10-Q 1 unt-2014930x10q.htm 10-Q UNT-2014.9.30-10Q
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 September 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 October 24, 2014, 49,574,090 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, natural gas liquids (NGLs), and natural gas;
demand for oil, NGLs, and natural gas;
our exploration and drilling prospects;
the estimates of our proved oil, NGLs, and natural gas reserves;
oil, NGLs, and natural gas reserve potential;
development and infill drilling potential;
expansion and other development trends of the oil and natural gas industry;
our business strategy;
our plans to maintain or increase production of oil, NGLs, and natural gas;
the number of gathering systems and processing plants we plan to construct or acquire;
volumes and prices for natural gas gathered and processed;
expansion and growth of our business and operations;
demand for our drilling rigs and drilling rig rates;
our belief that the final outcome of our legal proceedings will not materially affect our financial results;
our ability to timely secure third-party services used in completing our wells;
our ability to transport or convey our oil or natural gas production to established pipeline systems;
impact of federal and state legislative and regulatory actions impacting our costs and increasing operating restrictions or delays as well as other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets;
the number of wells our oil and natural gas segment plans to drill during the year; and
our outlook for the demand of our new drilling rig, the BOSS drilling rig.

These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, and expected future developments, as well as other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties, any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:
the risk factors discussed in this document and in the documents (if any) we incorporate by reference;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities that we pursue;
demand for our land drilling services;
changes in laws or regulations;
decreases or increases in commodity prices; and
other factors, most of which are beyond our control.
You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim any current intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this document to reflect the occurrence of unanticipated events.


2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
September 30,
2014
 
December 31,
2013
 
(In thousands except share amounts)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
895

 
$
18,593

Accounts receivable, net of allowance for doubtful accounts of $2,292 and $5,342 at September 30, 2014 and at December 31, 2013, respectively
179,464

 
139,788

Materials and supplies
8,776

 
10,998

Current derivative asset (Note 9)
4,047

 
515

Current deferred tax asset
13,585

 
13,585

Assets held for sale

 
15,621

Prepaid expenses and other
13,360

 
12,931

Total current assets
220,127

 
212,031

Property and equipment:
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
Proved properties
4,696,879

 
4,235,712

Unproved properties not being amortized
584,270

 
545,588

Drilling equipment
1,569,202

 
1,477,093

Gas gathering and processing equipment
606,815

 
549,422

Transportation equipment
40,402

 
39,666

Other
107,965

 
87,435

 
7,605,533

 
6,934,916

Less accumulated depreciation, depletion, amortization, and impairment
3,480,885

 
3,212,225

Net property and equipment
4,124,648

 
3,722,691

Debt issuance cost
10,653

 
11,844

Goodwill
62,808

 
62,808

Non-current derivative asset (Note 9)
658

 

Other assets
12,917

 
13,016

Total assets
$
4,431,811

 
$
4,022,390


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

3


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

 
September 30,
2014
 
December 31,
2013
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
237,736

 
$
154,062

Accrued liabilities (Note 4)
83,930

 
64,363

Income taxes payable
15,452

 
7,474

Current derivative liabilities (Note 9)

 
5,561

Current portion of other long-term liabilities (Note 5)
14,221

 
12,113

Total current liabilities
351,339

 
243,573

Long-term debt (Note 5)
676,843

 
645,696

Other long-term liabilities (Note 5)
147,214

 
158,331

Deferred income taxes
888,915

 
801,398

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

 

Common stock, $.20 par value, 175,000,000 shares authorized, 49,574,708 and 49,107,004 shares issued, respectively
9,730

 
9,659

Capital in excess of par value
460,680

 
445,470

Retained earnings
1,897,090

 
1,718,263

Total shareholders’ equity
2,367,500

 
2,173,392

Total liabilities and shareholders’ equity
$
4,431,811

 
$
4,022,390


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


4


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
 
 
 
Oil and natural gas
$
188,471

 
$
157,320

 
$
575,176

 
$
475,728

Contract drilling
120,652

 
100,647

 
341,530

 
313,180

Gas gathering and processing
91,851

 
75,809

 
277,687

 
203,821

Total revenues
400,974

 
333,776

 
1,194,393

 
992,729

Expenses:
 
