10-Q 1 unt-2014630x10q.htm 10-Q UNT-2014.6.30-10Q
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 June 30, 2014
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
[Commission File Number 1-9260]
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 July 25, 2014, 49,583,543 shares of the issuer's common stock were outstanding.



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

1


Forward-Looking Statements

This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document that addresses activities, events or developments 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, 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.


2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
June 30,
2014
 
December 31,
2013
 
(In thousands except share amounts)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,078

 
$
18,593

Accounts receivable, net of allowance for doubtful accounts of $2,120 and $5,342 at June 30, 2014 and at December 31, 2013, respectively
177,149

 
139,788

Materials and supplies
8,540

 
10,998

Current derivative asset (Note 9)

 
515

Current deferred tax asset
13,585

 
13,585

Assets held for sale

 
15,621

Prepaid expenses and other
10,914

 
12,931

Total current assets
211,266

 
212,031

Property and equipment:
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
Proved properties
4,544,173

 
4,235,712

Unproved properties not being amortized
555,434

 
545,588

Drilling equipment
1,526,923

 
1,477,093

Gas gathering and processing equipment
592,191

 
549,422

Transportation equipment
40,301

 
39,666

Other
101,452

 
87,435

 
7,360,474

 
6,934,916

Less accumulated depreciation, depletion, amortization, and impairment
3,380,809

 
3,212,225

Net property and equipment
3,979,665

 
3,722,691

Debt issuance cost
11,050

 
11,844

Goodwill
62,808

 
62,808

Other assets
12,893

 
13,016

Total assets
$
4,277,682

 
$
4,022,390


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

3


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

 
June 30,
2014
 
December 31,
2013
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
207,613

 
$
154,062

Accrued liabilities (Note 4)
65,744

 
64,363

Income taxes payable
10,776

 
7,474

Current derivative liabilities (Note 9)
15,839

 
5,561

Current portion of other long-term liabilities (Note 5)
14,578

 
12,113

Total current liabilities
314,550

 
243,573

Long-term debt (Note 5)
645,925

 
645,696

Non-current derivative liabilities (Note 9)
326

 

Other long-term liabilities (Note 5)
168,796

 
158,331

Deferred income taxes
853,398

 
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, 49,584,080 and 49,107,004 shares issued, respectively
9,729

 
9,659

Capital in excess of par value
455,390

 
445,470

Retained earnings
1,829,568

 
1,718,263

Total shareholders’ equity
2,294,687

 
2,173,392

Total liabilities and shareholders’ equity
$
4,277,682

 
$
4,022,390


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


4


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
 
 
 
Oil and natural gas
$
198,498

 
$
164,799

 
$
386,705

 
$
318,408

Contract drilling
114,278

 
105,005

 
220,878

 
212,533

Gas gathering and processing
92,655

 
70,617

 
185,836

 
128,012

Total revenues
405,431

 
340,421

 
793,419

 
658,953

Expenses:
 
 
 
 
 
 
 
Oil and natural gas:
 
 
 
 
 
 
 
Operating costs
44,723

 
44,994

 
85,138

 
88,032

Depreciation, depletion, and amortization
71,245

 
55,335

 
130,925

 
107,318

Contract drilling:
 
 
 
 
 
 
 
Operating costs
66,494

 
63,590

 
130,298

 
129,592

Depreciation
20,239

 
17,908

 
38,634

 
35,168

Gas gathering and processing:
 
 
 
 
 
 
 
Operating costs
78,648

 
59,557

 
159,608

 
108,967

Depreciation and amortization
10,109

 
8,214

 
19,700

 
15,370

General and administrative
10,600

 
9,679

 
20,237

 
18,352

Gain on disposition of assets
(195
)
 
(3,483
)
 
(9,621
)
 
(3,399
)
Total operating expenses
301,863

 
255,794

 
574,919

 
499,400

Income from operations
103,568

 
84,627

 
218,500

 
159,553

Other income (expense):
 
 
 
 
 
 
 
Interest, net
(4,131
)
 
(4,591
)
 
(7,921
)
 
(8,152
)
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net
(10,709
)
 
16,344

 
(29,075
)
 
10,420

Other
(49
)
 
(91
)
 
71

 
(157
)
Total other income (expense)
(14,889
)
 
11,662

 
(36,925
)
 
2,111

Income before income taxes
88,679

 
96,289

 
181,575

 
161,664

Income tax expense:
 
 
 
 
 
 
 
Current
8,475

 
2,117

 
18,270

 
4,634

Deferred
25,844

 
35,165

 
52,000

 
57,817

Total income taxes
34,319

 
37,282

 
70,270

 
62,451

Net income
$
54,360

 
$
59,007

 
$
111,305

 
$
99,213

Net income per common share:
 
 
 
 
 
 
 
