10-Q 1 unt-2017331x10q.htm 10-Q Document

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2017
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]
image2a01a07.jpg
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
73-1283193
(State or other jurisdiction of incorporation)
(I.R.S. Employer Identification No.)
8200 South Unit Drive, Tulsa, Oklahoma
74132
(Address of principal executive offices)
(Zip Code)
(918) 493-7700
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [x]            No [  ]                                                     
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [x]            No [  ]                                                     
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [ ]    Accelerated filer [ x ]    Non-accelerated filer (Do not check if a smaller reporting company) [  ]
Smaller reporting company [  ]    Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected no to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    [ ]        

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]            No [x]                                                     
As of April 21, 2017, 52,823,702 shares of the issuer's common stock were outstanding.



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

1


Forward-Looking Statements

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

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

2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
 
March 31,
2017
 
December 31,
2016
 
 
(In thousands except share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
8,470

 
$
893

Accounts receivable, net of allowance for doubtful accounts of $3,773 at both March 31, 2017 and December 31, 2016, respectively
 
81,752

 
83,954

Materials and supplies
 
3,267

 
3,340

Current income tax receivable
 
106

 
99

Current deferred tax asset (Note 8)
 

 
25,211

Prepaid expenses and other
 
7,328

 
7,699

Total current assets
 
100,923

 
121,196

Property and equipment:
 
 
 
 
Oil and natural gas properties on the full cost method:
 
 
 
 
Proved properties
 
5,461,119

 
5,446,305

Unproved properties not being amortized
 
328,266

 
314,867

Drilling equipment
 
1,572,335

 
1,565,268

Gas gathering and processing equipment
 
707,786

 
705,859

Saltwater disposal systems
 
60,746

 
60,638

Corporate land and building
 
59,070

 
59,066

Transportation equipment
 
29,562

 
32,842

Other
 
50,610

 
48,590

 
 
8,269,494

 
8,233,435

Less accumulated depreciation, depletion, amortization, and impairment
 
5,996,098

 
5,952,330

Net property and equipment
 
2,273,396

 
2,281,105

Goodwill
 
62,808

 
62,808

Non-current derivative asset (Note 10)
 

 
377

Other assets
 
15,423

 
13,817

Total assets
 
$
2,452,550

 
$
2,479,303


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

 
 
March 31,
2017
 
December 31,
2016
 
 
(In thousands except share amounts)
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
75,158

 
$
88,793

Accrued liabilities (Note 5)
 
46,412

 
39,651

Current derivative liability (Note 10)
 
5,604

 
21,564

Current portion of other long-term liabilities (Note 6)
 
15,045

 
14,907

Total current liabilities
 
142,219

 
164,915

Long-term debt less debt issuance costs (Note 6)
 
790,653

 
800,917

Non-current derivative liability (Note 10)
 
108

 
415

Other long-term liabilities (Note 6)
 
101,877

 
103,064

Deferred income taxes (Note 8)
 
204,647

 
215,922

Commitments and contingencies (Note 12)
 

 

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

 

Common stock, $.20 par value, 175,000,000 shares authorized, 52,018,042 and 51,494,318 shares issued as of March 31, 2017 and December 31, 2016, respectively
 
10,111

 
10,016

Capital in excess of par value
 
505,452

 
502,500

Retained earnings
 
697,483

 
681,554

Total shareholders’ equity
 
1,213,046

 
1,194,070

Total liabilities and shareholders’ equity
 
$
2,452,550

 
$
2,479,303


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


4


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
 
 
(In thousands except per share amounts)
Revenues:
 
 
 
 
Oil and natural gas
 
$
87,598

 
$
58,274

Contract drilling
 
37,185

 
38,710

Gas gathering and processing
 
50,941

 
39,200

Total revenues
 
175,724

 
136,184

Expenses:
 
 
 
 
Operating costs:
 
 
 
 
Oil and natural gas
 
29,204

 
33,346

Contract drilling
 
29,227

 
28,098

Gas gathering and processing
 
37,704

 
31,066

Total operating costs
 
96,135

 
92,510

Depreciation, depletion, and amortization
 
46,932

 
55,590

Impairments
 

 
37,829

General and administrative
 
8,954

 
8,611

Gain on disposition of assets
 
(824
)
 
(192
)
Total operating expenses
 
151,197

 
194,348

Income (loss) from operations
 
24,527

 
(58,164
)
Other income (expense):
 
 
 
 
Interest, net
 
(9,396
)
 
(9,617
)
Gain on derivatives
 
14,731

 
10,929

Other, net
 
3

 
(15
)
Total other income (expense)
 
5,338

 
1,297

Income (loss) before income taxes
 
29,865

 
(56,867
)
Income tax expense (benefit):
 
 
 
 
Deferred
 
13,936

 
(15,718
)
Total income taxes
 
13,936

 
(15,718
)
Net income (loss)
 
$
15,929

 
$
(41,149
)
Net income (loss) per common share:
 
 
 
 
Basic
 
$
0.32

 
$
(0.83
)
Diluted
 
$
0.31

 
$
(0.83
)

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


5


UNIT CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
 
 
(In thousands)
OPERATING ACTIVITIES:
 
 
 
 
Net income (loss)
 
$
15,929

 
$
(41,149
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion, and amortization
 
46,932

 
55,590

Impairments (Note 2)
 

 
37,829

Amortization of debt issuance costs and debt discount
 
536

 
526

Gain on derivatives
 
(14,731
)
 
(10,929
)
Cash (payments) receipts on derivatives settled
 
(1,159
)
 
7,140

Deferred tax expense (benefit)
 
13,936

 
(15,718
)
Gain on disposition of assets
 
(824
)
 
(469
)
Employee stock compensation plans
 
3,704

 
4,798

Other, net
 
626

 
(1,269
)
Changes in operating assets and liabilities increasing (decreasing) cash:
 
 
 
 
Accounts receivable
 
(1,900
)
 
10,003

Accounts payable
 
(7,735
)
 
11,013

Material and supplies
 
73

 
262

Accrued liabilities
 
9,832

 
10,702

Other, net
 
433

 
2,384

Net cash provided by operating activities
 
65,652

 
70,713

INVESTING ACTIVITIES:
 
 
 
 
Capital expenditures
 
(37,636
)
 
(76,035
)
Producing properties and other acquisitions
 
(7,508
)
 

