numerator)		Weighted Shares (Denominator)	Per-Share Amount
	(In thousands except per share amounts)
For the nine months ended September 30, 2014
Basic earnings per common share	$	178,827	48,596	$	3.68
Effect of dilutive stock options, restricted stock, and SARs	—		458	(0.03		)
Diluted earnings per common share	$	178,827	49,054	$	3.65
For the nine months ended September 30, 2013
Basic earnings per common share	$	133,445	48,193	$	2.77
Effect of dilutive stock options, restricted stock, and SARs	—		317	(0.02		)
Diluted earnings per common share	$	133,445	48,510	$	2.75



	Nine Months Ended
	September 30,
	2014		2013
Stock options and SARs	49,000		149,665
Average exercise price	$	67.83	$	58.41

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NOTE 4 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:



	September 30, 2014		December 31, 2013
	(In thousands)
Employee costs	$	27,242	$	27,633
Interest	17,343		6,504
Lease operating expenses	15,269		16,073
Taxes	12,994		2,313
Derivative settlements	114		416
Deposits on assets held for sale	—		3,750
Other	10,968		7,674
Total accrued liabilities	$	83,930	$	64,363

NOTE 5 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

As of the dates in the table, our long-term debt consisted of the following:



	September 30, 2014		December 31, 2013
	(In thousands)
Credit agreement with an average interest rate of 4.0% at September 30, 2014	$	30,800	$	—
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.0 million at September 30, 2014 and $4.3 million at December 31, 2013	646,043		645,696
Total long-term debt	$	676,843	$	645,696

Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount we can borrow is the lesser of the amount we elect (from time to time) 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 $900.0 million. Our current commitment amount is $500.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% 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. The credit agreement matures as of September 13, 2016. In connection with the most recent amendment of the credit agreement, we paid $1.5 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement.

The amount of the borrowing base–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. Effective with the April 2014 redetermination, the lenders approved an increase in our borrowing base to $900.0 million from $800.0 million. There was no additional change to the borrowing base with the October 2014 redetermination. 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 set forth 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 1.75% to 2.50% 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 in any event 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 anytime, without a premium or penalty. At September 30, 2014, we had $30.8 million outstanding borrowings under our credit agreement.

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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 (e) general corporate purposes.

The credit agreement prohibits, among other things:


•	the payment of dividends (other than stock dividends) during any fiscal year in excess of 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, 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; and


•	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, 2014, we were in compliance with the covenants contained 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). The interest is payable semi-annually (in arrears) on May 15 and November 15 of each year, and the Notes will mature on May 15, 2021. In connection with the issuance of the Notes, we incurred $14.7 million of fees 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 and providing for the issuance of the Notes. The Guarantors are all 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 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.

At any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. 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, 2014.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following:



	September 30, 2014		December 31, 2013
	(In thousands)
Asset retirement obligation (ARO) liability	$	96,679	$	133,657
Capital lease obligations	26,708		—
Workers’ compensation	19,224		20,041
Separation benefit plans	10,799		9,382
Deferred compensation plan	3,965		3,589
Gas balancing liability	3,775		3,775
Other	285		—
	161,435		170,444
Less current portion	14,221		12,113
Total other long-term liabilities	$	147,214	$	158,331

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, 2014 (and through 2019) are $14.2 million, $35.2 million, $9.2 million, $7.1 million, and $7.4 million, respectively.

Capital Leases

During the first nine months of 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 $3.4 million is included in current portion of other long-term liabilities and the non-current portion of $23.3 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2014. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $11.8 million and $3.9 million, respectively at September 30, 2014. Annual payments, net of maintenance and interest, average $3.9 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of the fair market value of the assets at that time.

Future payments required under the capital leases at September 30, 2014 are as follows:



	Amount
Ending September 30,	(In thousands)
2015	$	6,195
2016	6,195
2017	6,195
2018	6,195
2019	6,195
2020 and thereafter	11,516
Total future payments	42,491
Less payments related to:
Maintenance	11,848
Interest	3,935
Present value of future minimum payments	$	26,708

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NOTE 6 – 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,
	2014			2013
	(In thousands)
ARO liability, January 1:	$	133,657		$	146,159
Accretion of discount	3,538			4,152
Liability incurred	2,889			3,820
Liability settled	(3,936		)	(3,439		)
Liability sold	(1,206		)	(632		)
Revision of estimates ⁽¹⁾	(38,263		)	(16,166		)
ARO liability, September 30:	96,679			133,894
Less current portion	2,718			2,954
Total long-term ARO	$	93,961		$	130,940

_______________________


(1)	Plugging liability estimates were revised in both 2014 and 2013 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 7 – NEW ACCOUNTING PRONOUNCEMENTS

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.

Compensation - Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide that a Performance Target Could Be Achieved after the Requisite Service Period. The FASB has issued ASU 2014-12, the amendments in the ASU require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. A reporting entity should apply existing guidance in Topic 718, Compensation – Stock Compensation, as it relates to awards with performance conditions that affect vesting to account for such awards. The performance target should not be reflected in estimating the grant-date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved.The amendments in this ASU are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. We do not have any stock compensation awards with these conditions at this time.

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Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This 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. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are in the process of evaluating the impact it will have on our financial statements.

Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The FASB has issued ASU 2014-08, the amendments in this update change the criteria for reporting discontinued operations while enhancing disclosures in this area. It also addresses sources of confusion and inconsistent application related to financial reporting of discontinued operations guidance in U.S. GAAP. Under the new guidance, only disposals representing a strategic shift that would have a major effect on the organization's operations and financial results should be presented as discontinued operations. In addition, it requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income, and expenses of discontinued operations. It also requires disclosure of pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. The updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. Early adoption is permitted. We currently do not have any discontinued operations or disposals of components of an entity.

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, ASU 2013-11 was issued because GAAP does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendment provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments are applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The adoption of this standard did not have a material impact on our consolidated financial statements.

NOTE 8 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(In millions)
Recognized stock compensation expense	$	4.4	$	4.4	$	12.7	$	12.0
Capitalized stock compensation cost for our oil and natural gas properties	0.9		1.0		2.7		2.6
Tax benefit on stock based compensation	1.7		1.8		4.9		4.7

The remaining unrecognized compensation cost related to unvested awards at September 30, 2014 is approximately $22.0 million of which $3.6 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.8 of a year.

The Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012 (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 3,300,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan.

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We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2014 and 2013. The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the nine months ended September 30, 2014 and 2013, as there were no restricted stock awards granted during the three months ended September 30, 2014 or 2013.



	Nine Months Ended
	September 30,
	2014			2013
Shares granted:
Employees	438,342			448,549
Non employee directors	13,768			21,128
	452,110			469,677
Estimated fair value (in millions):
Employees	$	22.4		$	21.0
Non employee directors	0.9			0.9
	$	23.3		$	21.9
Percentage of shares granted expected to be distributed:
Employees	95		%	94		%
Non employee directors	100		%	100		%

The restricted stock awards granted during the first nine months of 2014 and 2013 are being recognized over a three year vesting period, except for a portion of those awards made to certain executive officers. As to those executive officers, 40% of the shares granted in 2014, or 71,674 shares, and 30% of the shares granted in 2013, or 57,405 shares, (the performance shares), will cliff vest in the first half of 2017 and 2016, respectively. The actual number of performance shares that vest in 2016 and 2017 will be based on the company’s achievement of certain stock performance measures at the end of the term, and will range from 0% to 150% of the restricted shares granted as performance shares. Based on the selected performance criteria, the participants are estimated to receive the targeted amount (or approximately 100%) of the 2014 and 2013 performance based shares. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2014 awards for the first nine months of 2014 was $7.6 million.

NOTE 9 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, 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 is based, in part, on our view of current and future market conditions. As of September 30, 2014, our derivative transactions consisted of the following types of 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.


•	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.

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. In August 2012, we determined–on a prospective basis–that we would no longer elect to use cash flow hedge accounting for our economic hedges. As a result, the change in fair value, on all commodity derivatives entered into after that determination, is reflected in the income statement and not in accumulated other comprehensive income (OCI). As of December 31, 2013, all cash flow hedges had expired.

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At September 30, 2014, the following non-designated hedges were outstanding:



Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct’14 – Dec’14	Crude oil – swap	3,000 Bbl/day	$91.77	WTI – NYMEX
Oct’14 – Dec’14	Crude oil – collar	4,000 Bbl/day	$90.00-96.08	WTI – NYMEX
Jan’15 – Dec’15	Crude oil – swap	1,000 Bbl/day	$95.00	WTI – NYMEX
Oct’14 – Dec’14	Natural gas – swap	80,000 MMBtu/day	$4.24	NYMEX (HH)
Oct’14 – Dec’14	Natural gas – collar	10,000 MMBtu/day	$3.75-4.37	NYMEX (HH)

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, 2014		December 31, 2013
		(In thousands)
Commodity derivatives:
Current	Current derivative asset	$	4,047	$	515
Long-term	Non-current derivative asset	658		—
Total derivative assets		$	4,705	$	515



		Derivative Liabilities
		Fair Value
	Balance Sheet Location	September 30, 2014		December 31, 2013
		(In thousands)
Commodity derivatives:
Current	Current derivative liabilities	$	—	$	5,561
Long-term	Non-current derivative liabilities	—		—
Total derivative liabilities		$	—	$	5,561

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.