Basic
$
1.12

 
$
1.22

 
$
2.29

 
$
2.06

Diluted
$
1.11

 
$
1.22

 
$
2.27

 
$
2.05


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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Net income
$
54,360

 
$
59,007

 
$
111,305

 
$
99,213

Other comprehensive income (loss), net of taxes:
 
 
 
 
 
 
 
Change in value of derivative instruments used as cash flow hedges, net of tax of $0, $3,874, $0, and ($2,504)

 
6,091

 

 
(3,820
)
Reclassification - derivative settlements, net of tax of $0, $317, $0, and ($1,177)

 
506

 

 
(1,831
)
Ineffective portion of derivatives, net of tax of $0, ($667), $0, and ($141)

 
(1,050
)
 

 
(227
)
Comprehensive income
$
54,360

 
$
64,554

 
$
111,305

 
$
93,335


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


6


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Six Months Ended
 
June 30,
 
2014
 
2013
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
Net income
$
111,305

 
$
99,213

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion, and amortization
190,813

 
159,369

(Gain) loss on derivatives
29,075

 
(13,429
)
Cash (payments) receipts on derivatives settled
(17,955
)
 
3,868

Deferred tax expense
52,000

 
57,817

Gain on disposition of assets
(9,621
)
 
(3,399
)
Employee stock compensation plans
11,655

 
10,654

Other, net
3,076

 
3,005

Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
Accounts receivable
(45,150
)
 
(13,001
)
Accounts payable
(11,585
)
 
2,219

Material and supplies
2,458

 
(751
)
Accrued liabilities
7,440

 
11,313

Other, net
2,017

 
1,010

Net cash provided by operating activities
325,528

 
317,888

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(420,235
)
 
(339,300
)
Proceeds from disposition of assets
40,825

 
16,829

Other
303

 

Net cash used in investing activities
(379,107
)
 
(322,471
)
FINANCING ACTIVITIES:
 
 
 
Borrowings under credit agreement
129,300

 
183,900

Payments under credit agreement
(129,300
)
 
(185,000
)
Net payments on capitalized leases
(711
)
 

Proceeds from exercise of stock options
887

 
81

Book overdrafts
35,888

 
5,669

Net cash provided by financing activities
36,064

 
4,650

Net increase (decrease) in cash and cash equivalents
(17,515
)
 
67

Cash and cash equivalents, beginning of period
18,593

 
974

Cash and cash equivalents, end of period
$
1,078

 
$
1,041

Supplemental disclosure of cash flow information:
 
 
 
Cash paid during the year for:
 
 
 
Interest paid (net of capitalized)
6,223

 
6,273

Income taxes
15,800

 
7,100

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
(29,247
)
 
28,615

Non-cash additions to oil and natural gas properties related to asset retirement obligations
(15,432
)
 
(11,945
)
Non-cash additions to property, plant, and equipment acquired under capital leases
(26,510
)
 


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

7


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 June 30, 2014 and December 31, 2013;
• Statements of Income for the three and six months ended June 30, 2014 and 2013;
• Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013; and
• Statements of Cash Flows for the six months ended June 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 six months ended June 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 six month periods ended June 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 August 5, 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 $11.3 million during the first six months of 2014. Proceeds from those dispositions 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.

During the second quarter of 2013, we sold one 2,000 horsepower electric drilling rig to an unaffiliated third-party.

8


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 June 30, 2014
 
 
 
 
 
Basic earnings per common share
$
54,360

 
48,642

 
$
1.12

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

 
474

 
(0.01
)
Diluted earnings per common share
$
54,360

 
49,116

 
$
1.11

For the three months ended June 30, 2013
 
 
 
 
 
Basic earnings per common share
$
59,007

 
48,208

 
$
1.22

Effect of dilutive stock options, restricted stock, and SARs

 
298

 

Diluted earnings per common share
$
59,007

 
48,506

 
$
1.22


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
 
June 30,
 
2014
 
2013
Stock options and SARs
24,500

 
250,901

Average exercise price
$
73.26

 
$
52.72


 
Income
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
(In thousands except per share amounts)
For the six months ended June 30, 2014
 
 
 
 
 
Basic earnings per common share
$
111,305

 
48,568

 
$
2.29

Effect of dilutive stock options, restricted stock, and SARs

 
442

 
(0.02
)
Diluted earnings per common share
$
111,305

 
49,010

 
$
2.27

For the six months ended June 30, 2013
 
 
 
 
 
Basic earnings per common share
$
99,213

 
48,162

 
$
2.06

Effect of dilutive stock options, restricted stock, and SARs

 
329

 
(0.01
)
Diluted earnings per common share
$
99,213

 
48,491

 
$
2.05


 
Six Months Ended
 
June 30,
 
2014
 
2013
Stock options and SARs
49,000

 
149,665

Average exercise price
$
67.83

 
$
58.41



9


NOTE 4 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:
 