Proceeds from disposition of assets
 
16,116

 
38,380

Other
 

 
169

Net cash used in investing activities
 
(29,028
)
 
(37,486
)
FINANCING ACTIVITIES:
 
 
 
 
Borrowings under credit agreement
 
49,700

 
75,000

Payments under credit agreement
 
(60,500
)
 
(95,800
)
Payments on capitalized leases
 
(946
)
 
(910
)
Tax expense from stock compensation
 

 
(376
)
Book overdrafts
 
(17,301
)
 
(11,237
)
Net cash used in financing activities
 
(29,047
)
 
(33,323
)
Net increase (decrease) in cash and cash equivalents
 
7,577

 
(96
)
Cash and cash equivalents, beginning of period
 
893

 
835

Cash and cash equivalents, end of period
 
$
8,470

 
$
739

Supplemental disclosure of cash flow information:
 
 
 
 
Cash paid during the year for:
 
 
 
 
Interest paid (net of capitalized)
 
(2,389
)
 
(2,024
)
Income taxes
 

 

Changes in accounts payable and accrued liabilities related to purchases of property, plant, and equipment
 
(11,401
)
 
19,685

Non-cash reductions to oil and natural gas properties related to asset retirement obligations
 
912

 
28,417

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

6


UNIT CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PREPARATION AND PRESENTATION

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

The accompanying condensed consolidated financial statements are unaudited and do not include all the notes in our annual financial statements. This report should be read with the audited consolidated financial statements and notes in our Form 10-K, filed February 28, 2017, for the year ended December 31, 2016.

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 March 31, 2017 and December 31, 2016;
Statements of Operations for the three months ended March 31, 2017 and 2016; and
Statements of Cash Flows for the three months ended March 31, 2017 and 2016.

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 three months ended March 31, 2017 and 2016 are not necessarily indicative of the results to be realized for the full year of 2017, or that we realized for the full year of 2016.

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

NOTE 2 – OIL AND NATURAL GAS PROPERTIES
    
Full cost accounting rules require us to review the carrying value of our oil and natural gas properties at the end of each quarter. Under those rules, the maximum amount allowed as the carrying value is referred to as the ceiling. The ceiling is the sum of the present value (using a 10% discount rate) of the estimated future net revenues from our proved reserves (using the unescalated 12-month average price of our oil, NGLs, and natural gas), plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes. If the net book value of the oil, NGLs, and natural gas properties being amortized exceeds the full cost ceiling, the excess amount is charged to expense in the period during which the excess occurs, even if prices are depressed for only a short while. Once incurred, a write-down of oil and natural gas properties is not reversible.

During the first quarter of 2016, we had a non-cash ceiling test write-down of $37.8 million pre-tax ($23.5 million, net of tax). We did not have a non-cash ceiling test write-down for the first quarter of 2017.

NOTE 3 – DIVESTITURES

Oil and Natural Gas

We sold non-core oil and natural gas assets, net of related expenses, for $14.8 million during the first three months of 2017, compared to $37.4 million during the first three months of 2016. Proceeds from those sales reduced the net book value of our full cost pool with no gain or loss recognized.



7


NOTE 4 – EARNINGS (LOSS) PER SHARE

Information related to the calculation of earnings (loss) per share follows:
 
 
Earnings (Loss)
(Numerator)
 
Weighted
Shares
(Denominator)
 
Per-Share
Amount
 
 
(In thousands except per share amounts)
For the three months ended March 31, 2017
 
 
 
 
 
 
Basic earnings per common share
 
$
15,929

 
50,293

 
$
0.32

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

 
568

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

 
50,861

 
$
0.31

For the three months ended March 31, 2016
 
 
 
 
 
 
Basic loss per common share
 
$
(41,149
)
 
49,880

 
$
(0.83
)
Effect of dilutive stock options, restricted stock, and SARs
 

 

 

Diluted loss per common share
 
$
(41,149
)
 
49,880

 
$
(0.83
)

Due to the net loss for the three months ended March 31, 2016, approximately 235,000 weighted average shares related to stock options, restricted stock, and SARs were antidilutive and were excluded from the loss per share calculation above.

The following table shows the number of stock options and SARs (and their average exercise price) excluded because their option exercise prices were greater than the average market price of our common stock:
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
Stock options and SARs
 
199,755

 
261,270

Average exercise price
 
$
48.79

 
$
50.34


NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of:
 
 
March 31,
2017
 
December 31,
2016
 
 
(In thousands)
Interest payable
 
$
17,360

 
$
6,524

Lease operating expenses
 
10,627

 
10,075

Employee costs
 
8,562

 
15,394

Taxes
 
4,461

 
2,219

Third-party credits
 
2,458

 
2,998

Other
 
2,944

 
2,441

Total accrued liabilities
 
$
46,412

 
$
39,651

 

8


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

Long-Term Debt

Our long-term debt consisted of the following as of the dates indicated:
 
 
March 31,
2017
 
December 31,
2016
 
 
(In thousands)
Credit agreement with an average interest rate of 2.9% and 2.8% at March 31, 2017 and December 31, 2016, respectively
 
$
150,000

 
$
160,800

6.625% senior subordinated notes due 2021
 
650,000

 
650,000

Total principal amount
 
800,000

 
810,800

Less: unamortized discount
 
(2,665
)
 
(2,804
)
Less: debt issuance costs, net
 
(6,682
)
 
(7,079
)
Total long-term debt
 
$
790,653

 
$
800,917


Credit Agreement. On April 8, 2016, we amended our Senior Credit Agreement (credit agreement) which is scheduled to mature on April 10, 2020. Under the credit agreement, the amount we can borrow is the lesser of the amount we elect as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to exceed $875.0 million. Our elected commitment amount is $475.0 million. Our borrowing base is $475.0 million. We are charged a commitment fee of 0.50% on the amount available but not borrowed. That fee varies based on the amount borrowed as a percentage of the amount of the total borrowing base. We paid $1.0 million in origination, agency, syndication, and other related fees. We are amortizing these fees over the life of the credit agreement. With the new amendment, we pledged the following collateral: (a) 85% of the proved developed producing (discounted as present worth at 8%) total value of our oil and gas properties and (b) 100% of our ownership interest in our midstream affiliate, Superior Pipeline Company, L.L.C.