For hedges designated under cash flow hedge accounting, we recognized in OCI the effective portion of any changes in fair value and reclassified the recognized gains (losses) on the sales to oil and natural gas revenue as the underlying transactions were settled. Because our cash flow hedges expired as of December 31, 2013, we had no balance in accumulated OCI at September 30, 2014. As of September 30, 2013, we had recognized a loss of $1.0 million, net of tax.

For our economic hedges that we did not apply cash flow accounting to, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net in our Unaudited Condensed Consolidated Statements of Income. Changes in the fair value of derivatives that were designated as cash flow hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value that resulted from ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net.

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Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:



Derivatives in Cash Flow Hedging Relationships	Amount of Gain or (Loss) Recognized in Accumulated OCI on Derivative (Effective Portion) ⁽¹⁾
	2014		2013
	(In thousands)
Commodity derivatives	$	—	$	(963	)

_______________________

(1) Net of taxes.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the three months ended September 30:



Derivative Instrument	Location of Gain or (Loss) Reclassified from Accumulated OCI into Income & Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income ⁽¹⁾					Amount of Gain or (Loss) Recognized in Income ⁽²⁾
		2014		2013			2014		2013
		(In thousands)
Commodity derivatives	Oil and natural gas revenue	$	—	$	(3,210	)	$	—	$	—
Commodity derivatives	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	—		—			—		(252		)
Total		$	—	$	(3,210	)	$	—	$	(252	)

_______________________


(1)	Effective portion of gain (loss).


(2)	Ineffective portion of gain (loss).

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the three months ended September 30:



Derivatives Not Designated as Hedging Instruments	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
		2014		2013
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net ⁽¹⁾	$	19,841	$	(13,508	)
Total		$	19,841	$	(13,508	)

_______________________


(1)	Amounts settled during the 2014 and 2013 periods include losses of $1.0 million and $2.4 million, respectively.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:



Derivative Instrument	Location of Gain or (Loss) Reclassified from Accumulated OCI into Income & Location of Gain or (Loss) Recognized in Income	Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income ⁽¹⁾					Amount of Gain or (Loss) Recognized in Income ⁽²⁾
		2014		2013			2014		2013
		(In thousands)
Commodity derivatives	Oil and natural gas revenue	$	—	$	(202	)	$	—	$	—
Commodity derivatives	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	—		—			—		116
Total		$	—	$	(202	)	$	—	$	116

_______________________


(1)	Effective portion of gain (loss).


(2)	Ineffective portion of gain (loss).

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Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the nine months ended September 30:



Derivatives Not Designated as Hedging Instruments	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
		2014			2013
		(In thousands)
Commodity derivatives	Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net ⁽¹⁾	$	(9,234	)	$	(3,456	)
Total		$	(9,234	)	$	(3,456	)

_______________________


(1)	Amounts settled during the 2014 and 2013 periods include losses of $19.0 million and $1.6 million, respectively.

NOTE 10 – 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. The highest priority is given to Level 1 and the lowest priority is 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 that are 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 that 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. We corroborate these inputs based on recent transactions and broker quotes and compare the fair value with actual settlements.

The following tables set forth our recurring fair value measurements:



	September 30, 2014
	Level 2		Level 3			Gross Amounts			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	4,114	$	630		$	4,744		$	(39	)	$	4,705
Liabilities	—		(39		)	(39		)	39			—
	$	4,114	$	591		$	4,705		$	—		$	4,705



	December 31, 2013
	Level 2			Level 3			Gross Amounts			Effect of Netting			Net Amounts Presented
	(In thousands)
Financial assets (liabilities):
Commodity derivatives:
Assets	$	1,978		$	20		$	1,998		$	(1,483	)	$	515
Liabilities	(4,429		)	(2,615		)	(7,044		)	1,483			(5,561		)
	$	(2,451	)	$	(2,595	)	$	(5,046	)	$	—		$	(5,046	)

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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.

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.

Level 3 Fair Value Measurements

Commodity Derivatives. The fair values of our natural gas and crude oil 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:



	Commodity Collars
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(In thousands)
Beginning of period	$	(6,081	)	$	1,446		$	(2,595	)	$	(595	)
Total gains or losses (realized and unrealized):
Included in earnings ⁽¹⁾	5,785			(3,949		)	(2,043		)	(2,544		)
Included in other comprehensive income (loss)	—			(119		)	—			(119		)
Settlements	887			—			5,229			636
End of period	$	591		$	(2,622	)	$	591		$	(2,622	)
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	$	6,672		$	(3,949	)	$	3,186		$	(1,908	)

_______________________


(1)	Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Income in oil and natural gas revenues (for cash flow hedges) and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively.

The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2014:



Commodity ⁽¹⁾	Fair Value			Valuation Technique	Unobservable Input	Range
	(In thousands)
Oil collars	$	630		Discounted cash flow	Forward commodity price curve	$0.14 - $3.61
Natural gas collar	$	(39	)	Discounted cash flow	Forward commodity price curve	$0.00 - $0.16

_______________________


(1)	The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas 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, 2014, we determined that risk of non-performance by our counterparties was immaterial.

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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 these estimates. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

At September 30, 2014, 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 has historically approximated its fair value and at September 30, 2014 was $30.8 million. This debt would be classified as Level 2.

The carrying amounts of long-term debt, net of unamortized discount, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 were $646.0 million and $645.7 million, respectively. We estimated the fair value of these Notes using quoted marked prices at September 30, 2014 and December 31, 2013 which were $655.8 million and $688.2 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 6 – Asset Retirement Obligations.

NOTE 11 – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

There was no activity in accumulated other comprehensive income in 2014.

Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended September 30, 2013 are as follows:



	Net Gains (Losses) on Cash Flow Hedges
	(In thousands)
Balance at July 1:	$	1,709
Other comprehensive loss before reclassification	(4,797		)
Amounts reclassified from accumulated other comprehensive income	2,125
New current-period other comprehensive loss	(2,672		)
Balance at September 30:	$	(963	)

Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the three months ended September 30, 2013 are as follows:



	Amount			Affected Line Item in the Statement Where Net Income is Presented
	(In thousands)
Net gains (loss) on cash flow hedges
Commodity derivatives	$	(3,210	)	Oil and natural gas revenues
Commodity derivatives	(252		)	Loss on derivatives not designated as hedges and hedge ineffectiveness, net
	(3,462		)	Total before tax
	1,337			Tax expense
Total reclassification for the period	$	(2,125	)	Net of tax

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Changes in accumulated other comprehensive income (loss) by component, net of tax, for the nine months ended September 30, 2013 are as follows:



	Net Gains (Losses) on Cash Flow Hedges
	(In thousands)
Balance at January 1:	$	7,587
Other comprehensive loss before reclassification	(8,617		)
Amounts reclassified from accumulated other comprehensive income	67
New current-period other comprehensive loss	(8,550		)
Balance at September 30:	$	(963	)

Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the nine months ended September 30, 2013 are as follows:



	Amount			Affected Line Item in the Statement Where Net Income is Presented
	(In thousands)
Net gains (loss) on cash flow hedges
Commodity derivatives	$	(202	)	Oil and natural gas revenues
Commodity derivatives	116			Gain on derivatives not designated as hedges and hedge ineffectiveness, net
	(86		)	Total before tax
	19			Tax expense
Total reclassification for the period	$	(67	)	Net of tax

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NOTE 12 – INDUSTRY SEGMENT INFORMATION

We have three main business segments offering different products and services:


•	Oil and natural gas,


•	Contract drilling, and


•	Mid-stream

The 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. Our oil and natural gas production outside the United States is not significant.