June 30,
2014
 
December 31,
2013
 
(In thousands)
Employee costs
$
21,440

 
$
27,633

Lease operating expenses
16,503

 
16,073

Taxes
9,166

 
2,313

Interest
6,519

 
6,504

Derivative settlements
2,369

 
416

Deposits on assets held for sale

 
3,750

Other
9,747

 
7,674

Total accrued liabilities
$
65,744

 
$
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:
 
June 30,
2014
 
December 31,
2013
 
(In thousands)
Credit agreement
$

 
$

6.625% senior subordinated notes due 2021, net of unamortized discount of $4.1 million at June 30, 2014 and $4.3 million at December 31, 2013
645,925

 
645,696

Total long-term debt
$
645,925

 
$
645,696


Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount available to be borrowed 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 of our credit agreement approved an increase in our borrowing base to $900.0 million from $800.0 million. 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 June 30, 2014, we had no outstanding borrowings under our credit agreement.


10


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 June 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 Guarantor, 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 discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

The Notes are guaranteed by our 100% owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the parent company, has no independent assets or operations. These guarantees (registered under the registration statements) are full and unconditional, joint and several, subject to certain automatic customary releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, and other conditions and terms set out in the 2011 Indenture. Any of our subsidiaries that are not Guarantors are minor. There are no significant restrictions on our ability to receive funds from any of our subsidiaries through dividends, loans, advances, or otherwise.

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 June 30, 2014.

11



Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
June 30,
2014
 
December 31,
2013
 
(In thousands)
Asset retirement obligation (ARO) liability
$
120,591

 
$
133,657

Capital lease obligations
25,799

 

Workers’ compensation
18,868

 
20,041

Separation benefit plans
10,357

 
9,382

Deferred compensation plan
3,984

 
3,589

Gas balancing liability
3,775

 
3,775

 
183,374

 
170,444

Less current portion
14,578

 
12,113

Total other long-term liabilities
$
168,796

 
$
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 July 1, 2014 (and through 2018) are $14.6 million, $38.8 million, $9.6 million, $7.2 million, and $7.4 million, respectively.

Capital Leases

During the second quarter, 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 $3.1 million is included in current portion of other long-term liabilities and the non-current portion of $22.7 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2014. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $12.3 million and $4.2 million, respectively at June 30, 2014. Annual payments, net of maintenance and interest, average $4.1 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 June 30, 2014 are as follows:
 
 
Amount
Ending June 30,
 
(In thousands)
2015
 
$
6,134

2016
 
6,195

2017
 
6,195

2018
 
6,195

2019
 
6,195

2020 and thereafter
 
13,065

Total future payments
 
43,979

Less payments related to:
 
 
Maintenance
 
12,285

Interest
 
4,196

Signed contract effective September 2014
 
1,699

Present value of future minimum payments
 
$
25,799



12


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:
 
Six Months Ended
 
June 30,
 
2014
 
2013
 
(In thousands)
ARO liability, January 1:
$
133,657

 
$
146,159

Accretion of discount
2,366

 
2,825

Liability incurred
1,900

 
2,869

Liability settled
(1,917
)
 
(3,192
)
Liability sold
(877
)
 
(324
)
Revision of estimates (1)
(14,538
)

(11,298
)
ARO liability, June 30:
120,591

 
137,039

Less current portion
3,118

 
2,948

Total long-term ARO
$
117,473

 
$
134,091

_______________________ 
(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

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.

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.
 

13


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. There was no effect on our financial position or results of operations when adopted.

NOTE 8 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(In millions)
Recognized stock compensation expense
$
4.5

 
$
4.3

 
$
8.3

 
$
7.6

Capitalized stock compensation cost for our oil and natural gas properties
1.0

 
0.9

 
1.8

 
1.6

Tax benefit on stock based compensation
1.7

 
1.6

 
3.2

 
2.9


The remaining unrecognized compensation cost related to unvested awards at June 30, 2014 is approximately $27.4 million of which $4.5 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.9 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.


14


We did not grant any SARs or stock options during either of the three or six month periods ending June 30, 2014 and 2013. The following table shows the fair value of any restricted stock awards granted to employees and non-employee directors during the periods indicated:  
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
Shares granted:
 
 
 
 
 
 
 
Employees

 

 
438,342

 
448,549

Non employee directors
13,768

 
21,128

 
13,768

 
21,128

 
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

 
0.9

 
0.9

 
$
0.9

 
$
0.9

 
$
23.3

 
$
21.9

Percentage of shares granted expected to be distributed:
 
 
 
 
 
 
 
Employees
N/A

 
N/A

 
95
%
 
94
%
Non employee directors
100
%
 
100
%
 
100
%
 
100
%

The restricted stock awards granted during the first three and six 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 six months of 2014 was $4.3 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 June 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.