The borrowing base amount–which is subject to redetermination by the lenders on April 1st and October 1st of each year–is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. The April 2017 redetermination did not result in any changes. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 2.00% to 3.00% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in whole or in part at any time, without a premium or penalty. At March 31, 2017, we had $150.0 million of outstanding borrowings under our credit agreement.

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

The credit agreement prohibits, among other things:

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


9


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

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

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

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

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

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

As of March 31, 2017, we were in compliance with the credit agreement covenants.

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

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

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

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 March 31, 2017.


10


Other Long-Term Liabilities

Other long-term liabilities consisted of the following:
 
 
March 31,
2017
 
December 31,
2016
 
 
(In thousands)
Asset retirement obligation (ARO) liability
 
$
70,043

 
$
70,170

Capital lease obligations
 
18,008

 
18,918

Workers’ compensation
 
15,066

 
15,163

Separation benefit plans
 
5,149

 
4,943

Deferred compensation plan
 
4,924

 
4,578

Gas balancing liability
 
3,322

 
3,789

Other
 
410

 
410

 
 
116,922

 
117,971

Less current portion
 
15,045

 
14,907

Total other long-term liabilities
 
$
101,877

 
$
103,064


Estimated annual principal payments under the terms of debt and other long-term liabilities during the five successive twelve month periods beginning April 1, 2017 (and through 2022) are $15.0 million, $44.7 million, $8.9 million, $160.6 million, and $653.0 million, respectively.

Capital Leases

In 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 $3.7 million current portion of our capital lease obligations is included in current portion of other long-term liabilities and the non-current portion of $14.3 million is included in other long-term liabilities in the accompanying Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017. These capital leases are discounted using annual rates of 4.00%. Total maintenance and interest remaining related to these leases are $7.2 million and $1.7 million, respectively, at March 31, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their then fair market value.

Future payments required under the capital leases at March 31, 2017:
 
 
Amount
Beginning April 1,
 
(In thousands)
2017
 
$
6,168

2018
 
6,168

2019
 
6,168

2020
 
7,815

2021
 
579

Total future payments
 
26,898

Less payments related to:
 
 
Maintenance
 
7,213

Interest
 
1,677

Present value of future minimum payments
 
$
18,008



11


NOTE 7 – ASSET RETIREMENT OBLIGATIONS

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

The following table shows certain information about our AROs for the periods indicated:
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
 
 
(In thousands)
ARO liability, January 1:
 
$
70,170

 
$
98,297

Accretion of discount
 
785

 
879

Liability incurred
 
658

 
90

Liability settled
 
(630
)
 
(375
)
Liability sold (1)
 
(432
)
 
(9,950
)
Revision of estimates (2)
 
(508
)

(18,182
)
ARO liability, March 31:
 
70,043

 
70,759

Less current portion
 
3,243

 
3,499

Total long-term ARO
 
$
66,800

 
$
67,260

_______________________ 
(1)
We sold our interest in a number of non-core wells to unaffiliated third-parties during the first three months of 2017 and 2016, respectively.
(2)
Plugging liability estimates were revised in both 2017 and 2016 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments.

NOTE 8 – NEW ACCOUNTING PRONOUNCEMENTS

Intangibles—Goodwill and Other: Simplifying the Test for Goodwill Impairment. The FASB issued ASU 2017-04, to simplify the subsequent measurement of goodwill. The amendment eliminates Step 2 from the goodwill impairment test. This amendment will be effective prospectively for reporting periods beginning after December 31, 2019, and early adoption is permitted. We do not believe this ASU will have a material impact on our financial statements.

Business Combinations; Clarifying the Definition of a Business. The FASB issued ASU 2017-01, clarifying the definition of a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. For public companies, the amendments are effective for annual periods beginning after December 15, 2017. We are in the process of evaluating the impact these amendments will have on our financial statements.

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

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

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This guidance affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts).

12


The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, "Narrow-Scope Improvements and Practical Expedients," which provides clarifying guidance in certain areas and adds some practical expedients. Also in May 2016, the FASB issued ASU 2016-11, "Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting." This ASU rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities— Oil and Gas, effective on the adoption of Topic 606, Revenue from Contracts with Customers. In April 2016, the FASB issued ASU 2016-10, "Identifying Performance Obligations and Licensing," which amends the revenue guidance on identifying performance obligations and accounting for licenses of intellectual property. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We will adopt these amendments effective January 1, 2018. We have begun the identification and impact assessment of revenue within the scope of the guidance and are utilizing a bottom-up approach to analyze the impact of the new standard on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts. While we have not identified any material differences in the amount and timing of revenue recognition to date, our evaluation is not complete, and we have not reached a conclusion on the overall impacts of adopting Topic 606. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative effect adjustment to retained earnings at the date of adoption. We currently believe we will adopt the cumulative effect method.

Adopted Standards

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption of the amendments is permitted. The amendments will require current deferred tax assets to be combined with noncurrent deferred tax assets. We have adopted this ASU during the first quarter of 2017 on a prospective basis. Previously, we had a net current deferred tax asset which is now netted with our noncurrent deferred tax liability. Prior periods were not retrospectively adjusted.

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

NOTE 9 – STOCK-BASED COMPENSATION

For restricted stock awards and stock options, we had:
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
 
 
(In millions)
Recognized stock compensation expense
 
$
2.6

 
$
3.3

Capitalized stock compensation cost for our oil and natural gas properties
 
0.4

 
0.8

Tax benefit on stock based compensation
 
1.0

 
1.3


The remaining unrecognized compensation cost related to unvested awards at March 31, 2017 is approximately $19.8 million, of which $2.2 million is anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is one year.


13


Our Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as to non-employee directors. As of the date of this report, a total of 4,500,000 shares of the company's common stock was authorized for issuance to eligible participants under the amended plan with 2,000,000 shares being the maximum number of shares that can be issued as "incentive stock options."