 
 
 
 
 
 
Oil and natural gas:
 
 
 
 
 
 
 
Operating costs
48,841

 
50,139

 
133,979

 
138,171

Depreciation, depletion, and amortization
70,033

 
56,294

 
200,958

 
163,612

Contract drilling:
 
 
 
 
 
 
 
Operating costs
66,727

 
58,988

 
197,025

 
188,580

Depreciation
22,560

 
17,402

 
61,194

 
52,570

Gas gathering and processing:
 
 
 
 
 
 
 
Operating costs
78,558

 
63,098

 
238,166

 
172,065

Depreciation and amortization
10,272

 
8,773

 
29,972

 
24,143

General and administrative
10,172

 
9,936

 
30,409

 
28,288

(Gain) loss on disposition of assets
529

 
(4,345
)
 
(9,092
)
 
(7,744
)
Total operating expenses
307,692

 
260,285

 
882,611

 
759,685

Income from operations
93,282

 
73,491

 
311,782

 
233,044

Other income (expense):
 
 
 
 
 
 
 
Interest, net
(4,280
)
 
(3,625
)
 
(12,201
)
 
(11,777
)
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net
19,841

 
(13,760
)
 
(9,234
)
 
(3,340
)
Other
(68
)
 
(14
)
 
3

 
(171
)
Total other income (expense)
15,493

 
(17,399
)
 
(21,432
)
 
(15,288
)
Income before income taxes
108,775

 
56,092

 
290,350

 
217,756

Income tax expense:
 
 
 
 
 
 
 
Current
5,451

 
2,111

 
23,721

 
6,745

Deferred
35,802

 
19,749

 
87,802

 
77,566

Total income taxes
41,253

 
21,860

 
111,523

 
84,311

Net income
$
67,522

 
$
34,232

 
$
178,827

 
$
133,445

Net income per common share:
 
 
 
 
 
 
 
Basic
$
1.39

 
$
0.71

 
$
3.68

 
$
2.77

Diluted
$
1.37

 
$
0.70

 
$
3.65

 
$
2.75


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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Net income
$
67,522

 
$
34,232

 
$
178,827

 
$
133,445

Other comprehensive income (loss), net of taxes:
 
 
 
 
 
 
 
Change in value of derivative instruments used as cash flow hedges, net of tax of $0, ($3,013), $0, and ($5,517)

 
(4,797
)
 

 
(8,617
)
Reclassification - derivative settlements, net of tax of $0, $1,240, $0, and $63

 
1,970

 

 
139

Ineffective portion of derivatives, net of tax of $0, $97, $0, and ($44)

 
155

 

 
(72
)
Comprehensive income
$
67,522

 
$
31,560

 
$
178,827

 
$
124,895


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


6


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Nine Months Ended
 
September 30,
 
2014
 
2013
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
Net income
$
178,827

 
$
133,445

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion, and amortization
294,412

 
242,590

Loss on derivatives
9,234

 
3,542

Cash payments on derivatives settled
(18,984
)
 
(1,777
)
Deferred tax expense
87,802

 
77,566

Gain on disposition of assets
(9,092
)
 
(7,744
)
Employee stock compensation plans
17,780

 
16,652

Other, net
5,156

 
4,263

Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
Accounts receivable
(47,704
)
 
1,888

Accounts payable
1,708

 
320

Material and supplies
2,222

 
(1,767
)
Accrued liabilities
28,596

 
31,041

Other, net
(430
)
 
942

Net cash provided by operating activities
549,527

 
500,961

INVESTING ACTIVITIES:
 
 
 
Capital expenditures
(686,405
)
 
(512,574
)
Proceeds from disposition of assets
49,341

 
89,916

Other
303

 

Net cash used in investing activities
(636,761
)
 
(422,658
)
FINANCING ACTIVITIES:
 
 
 
Borrowings under credit agreement
395,700

 
222,500

Payments under credit agreement
(364,900
)
 
(293,600
)
Payments on capitalized leases
(1,505
)
 

Proceeds from exercise of stock options
926

 
578

Book overdrafts
39,315

 
(7,014
)
Net cash provided by (used in) financing activities
69,536

 
(77,536
)
Net increase (decrease) in cash and cash equivalents
(17,698
)
 