15



At June 30, 2014, the following non-designated hedges were outstanding:
Term
Commodity
Hedged Volume
Weighted Average Fixed
Price for Swaps
Hedged Market
Jul’14 – Dec’14
Crude oil – swap
3,000 Bbl/day
$91.77
WTI – NYMEX
Jul’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
Jul’14 – Dec’14
Natural gas – swap
80,000 MMBtu/day
$4.24
NYMEX (HH)
Jul’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
June 30,
2014
 
December 31,
2013
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
Current
Current derivative asset
$

 
$
515

Long-term
Non-current derivative asset

 

Total derivative assets
 
$

 
$
515

 
 
Derivative Liabilities
 
 
Fair Value
 
Balance Sheet Location
June 30,
2014
 
December 31,
2013
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
Current
Current derivative liabilities
$
15,839

 
$
5,561

Long-term
Non-current derivative liabilities
326

 

Total derivative liabilities
 
$
16,165

 
$
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.

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 June 30, 2014. As of June 30, 2013, we had recognized a gain of $1.7 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.

16



Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the six months ended June 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
$

 
$
1,709

_______________________
 (1) Net of taxes.

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

 
$
(823
)
 
$

 
$

Commodity derivatives
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net 

 

 

 
1,717

Total
 
$

 
$
(823
)
 
$

 
$
1,717

 _______________________
(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 June 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)
$
(10,709
)
 
$
14,627

Total
 
$
(10,709
)
 
$
14,627

_______________________
(1)
Amounts settled during the 2014 and 2013 periods include losses of $(9.1) million and $(0.2) million, respectively.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the six months ended June 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
$

 
$
3,008

 
$

 
$

Commodity derivatives
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net 

 

 

 
368

Total
 
$

 
$
3,008

 
$

 
$
368

 _______________________
(1)
Effective portion of gain (loss).
(2)
Ineffective portion of gain (loss).

17



Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the six months ended June 30:
Derivatives Not Designated as Hedging
Instruments
Location of Gain or (Loss)
Recognized in Income on
Derivative
Amount of Gain of (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)
$
(29,075
)
 
$
10,052

Total
 
$
(29,075
)
 
$
10,052

_______________________
(1)
Amounts settled during the 2014 and 2013 periods include a loss of $(18.0) million and a gain of $0.9 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.

18



The following tables set forth our recurring fair value measurements:
 
June 30, 2014
 
Level 2
 
Level 3
 
Gross Amounts
 
Effect of Netting
 
Net Amounts Presented
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
Assets
$

 
$

 
$

 
$

 
$

Liabilities
(10,084
)
 
(6,081
)
 
(16,165
)
 

 
(16,165
)
 
$
(10,084
)
 
$
(6,081
)
 
$
(16,165
)
 
$

 
$
(16,165
)
 
 
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
)

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.


19


The following tables are reconciliations of our level 3 fair value measurements: 
 
Commodity Collars
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Beginning of period
$
(4,464
)
 
$
(2,536
)
 
$
(2,595
)
 
$
(595
)
Total gains or losses (realized and unrealized):
 
 
 
 
 
 
 
Included in earnings (1)
(4,401
)
 
3,346

 
(7,829
)
 
1,405

Included in other comprehensive income (loss)

 

 

 

Settlements
2,784

 
636

 
4,343

 
636

End of period
$
(6,081
)
 
$
1,446

 
$
(6,081
)
 
$
1,446

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
$
(1,617
)
 
$
3,982

 
$
(3,486
)
 
$
2,041

_______________________
(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 June 30, 2014:
Commodity (1)
Fair Value
Valuation Technique
Unobservable Input
Range
 
(In thousands)
 
 
 
Oil collars
$
(5,674
)
Discounted cash flow
Forward commodity price curve
$0.06 - $10.27
Natural gas collar
$
(407
)
Discounted cash flow
Forward commodity price curve
$0.00 - $0.40
 _______________________
(1)
The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars 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 June 30, 2014, we determined that risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

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

At June 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 June 30, 2014 was zero. 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 June 30, 2014 and December 31, 2013 were $645.9 million and $645.7 million, respectively. We estimated the fair value of these Notes using quoted marked prices at June 30, 2014 and December 31, 2013 which were $695.5 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

20


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 June 30, 2013 are as follows:
 
Net Gains (Losses) on Cash Flow Hedges
 
(In thousands)
Balance at April 1:
$
(3,838
)
Other comprehensive income before reclassification
6,091

Amounts reclassified from accumulated other comprehensive income
(544
)
New current-period other comprehensive income
5,547

Balance at June 30:
$
1,709


Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the three months ended June 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
$
(823
)
 