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(In thousands)
Revenues:
Oil and natural gas	$	188,471		$	157,320		$	575,176		$	475,728

Contract drilling	147,866			119,105			407,905			357,118
Elimination of inter-segment revenue	(27,214		)	(18,458		)	(66,375		)	(43,938		)
Contract drilling net of inter-segment revenue	120,652			100,647			341,530			313,180

Gas gathering and processing	113,467			99,007			350,181			272,073
Elimination of inter-segment revenue	(21,616		)	(23,198		)	(72,494		)	(68,252		)
Gas gathering and processing net of inter-segment revenue	91,851			75,809			277,687			203,821

Total revenues	$	400,974		$	333,776		$	1,194,393		$	992,729
Operating income:
Oil and natural gas	$	69,597		$	50,887		$	240,239		$	173,945
Contract drilling	31,365			24,257			83,311			72,030
Gas gathering and processing	3,021			3,938			9,549			7,613
Total operating income ⁽¹⁾	103,983			79,082			333,099			253,588
General and administrative	(10,172		)	(9,936		)	(30,409		)	(28,288		)
Gain (loss) on disposition of assets	(529		)	4,345			9,092			7,744
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	19,841			(13,760		)	(9,234		)	(3,340		)
Interest expense, net	(4,280		)	(3,625		)	(12,201		)	(11,777		)
Other	(68		)	(14		)	3			(171		)
Income before income taxes	$	108,775		$	56,092		$	290,350		$	217,756

_______________________


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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Unit Corporation

We have reviewed the accompanying Unaudited Condensed Consolidated Balance Sheets of Unit Corporation and its subsidiaries as of September 30, 2014, and the related Unaudited Condensed Consolidated Statements of Income and Comprehensive Income for the three and nine-month periods ended September 30, 2014 and 2013 and the Unaudited Condensed Consolidated Statements of Cash Flows for the nine-month periods ended September 30, 2014 and 2013. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2013, and the related consolidated statements of income, shareholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 25, 2014, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2013, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

November 4, 2014

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

Management’s Discussion and Analysis (MD&A) provides an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year. We have organized MD&A into the following sections:


•	General;


•	Business Outlook;


•	Executive Summary;


•	Financial Condition and Liquidity;


•	New Accounting Pronouncements; and


•	Results of Operations.

Please read the following discussion and our unaudited condensed consolidated financial statements and related notes with the information contained in our most recent Annual Report on Form 10-K.

Unless otherwise indicated or required by the content, when used in this report the terms “company,” “Unit,” “us,” “our,” “we,” and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries.

General

We operate, manage, and analyze our results of operations through our three principal business segments:


•	Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.


•	Contract Drilling – carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.


•	Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.

Business Outlook

As discussed in other parts of this report, the success of our consolidated business, as well as that of each of our three operating segments, depends, to a large extent, on: the prices we receive for and the amount of our oil, NGLs, and natural gas production; the demand for oil, NGLs, and natural gas; and, the demand for our drilling rigs which, in turn, influences the amounts we can charge for the use of those drilling rigs. Although all of our current operations are located within the United States, events outside the United States can and do have an impact on us and our industry.

Oil and natural gas prices have declined significantly during the recent months. The decline in commodity prices may cause us (and other oil and natural gas companies) to reduce our overall level of drilling activity and spending. When drilling activity and spending decline, for any sustained period of time, our dayrates and utilization rates also tend to decline.

In addition to their direct impact on us, low commodity prices–if sustained for a long period of time–could impact the liquidity of some of our industry partners and customers which, in turn, could limit their ability to meet their financial obligations to us.

Executive Summary

Oil and Natural Gas

Third quarter 2014 production from our oil and natural gas segment was 4,612,000 barrels of oil equivalent (Boe) which was essentially unchanged compared to the second quarter of 2014. The third quarter of 2014 production was negatively impacted by approximately 0.5 billion cubic feet of natural gas equivalent (Bcfe) due to a third-party plant being shut down in the Wilcox play for approximately seven days. Third quarter 2014 production had increased 9% over the third quarter of 2013 primarily from production associated with new wells.

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Third quarter 2014 oil and natural gas revenues decreased 5% from the second quarter of 2014 and increased 20% over the third quarter of 2013. The decrease from the second quarter of 2014 was due primarily to lower oil and natural gas prices. The increase over the third quarter of 2013 was due primarily to increased production along with higher natural gas and NGLs prices.

Our oil prices for the third quarter of 2014 decreased 3% compared to the second quarter of 2014 and decreased 4% from the third quarter of 2013. Our NGLs prices were essentially unchanged from the second quarter of 2014 and increased 7% over the third quarter of 2013. Our natural gas prices decreased 9% from the second quarter of 2014 and increased 18% over the third quarter of 2013.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) decreased 9% from the second quarter of 2014 and increased 30% over the third quarter of 2013. The decrease from the second quarter of 2014 was primarily due to lower oil and natural gas prices coupled with higher gross production taxes due to fewer tax credits being received in the third quarter. The increase over the third quarter of 2013 was due primarily to increases in production and decreases in salt water disposal expense partially offset by lower oil prices and higher general and administrative expense. The second quarter of 2014 included refunds for production tax credits attributable to certain types of gas wells of $3.8 million compared to $1.4 million during the third quarter of 2014.

Operating cost per Boe produced for the third quarter of 2014 increased 9% over the second quarter of 2014 and decreased 11% from the third quarter of 2013. Costs were higher between the third and second quarter of 2014 primarily due to higher gross production taxes and higher general and administrative expense. Third quarter 2014 costs decreased from the third quarter of 2013 due to lower lease operating expenses and salt water disposal expense and higher gross production tax credits partially offset by higher general and administrative expense.

For the remainder of 2014, we have derivative contracts covering 7,000 Bbls per day of oil production and 90,000 Mmbtu per day of natural gas production. The contracts for the oil production are swap contracts covering 3,000 Bbls per day and collars for 4,000 Bbls per day. The swap transactions are at a comparable average NYMEX prices of $91.77 per barrel. The collar transactions are at a comparable average NYMEX floor price of $90.00 and ceiling price of $96.08. The contracts for our natural gas production are swaps covering 80,000 Mmbtu per day and a collar covering 10,000 Mmbtu per day. The swap transactions are at a comparable average NYMEX price of $4.24. The collar transaction is at a comparable average NYMEX floor price of $3.75 and ceiling price of $4.37.

For 2015, we have a derivative contract covering 1,000 Bbls per day of oil production. That contract is a swap contract at an average price of $95.00 per barrel.

As of September 30, 2014, we completed drilling 130 gross wells (85.45 net wells). For all of 2014, we plan to participate in the drilling of approximately 180 wells. Our estimated 2014 capital expenditures, excluding acquisitions, for this segment are $727.5 million. Our current 2014 production guidance is approximately 18.2 to 18.4 MMBoe, an increase of 9% to 10% over 2013, although actual results continue to be subject to many factors.

Contract Drilling

The rate at which our drilling rigs were used (“our utilization rate”) for the third quarter 2014 was 67%, compared to 62% and 51% for the second quarter of 2014 and the third quarter of 2013, respectively.

Dayrates for the third quarter of 2014 averaged $20,070, a 1% increase over the second quarter of 2014 and a 2% increase over the third quarter of 2013. The increases were due to improving market conditions.

Direct profit (contract drilling revenue less contract drilling operating expense) for the third quarter of 2014 increased 13% and 29% over the second quarter of 2014 and the third quarter of 2013, respectively. The increases were primarily due to the increase in the number of drilling rigs operating and increased dayrates.

Operating cost per day for the third quarter of 2014 decreased 8% from the second quarter of 2014 and decreased 9% from the third quarter of 2013. The decrease from the third quarter 2013 was primarily due to more revenue days and lower per day direct costs. The decrease from the second quarter 2014 was due to more revenue days and a reduction in bad debt expense.

Our drilling rig fleet is diverse with drilling rig capabilities ranging from the shallow to the ultra-deep. This allows us the flexibility to meet customer demands for multiple market plays. The majority of our fleet is drilling horizontal or directional wells in the Bakken Shale, Green River Basin, Permian Basin, Eagle Ford Shale, South Central Oklahoma Oil Province

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(SCOOP), Granite Wash, and the Cleveland, Tonkawa, and Marmaton plays. These areas cover North Dakota, Wyoming, Texas, Oklahoma, and Kansas. Our smaller drilling rigs are used in shallow plays like the Mississippian in northern Oklahoma and southern Kansas. We also are working on an ultra-deep gas exploration contract in southern Louisiana. Depending on the depth and complexity of the drilling program determines the equipment required for the contract, which affects the dayrates and margins.

Currently, we have 82 drilling rigs operating. Of those, 44 are on spot market contracts and 38 are on term drilling contracts, with original terms ranging from six months to two years. Fourteen of the term contracts are up for renewal during the fourth quarter of 2014, 22 are up for renewal in 2015, and two are up for renewal in 2016. Term contracts may contain a fixed rate for the duration of the contract or provide for rate adjustments within a specific range from the existing rate.

During the first quarter of 2014, four idle 3,000 horsepower drilling rigs were sold to an unaffiliated third party. The proceeds from that sale are being used in our construction program for our new proprietary 1,500 horsepower, AC electric drilling rig, called the BOSS drilling rig. This new drilling rig design is positioning us to more effectively meet the demands of our existing customers as well as allowing us to compete for the work of new customers.

In the second and third quarters of 2013, we sold three 2,000 horsepower electric drilling rigs to unaffiliated third-parties.