767

Cash and cash equivalents, beginning of period
18,593

 
974

Cash and cash equivalents, end of period
$
895

 
$
1,741

Supplemental disclosure of cash flow information:
 
 
 
Cash paid during the year for:
 
 
 
Interest paid (net of capitalized)
(1,340
)
 
(1,301
)
Income taxes
16,000

 
7,300

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
(42,651
)
 
(516
)
Non-cash reductions to oil and natural gas properties related to asset retirement obligations
40,516

 
16,417

Non-cash additions to property, plant, and equipment acquired under capital leases
(28,202
)
 

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

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 September 30, 2014 and December 31, 2013;
• Statements of Income for the three and nine months ended September 30, 2014 and 2013;
• Statements of Comprehensive Income for the three and nine months ended September 30, 2014 and 2013; and
• Statements of Cash Flows for the nine months ended September 30, 2014 and 2013.

Our financial statements are prepared in conformity with generally accepted accounting principles in the United States (GAAP). GAAP requires us to make certain estimates and assumptions that may affect the amounts reported in our unaudited condensed consolidated financial statements and accompanying notes. Actual results may differ from those estimates. Results for the nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results to be realized for the full year in the case of 2014, or that we realized for the full year of 2013.

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

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

NOTE 2 – DIVESTITURES

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

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

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


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 September 30, 2014
 
 
 
 
 
Basic earnings per common share
$
67,522

 
48,650

 
$
1.39

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

 
527

 
(0.02
)
Diluted earnings per common share
$
67,522

 
49,177

 
$
1.37

For the three months ended September 30, 2013
 
 
 
 
 
Basic earnings per common share
$
34,232

 
48,254

 
$
0.71

Effect of dilutive stock options, restricted stock, and SARs

 
404

 
(0.01
)
Diluted earnings per common share
$
34,232

 
48,658

 
$
0.70


The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
Three Months Ended
 
September 30,
 
2014
 
2013
Stock options and SARs
24,500

 
149,665

Average exercise price
$
73.26

 
$
58.41


 
Income
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
(In thousands except per share amounts)
For the nine months ended September 30, 2014
 
 
 
 
 
Basic earnings per common share
$
178,827

 
48,596

 
$
3.68

Effect of dilutive stock options, restricted stock, and SARs

 
458

 
(0.03
)
Diluted earnings per common share
$
178,827

 
49,054

 
$
3.65

For the nine months ended September 30, 2013
 
 
 
 
 
Basic earnings per common share
$
133,445

 
48,193

 
$
2.77

Effect of dilutive stock options, restricted stock, and SARs

 
317

 
(0.02
)
Diluted earnings per common share
$
133,445

 
48,510

 
$
2.75


 
Nine Months Ended
 
September 30,
 
2014
 
2013
Stock options and SARs
49,000

 
149,665

Average exercise price
$
67.83

 
$
58.41



9


NOTE 4 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following:
 
September 30,
2014
 
December 31,
2013
 
(In thousands)
Employee costs
$
27,242

 
$
27,633

Interest
17,343

 
6,504

Lease operating expenses
15,269

 
16,073

Taxes
12,994

 
2,313

Derivative settlements
114

 
416

Deposits on assets held for sale

 
3,750

Other
10,968

 
7,674

Total accrued liabilities
$
83,930

 
$
64,363

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

Long-Term Debt

As of the dates in the table, our long-term debt consisted of the following:
 
September 30,
2014
 
December 31,
2013
 
(In thousands)
Credit agreement with an average interest rate of 4.0% at September 30, 2014
$
30,800

 
$

6.625% senior subordinated notes due 2021, net of unamortized discount of $4.0 million at September 30, 2014 and $4.3 million at December 31, 2013
646,043

 
645,696

Total long-term debt
$
676,843

 
$
645,696


Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount we can borrow is the lesser of the amount we elect (from time to time) as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $900.0 million. Our current commitment amount is $500.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. The fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. The credit agreement matures as of September 13, 2016. In connection with the most recent amendment of the credit agreement, we paid $1.5 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement.