We did not grant any SARs or stock options during either of the three month periods ending March 31, 2017 or 2016. The following table shows the fair value of restricted stock awards granted to employees and non-employee directors during the three month periods ending March 31, 2017 and 2016:

 
 
Three Months Ended
 
Three Months Ended
 
 
March 31, 2017
 
March 31, 2016
 
 
Time
Vested
 
Performance Vested
 
Time
Vested
 
Performance Vested
Shares granted:
 
 
 
 
 
 
 
 
Employees
 
461,799

 
152,373

 
486,578

 
152,373

Non-employee directors
 

 

 

 

 
 
461,799

 
152,373

 
486,578

 
152,373

Estimated fair value (in millions):(1)
 
 
 
 
 
 
 
 
Employees
 
$
11.4

 
$
4.0

 
$
2.6

 
$
0.8

Non-employee directors
 

 

 

 

 
 
$
11.4

 
$
4.0

 
$
2.6

 
$
0.8

Percentage of shares granted expected to be distributed:
 
 
 
 
 
 
 
 
Employees
 
94
%
 
105
%
 
94
%
 
52
%
Non-employee directors
 
N/A

 
N/A

 
N/A

 
N/A

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

The time vested restricted stock awards granted during the first three months of 2017 and 2016 are being recognized over a three year vesting period. During the first quarter of 2017 and 2016, there were two different performance vested restricted stock awards granted to certain executive officers. The first will cliff vest three years from the grant date based on the company's achievement of certain stock performance measures at the end of the term and will range from 0% to 200% of the restricted shares granted as performance shares. The second will vest, one-third each year, over a three year vesting period based on the company's achievement of cash flow to total assets (CFTA) performance measurement each year and will range from 0% to 200%. Based on a probability assessment of the selected performance criteria at March 31, 2017, the participants are estimated to receive 111% of the 2017, 132% of the 2016, and 27% of the 2015 performance based shares. The CFTA performance measurement at March 31, 2017 was assessed to vest at target or 100%. The total aggregate stock compensation expense and capitalized cost related to oil and natural gas properties for 2017 awards for the first three months of 2017 was $1.0 million.

NOTE 10 – DERIVATIVES

Commodity Derivatives

We have entered into various types of derivative transactions covering some of our projected natural gas and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production subject to a derivative contract are based, in part, on our view of current and future market conditions. As of March 31, 2017, our derivative transactions were comprised of the following hedges:

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



14


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

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

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

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

At March 31, 2017, we had the following derivatives outstanding:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Apr’17 – Oct'17
 
Natural gas – swap
 
70,000 MMBtu/day
 
$3.038
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – swap
 
60,000 MMBtu/day
 
$2.960
 
IF – NYMEX (HH)
Jan’18 – Dec'18
 
Natural gas – swap
 
20,000 MMBtu/day
 
$3.013
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – basis swap
 
20,000 MMBtu/day
 
$(0.215)
 
IF – NYMEX (HH)
Jan’18 – Mar'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Nov’18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Apr’17 – Oct'17
 
Natural gas – collar
 
20,000 MMBtu/day
 
$2.88 - $3.10
 
IF – NYMEX (HH)
Apr'17 – Oct'17
 
Natural gas – three-way collar
 
15,000 MMBtu/day
 
$2.50 - $2.00 - $3.32
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – three-way collar
 
25,000 MMBtu/day
 
$2.90 - $2.30 - $3.59
 
IF – NYMEX (HH)
Jan'18 – Mar'18
 
Natural gas – three-way collar
 
60,000 MMBtu/day
 
$3.29 - $2.63 - $4.07
 
IF – NYMEX (HH)
Apr'18 – Dec'18
 
Natural gas – three-way collar
 
20,000 MMBtu/day
 
$3.00 - $2.50 - $3.51
 
IF – NYMEX (HH)
Apr’17 – Dec'17
 
Crude oil – three-way collar
 
3,750 Bbl/day
 
$49.79 - $39.58 - $60.98
 
WTI – NYMEX



15


The following tables present the fair values and locations of the derivative transactions recorded in our Unaudited Condensed Consolidated Balance Sheets:
 
 
 
 
Derivative Assets
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
March 31,
2017
 
December 31,
2016
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative asset
 
$

 
$

Long-term
 
Non-current derivative asset
 

 
377

Total derivative assets
 
 
 
$

 
$
377


 
 
 
 
Derivative Liabilities
 
 
 
 
Fair Value
 
 
Balance Sheet Location
 
March 31,
2017
 
December 31,
2016
 
 
 
 
(In thousands)
Commodity derivatives:
 
 
 
 
 
 
Current
 
Current derivative liability
 
$
5,604

 
$
21,564

Long-term
 
Non-current derivative liability
 
108

 
415

Total derivative liabilities
 
 
 
$
5,712

 
$
21,979


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

Following is the effect of derivative instruments on the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31:
Derivatives Instruments
 
Location of Gain Recognized in
Income on Derivative
 
Amount of Gain Recognized in Income on Derivative
 
 
 
 
2017
 
2016
 
 
 
 
(In thousands)
Commodity derivatives
 
Gain on derivatives (1)
 
$
14,731

 
$
10,929

Total
 
 
 
$
14,731

 
$
10,929

_______________________
(1)
Amounts settled during the 2017 and 2016 periods include a loss of $1.2 million and a gain of $7.1 million, respectively.

NOTE 11 – FAIR VALUE MEASUREMENTS

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

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

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

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


16


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

The following tables set forth our recurring fair value measurements:
 
 
March 31, 2017
 
 
Level 2
 
Level 3
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
Assets
 
$
778

 
$
1,779

 
$
(2,557
)
 
$

Liabilities
 
(5,888
)
 
(2,381
)
 
2,557

 
(5,712
)
 
 
$
(5,110
)
 
$
(602
)
 
$

 
$
(5,712
)
 
 
December 31, 2016
 
 
Level 2
 
Level 3
 
 
Effect
of Netting
 
Net Amounts Presented
 
 
(In thousands)
Financial assets (liabilities):
 
 
 
 
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
 
 
 
 
Assets
 
$
878

 
$
43

 
 
$
(544
)
 
$
377

Liabilities
 
(15,358
)
 
(7,165
)
 
 
544

 
(21,979
)
 
 
$
(14,480
)
 
$
(7,122
)
 
 
$

 
$
(21,602
)

All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post cash collateral with our counterparties and no collateral has been posted as of March 31, 2017.

We used the following methods and assumptions 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 and three-way collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements.