Our first BOSS drilling rig, which originally was placed into service with our oil and natural gas segment, has now been contracted to a third-party operator that plans to take delivery during the fourth quarter of 2014. Our second BOSS drilling rig began operating during the third quarter of 2014, and recently our third BOSS drilling rig was delivered and began operating, bringing our fleet to a total of 120 drilling rigs. Six additional BOSS drilling rigs have been contracted to be built for third-party operators, one will be placed into service during the fourth quarter and the rest will be placed into service in 2015. The long lead time components for three additional BOSS drilling rigs have also been ordered. Our estimated 2014 capital expenditures for this segment are $161.1 million.

Mid-Stream

Third quarter 2014 liquids sold per day increased 1% and 32% over the second quarter of 2014 and the third quarter of 2013, respectively. The increases were due to new wells being connected to our systems. For the third quarter of 2014, gas processed per day increased 5% over the second quarter of 2014 and increased 17% over the third quarter of 2013. These increases are primarily due to connecting new wells to both existing and newly constructed systems. For the third quarter of 2014, gas gathered per day decreased 2% from both the second quarter of 2014 and the third quarter of 2013. The decreases were primarily due to lower gathered volumes from Pittsburgh Mills system somewhat offset by higher volumes from several other gathering systems.

NGLs prices in the third quarter of 2014 increased 2% over the prices received in the second quarter of 2014 and decreased 14% from the prices received in the third quarter of 2013. Because certain of the contracts used by our mid-stream segment for NGLs transactions are percent of proceeds (POP) contracts–under which we receive a share of the proceeds from the sale of the NGLs–our revenues from those POP contracts fluctuate based on the price of NGLs.

Direct profit (mid-stream revenues less mid-stream operating expense) for the third quarter of 2014 decreased 5% from the second quarter of 2014 and increased 5% over the third quarter of 2013. The decrease from the second quarter of 2014 was primarily due to a decrease in the price of gas sold and lower condensate volumes in the warmer summer months. The increase over the third quarter of 2013 was primarily due to increased revenues due to the increase in the liquids sold and from higher gas sales and prices. Total operating cost for our mid-stream segment for the third quarter of 2014 were essentially unchanged from the second quarter of 2014 and increased 25% over the third quarter of 2013.

At our Hemphill County, Texas facility, total processing capacity remains at 135 MMcf per day and we are connecting new wells to our system as they are drilled and completed. We are completing the construction of a nine mile trunkline and related compression facilities which will connect our Buffalo Wallow gathering system to our Hemphill processing facility. On completion of this trunkline project, we will have the ability to process Buffalo Wallow gathered production at our Hemphill processing facility. This trunkline project is scheduled for completion in November 2014, with gas flow to begin on January 1, 2015.

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the north end of our system. At the Waswo compressor station, construction is underway to install the fourth compressor and we expect to complete this project by the end of 2014.

Activity around our Perkins facility remains high and we are continuing to connect wells from various producers. As of September 2014, we have connected 21 new wells this year to this system. Our current processing capacity is 20 MMcf per day and we are in the process of upgrading our processing facilities which will increase our total processing capacity to approximately 27 MMcf per day. This plant upgrade project is expected to be completed by the end of 2014.

In the Mississippian play in north central Oklahoma, we continue to add wells and increase volumes on our Bellmon facility. As of September 2014, we have connected 56 new wells to this system during this year. Our current processing capacity is approximately 90 MMcf per day. We recently completed several pipeline expansion projects and lateral lines for various producers that will allow us the ability connect additional wells to this system. With approximately 50 MMcf per day of available processing capacity, we can add additional volumes with minimal future capital expenditures.

In the Appalachian region, we continue to expand our Pittsburgh Mills gathering system. Construction is underway to extend our gathering system north into Butler County, Pennsylvania. This planned expansion will allow us the ability to connect additional wells that are scheduled to be drilled in 2015. This expansion project is expected to be completed in the first quarter of 2015.

Our estimated 2014 capital expenditures for this segment are $60.2 million, excluding capital leases. We have recently signed a fee-based contract under which we will build our new Showshoe project in the Marcellus. This project will consist of the construction of a seven-mile, 16 inch and 24 inch trunkline to gather production in Centre County, Pennsylvania for delivery to an interstate pipeline. Construction has started with an expected completion date in the third quarter of 2015.

Financial Condition and Liquidity

Summary

Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreement. The principal factors determining the amount of our cash flow are:


•	the quantity of natural gas, oil, and NGLs we produce;


•	the prices we receive for our natural gas, oil, and NGLs production;


•	the demand for and the dayrates we receive for our drilling rigs; and


•	the fees and margins we obtain from our natural gas gathering and processing contracts.



	Nine Months Ended September 30,						% Change
	2014			2013			% Change
	(In thousands except percentages)
Net cash provided by operating activities	$	549,527		$	500,961		10	%
Net cash used in investing activities	$	(636,761	)	$	(422,658	)	51	%
Net cash provided by (used in) financing activities	$	69,536		$	(77,536	)	190	%
Net increase (decrease) in cash and cash equivalents	$	(17,698	)	$	767

Cash Flows from Operating Activities

Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production, the quantity of oil, NGLs, and natural gas we produce, settlements of derivative contracts, third-party demand for our drilling rigs, and mid-stream services and the rates we are able to charge for those services. Our cash flows from operating activities are also impacted by changes in working capital.

Net cash provided by operating activities in the first nine months of 2014 increased by $48.6 million over the first nine months of 2013 due primarily to increases in profit margins in our oil and natural gas and contract drilling segments and to a lesser extent from changes in operating assets and liabilities related to the timing of cash receipts and disbursements.

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Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration for and production of oil, NGLs, and natural gas. These capital expenditures are necessary to offset inherent declines in production, which is typical in the capital-intensive oil and natural gas industry.

Cash flows used in investing activities increased by $214.1 million for the first nine months of 2014 compared to the first nine months of 2013. The change was due primarily to an increase in capital expenditures partially offset by the proceeds received from the disposition of assets. See additional information on capital expenditures below under Capital Requirements.

Cash Flows from Financing Activities

Cash flows provided by financing activities increased by $147.1 million for the first nine months of 2014 compared to the first nine months of 2013. This increase was primarily due to our borrowings under our line of credit as well as an increase in our book overdrafts, which are checks that have been issued but not presented to our bank for payment before the end of the period.

At September 30, 2014, we had unrestricted cash totaling $0.9 million and had borrowed $30.8 million of the $500.0 million we had elected to then have available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.

The following is a summary of certain financial information as of September 30, 2014 and 2013 and for the nine months ended September 30, 2014 and 2013:



	September 30,						% Change
	2014			2013			% Change
	(In thousands except percentages)
Working capital	$	(131,212	)	$	(48,080	)	(173	)%
Long-term debt	$	676,843		$	645,584		5	%
Shareholders’ equity	$	2,367,500		$	2,116,945		12	%
Ratio of long-term debt to total capitalization	22		%	23		%
Net income	$	178,827		$	133,445		34	%

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The following table summarizes certain operating information:



	Nine Months Ended
	September 30,		% Change
	2014	2013	% Change
Oil and Natural Gas:
Oil production (MBbls)	2,801	2,470	13	%
NGLs production (MBbls)	3,376	2,758	22	%
Natural gas production (MMcf)	43,424	42,411	2	%
Average oil price per barrel received	$92.44	$95.20	(3	)%
Average oil price per barrel received excluding derivatives	$96.34	$95.49	1	%
Average NGLs price per barrel received	$33.05	$30.87	7	%
Average NGLs price per barrel received excluding derivatives	$33.05	$30.87	7	%
Average natural gas price per mcf received	$3.99	$3.35	19	%
Average natural gas price per mcf received excluding derivatives	$4.17	$3.38	23	%
Contract Drilling:
Average number of our drilling rigs in use during the period	73.5	65.0	13	%
Total number of drilling rigs owned at the end of the period	119	124	(4	)%
Average dayrate	$19,876	$19,651	1	%
Mid-Stream:
Gas gathered—Mcf/day	316,658	308,645	3	%
Gas processed—Mcf/day	160,373	137,725	16	%
Gas liquids sold—gallons/day	748,805	505,584	48	%
Number of natural gas gathering systems	38	39	(3	)%
Number of processing plants	14	15	(7	)%

Working Capital

Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative activity. We had negative working capital of $131.2 million and negative working capital of $48.1 million as of September 30, 2014 and 2013, respectively. This is primarily from the timing of our accounts payable associated with our capital expenditures. The effect of our derivative contracts increased working capital by $4.0 million as of September 30, 2014 and decreased working capital by $1.4 million as of September 30, 2013.

Oil and Natural Gas Operations

Any significant change in oil, NGLs, or natural gas prices has a material affect on our revenues, cash flow, and the value of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, and by worldwide oil price levels. Domestic oil prices are primarily influenced by global oil market developments. All of these factors are beyond our control and we cannot predict nor measure their future impact on the prices we will receive.