The amount of the borrowing base–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. Effective with the April 2014 redetermination, the lenders approved an increase in our borrowing base to $900.0 million from $800.0 million. There was no additional change to the borrowing base with the October 2014 redetermination. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that in any event cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at anytime, without a premium or penalty. At September 30, 2014, we had $30.8 million outstanding borrowings under our credit agreement.


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 September 30, 2014, we were in compliance with the covenants contained in the credit agreement.

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

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

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

At any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of September 30, 2014.

11



Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
September 30,
2014
 
December 31,
2013
 
(In thousands)
Asset retirement obligation (ARO) liability
$
96,679

 
$
133,657

Capital lease obligations
26,708

 

Workers’ compensation
19,224

 
20,041

Separation benefit plans
10,799

 
9,382

Deferred compensation plan
3,965

 
3,589

Gas balancing liability
3,775

 
3,775

Other
285

 

 
161,435

 
170,444

Less current portion
14,221

 
12,113

Total other long-term liabilities
$
147,214

 
$
158,331


Estimated annual principal payments under the terms of debt and other long-term liabilities during each of the five successive twelve month periods beginning October 1, 2014 (and through 2019) are $14.2 million, $35.2 million, $9.2 million, $7.1 million, and $7.4 million, respectively.

Capital Leases

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

Future payments required under the capital leases at September 30, 2014 are as follows:
 
 
Amount
Ending September 30,
 
(In thousands)
2015
 
$
6,195

2016
 
6,195

2017
 
6,195

2018
 
6,195

2019
 
6,195

2020 and thereafter
 
11,516

Total future payments
 
42,491

Less payments related to:
 
 
Maintenance
 
11,848

Interest
 
3,935

Present value of future minimum payments
 
$
26,708



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

 
$
146,159

Accretion of discount
3,538

 
4,152

Liability incurred
2,889

 
3,820

Liability settled
(3,936
)
 
(3,439
)
Liability sold
(1,206
)
 
(632
)
Revision of estimates (1)
(38,263
)

(16,166
)
ARO liability, September 30:
96,679

 
133,894

Less current portion
2,718

 
2,954

Total long-term ARO
$
93,961

 
$
130,940

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

NOTE 7 – NEW ACCOUNTING PRONOUNCEMENTS

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

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


13


Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts). The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. We are in the process of evaluating the impact it will have on our financial statements.
 
Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The FASB has issued ASU 2014-08, the amendments in this update change the criteria for reporting discontinued operations while enhancing disclosures in this area. It also addresses sources of confusion and inconsistent application related to financial reporting of discontinued operations guidance in U.S. GAAP. Under the new guidance, only disposals representing a strategic shift that would have a major effect on the organization's operations and financial results should be presented as discontinued operations. In addition, it requires expanded disclosures about discontinued operations that will provide financial statement users with more information about the assets, liabilities, income, and expenses of discontinued operations. It also requires disclosure of pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting. The updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. Early adoption is permitted. We currently do not have any discontinued operations or disposals of components of an entity.

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

NOTE 8 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(In millions)
Recognized stock compensation expense
$
4.4

 
$
4.4

 
$
12.7

 
$
12.0

Capitalized stock compensation cost for our oil and natural gas properties
0.9

 
1.0

 
2.7

 
2.6

Tax benefit on stock based compensation
1.7

 
1.8

 
4.9

 
4.7


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

The Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors. A total of 3,300,000 shares of the company's common stock is authorized for issuance to eligible participants under the amended plan.


14


We did not grant any SARs or stock options during either of the three or nine month periods ending September 30, 2014 and 2013. The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the nine months ended September 30, 2014 and 2013, as there were no restricted stock awards granted during the three months ended September 30, 2014 or 2013.  
 
Nine Months Ended
 
September 30,
 
2014
 
2013
Shares granted:
 
 
 
Employees
438,342

 
448,549

Non employee directors
13,768

 
21,128

 
452,110

 
469,677

Estimated fair value (in millions):
 
 
 
Employees
$
22.4

 
$
21.0

Non employee directors
0.9

 
0.9

 
$
23.3

 
$
21.9

Percentage of shares granted expected to be distributed:
 
 
 
Employees
95
%
 
94
%
Non employee directors
100
%
 
100
%

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

NOTE 9 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract is based, in part, on our view of current and future market conditions. As of September 30, 2014, our derivative transactions consisted of the following types of hedges:

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

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

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

15



At September 30, 2014, the following non-designated hedges were outstanding:
Term
Commodity
Hedged Volume
Weighted Average Fixed
Price for Swaps
Hedged Market
Oct’14 – Dec’14
Crude oil – swap
3,000 Bbl/day
$91.77
WTI – NYMEX
Oct’14 – Dec’14
Crude oil – collar
4,000 Bbl/day
$90.00-96.08
WTI – NYMEX
Jan’15 – Dec’15
Crude oil – swap
1,000 Bbl/day
$95.00
WTI – NYMEX
Oct’14 – Dec’14
Natural gas – swap
80,000 MMBtu/day
$4.24
NYMEX (HH)
Oct’14 – Dec’14
Natural gas – collar
10,000 MMBtu/day
$3.75-4.37
NYMEX (HH)

The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
 
 
Derivative Assets
 
 
Fair Value
 
Balance Sheet Location
September 30,
2014
 
December 31,
2013
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
Current
Current derivative asset
$
4,047

 
$
515

Long-term
Non-current derivative asset
658

 

Total derivative assets
 
$
4,705

 
$
515

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

 
$
5,561

Long-term
Non-current derivative liabilities

 

Total derivative liabilities
 
$

 
$
5,561


If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our Unaudited Condensed Consolidated Balance Sheets.

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

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

16



Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
Derivatives in Cash Flow Hedging
Relationships
Amount of Gain or (Loss) Recognized in
Accumulated OCI on Derivative (Effective Portion)
(1)
 
2014
 
2013
 
(In thousands)
Commodity derivatives
$

 
$
(963
)
_______________________
(1) Net of taxes.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the three months ended September 30:
 
Derivative Instrument
Location of Gain or (Loss) Reclassified 
from Accumulated OCI into Income
& Location of Gain or (Loss) Recognized in Income
Amount of Gain or (Loss)
Reclassified from Accumulated
OCI into Income (1)
 
Amount of Gain or (Loss)
Recognized in Income (2)
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands)
Commodity derivatives
Oil and natural gas revenue
$

 
$
(3,210
)
 
$

 
$

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

 

 

 
(252
)
Total
 
$

 
$
(3,210
)
 
$

 
$
(252
)
 _______________________
(1)
Effective portion of gain (loss).
(2)
Ineffective portion of gain (loss).

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the three months ended September 30:
Derivatives Not Designated as Hedging
Instruments
Location of Gain or (Loss)
Recognized in Income on
Derivative
Amount of Gain or (Loss) Recognized in
Income on Derivative
 
 
2014
 
2013
 
 
(In thousands)
Commodity derivatives
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (1)
$
19,841

 
$
(13,508
)
Total
 
$
19,841

 
$
(13,508
)
_______________________
(1)
Amounts settled during the 2014 and 2013 periods include losses of $1.0 million and $2.4 million, respectively.

Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (cash flow hedges) for the nine months ended September 30:
 
Derivative Instrument
Location of Gain or (Loss) Reclassified 
from Accumulated OCI into Income
& Location of Gain or (Loss) Recognized in Income
Amount of Gain or (Loss)
Reclassified from Accumulated
OCI into Income (1)
 
Amount of Gain or (Loss)
Recognized in Income (2)
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands)
Commodity derivatives
Oil and natural gas revenue
$

 
$
(202
)
 
$

 
$

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

 

 

 
116

Total
 
$

 
$
(202
)
 
$

 
$
116

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

17



Effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Income (derivatives not designated as hedging instruments) for the nine months ended September 30:
Derivatives Not Designated as Hedging
Instruments
Location of Gain or (Loss)
Recognized in Income on
Derivative
Amount of Gain or (Loss) Recognized in
Income on Derivative
 
 
2014
 
2013
 
 
(In thousands)
Commodity derivatives
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (1)
$
(9,234
)
 
$
(3,456
)
Total
 
$
(9,234
)
 
$
(3,456
)
_______________________
(1)
Amounts settled during the 2014 and 2013 periods include losses of $19.0 million and $1.6 million, respectively.

NOTE 10 – FAIR VALUE MEASUREMENTS

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

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

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

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

The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments. We corroborate these inputs based on recent transactions and broker quotes and compare the fair value with actual settlements.