Oil and natural gas revenues
Commodity derivatives
1,717

 
Gain on derivatives not designated as hedges and hedge ineffectiveness, net
 
894

 
Total before tax
 
(350
)
 
Tax expense
Total reclassification for the period
$
544

 
Net of tax

Changes in accumulated other comprehensive income (loss) by component, net of tax, for the six months ended June 30, 2013 are as follows:
 
Net Gains (Losses) on Cash Flow Hedges
 
(In thousands)
Balance at January 1:
$
7,587

Other comprehensive income before reclassification
(3,820
)
Amounts reclassified from accumulated other comprehensive income
(2,058
)
New current-period other comprehensive income
(5,878
)
Balance at June 30:
$
1,709


21



Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the six months ended June 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
$
3,008

 
Oil and natural gas revenues
Commodity derivatives
368

 
Gain on derivatives not designated as hedges and hedge ineffectiveness, net
 
3,376

 
Total before tax
 
(1,318
)
 
Tax expense
Total reclassification for the period
$
2,058

 
Net of tax


22


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
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands)
 
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
$
198,498

 
$
164,799

 
$
386,705

 
$
318,408

 
 
 
 
 
 
 
 
 
 
Contract drilling
135,782

 
118,660

 
260,040

 
238,013

 
Elimination of inter-segment revenue
(21,504
)
 
(13,655
)
 
(39,162
)
 
(25,480
)
 
Contract drilling net of inter-segment revenue
114,278

 
105,005

 
220,878

 
212,533

 
 
 
 
 
 
 
 
 
 
Gas gathering and processing
116,354

 
92,910

 
236,714

 
173,066

 
Elimination of inter-segment revenue
(23,699
)
 
(22,293
)
 
(50,878
)
 
(45,054
)
 
Gas gathering and processing net of inter-segment revenue
92,655

 
70,617

 
185,836

 
128,012

 
 
 
 
 
 
 
 
 
 
Total revenues
$
405,431

 
$
340,421

 
$
793,419

 
$
658,953

 
Operating income:

 

 

 

 
Oil and natural gas
$
82,530

 
$
64,470

 
$
170,642

 
$
123,058

 
Contract drilling
27,545

 
23,507

 
51,946

 
47,773

 
Gas gathering and processing
3,898

 
2,846

 
6,528

 
3,675

 
Total operating income (1)
113,973

 
90,823

 
229,116

 
174,506

 
General and administrative
(10,600
)
 
(9,679
)
 
(20,237
)
 
(18,352
)
 
Gain on disposition of assets
195

 
3,483

 
9,621

 
3,399

 
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net
(10,709
)
 
16,344

 
(29,075
)
 
10,420

 
Interest expense, net
(4,131
)
 
(4,591
)
 
(7,921
)
 
(8,152
)
 
Other
(49
)
 
(91
)
 
71

 
(157
)
 
Income before income taxes
$
88,679

 
$
96,289

 
$
181,575

 
$
161,664

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


23


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 June 30, 2014, and the related Unaudited Condensed Consolidated Statements of Income and Comprehensive Income for the three and six-month periods ended June 30, 2014 and 2013 and the Unaudited Condensed Consolidated Statements of Cash Flows for the six-month periods ended June 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
August 5, 2014


24


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

Our current 2014 capital budget for all of our business segments forecasts a 33% increase over our 2013 capital
expenditures, excluding acquisitions. Our oil and natural gas segment’s capital budget is $718.0 million, a 31% increase over 2013, excluding acquisitions and ARO liability. Our drilling segment’s capital budget is $132.0 million, a 105% increase over
2013. Our mid-stream segment’s capital budget is $78.0 million, a 19% decrease from 2013, excluding capital leases. New and continued projects are discussed further in the Executive Summary.

Our 2014 current capital budget is based on realized prices for the year of $90.08 per barrel of oil, $29.45
per barrel of NGLs, and $3.77 per Mcf of natural gas. This budget is subject to possible periodic adjustments for various
reasons including changes in commodity prices and industry conditions. Funding for the budget will come primarily from internally generated cash flow and, if necessary, borrowings under our credit agreement.

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.

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

Second quarter 2014 production from our oil and natural gas segment was 4,618,000 barrels of oil equivalent (Boe), a 10% increase over the first quarter of 2014 and a 12% increase over the second quarter of 2013. The increase over the first

25


quarter of 2014 was primarily due to production associated with new wells and the impact of weather conditions, mechanical issues, and fewer days had on the first quarter. The increase over the second quarter of 2013 came primarily from production associated with new wells.

Second quarter 2014 oil and natural gas revenues increased 5% over the first quarter of 2014 and increased 20% over the second quarter of 2013. The increase over the first quarter of 2014 was due primarily to increased production coupled with higher oil prices somewhat offset by lower natural gas and NGLs prices. The increase over the second quarter of 2013 was due primarily to increased production along with higher natural gas prices.