Based on our first nine months of 2014 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would result in a corresponding $461,000 per month ($5.5 million annualized) change in our pre-tax operating cash flow. The average price we received for our natural gas production, including the effect of derivatives, during the first nine months of 2014 was $3.99 compared to $3.35 for the first nine months of 2013. Based on our first nine months of 2014 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $300,000 per month ($3.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a $359,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow. In the first nine months of 2014, our average oil price per barrel received, including the effect of derivatives, was $92.44 compared with an average oil price, including the effect of derivatives, of $95.20 in the first nine months of 2013 and our first nine months of 2014 average NGLs price per barrel received was $33.05 compared with an average NGLs price per barrel of $30.87 in the first nine months of 2013.

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Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can result in a decline in the carrying value of our oil and natural gas properties. At September 30, 2014, the 12-month average unescalated prices were $99.08 per barrel of oil, $48.04 per barrel of NGLs, and $4.25 per Mcf of natural gas, then adjusted for price differentials. We were not required to take a write-down in the third quarter of 2014. If there are declines in the 12-month average prices, we may be required to record write-downs in future periods.

Price declines can also adversely affect the semi-annual determination of the amount we can borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs, and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects.

Our natural gas production is sold to intrastate and interstate pipelines as well as to independent marketing firms and gatherers under contracts with terms generally ranging anywhere from one month to five years. Our oil production is sold to independent marketing firms generally in six month increments.

Contract Drilling Operations

Many factors influence the number of drilling rigs we are working at any given time as well as the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs, and our ability to supply the equipment needed.

Competition to keep qualified labor continues to be an issue we face in this segment. We do not believe that this competition for qualified labor will keep us from working additional rigs, but it could cause some delays in the time needed to crew drilling rigs starting to work. Beginning in third quarter 2014, we increased compensation for drilling personnel in Oklahoma, the Texas Panhandle, and the Gulf Coast.

Today, almost all of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. The size of the drilling rig used in these plays will vary depending on a number of factors such as the depth to be drilled and the projected length of the horizontal part of the well. For example, operators drilling in shallower oil plays like the Mississippian play in northern Oklahoma and southern Kansas tend to use drilling rigs with lower horsepower which in turn command lower dayrates and margins. But deeper wells (drilled using improving technology) with longer horizontal laterals require drilling rigs with higher horsepower. All of these factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the availability of drilling rigs to meet that demand will have an impact on our future dayrates. For the first nine months of 2014, our average dayrate was $19,876 per day compared to $19,651 per day for the first nine months of 2013. The average number of our drilling rigs used in the first nine months of 2014 was 73.5 drilling rigs (62%) compared with 65.0 drilling rigs (51%) in the first nine months of 2013. Based on the average utilization of our drilling rigs during the first nine months of 2014, a $100 per day change in dayrates has a $7,350 per day ($2.7 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment also provides drilling services for our oil and natural gas segment. Some of those services, depending on when they are performed, are deemed to be associated with the acquisition of an ownership interest in the drilled property. Accordingly, revenues and expenses for those drilling services are eliminated in our income statement, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $66.4 million and $43.9 million for the nine months of 2014 and 2013, respectively, from our contract drilling segment and eliminated the associated operating expense of $46.4 million and $32.2 million during the nine months of 2014 and 2013, respectively, yielding $20.0 million and $11.7 million during the nine months of 2014 and 2013, respectively, as a reduction to the carrying value of our oil and natural gas properties.

Mid-Stream Operations

Our mid-stream segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates two natural gas treatment plants, 14 processing plants, 38 gathering systems, and approximately 1,500 miles of pipeline. It operates in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. In addition to serving third parties, this segment also enhances our ability to gather and market our own natural gas and NGLs as well as serving as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2014 and 2013, our mid-stream operations purchased $65.7 million and $62.6 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $6.8 million and $5.7 million, respectively.

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Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our unaudited condensed consolidated financial statements.

This segment gathered an average of 316,658 Mcf per day in the first nine months of 2014 compared to 308,645 Mcf per day in the first nine months of 2013. It processed an average of 160,373 Mcf per day in the first nine months of 2014 compared to 137,725 Mcf per day in the first nine months of 2013. The amount of NGLs sold was 748,805 gallons per day in the first nine months of 2014 compared to 505,584 gallons per day in the first nine months of 2013. Gas gathering volumes per day in the first nine months of 2014 increased 3% compared to the first nine months of 2013 primarily from an increase in the number of wells connected to our systems between the comparative periods. Processed volumes increased 16% over the comparative nine months and NGLs sold increased 48% over the comparative period due primarily to new wells connected.

Our Credit Agreement and Senior Subordinated Notes

The current lenders under our credit agreement and their respective participation interests are as follows:



Lender	Participation Interest
BOK (BOKF, NA, dba Bank of Oklahoma)	17	%
BBVA Compass Banks	17	%
Bank of Montreal	15	%
Bank of America, N.A.	15	%
Comerica Bank	8	%
Crédit Agricole Corporate and Investment Bank, London Branch	8	%
Wells Fargo Bank, National Association	8	%
Canadian Imperial Bank of Commerce	8	%
The Bank of Nova Scotia	4	%
	100	%

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The credit agreement prohibits, among other things:


•	the payment of dividends (other than stock dividends) during any fiscal year in excess of 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, 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; and


•	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, 2014, we were in compliance with the covenants contained in the credit agreement.

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

Capital Requirements

Oil and Natural Gas Segment Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this segment are discretionary and directed toward future growth. Our decisions to increase our oil, NGLs, and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential, and opportunities to obtain financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when and if to incur these costs. We completed drilling 130 gross wells (85.45 net wells) in the first nine months of 2014 compared to 102 gross wells (56.79 net wells) in the first nine months of 2013. Total capital expenditures for oil and gas properties on the full cost method for the first nine months of 2014 by this segment, excluding a $40.5 million reduction in the ARO liability, totaled $572.9 million. Total capital expenditures for the first nine months of 2013, excluding a $16.4 million reduction in the ARO liability, totaled $397.6 million.

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Currently we plan to participate in drilling approximately 180 gross wells in 2014 and our total estimated capital expenditures (excluding any possible acquisitions) for this segment are approximately $727.5 million. Whether we are able to drill the full number of wells planned is dependent on a number of factors, many of which are beyond our control, including the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs, and natural gas, demand for oil, NGLs, and natural gas, the cost to drill wells, the weather, and the efforts of outside industry partners.

Contract Drilling Segment Dispositions, Acquisitions, and Capital Expenditures. During the first quarter of 2014, four idle 3,000 horsepower drilling rigs were sold to an unaffiliated third party. The proceeds from that sale are being used in our construction program for our new proprietary 1,500 horsepower, AC electric drilling rig, called the BOSS drilling rig. This new drilling rig design is positioning us to more effectively meet the demands of our existing customers as well as allowing us to compete for the work of new customers.

In the second and third quarters of 2013, we sold three 2,000 horsepower electric drilling rigs to unaffiliated third-parties.

Our estimated 2014 capital expenditures for this segment are $161.1 million. At September 30, 2014, we had commitments to purchase approximately $24.3 million for drilling equipment over the next twelve months. We have spent $121.3 million for capital expenditures, including $66.0 million for the BOSS drilling rigs during the first nine months of 2014, compared to $37.4 million in total capital expenditures in the first nine months of 2013.

Mid-Stream Acquisitions and Capital Expenditures. At our Hemphill County, Texas facility, total processing capacity remains at 135 MMcf per day and we are connecting new wells to our system as they are drilled and completed. We are completing the construction of a nine mile trunkline and related compression facilities which will connect our Buffalo Wallow gathering system to our Hemphill processing facility. On completion of this trunkline project, we will have the ability to process Buffalo Wallow gathered production at our Hemphill processing facility. This trunkline project is scheduled for completion in November 2014, with gas flow to begin on January 1, 2015.

At our Cashion facility located in central Oklahoma, our total processing capacity is currently 45 MMcf per day and drilling activity remains high in the area around our system. As of September 2014, we have connected 24 new wells this year to this system and we are in the process of expanding the Waswo compressor station to accommodate additional volumes from the north end of our system. At the Waswo compressor station, construction is underway to install the fourth compressor and we expect to complete this project by the end of 2014.

During the first nine months of 2014, our mid-stream segment incurred $29.2 million in capital expenditures, excluding $28.2 million for capital leases added during the third quarter of 2014, as compared to $76.6 million in the first nine months of 2013. For 2014, our estimated capital expenditures (excluding capital leases) are $60.2 million. We have recently signed a fee-based contract under which we will build our new Showshoe project in the Marcellus. This project will consist of the

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construction of a seven-mile, 16 inch and 24 inch trunkline to gather production in Centre County, Pennsylvania for delivery to an interstate pipeline. Construction has started with an expected completion date in the third quarter of 2015.