17


The following table is a reconciliation of our level 3 fair value measurements: 
 
 
Net Derivatives
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
 
 
(In thousands)
Beginning of period
 
$
(7,122
)
 
$
9,094

Total gains or losses (realized and unrealized):
 
 
 
 
Included in earnings (1)
 
5,903

 
5,988

Settlements
 
617

 
(5,099
)
End of period
 
$
(602
)
 
$
9,983

Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period
 
$
6,520

 
$
889

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

The following table provides quantitative information about our Level 3 unobservable inputs at March 31, 2017:
Commodity (1)
 
Fair Value
 
Valuation Technique
 
Unobservable Input
 
Range
 
 
(In thousands)
 
 
 
 
 
 
Oil three-way collars
 
$
1,378

 
Discounted cash flow
 
Forward commodity price curve
 
($1.75) - $3.85
Natural gas collar
 
$
(1,136
)
 
Discounted cash flow
 
Forward commodity price curve
 
($0.57) - $0.15
Natural gas three-way collars
 
$
(844
)
 
Discounted cash flow
 
Forward commodity price curve
 
($0.54) - $0.55
 _______________________
(1)
The commodity contracts detailed in this category include non-exchange-traded crude oil and natural gas collars and three-way collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be paid or received within the settlement period.

Based on our valuation at March 31, 2017, we determined that risk of non-performance by our counterparties was immaterial.

Fair Value of Other Financial Instruments

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

At March 31, 2017, the carrying values on the Unaudited Condensed Consolidated Balance Sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature.

Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement approximates its fair value and at March 31, 2017 and December 31, 2016 was $150.0 million and $160.8 million, respectively. This debt would be classified as Level 2.

The carrying amounts of long-term debt, net of unamortized discount and debt issuance costs, associated with the Notes reported in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016 were $640.7 million and $640.1 million, respectively. We estimate the fair value of the Notes using quoted marked prices at March 31, 2017 and December 31, 2016 was $640.3 million and $649.9 million, respectively. The Notes would be classified as Level 2.


18


Fair Value of Non-Financial Instruments

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

NOTE 12 – COMMITMENTS AND CONTINGENCIES

We lease office space or yards in Edmond and Oklahoma City, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Canonsburg, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $2.7 million, $0.8 million, $0.2 million, $0.2 million, and $0.1 million in twelve month periods beginning April 1, 2017 (and through the end of 2021), respectively. Total rent expense incurred was $2.1 million and $3.3 million for the first quarter of 2017 and 2016, respectively.

In 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of seven years. Estimated annual capital lease payments under the terms during the five successive twelve month periods beginning April 1, 2017 (and through the end of 2021) are $6.2 million, $6.2 million, $6.2 million, $7.8 million, and $0.6 million. Total maintenance and interest remaining related to these leases are $7.2 million and $1.7 million, respectively at March 31, 2017. Annual payments, net of maintenance and interest, average $4.1 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the assets at 10% of their fair market value at that time.

The employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. These repurchases in any one year are limited to 20% of the units outstanding. We did not have any repurchases in the first quarter of 2017 or 2016.

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

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

For the next twelve months, we have committed to purchase approximately $4.2 million of new drilling rig components. We have also committed to paying $1.3 million for Enterprise Resource Planning software over the next year.

NOTE 13 – INDUSTRY SEGMENT INFORMATION

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

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


19


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

The following tables provide certain information about the operations of each of our segments:
 
 
Three Months Ended March 31, 2017
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
87,598

 
$

 
$

 
$

 
$

 
$
87,598

Contract drilling
 

 
37,185

 

 

 

 
37,185

Gas gathering and processing
 

 

 
66,464

 

 
(15,523
)
 
50,941

Total revenues
 
87,598

 
37,185

 
66,464

 

 
(15,523
)
 
175,724

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

 

 

 

 
(1,122
)
 
29,204

Contract drilling
 

 
29,227

 

 

 

 
29,227

Gas gathering and processing
 

 

 
52,105

 

 
(14,401
)
 
37,704

Total operating costs
 
30,326

 
29,227

 
52,105

 

 
(15,523
)
 
96,135

Depreciation, depletion, and amortization
 
21,526

 
12,847

 
10,818

 
1,741

 

 
46,932

Total expenses
 
51,852

 
42,074

 
62,923

 
1,741

 
(15,523
)
 
143,067

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

 
(4,889
)
 
3,541

 
(1,741
)
 

 
 
General and administrative expense
 

 

 

 
(8,954
)
 

 
(8,954
)
Gain on disposition of assets
 
9

 
7

 

 
808

 

 
824

Gain on derivatives
 

 

 

 
14,731

 

 
14,731

Interest expense, net
 

 

 

 
(9,396
)
 

 
(9,396
)
Other
 

 

 

 
3

 

 
3

Income (loss) before income taxes
 
$
35,755

 
$
(4,882
)
 
$
3,541

 
$
(4,549
)
 
$

 
$
29,865

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

20



 
 
Three Months Ended March 31, 2016
 
 
Oil and Natural Gas
 
Contract Drilling
 
Mid-stream
 
Other
 
Eliminations
 
Total Consolidated
 
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
$
58,274

 
$

 
$

 
$

 
$

 
$
58,274

Contract drilling
 

 
38,710

 

 

 

 
38,710

Gas gathering and processing
 

 

 
49,045

 

 
(9,845
)
 
39,200

Total revenues
 
58,274

 
38,710

 
49,045

 

 
(9,845
)
 
136,184

Expenses:
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas
 
34,804

 

 

 

 
(1,458
)
 
33,346

Contract drilling
 

 
28,098

 

 

 

 
28,098

Gas gathering and processing
 

 

 
39,453

 

 
(8,387
)
 
31,066

Total operating costs
 
34,804

 
28,098

 
39,453

 

 
(9,845
)
 
92,510

Depreciation, depletion, and amortization
 
31,832

 
12,195

 
11,459

 
104

 

 
55,590

Impairments
 
37,829

 

 

 

 

 
37,829

Total expenses
 
104,465

 
40,293

 
50,912

 
104

 
(9,845
)
 
185,929

Total operating loss(1)
 
(46,191
)
 
(1,583
)
 
(1,867
)
 
(104
)
 

 
 
General and administrative expense
 

 

 

 
(8,611
)
 

 
(8,611
)
Gain (loss) on disposition of assets
 

 
494

 
(302
)
 

 

 
192

Gain on derivatives
 

 

 

 
10,929

 

 
10,929

Interest expense, net
 

 

 

 
(9,617
)
 

 
(9,617
)
Other
 

 

 

 
(15
)
 

 
(15
)
Loss before income taxes
 
$
(46,191
)
 
$
(1,089
)
 
$
(2,169
)
 
$
(7,418
)
 
$

 
$
(56,867
)
_______________________
(1)
Operating loss 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 on derivatives, interest expense, other income (loss), or income taxes.