The following tables set forth our recurring fair value measurements:
 
September 30, 2014
 
Level 2
 
Level 3
 
Gross Amounts
 
Effect of Netting
 
Net Amounts Presented
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
Assets
$
4,114

 
$
630

 
$
4,744

 
$
(39
)
 
$
4,705

Liabilities

 
(39
)
 
(39
)
 
39

 

 
$
4,114

 
$
591

 
$
4,705

 
$

 
$
4,705

 
December 31, 2013
 
Level 2
 
Level 3
 
Gross Amounts
 
Effect of Netting
 
Net Amounts Presented
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
Assets
$
1,978

 
$
20

 
$
1,998

 
$
(1,483
)
 
$
515

Liabilities
(4,429
)
 
(2,615
)
 
(7,044
)
 
1,483

 
(5,561
)
 
$
(2,451
)
 
$
(2,595
)
 
$
(5,046
)
 
$

 
$
(5,046
)


18


All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties.

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

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

The following tables are reconciliations of our level 3 fair value measurements: 
 
Commodity Collars
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Beginning of period
$
(6,081
)
 
$
1,446

 
$
(2,595
)
 
$
(595
)
Total gains or losses (realized and unrealized):
 
 
 
 
 
 
 
Included in earnings (1)
5,785

 
(3,949
)
 
(2,043
)
 
(2,544
)
Included in other comprehensive income (loss)

 
(119
)
 

 
(119
)
Settlements
887

 

 
5,229

 
636

End of period
$
591

 
$
(2,622
)
 
$
591

 
$
(2,622
)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period
$
6,672

 
$
(3,949
)
 
$
3,186

 
$
(1,908
)
_______________________
(1)
Commodity collars are reported in the Unaudited Condensed Consolidated Statements of Income in oil and natural gas revenues (for cash flow hedges) and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively.

The following table provides quantitative information about our Level 3 unobservable inputs at September 30, 2014:
Commodity (1)
Fair Value
Valuation Technique
Unobservable Input
Range
 
(In thousands)
 
 
 
Oil collars
$
630

Discounted cash flow
Forward commodity price curve
$0.14 - $3.61
Natural gas collar
$
(39
)
Discounted cash flow
Forward commodity price curve
$0.00 - $0.16
 _______________________
(1)
The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Based on our valuation at September 30, 2014, we determined that risk of non-performance by our counterparties was immaterial.


19


Fair Value of Other Financial Instruments

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

At September 30, 2014, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement has historically approximated its fair value and at September 30, 2014 was $30.8 million. This debt would be classified as Level 2.

The carrying amounts of long-term debt, net of unamortized discount, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 were $646.0 million and $645.7 million, respectively. We estimated the fair value of these Notes using quoted marked prices at September 30, 2014 and December 31, 2013 which were $655.8 million and $688.2 million, respectively. These Notes would be classified as Level 2.

Fair Value of Non-Financial Instruments

The initial measurement of AROs at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant, and equipment. Significant Level 3 inputs used in the calculation of AROs include plugging costs and remaining reserve lives. A reconciliation of the Company’s AROs is presented in Note 6 – Asset Retirement Obligations.

NOTE 11 – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

Changes in accumulated other comprehensive income (loss) by component, net of tax, for the three months ended September 30, 2013 are as follows:
 
Net Gains (Losses) on Cash Flow Hedges
 
(In thousands)
Balance at July 1:
$
1,709

Other comprehensive loss before reclassification
(4,797
)
Amounts reclassified from accumulated other comprehensive income
2,125

New current-period other comprehensive loss
(2,672
)
Balance at September 30:
$
(963
)

Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the three months ended September 30, 2013 are as follows:
 
Amount
 
Affected Line Item in the Statement Where Net Income is Presented
 
(In thousands)
 
 
Net gains (loss) on cash flow hedges
 
 
 
Commodity derivatives
$
(3,210
)
 
Oil and natural gas revenues
Commodity derivatives
(252
)
 
Loss on derivatives not designated as hedges and hedge ineffectiveness, net
 
(3,462
)
 
Total before tax
 
1,337

 
Tax expense
Total reclassification for the period
$
(2,125
)
 