Contractual Commitments

At September 30, 2014, we had certain contractual obligations including the following:



	Payments Due by Period
	Total		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)
Long-term debt ⁽¹⁾	$	968,373	$	44,294	$	118,110	$	86,125	$	719,844
Operating leases ⁽²⁾	10,651		7,168		3,408		75		—
Capital lease interest and maintenance⁽³⁾	15,783		2,818		5,219		4,623		3,123
Drill pipe, drilling components, and equipment purchases ⁽⁴⁾	24,311		24,311		—		—		—
Enterprise Resource Planning software obligations ⁽⁵⁾	2,386		1,900		486		—		—
Gas accounting system ⁽⁶⁾	221		221		—		—		—
Total contractual obligations	$	1,021,725	$	80,712	$	127,223	$	90,823	$	722,967

_______________________


(1)	See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit agreement and includes interest calculated using our September 30, 2014 interest rates of 6.625% for the Notes and 4.0% for the credit agreement.


(2)	We lease office space or yards in Edmond, Oklahoma City, and Tulsa, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Pittsburgh, Pennsylvania under the terms of operating leases expiring through July, 2019. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.


(3)	Maintenance and interest payments are included in our capital lease agreements. The capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining are $11.8 million and $3.9 million, respectively.


(4)	We have committed to pay $24.3 million for drilling equipment over the next twelve months.


(5)	We have committed to pay $1.9 million for Enterprise Resource Planning software and $0.5 million for maintenance for one year following implementation.


(6)	We have committed to pay $0.2 million for a gas accounting system over the next twelve months.

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At September 30, 2014, we also had the following commitments and contingencies that could create, increase, or accelerate our liabilities:



	Estimated Amount of Commitment Expiration Per Period
Other Commitments	Total Accrued		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
	(In thousands)
Deferred compensation plan ⁽¹⁾	$	3,965	Unknown		Unknown		Unknown		Unknown
Separation benefit plans ⁽²⁾	$	10,799	$	319	Unknown		Unknown		Unknown
Asset retirement liability ⁽³⁾	$	96,679	$	2,718	$	34,752	$	5,490	$	53,719
Gas balancing liability ⁽⁴⁾	$	3,775	Unknown		Unknown		Unknown		Unknown
Repurchase obligations ⁽⁵⁾	$	—	Unknown		Unknown		Unknown		Unknown
Workers’ compensation liability ⁽⁶⁾	$	19,224	$	7,808	$	2,243	$	1,146	$	8,027
Capital leases obligations ⁽⁷⁾	$	26,708	$	3,376	$	7,171	$	7,767	$	8,394
Other	$	285	Unknown		$	285	Unknown		Unknown

_______________________

(1)

We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death, or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Unaudited Condensed Consolidated Balance Sheets, at the time of deferral.

(2)

Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Currently there are no participants in the Senior Plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, all these plans were amended to bring the plans into compliance with Section 409A of the Internal Revenue Code of 1986, as amended.


(3)	When a well is drilled or acquired, under “Accounting for Asset Retirement Obligations,” we record the discounted fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).


(4)	We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners to recover their under-production from future production volumes.

(5)

We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011. One of our subsidiaries serves as the general partner of each of these programs. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $37,000 and $16,000 in 2014 and 2013, respectively through the first nine months.


(6)	We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling segment.


(7)	The amount includes commitments under capital lease arrangements for compressors in our mid-stream segment.

Derivative Activities

Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and natural gas production. In August 2012, we determined on a prospective basis, to enter into economic hedges without electing cash flow hedge accounting. All of our previous cash flow hedges expired as of December 31, 2013. Any change in fair value on all commodity derivatives we have entered into are now reflected in the income statement and not in accumulated other comprehensive income.

Commodity Derivatives. Our commodity derivatives are intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our

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view of current and future market conditions. At September 30, 2014, based on our third quarter 2014 average daily production, the approximated percentages of our production under derivative contracts are as follows:



	Mark-to-Market
	2014		2015
Daily oil production	62	%	9	%
Daily natural gas production	57	%	—	%

With respect to the commodities subject to derivative contracts, those contracts serve to limit the risk of adverse downward price movements. However, they also limit increases in future revenues that would otherwise result from price movements above the contracted prices.

The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial obligations under the transactions. Based on our September 30, 2014 evaluation, we believe the risk of non-performance by our counterparties is not material. At September 30, 2014, the fair values of the net assets (liabilities) we had with each of the counterparties to our commodity derivative transactions are as follows:



	September 30, 2014
	(In millions)
Bank of Montreal	$	3.6
The Bank of Nova Scotia	0.8
Canadian Imperial Bank of Commerce	0.3
Total assets	$	4.7

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. At September 30, 2014, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $4.0 million and $0.7 million. At September 30, 2013, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $4.5 million and $1.1 million, respectively, and current and non-current derivative liabilities of $6.5 million and $0.9 million, respectively.

For our economic hedges that we did not apply cash flow accounting to, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net in our Unaudited Condensed Consolidated Statements of Income. The commodity derivative instruments we had under cash flow accounting expired as of December 2013. Previous changes in the fair value of derivatives designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item is recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value resulting from ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net. These gains (losses) at September 30 are as follows:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014			2013
	(In thousands)
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net:
Gain (loss) on derivatives not designated as hedges, included are amounts settled during the period of ($1,029), ($2,434), ($18,984), and ($1,575) respectively	$	19,841	$	(13,508	)	$	(9,234	)	$	(3,456	)
Gain (loss) on ineffectiveness of cash flow hedges	—		(252		)	—			116
	$	19,841	$	(13,760	)	$	(9,234	)	$	(3,340	)

Stock and Incentive Compensation

During the first nine months of 2014, we granted awards covering 452,110 shares of restricted stock. These awards had an estimated fair value as of their grant date of $23.3 million. Compensation expense will be recognized over the three year vesting periods, and during the nine months of 2014, we recognized $6.3 million in compensation expense and capitalized $1.3

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million for these awards. During the first nine months of 2014, we recognized compensation expense of $12.7 million for all of our restricted stock, stock options, and SAR grants and capitalized $2.7 million of compensation cost for oil and natural gas properties.

Insurance

We are self-insured for certain losses relating to workers’ compensation, general liability, control of well, and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from $50,000 to $1.5 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. There is no assurance that the insurance coverage we have will protect us against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover all Texas drilling operations in lieu of covering them under Texas workers’ compensation. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these rather than pay higher premiums.

Oil and Natural Gas Limited Partnerships and Other Entity Relationships

We are the general partner of 16 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision, and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and are considered by us to be reasonable. For the first nine months of 2014 and 2013, the total we received for all of these fees was $0.4 million and $0.4 million, respectively. Our proportionate share of assets, liabilities, and net income (loss) relating to the oil and natural gas partnerships is included in our unaudited condensed consolidated financial statements.

New Accounting Pronouncements

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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. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are in the process of evaluating the impact it will have on our financial statements.

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Results of Operations

Quarter Ended September 30, 2014 versus Quarter Ended September 30, 2013

Provided below is a comparison of selected operating and financial data:



	Quarter Ended September 30,						Percent Change ⁽¹⁾
	2014			2013			Percent Change ⁽¹⁾
	(In thousands unless otherwise specified)
Total revenue	$	400,974		$	333,776		20	%
Net income	$	67,522		$	34,232		97	%

Oil and Natural Gas:
Revenue	$	188,471		$	157,320		20	%
Operating costs excluding depreciation, depletion, and amortization	$	48,841		$	50,139		(3	)%
Depreciation, depletion, and amortization	$	70,033		$	56,294		24	%

Average oil price received (Bbl)	$	91.57		$	95.49		(4	)%
Average NGLs price received (Bbl)	$	30.11		$	28.10		7	%
Average natural gas price received (Mcf)	$	3.68		$	3.11		18	%
Oil production (Bbl)	1,040,000			814,000			28	%
NGLs production (Bbl)	1,147,000			1,019,000			13	%
Natural gas production (Mcf)	14,543,000			14,304,000			2	%
Depreciation, depletion, and amortization rate (Boe)	$	14.88		$	13.14		13	%

Contract Drilling:
Revenue	$	120,652		$	100,647		20	%
Operating costs excluding depreciation	$	66,727		$	58,988		13	%
Depreciation	$	22,560		$	17,402		30	%

Percentage of revenue from daywork contracts	100		%	100		%	—	%
Average number of drilling rigs in use	79.1			63.5			25	%
Average dayrate on daywork contracts	$	20,070		$	19,773		2	%

Mid-Stream:
Revenue	$	91,851		$	75,809		21	%
Operating costs excluding depreciation and amortization	$	78,558		$	63,098		25	%
Depreciation and amortization	$	10,272		$	8,773		17	%

Gas gathered—Mcf/day	319,692			326,474			(2	)%
Gas processed—Mcf/day	169,357			145,020			17	%
Gas liquids sold—gallons/day	771,334			586,446			32	%

Corporate and other:
General and administrative expense	$	10,172		$	9,936		2	%
Gain (loss) on disposition of assets	$	(529	)	$	4,345		(112	)%
Other income (expense):
Interest expense, net	$	(4,280	)	$	(3,625	)	18	%
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net	$	19,841		$	(13,760	)	NM
Other	$	(68	)	$	(14	)	NM
Income tax expense	$	41,253		$	21,860		89	%
Average long-term debt outstanding	$	662,063		$	672,938		(2	)%
Average interest rate	6.6		%	6.5		%	2	%

_______________________


(1)	NM - A percentage calculation is not meaningful due to a percentage greater than 200.