21


NOTE 14 – SUBSEQUENT EVENTS

On April 3, 2017, we completed the acquisition of certain oil and natural gas assets from an unrelated third party. The acquisition includes approximately 47 proved developed producing wells and 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The purchase price was approximately $57.0 million in cash plus the conveyance of 180 net leasehold acres we held in McClain County, Oklahoma. This acquisition is subject to certain post-closing adjustments. The effective date of this acquisition is January 1, 2017.

On April 4, 2017, we entered into a Distribution Agreement (the Agreement) with a sales agent, under which we may offer and sell, from time to time, through the sales agent shares of our common stock, par value $0.20 per share (the Shares), up to an aggregate offering price of $100.0 million. We intend to use the net proceeds from these sales to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.
 
Under the Agreement, the sales agent may sell the Shares by methods deemed to be an “at-the-market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended (the Securities Act), including sales made directly on the NYSE, on any other existing trading market for the Shares or to or through a market maker. In addition, under the Agreement, the sales agent may sell the Shares by any other method permitted by law, including in privately negotiated transactions. Subject to the terms and conditions of the Agreement, the sales agent will use commercially reasonable efforts, consistent with its normal trading and sales practices and applicable state and federal law, rules and regulations and the rules of the NYSE, to sell the Shares from time to time, based on our instructions (including any price, time or size limits or other customary parameters or conditions that we may impose).
 
We are not obligated to make any sales of the Shares under the Agreement. The offering of Shares under the Agreement will terminate on the earlier of (1) the sale of all of the Shares subject to the Agreement or (2) the termination of the Agreement by the sales agent or us. We will pay the sales agent a commission of 2.0% of the gross sales price per share sold and have agreed to provide the sales agent with customary indemnification and contribution rights.
 
As of April 21, 2017, we sold 770,660 shares of our common stock resulting in net proceeds of approximately $18.3 million.







22


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

Management’s Discussion and Analysis (MD&A) provides you with an understanding of our operating results and financial condition by focusing on changes in certain key measures from year to year or period to period. 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 information in our most recent Annual Report on Form 10-K in connection with your review of the information below as well as our unaudited condensed consolidated financial statements and related notes.

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 the results of our 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. This segment contracts to drill onshore oil and natural gas wells for others and for our oil and natural gas segment.
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 oil and natural gas segment.

Business Outlook

As discussed in other parts of this report, our success depends, to a large degree, on the prices we receive for our oil and natural gas production, the demand for oil and natural gas, as well as, the demand for our drilling rigs which, in turn, influences the amounts we can charge for those drilling rigs. While our operations are located within the United States, events outside the United States affect us and our industry.

Deteriorating commodity prices worldwide during the past several years brought about significant and adverse changes to our industry and us. These lower prices caused us (and other oil and gas companies) to reduce, for a period of time, our oil and natural gas segment's drilling activity. Industry wide reductions in drilling activity and spending for extended periods also tends to reduce the rates for and the number of our drilling rigs that we are able to work. In addition, sustained lower commodity prices impact the liquidity condition of some of our industry partners and customers, which, in turn, could limit their ability to meet their financial obligations to us.

During 2016, commodity prices began to improve and we are starting to see signs of improvement. In the fourth quarter of 2016, our oil and natural gas segment began using two of our contract drilling rigs and has continued using them during the first quarter of 2017. Our contract drilling segment completed the construction and contracted the ninth BOSS drilling rig in the fourth quarter of 2016 and started construction of the tenth BOSS drilling rig during the first quarter of 2017 which will be completed late in the second quarter. Our drilling rig segment's rig utilization has increased from 15 drilling rigs working as of March 31, 2016 to 29 drilling rigs working as of March 31, 2017. The extent and duration of this improvement remains uncertain.

23


The previous reduction in oil, NGLs, and natural gas prices has had a number of consequences for us (although, as noted, we are starting to see some improvements as well). Below are some of the recent impacts:

We incurred non-cash ceiling test write-downs in the first nine months of 2016 of $161.6 million ($100.6 million net of tax). We did not have a write-down in the fourth quarter of 2016 or the first quarter of 2017. It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to these inherent uncertainties, if we hold these same factors constant as they existed at March 31, 2017 and only adjust the 12-month average price to an estimated second quarter ending average (holding April 2017 prices constant for the remaining two months of the second quarter of 2017), our forward looking expectation is that we will not recognize an impairment in the second quarter of 2017. But commodity prices (and other factors) remain volatile and they could negatively impact the 12-month average price resulting in the potential for an impairment in the future.
We reduced the number of gross wells our oil and natural gas segment drilled in 2016 by approximately 64% from the number drilled in 2015 due to our reduced cash flow. For 2017, we plan to increase the number of gross wells drilled by approximately 67-90% (depending on future commodity prices) from the number of wells drilled in 2016.
The decline in drilling by our customers reduced the average utilization of our drilling rig fleet. At December 31, 2015, we had 26 drilling rigs operating. In 2016, utilization continued downward bottoming out in May at 13 operating drilling rigs. After May commodity prices began improving for the remainder of the year and we exited 2016 with 21 active rigs. As of March 31, 2017, we had 29 drilling rigs operating (an improvement of 38% over the end of the year). Operators have been increasing drilling, but the extent of further increases remain uncertain. Currently, all nine of our BOSS drilling rigs are under contract and the tenth BOSS drilling rig is being constructed.
Due to low NGLs prices, we continue to operate most of our mid-stream processing facilities in ethane rejection mode which reduces the amount of liquids sold. As long as NGLs prices remain depressed, we expect to continue operating in ethane rejection mode. Low prices have reduced drilling activity around our processing systems thus reducing the number of new wells available to connect to these systems which has resulted in lower processed volumes as production from connected wells naturally decline.
Also, as noted elsewhere, on April 4, 2017, we filed a prospectus supplement related to an at-the-market offering for the sale of shares of our common stock, from time to time, up to an aggregate of $100 million in gross proceeds. As of April 21, 2017, we sold 770,660 shares for $18.3 million, net of offering costs of $0.4 million. Approximately $81.3 million remain available for sale under the program. We intend to use net proceeds from the offering to fund (or offset costs of) acquisitions, future capital expenditures, repay amounts outstanding under our revolving credit facility, and general corporate purposes.