Net of tax

20



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

Other comprehensive loss before reclassification
(8,617
)
Amounts reclassified from accumulated other comprehensive income
67

New current-period other comprehensive loss
(8,550
)
Balance at September 30:
$
(963
)

Amounts reclassified from accumulated other comprehensive income (loss) into the Unaudited Condensed Consolidated Statements of Income for the nine months ended September 30, 2013 are as follows:
 
Amount
 
Affected Line Item in the Statement Where Net Income is Presented
 
(In thousands)
 
 
Net gains (loss) on cash flow hedges
 
 
 
Commodity derivatives
$
(202
)
 
Oil and natural gas revenues
Commodity derivatives
116

 
Gain on derivatives not designated as hedges and hedge ineffectiveness, net
 
(86
)
 
Total before tax
 
19

 
Tax expense
Total reclassification for the period
$
(67
)
 
Net of tax


21


NOTE 12 – INDUSTRY SEGMENT INFORMATION

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

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

We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. Our oil and natural gas production outside the United States is not significant.

The following table provides certain information about the operations of each of our segments:
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(In thousands)
 
Revenues:
 
 
 
 
 
 
 
 
Oil and natural gas
$
188,471

 
$
157,320

 
$
575,176

 
$
475,728

 
 
 
 
 
 
 
 
 
 
Contract drilling
147,866

 
119,105

 
407,905

 
357,118

 
Elimination of inter-segment revenue
(27,214
)
 
(18,458
)
 
(66,375
)
 
(43,938
)
 
Contract drilling net of inter-segment revenue
120,652

 
100,647

 
341,530

 
313,180

 
 
 
 
 
 
 
 
 
 
Gas gathering and processing
113,467

 
99,007

 
350,181

 
272,073

 
Elimination of inter-segment revenue
(21,616
)
 
(23,198
)
 
(72,494
)
 
(68,252
)
 
Gas gathering and processing net of inter-segment revenue
91,851

 
75,809

 
277,687

 
203,821

 
 
 
 
 
 
 
 
 
 
Total revenues
$
400,974

 
$
333,776

 
$
1,194,393

 
$
992,729

 
Operating income:

 

 

 

 
Oil and natural gas
$
69,597

 
$
50,887

 
$
240,239

 
$
173,945

 
Contract drilling
31,365

 
24,257

 
83,311

 
72,030

 
Gas gathering and processing
3,021

 
3,938

 
9,549

 
7,613

 
Total operating income (1)
103,983

 
79,082

 
333,099

 
253,588

 
General and administrative
(10,172
)
 
(9,936
)
 
(30,409
)
 
(28,288
)
 
Gain (loss) on disposition of assets
(529
)
 
4,345

 
9,092

 
7,744

 
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net
19,841

 
(13,760
)
 
(9,234
)
 
(3,340
)
 
Interest expense, net
(4,280
)
 
(3,625
)
 
(12,201
)
 
(11,777
)
 
Other
(68
)
 
(14
)
 
3

 
(171
)
 
Income before income taxes
$
108,775

 
$
56,092

 
$
290,350

 
$
217,756

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


22


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Unit Corporation

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

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2013, and the related consolidated statements of income, shareholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 25, 2014, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2013, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
/s/ PricewaterhouseCoopers LLP
 
Tulsa, Oklahoma
November 4, 2014


23


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

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

General;
Business Outlook;
Executive Summary;
Financial Condition and Liquidity;
New Accounting Pronouncements; and
Results of Operations.

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

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

General

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

Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.
Contract Drilling – carried out by our subsidiary Unit Drilling Company and its subsidiaries. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.
Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.

Business Outlook

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

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

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

Executive Summary

Oil and Natural Gas

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


24


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

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

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

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

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

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

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

Contract Drilling

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

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

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

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

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

25


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

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

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

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

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

Mid-Stream

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

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

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

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

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

26


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

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

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

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

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

Financial Condition and Liquidity

Summary

Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreement. The principal factors determining the amount of our cash flow are:
 
the quantity of natural gas, oil, and NGLs we produce;
the prices we receive for our natural gas, oil, and NGLs production;
the demand for and the dayrates we receive for our drilling rigs; and
the fees and margins we obtain from our natural gas gathering and processing contracts.