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Oil and Natural Gas

Oil and natural gas revenues increased $31.2 million or 20% in the third quarter of 2014 as compared to the third quarter of 2013 due to a 9% increase in equivalent production and higher natural gas and NGLs prices. In the third quarter of 2014, as compared to the third quarter of 2013, oil production increased 28%, NGLs production increased 13%, and natural gas production increased 2%. Average natural gas prices increased 18% to $3.68 per Mcf and NGLs prices increased 7% to $30.11 per barrel, while average oil prices decreased 4% to $91.57 per barrel.

Oil and natural gas operating costs decreased $1.3 million or 3% between the comparative third quarters of 2014 and 2013 due to lower saltwater disposal expenses and lease operating expenses offset partially by increased general and administrative expense.

Depreciation, depletion, and amortization (“DD&A”) increased $13.7 million due primarily to a 13% increase in our DD&A rate and a 9% increase in equivalent production. The increase in our DD&A rate in the third quarter of 2014 compared to the third quarter of 2013 resulted primarily from increased capitalized cost on new wells drilled between periods. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

Contract Drilling

Drilling revenues increased $20.0 million or 20% in the third quarter of 2014 versus the third quarter of 2013. The increase was due primarily to a 25% increase in the average number of drilling rigs in use and to a lesser extent from a 2% increase in the average dayrate in the third quarter of 2014 compared to the third quarter of 2013. Average drilling rig utilization increased from 63.5 drilling rigs in the third quarter of 2013 to 79.1 drilling rigs in the third quarter of 2014.

Drilling operating costs increased $7.7 million or 13% between the comparative third quarters of 2014 and 2013. The increase was due primarily to the increase in utilization. Contract drilling depreciation increased $5.2 million or 30% also due primarily to the increase in utilization.

Mid-Stream

Our mid-stream revenues increased $16.0 million or 21% in the third quarter of 2014 as compared to the third quarter of 2013. The average price for natural gas sold increased 10% while the average price for NGLs sold decreased 14%. Gas processing volumes per day increased 17% between the comparative quarters and NGLs sold per day increased 32% between the comparative quarters primarily from new well connections. Gas gathering volumes per day decreased 2% between the comparative quarters.

Operating costs increased $15.5 million or 25% in the third quarter of 2014 compared to the third quarter of 2013 primarily due to a 5% increase in prices paid for natural gas purchased and a 14% increase in the per day gas volumes purchased. Depreciation and amortization increased $1.5 million, or 17%, primarily due to additional assets placed into service.

General and Administrative

General and administrative expenses increased $0.2 million or 2% in the third quarter of 2014 compared to the third quarter of 2013 primarily due to increases in the number of employees and increased employee costs.

Gain (Loss) on Disposition of Assets

There was a $4.3 million gain on disposition of assets in the third quarter of 2013 primarily due to the sale of two drilling rigs in the third quarter of 2013, compared to a loss of $0.5 million for the sale of old drilling equipment in the third quarter of 2014.

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Other Income (Expense)

Interest expense, net of capitalized interest, increased $0.7 million between the comparative third quarters of 2014 and 2013. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for the third quarter of 2014 was $8.2 million compared to $8.5 million in the third quarter of 2013, and was netted against our gross interest of $12.5 million and $12.1 million for the third quarters of 2014 and 2013, respectively. Our average interest rate increased from 6.5% to 6.6% and our average debt outstanding was $10.9 million lower in the third quarter of 2014 as compared to the third quarter of 2013 primarily due to the reduction of outstanding borrowings under our credit agreement over the comparative periods.

Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net increased $33.6 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Expense

Income tax expense increased $19.4 million or 89% in the third quarter of 2014 compared to the third quarter of 2013 primarily due to increased pre-tax income. Our effective tax rate was 37.9% for the third quarter of 2014 compared to 39.0% for the third quarter of 2013. This decrease is primarily due to the recognition of a research and development income tax credit that was identified and quantified in the third quarter of 2014. Current income tax expense was $5.5 million for the third quarter of 2014 compared to $2.1 million for the third quarter of 2013 with the increase primarily due to increased alternative minimum taxes. We paid $0.2 million of income taxes in the third quarter of 2014.

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Nine Months Ended September 30, 2014 versus Nine Months Ended September 30, 2013

Provided below is a comparison of selected operating and financial data:



	Nine Months Ended September 30,						Percent Change ⁽¹⁾
	2014			2013			Percent Change ⁽¹⁾
	(In thousands unless otherwise specified)
Total revenue	$	1,194,393		$	992,729		20	%
Net income	$	178,827		$	133,445		34	%

Oil and Natural Gas:
Revenue	$	575,176		$	475,728		21	%
Operating costs excluding depreciation, depletion, and amortization	$	133,979		$	138,171		(3	)%
Depreciation, depletion, and amortization	$	200,958		$	163,612		23	%

Average oil price received (Bbl)	$	92.44		$	95.20		(3	)%
Average NGLs price received (Bbl)	$	33.05		$	30.87		7	%
Average natural gas price received (Mcf)	$	3.99		$	3.35		19	%
Oil production (Bbl)	2,801,000			2,470,000			13	%
NGLs production (Bbl)	3,376,000			2,758,000			22	%
Natural gas production (Mcf)	43,424,000			42,411,000			2	%
Depreciation, depletion, and amortization rate (Boe)	$	14.70		$	13.08		12	%

Contract Drilling:
Revenue	$	341,530		$	313,180		9	%
Operating costs excluding depreciation	$	197,025		$	188,580		4	%
Depreciation	$	61,194		$	52,570		16	%

Percentage of revenue from daywork contracts	100		%	100		%	—	%
Average number of drilling rigs in use	73.5			65.0			13	%
Average dayrate on daywork contracts	$	19,876		$	19,651		1	%

Mid-Stream:
Revenue	$	277,687		$	203,821		36	%
Operating costs excluding depreciation and amortization	$	238,166		$	172,065		38	%
Depreciation and amortization	$	29,972		$	24,143		24	%

Gas gathered—Mcf/day	316,658			308,645			3	%
Gas processed—Mcf/day	160,373			137,725			16	%
Gas liquids sold—gallons/day	748,805			505,584			48	%

Corporate and other:
General and administrative expense	$	30,409		$	28,288		8	%
Gain on disposition of assets	$	9,092		$	7,744		17	%
Other income (expense):
Interest expense, net	$	(12,201	)	$	(11,777	)	4	%
Loss on derivatives not designated as hedges and hedge ineffectiveness, net	$	(9,234	)	$	(3,340	)	176	%
Other	$	3		$	(171	)	102	%
Income tax expense	$	111,523		$	84,311		32	%
Average long-term debt outstanding	$	653,521		$	703,771		(7	)%
Average interest rate	6.7		%	6.3		%	6	%

_______________________


(1)	NM - A percentage calculation is not meaningful due to a percentage greater than 200.

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Oil and Natural Gas

Oil and natural gas revenues increased $99.4 million or 21% in the first nine months of 2014 as compared to the first nine months of 2013 due to a 9% increase in equivalent production and higher natural gas and NGLs prices. In the first nine months of 2014, as compared to the first nine months of 2013, oil production increased 13%, NGLs production increased 22%, and natural gas production increased 2%. Average natural gas prices increased 19% to $3.99 per Mcf, NGLs prices increased 7% to $33.05 per barrel, and oil prices decreased 3% to $92.44 per barrel.

Oil and natural gas operating costs decreased $4.2 million or 3% between the comparative first nine months of 2014 and 2013 due primarily to a decrease in gross production taxes from refunds of $13.1 million attributable to high cost gas wells partially offset by higher lease operating expenses from the addition of new wells.

DD&A increased $37.3 million between the comparative periods due primarily to a 12% increase in our DD&A rate and a 9% increase in equivalent production. The increase in our DD&A rate in the first nine months of 2014 compared to the first nine months of 2013 resulted primarily from increased capitalized cost on new wells drilled between periods. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

Contract Drilling

Drilling revenues increased $28.4 million or 9% in the first nine months of 2014 versus the first nine months of 2013. The increase was due primarily to a 13% increase in the average number of drilling rigs in use and a 1% increase in the average dayrate in the first nine months of 2014 compared to the first nine months of 2013. Average drilling rig utilization increased from 65.0 drilling rigs in the first nine months of 2013 to 73.5 drilling rigs in the first nine months of 2014.