On April 3, 2017, we completed the acquisition of certain oil and natural gas assets from an unrelated third party. The acquisition includes approximately 47 proved developed producing wells and 8,300 net acres primarily in Grady and Caddo Counties in western Oklahoma. The purchase price was approximately $57.0 million in cash plus the conveyance of 180 net leasehold acres we held in McClain County, Oklahoma. This acquisition is subject to certain post-closing adjustments. The effective date of this acquisition is January 1, 2017.

Executive Summary

Oil and Natural Gas

First quarter 2017 production from our oil and natural gas segment was 3,777,000 barrels of oil equivalent (Boe), a decrease of 10% and 16% from the fourth quarter of 2016 and the first quarter of 2016, respectively. In addition to the continued production decline of existing wells, the decreases were due primarily to reduced drilling activity and approximately 0.5 Bcfe of production in the Wilcox play being shut in for five days during the first quarter because of maintenance on a third-party operated processing plant as well as 0.3 Bcfe of production reduced due to weather related events.

First quarter 2017 oil and natural gas revenues were essentially unchanged from the fourth quarter of 2016 and increased 50% from the first quarter of 2016. The increase over the first quarter of 2016 was due primarily to higher commodity prices partially offset by lower production volumes.

Our oil prices for the first quarter of 2017 increased 6% and 50% over the fourth quarter of 2016 and the first quarter of 2016, respectively. Our NGLs prices increased 22% and 170% over the fourth quarter of 2016 and the first quarter of 2016,

24


respectively. Our natural gas prices increased 13% and 43% over the fourth quarter of 2016 and the first quarter of 2016, respectively.

Operating cost per Boe produced for the first quarter of 2017 increased 18% and 5% over the fourth quarter of 2016 and the first quarter of 2016, respectively. The increases were primarily due to lower production volumes.

At March 31, 2017, we had the following derivatives outstanding:
Term
 
Commodity
 
Contracted Volume
 
Weighted Average 
Fixed Price
 
Contracted Market
Apr’17 – Oct'17
 
Natural gas – swap
 
70,000 MMBtu/day
 
$3.038
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – swap
 
60,000 MMBtu/day
 
$2.960
 
IF – NYMEX (HH)
Jan’18 – Dec'18
 
Natural gas – swap
 
20,000 MMBtu/day
 
$3.013
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – basis swap
 
20,000 MMBtu/day
 
$(0.215)
 
IF – NYMEX (HH)
Jan’18 – Mar'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Nov’18 – Dec'18
 
Natural gas – basis swap
 
10,000 MMBtu/day
 
$(0.208)
 
IF – NYMEX (HH)
Apr’17 – Oct'17
 
Natural gas – collar
 
20,000 MMBtu/day
 
$2.88 - $3.10
 
IF – NYMEX (HH)
Apr'17 – Oct'17
 
Natural gas – three-way collar
 
15,000 MMBtu/day
 
$2.50 - $2.00 - $3.32
 
IF – NYMEX (HH)
Nov’17 – Dec'17
 
Natural gas – three-way collar
 
25,000 MMBtu/day
 
$2.90 - $2.30 - $3.59
 
IF – NYMEX (HH)
Jan'18 – Mar'18
 
Natural gas – three-way collar
 
60,000 MMBtu/day
 
$3.29 - $2.63 - $4.07
 
IF – NYMEX (HH)
Apr'18 – Dec'18
 
Natural gas – three-way collar
 
20,000 MMBtu/day
 
$3.00 - $2.50 - $3.51
 
IF – NYMEX (HH)
Apr’17 – Dec'17
 
Crude oil – three-way collar
 
3,750 Bbl/day
 
$49.79 - $39.58 - $60.98
 
WTI – NYMEX

For the three months ended March 31, 2017, we completed drilling eight gross wells (3.96 net wells). For all of 2017, we plan to participate in the drilling of approximately 35 to 40 gross wells. Excluding acquisitions and ARO liability, our estimated 2017 capital expenditures for this segment are approximately $188.0 million. Our current 2017 production guidance is approximately 16.1 to 16.7 MMBoe, a decrease of 3% to 7% from 2016, although actual results continue to be subject to many factors.

Contract Drilling

The average number of drilling rigs we operated in the first quarter of 2017 was 25.5 compared to 19.5 and 20.6 in the fourth quarter of 2016 and the first quarter of 2016, respectively. As of March 31, 2017, 29 of our drilling rigs were operating.

Revenue for the first quarter of 2017 increased 12% over the fourth quarter of 2016 and decreased 4% from the first quarter of 2016, respectively. The increase over the fourth quarter of 2016 was due primarily to a 31% increase in the drilling rigs operating partially offset by a 6% decrease in dayrates. The decrease from the first quarter of 2016 was primarily due to a 14% decrease in dayrates partially offset by a 24% increase in drilling rigs operating.

Dayrates for the first quarter of 2017 averaged $15,835, a 6% decrease from the fourth quarter of 2016 and a 14% decrease from the first quarter of 2016. The decreases from both periods were primarily due to downward pressure on dayrates due to lower demand.

Operating costs for the first quarter of 2017 increased 35% and 4% over the fourth quarter of 2016 and the first quarter of 2016, respectively. The increases were due primarily to more drilling rigs operating.

During 2016 and 2017, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. The improved commodity pricing for oil and natural gas that began during the second half of 2016 has increased demand for drilling rigs. Our drilling rig count bottomed out at 13 drilling rigs operating during the second quarter of 2016, but increased to 21 drilling rigs operating at the end of 2016. Our drilling rig count continued to increase during the first quarter of 2017 to 29 operating drilling rigs. The future demand for and the availability of drilling rigs to meet that demand will have an impact on our future dayrates.

As of March 31, 2017 we had 29 drilling rigs operating. We had eight term drilling contracts with original terms ranging from six months to two years. Two of these contracts are up for renewal in second quarter of 2017, three in the third quarter of 2017, two in the fourth quarter of 2017, and one is up for renewal in 2018. Term contracts may contain a fixed rate for the

25


duration of the contract or provide for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts opted to release the drilling rig and pay an early termination penalty for the remaining term of the contract. During the first quarter of 2017, no early termination fees were recorded compared to $2.6 million in the first quarter of 2016.