Our oil prices for the second quarter of 2014 increased 3% compared to the first quarter of 2014 and decreased 1% from the second quarter of 2013. Our NGLs prices decreased 24% and 1% from the first quarter of 2014 and second quarter of 2013, respectively. Our natural gas prices decreased 4% from the first quarter of 2014 and increased 11% over the second quarter of 2013.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 4% and 28% over the first quarter of 2014 and the second quarter of 2013, respectively. The increases were due primarily to increases in production partially offset by lower liquids prices and increases in lease operating expenses. Additionally, direct profit was reduced in the second quarter of 2014 compared to the first quarter of 2014 due to higher gross production tax credits in the first quarter. The first quarter of 2014 included refunds for production tax credits attributable to certain types of gas wells of $7.9 million compared to $3.8 million during the second quarter of 2014.

Operating cost per Boe produced for the second quarter of 2014 was essentially unchanged compared to the first quarter of 2014 and decreased 12% from the second quarter of 2013. Costs were higher between the second and first quarter of 2014 primarily due to lower gross production tax credits and higher lease operating expenses offset by lower salt water disposal expense. Second quarter 2014 costs were essentially unchanged compared to the second quarter of 2013 due to higher lease operating expenses partially offset by higher gross production tax credits and lower saltwater disposal 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.

From January 1st through June 30, 2014, we completed drilling 85 gross wells (53.16 net wells). Our current 2014 production guidance is approximately 18.9 to 19.2 MMBoe, an increase of 13% to 15% over 2013, although actual results continue to be subject to many factors. For 2014, we plan to participate in the drilling of 180 gross wells. Excluding acquisitions and ARO liability, our oil and natural gas segment's capital budget is $718.0 million, a 31% increase over 2013.

Contract Drilling

The rate at which our drilling rigs were used (“our utilization rate”) for the second quarter 2014 was 62%, compared to 57% and 51% for the first quarter of 2014 and the second quarter of 2013, respectively.

Dayrates for the second quarter of 2014 averaged $19,904, a 1% increase over the first quarter of 2014 and a 2% increase over the second quarter of 2013. The increases were due to improving market conditions.

Direct profit (contract drilling revenue less contract drilling operating expense) for the second quarter of 2014 increased 12% and 15% over the first quarter of 2014 and the second 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 second quarter of 2014 decreased 5% from the first quarter of 2014 and decreased 7% from the second quarter of 2013. The decreases were primarily due to lower per day direct costs, lower workers compensation expense, and higher utilization covering fixed indirect expense.


26


Unit’s 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 (SCOOP), Granite Wash, and the Cleveland, Tonkawa, and Marmaton plays.  These areas cover North Dakota, Wyoming, Texas, Oklahoma, and Kansas. Our smaller drilling rigs being utilized are in shallow plays like the Mississippian in northern Oklahoma and southern Kansas. We also are working in ultra-deep gas exploration 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 80 drilling rigs operating.  Of the 80 operating drilling rigs, 45 are on spot market contracts and 35 are on term drilling contracts, with original terms ranging from six months to two years. Seventeen of the term contracts are up for renewal in 2014, five in the third quarter, 12 in the fourth quarter, and 18 are up for renewal in 2015. 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. We anticipate this new drilling rig design will position us to more effectively meet the demands of our existing customers as well as allowing us to compete for the work of new customers.

During the second quarter of 2013, we sold a 2,000 horsepower electric drilling rig to an unaffiliated third-party.

The 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 in the fourth quarter of 2014. Five additional BOSS drilling rigs have been contracted to be built for third-party operators and are expected to be placed into service during the balance of 2014 and early 2015. We have modified our building schedule for the BOSS drilling rig with the objective of staying two drilling rigs ahead of contracts in place. Not including the five BOSS drilling rigs under construction, we currently have 118 drilling rigs in our fleet. Our anticipated 2014 capital expenditures for this segment are $132.0 million, a 105% increase over 2013.

Mid-Stream

Second quarter 2014 liquids sold per day increased 7% over the first quarter of 2014 and increased 50% over the second quarter of 2013. The increases were due to new wells being connected to our systems. For the second quarter of 2014, gas processed per day increased 8% over the first quarter of 2014 and increased 17% over the second quarter of 2013. These increases are primarily due to connecting new wells to both existing and newly constructed systems. For the second quarter of 2014, gas gathered per day increased 7% over the first quarter of 2014 and was essentially unchanged compared to the second quarter of 2013. The increases over the first quarter of 2014 were primarily from new wells connected.