 
Nine Months Ended September 30,
 
%
Change
 
2014
 
2013
 
 
(In thousands except percentages)
Net cash provided by operating activities
$
549,527

 
$
500,961

 
10
%
Net cash used in investing activities
$
(636,761
)
 
$
(422,658
)
 
51
%
Net cash provided by (used in) financing activities
$
69,536

 
$
(77,536
)
 
190
%
Net increase (decrease) in cash and cash equivalents
$
(17,698
)
 
$
767

 
 

Cash Flows from Operating Activities

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

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


27


Cash Flows from Investing Activities

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

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

Cash Flows from Financing Activities

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

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

The following is a summary of certain financial information as of September 30, 2014 and 2013 and for the nine months ended September 30, 2014 and 2013:
 
September 30,
 
%
Change
 
2014
 
2013
 
 
(In thousands except percentages)
Working capital
$
(131,212
)
 
$
(48,080
)
 
(173
)%
Long-term debt
$
676,843

 
$
645,584

 
5
 %
Shareholders’ equity
$
2,367,500

 
$
2,116,945

 
12
 %
Ratio of long-term debt to total capitalization
22
%
 
23
%
 
 
Net income
$
178,827

 
$
133,445

 
34
 %


28


The following table summarizes certain operating information:
 
Nine Months Ended
 
 
 
September 30,
 
%
Change
 
2014
 
2013
 
Oil and Natural Gas:
 
 
 
 
 
Oil production (MBbls)
2,801

 
2,470

 
13
 %
NGLs production (MBbls)
3,376

 
2,758

 
22
 %
Natural gas production (MMcf)
43,424

 
42,411

 
2
 %
Average oil price per barrel received
$92.44
 
$95.20
 
(3
)%
Average oil price per barrel received excluding derivatives
$96.34
 
$95.49
 
1
 %
Average NGLs price per barrel received
$33.05
 
$30.87
 
7
 %
Average NGLs price per barrel received excluding derivatives
$33.05
 
$30.87
 
7
 %
Average natural gas price per mcf received
$3.99
 
$3.35
 
19
 %
Average natural gas price per mcf received excluding derivatives
$4.17
 
$3.38
 
23
 %
Contract Drilling:
 
 
 
 
 
Average number of our drilling rigs in use during the period
73.5

 
65.0

 
13
 %
Total number of drilling rigs owned at the end of the period
119

 
124

 
(4
)%
Average dayrate
$19,876
 
$19,651
 
1
 %
Mid-Stream:
 
 
 
 
 
Gas gathered—Mcf/day
316,658

 
308,645

 
3
 %
Gas processed—Mcf/day
160,373

 
137,725

 
16
 %
Gas liquids sold—gallons/day
748,805

 
505,584

 
48
 %
Number of natural gas gathering systems
38

 
39

 
(3
)%
Number of processing plants
14

 
15

 
(7
)%

Working Capital

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

Oil and Natural Gas Operations

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

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

29



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

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

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

Contract Drilling Operations

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

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

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

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

Mid-Stream Operations

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

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

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

Our Credit Agreement and Senior Subordinated Notes

Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount we can borrow is the lesser of the amount we elect (from time to time) as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed the maximum credit agreement amount of $900.0 million. Our current commitment amount is $500.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. The fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. The credit agreement matures as of September 13, 2016. In connection with the most recent amendment of the credit agreement, we paid $1.5 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. At September 30, 2014 and October 24, 2014, borrowings were $30.8 million and $81.3 million, respectively.

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 approved an increase in our borrowing base to $900.0 million from $800.0 million. There was no additional change to the borrowing base with the October 2014 redetermination. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that in any event cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at anytime, without a premium or penalty.

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 September 30, 2014, we were in compliance with the covenants contained in the credit agreement.

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

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

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

At any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011 Indenture also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of September 30, 2014.

Capital Requirements

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


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

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

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

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

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

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

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

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

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

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

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

33


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

Contractual Commitments

At September 30, 2014, we had certain contractual obligations including the following:
 
Payments Due by Period
 
Total
 
Less
Than
1 Year
 
2-3
Years
 
4-5
Years
 
After
5 Years
 
(In thousands)
Long-term debt (1)
$
968,373