Drilling operating costs increased $8.4 million or 4% between the comparative first nine months of 2014 and 2013. The increase was due primarily to the increase in utilization. Contract drilling depreciation increased $8.6 million or 16% also due primarily to the increase in utilization.

Mid-Stream

Our mid-stream revenues increased $73.9 million or 36% for the first nine months of 2014 as compared to the first nine months of 2013. Gas processing volumes per day increased 16% between the comparative periods and NGLs sold per day increased 48% between the comparative periods primarily from new well connections. Gas gathering volumes per day increased 3% primarily from new well connections.

Operating costs increased $66.1 million or 38% in the first nine months of 2014 compared to the first nine months of 2013 primarily due to a 18% increase in prices paid for natural gas purchased and a 13% increase in volumes purchased per day partially and by increased field operating costs due to the expansion of various systems. Depreciation and amortization increased $5.8 million, or 24%, primarily due to additional assets placed into service.

General and Administrative

General and administrative expenses increased $2.1 million or 8% in the first nine months of 2014 compared to the first nine months of 2013 primarily due to increases in the number of employees and increased employee costs.

Gain on Disposition of Assets

Gain on disposition of assets increased $1.3 million in the first nine months of 2014 compared to the first nine months of 2013 primarily due to the sale of four drilling rigs during the first nine months of 2014 compared to the sale of three drilling rigs during the first nine months of 2013.

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Other Income (Expense)

Interest expense, net of capitalized interest, increased $0.4 million between the comparative first nine months of 2014 and 2013. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for the first nine months of 2014 was $24.5 million compared to $24.9 million in the first nine months of 2013, and was netted against our gross interest of $36.7 million for both of the first nine months of 2014 and 2013, respectively. Our average interest rate increased from 6.3% to 6.7% and our average debt outstanding was $50.3 million lower in the first nine months of 2014 as compared to the first nine months of 2013 primarily due to the reduction of outstanding borrowings under our credit agreement over the comparative periods.

Loss on derivatives not designated as hedges and hedge ineffectiveness, net increased $5.9 million primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Expense

Income tax expense increased $27.2 million or 32% in the first nine months of 2014 compared to the first nine months of 2013 primarily due to increased pre-tax income. Our effective tax rate was 38.4% for the first nine months of 2014 and 38.7% for the first nine months of 2013. This decrease is primarily due to the recognition of a research and development income tax credit that was identified and quantified in the third quarter of 2014. Current income tax expense was $23.7 million for the first nine months of 2014 compared to $6.7 million for the first nine months of 2013 with the increase primarily due to increased alternative minimum taxes. We paid $16.0 million of income taxes in the first nine months of 2014.

Safe Harbor Statement

This report, including information included in, or incorporated by reference from, future filings by us with the SEC, as well as information contained in written material, press releases, and oral statements issued by or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaning of federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address activities, events, or developments which 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.

These forward-looking statements include, among others, such things as:


•	the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;


•	the amount of wells we plan to drill or rework;


•	prices for oil, 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 initiatives relating to hydrocarbon fracturing impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;


•	our projected production guidelines for the year;


•	our anticipated capital budgets;


•	the number of wells our oil and natural gas segment plans to drill during the year; and

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•	our outlook for the demand of our new drilling rig, the BOSS drilling rig.

These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:


•	the risk factors discussed in this report and in the documents we incorporate by reference;


•	general economic, market, or business conditions;


•	the availability of and nature or lack of business opportunities that we pursue;


•	demand for our land drilling services;


•	changes in laws or regulations;


•	decreases or increases in commodity prices; 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 make to forward-looking statements to reflect events or circumstances after the date of this report to reflect the occurrence of unanticipated events.

A more thorough discussion of forward-looking statements with the possible impact of some of these risks and uncertainties is provided in our Annual Report on Form 10-K filed with the SEC. We encourage you to get and read that document.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

Our operations are exposed to market risks primarily because of changes in commodity prices and interest rates.

Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas production. These prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our NGLs and natural gas production. Historically, these prices have fluctuated and we expect this to continue. The prices for oil, NGLs, and natural gas also affects the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our first nine months 2014 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of hedging, would result in a corresponding $461,000 per month ($5.5 million annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $300,000 per month ($3.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of hedging, would have a $359,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow.

We use derivative transactions to manage the risk associated with price volatility. Our decisions regarding the amount and prices at which we choose to enter into a contract for certain of our products is based, in part, on our view of current and future market conditions. The transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a variable market price to the contract counterparty. We do not hold or issue derivative instruments for speculative trading purposes.

At September 30, 2014, the following non-designated hedges were outstanding:



Term	Commodity	Hedged Volume	Weighted Average Fixed Price for Swaps	Hedged Market
Oct’14 – Dec’14	Crude oil – swap	3,000 Bbl/day	$91.77	WTI – NYMEX
Oct’14 – Dec’14	Crude oil – collar	4,000 Bbl/day	$90.00-96.08	WTI – NYMEX
Jan’15 – Dec’15	Crude oil – swap	1,000 Bbl/day	$95.00	WTI – NYMEX
Oct’14 – Dec’14	Natural gas – swap	80,000 MMBtu/day	$4.24	NYMEX (HH)
Oct’14 – Dec’14	Natural gas – collar	10,000 MMBtu/day	$3.75-4.37	NYMEX (HH)

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreement and the Notes. The credit agreement, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election,

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borrowings under our credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average outstanding long-term debt subject to a variable rate in the first nine months of 2014, a 1% increase in the floating rate would not have a material impact on our annual pre-tax cash flow. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year).

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures under Exchange Act Rule 13a-15. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of September 30, 2014 in ensuring the appropriate information is recorded, processed, summarized and reported in our periodic SEC filings relating to the company (including its consolidated subsidiaries) and is accumulated and communicated to the Chief Executive Officer, Chief Financial Officer, and management to allow timely decisions.

Changes in Internal Controls. There were no changes in our internal controls over financial reporting during the quarter ended September 30, 2014 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting, as defined in Rule 13a – 15(f) under the Exchange Act.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.

Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson and Charlotte Abernathy are the Plaintiffs in this case and are royalty owners in oil and gas drilling and spacing units for which the company’s exploration segment distributes royalty. The Plaintiffs’ central allegation is that the company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees. Plaintiffs sought to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma production. We have asserted several defenses including that the deductions are permitted under Oklahoma law. We have also asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. On May 11, 2012 the court of civil appeals reversed the trial court’s order certifying the class. The Plaintiffs petitioned the supreme court for certiorari and on October 8, 2012, the Plaintiff’s petition was denied. On January 22, 2013, the Plaintiffs filed a second request to certify a class of royalty owners that was slightly smaller than their first attempt. Since then, the Plaintiffs have further amended their proposed class to just include royalty owners entitled to royalties under certain leases located in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, in addition to the defenses described above, we argued that the amended class definition is still deficient under the court of civil appeals opinion reversing the initial class certification. The court has ordered closing arguments to be held on December 2, 2014. We will continue to resist certification using the defenses described above. The merits of Plaintiffs’ claims will remain stayed while class certification issues are pending.

Item 1A. Risk Factors

In addition to the other information set forth in this quarterly report, you should carefully consider the factors discussed below, if any, and in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended

December 31, 2013, which could materially affect our business, financial condition, or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, and/or operating results.

There have been no material changes to the risk factors disclosed in Item 1A in our Form 10-K for the year ended December 31, 2013.

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

The following table provides information relating to our repurchase of common stock for the three months ended September 30, 2014:



Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid Per Share(2)		(c) Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2014 to July 31, 2014	213	$	67.70	213	—
August 1, 2014 to August 31, 2014	1,719	62.56		1,719	—
September 1, 2014 to September 30, 2014	—	—		—	—
Total	1,932	$	63.12	1,932	—

_______________________


(1)	The shares were repurchased to remit withholding of taxes on the value of stock distributed with the third quarter 2014 vesting of restricted stock for grants previously made from our “Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012.”


(2)	The price paid per common share represents the closing sales price of a share of our common stock as reported by the NYSE on the day that the stock was acquired by us.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibits:



15	Letter re: Unaudited Interim Financial Information.

31.1	Certification of Chief Executive Officer under Rule 13a – 14(a) of the Exchange Act.

31.2	Certification of Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act.

32	Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS	XBRL Instance Document.

101.SCH	XBRL Taxonomy Extension Schema Document.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB	XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

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



		Unit Corporation

Date:	November 4, 2014	By: /s/ Larry D. Pinkston
		LARRY D. PINKSTON
		Chief Executive Officer and Director

Date:	November 4, 2014	By: /s/ David T. Merrill
		DAVID T. MERRILL
		Senior Vice President, Chief Financial Officer, and Treasurer

Attached files

UNIT CORP Reports

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