NGLs prices in the second quarter of 2014 decreased 14% from the prices received in the first quarter of 2014 and decreased 7% from the prices received in the second 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 second quarter of 2014 increased 15% over the first quarter of 2014 and increased 27% over the second quarter of 2013. The increase over the first quarter of 2014 was primarily due to lower operating expenses due to a 13% decrease in the price of gas purchased. The increase over the second quarter was primarily due to increased revenues due to the increase in the liquids sold and to a lessor extent from higher gas sales and prices. The increases in direct profit over increased revenues were somewhat offset by the higher cost of gas purchased. Total operating cost for our mid-stream segment for the second quarter of 2014 decreased 3% from the first quarter of 2014 and increased 32% over the second quarter of 2013.

At our Hemphill County, Texas facility, we are continuing to connect new wells to our system as they are drilled and completed. We are in the process of constructing a trunkline that will connect our Buffalo Wallow gathering system to our Hemphill system which will allow us the ability to process gathered production from Buffalo Wallow at our Hemphill processing facility. This trunkline will consist of approximately nine miles of pipeline with related compression and is expected to be completed by the end of 2014.  

At our gathering and processing facility in Reno County, Kansas, we currently have available processing capacity of approximately 25 MMcf per day. This capacity is provided by a five MMcf per day refrigerated JT plant skid and a 20 MMcf

27


per day turbo expander plant skid. At this facility we are continuing to connect wells to this system as they are drilled and completed.

At our Cashion facility located in central Oklahoma, producers continue to be active in this area and are drilling and completing new wells in the areas around our system. We have connected 16 new wells to our system in the first six months of 2014. With our existing processing capacity of 45 MMcf per day, we are positioned to add additional volumes with minimal future capital expenditures.

In the Mississippian play in north central Oklahoma, our Bellmon facility has total processing capacity of approximately 90 MMcf per day and we continue to connect new wells to this system as they are drilled. In the first six months of 2014, we connected 32 new wells to this system and have 50 MMcf per day of available processing capacity to connect additional volumes. We are in the process of completing several expansion projects and lateral lines that will  allow us the ability to connect additional wells.

In the Appalachian region, we have 19 wells connected to the Pittsburgh Mills gathering system and are in the process of constructing the second phase of this project which will extend  our pipeline north into Butler County, Pennsylvania. Right of way has been acquired and construction of phase 2 is expected to begin in the third quarter of 2014 with an expected completion date in the first quarter of 2015. This will allow us the ability to connect additional wells to our system which are scheduled for completion in early and mid-2015.

Our anticipated 2014 capital expenditures for this segment are $78.0 million, a 19% decrease from 2013, excluding capital leases.

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

 
Six Months Ended June 30,
 
%
Change (1)
 
2014
 
2013
 
 
(In thousands except percentages)
Net cash provided by operating activities
$
325,528

 
$
317,888

 
2
%
Net cash used in investing activities
$
(379,107
)
 
$
(322,471
)
 
18
%
Net cash provided by financing activities
$
36,064

 
$
4,650

 
NM

Net increase (decrease) in cash and cash equivalents
$
(17,515
)
 
$
67

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

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 these services. Our cash flows from operating activities are also impacted by changes in working capital.

Net cash provided by operating activities in the first six months of 2014 increased by $7.6 million over the first six months of 2013 due primarily to increases in profit margins in all three operating segments partially offset by changes in operating assets and liabilities related to the timing of cash receipts and disbursements.

28



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 $56.6 million for the first six months of 2014 compared to the first six 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 $31.4 million for the first six months of 2014 compared to the first six months of 2013. This was primarily due to 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 June 30, 2014, we had unrestricted cash totaling $1.1 million and had borrowed none 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 June 30, 2014 and 2013 and for the six months ended June 30, 2014 and 2013:
 
June 30,
 
%
Change (1)
 
2014
 
2013
 
 
(In thousands except percentages)
Working capital
$
(103,284
)
 
$
9,738

 
NM

Long-term debt
$
645,925

 
$
715,474

 
(10
)%
Shareholders’ equity
$
2,294,687

 
$
2,079,549

 
10
 %
Ratio of long-term debt to total capitalization
22
%
 
26
%
 
(15
)%
Net income
$
111,305

 
$
99,213

 
12
 %
_______________________
(1)
NM - A percentage calculation is not meaningful due to a percentage greater than 200.


29


The following table summarizes certain operating information:
 
Six Months Ended
 
 
 
June 30,
 
%
Change
 
2014
 
2013
 
Oil and Natural Gas:
 
 
 
 
 
Oil production (MBbls)
1,760

 
1,656

 
6
 %
Natural gas liquids production (MBbls)
2,228

 
1,739

 
28
 %
Natural gas production (MMcf)
28,881

 
28,107

 
3
 %
Average oil price per barrel received
$92.95
 
$95.05
 
(2
)%
Average oil price per barrel received excluding derivatives
$97.81
 
$91.75
 
7
 %
Average NGLs price per barrel received
$34.57
 
$32.47
 
6
 %
Average NGLs price per barrel received excluding derivatives
$34.57
 
$32.47
 
6
 %
Average natural gas price per mcf received
$4.14
 
$3.47
 
19
 %
Average natural gas price per mcf received excluding derivatives
$4.47
 
$3.53
 
27
 %
Contract Drilling:
 
 
 
 
 
Average number of our drilling rigs in use during the period
70.7

 
65.8

 
7
 %
Total number of drilling rigs owned at the end of the period
118

 
126

 
(6
)%
Average dayrate
$19,766
 
$19,590
 
1
 %
Mid-Stream:
 
 
 
 
 
Gas gathered—Mcf/day
315,116

 
299,582

 
5
 %
Gas processed—Mcf/day
155,807

 
134,016

 
16
 %
Gas liquids sold—gallons/day
737,353

 
464,483

 
59
 %
Number of natural gas gathering systems
38

 
40

 
(5
)%
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 $103.3 million and positive working capital of $9.7 million as of June 30, 2014 and 2013, respectively. The effect of our derivative contracts decreased working capital by $15.8 million as of June 30, 2014 and increased working capital by $7.9 million as of June 30, 2013.

Impact of Prices for Our Oil, NGLs, and Natural Gas

Any significant change in oil, NGLs, or natural gas prices has a material effect 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 world oil market developments. All of these factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.

Based on our first six 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 six months of 2014 was $4.14 compared to $3.47 for the first six months of 2013. Based on our first six months of 2014 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $284,000 per month ($3.4 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 $357,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow. In the first six months of 2014, our average oil price per barrel received, including the effect of derivatives, was $92.95 compared with an average oil price, including the effect of derivatives, of $95.05 in the first six months of 2013 and our first six months of 2014 average NGLs price per barrel received, including the effect of derivatives, was $34.57 compared with an average NGLs price per barrel of $32.47 in the first six months of 2013.


30


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 June 30, 2014, the 12-month average unescalated prices were $100.27 per barrel of oil, $47.77 per barrel of NGLs, and $4.11per Mcf of natural gas, then adjusted for price differentials. We were not required to take a write-down in the second 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

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 shortage of qualified labor will keep us from working additional rigs, but it could cause some delays in the time needed to crew the new drilling rigs. Beginning in third quarter 2014, we increased compensation for drilling personnel in Oklahoma, 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 combined with improving technology and longer horizontal laterals require drilling rigs with higher horsepower in plays such as the Granite Wash play in western Oklahoma and the Texas panhandle. 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 six months of 2014, our average dayrate was $19,766 per day compared to $19,590 per day for the first six months of 2013. The average number of our drilling rigs used in the first six months of 2014 was 70.7 drilling rigs (60%) compared with 65.8 drilling rigs (52%) in the first six months of 2013. Based on the average utilization of our drilling rigs during the first six months of 2014, a $100 per day change in dayrates has a $7,070 per day ($2.6 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our oil and natural gas segment. Depending on the timing of those services, some of those services are deemed to be associated with the acquisition of an ownership interest in the 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 $39.2 million and $25.5 million for the six months of 2014 and 2013, respectively, from our contract drilling segment and eliminated the associated operating expense of $26.8 million and $18.4 million during the six months of 2014 and 2013, respectively, yielding $12.4 million and $7.1 million during the six 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 three 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. This segment enhances our ability to gather and market not only our own natural gas and NGLs but also that owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During the first six months of 2014 and 2013, our mid-stream operations purchased $45.8 million and $41.3 million, respectively, of our natural gas production and NGLs, and provided gathering and transportation services of $5.1 million and $3.8 million, respectively. Intercompany revenue

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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 315,116 Mcf per day in the first six months of 2014 compared to 299,582 Mcf per day in the first six months of 2013. It processed an average of 155,807 Mcf per day in the first six months of 2014 compared to 134,016 Mcf per day in the first six months of 2013. The amount of NGLs sold was 737,353 gallons per day in the first six months of 2014 compared to 464,483 gallons per day in the first six months of 2013. Gas gathering volumes per day in the first six months of 2014 increased 5% compared to the first six 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 six months and NGLs sold increased 59% over the comparative period due primarily to new wells connected.

Our Credit Agreement and Senior Subordinated Notes

Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount available to be borrowed 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. At June 30, 2014 and July 25, 2014, we did not have any borrowings under our credit agreement.

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
%

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 of our credit agreement approved an increase in our borrowing base to $900.0 million from $800.0 million. 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.

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.


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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 June 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.

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 Guarantor, 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 discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

The Notes are guaranteed by our 100% owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the parent company, has no independent assets or operations. These guarantees (registered under the 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 June 30, 2014.

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. Any decision 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 85 gross wells (53.16