Currently, all nine of our existing BOSS drilling rigs are under contract. We have secured a term contract to build our tenth BOSS rig, with construction expected to be completed late in the second quarter. Additionally, we have contracted two of our stacked SCR drilling rigs to be placed into service under term contract in our Mid-Continent division during the second quarter. One SCR drilling rig is being upgraded and the other is being relocated from our Rocky Mountain division. Our estimated 2017 capital expenditures for this segment are approximately $24.0 million.

Mid-Stream

First quarter 2017 liquids sold per day decreased 7% and 4% from the fourth quarter of 2016 and the first quarter of 2016, respectively. The decreases were due to less volume available to process at our plants. For the first quarter of 2017, gas processed per day decreased 10% from the fourth quarter of 2016 and decreased 24% from the first quarter of 2016. The decreases were primarily due to declines in existing volumes, fewer new wells connected, and the loss of an offload volume at our Hemphill facility in mid-2016. For the first quarter of 2017, gas gathered per day decreased 8% from the fourth quarter of 2016 and increased 2% over the first quarter of 2016. The decrease from the fourth quarter of 2016 was primarily due to declining volume on our Appalachian systems. The increase from the first quarter of 2016 was primarily from additional wells added to our Pittsburgh Mills gathering system.

NGLs prices in the first quarter of 2017 increased 10% over the prices received in the fourth quarter of 2016 and increased 71% over the prices received in the first quarter of 2016. Because certain of the contracts used by our mid-stream segment for NGLs transactions are commodity-based contracts–under which we receive a share of the proceeds from the sale of the NGLs–our revenues from those commodity-based contracts fluctuate based on the price of NGLs.

Total operating cost for our mid-stream segment for the first quarter of 2017 decreased 2% from the fourth quarter of 2016 and increased 21% over the first quarter of 2016. First quarter of 2017 costs were lower than the fourth quarter of 2016 due to lower field direct expenses while first quarter of 2017 versus first quarter of 2016 was higher due to higher gas purchase prices partially offset by lower field direct expenses.

In the Appalachian region, the Pittsburgh Mills gathering system continues to be one of our top performing systems. Our average gathered volume for the first quarter of 2017 was approximately 142 MMcf per day. We are completing construction of the next well pad connection. We expect to complete construction and have the next well pad connected by June 2017. This well pad will have five wells and is located on the north end of our system close to our Clinton compressor station.

Also in the Appalachian area, our newest facility, Snow Shoe gathering system, is averaging approximately 9.2 MMcd per day from two producers who have connected a total of six wells from three pads. We have not connected any new wells to this system in 2017. We are completing construction of the Snow Shoe compressor station but we do not intend to install compressors at this facility until compression services are required.

At our Hemphill Texas system, for the first quarter of 2017, our total throughput volume averaged 54 MMcf per day and our total production of natural gas liquids was approximately 128,000 gallons per day. At this processing facility we have the capacity to process 135 MMcf per day through three processing skids. During the first quarter, we connected one new well from an existing well pad and we are in the process of connecting a new well pad which will begin producing in the second quarter of 2017. 

At our Cashion processing facility located in central Oklahoma, our total throughput volume for the first quarter of 2017 averaged approximately 33.6 MMcf per day and our total production of natural gas liquids increased to approximately 194,100 gallons per day. The total processing capacity at this facility remains at approximately 45 MMcf per day. In the first quarter of 2017, after the completion of a construction project that allows us to bring additional gas from a new producer to the Cashion processing plant, we have the ability to receive an additional 10 MMcf per day. The new producer will deliver fee-based volume to us for five years or will pay a shortfall fee which is settled on an annual basis. During the first quarter of 2017, we connected two new wells to this system. 

At our Bellmon processing facility located in the Mississippian play in north central Oklahoma, we connected one new well in the first quarter of 2017 and our total throughput volume averaged approximately 26.3 MMcf per day. Our total natural

26


gas liquids averaged approximately 134,700 gallons per day while operating in ethane recovery mode. We currently have two processing skids available for processing at this facility that provide total processing capacity of 90 MMcf per day. 

At our Segno gathering facility located in Southeast Texas, our average gathered volume for the first quarter of 2017 averaged approximately 84 MMcf per day after being down a few days in January for third-party plant maintenance. We have increased our gathering and dehydration capacity to approximately 120 MMcf per day at this facility. We have not connected any new wells in the first quarter but there continues to be activity in the area around this system.

Our estimated 2017 capital expenditures for this segment are approximately $13.0 million.

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 amount of our cash flow is based primarily on:
 
the amount 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.

We currently believe we will have sufficient cash flow and liquidity to meet our obligations and remain in compliance with our debt covenants for the next twelve months. Our ability to meet our debt covenants (under our credit agreement as well as our 2011 Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which in turn will be affected by financial, business, economic, regulatory, and other factors. For example, lower oil, natural gas, and NGLs prices since the last borrowing base determination under our credit agreement could result in a reduction of the borrowing base and therefore reduce or limit our ability to incur indebtedness. As a result, we monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues, and work, where possible, with our lenders to address those issues, if any, ahead of time.

 
 
Three Months Ended March 31,
 
%
Change
 
 
2017
 
2016
 
 
 
(In thousands except percentages)
Net cash provided by operating activities
 
$
65,652

 
$
70,713

 
(7
)%
Net cash used in investing activities
 
(29,028
)
 
(37,486
)
 
(23
)%
Net cash used in financing activities
 
(29,047
)
 
(33,323
)
 
(13
)%
Net increase (decrease) in cash and cash equivalents
 
$
7,577

 
$
(96
)
 
 

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, and third-party demand for our drilling rigs and mid-stream services and the rates we obtain 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 three months of 2017 decreased by $5.1 million as compared to the first three months of 2016. The decrease was the result of changes in operating assets and liabilities related to the timing of cash receipts and disbursements partially offset by higher revenues.


27


Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital budget to the exploration for and production of oil, NGLs, and natural gas. These expenditures are necessary to off-set the inherent production declines typically experienced in oil and gas wells.

Cash flows used in investing activities decreased by $8.5 million for the first three months of 2017 compared to the first three months of 2016. The change was due primarily to a decrease in capital expenditures and a decrease in 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 used in financing activities decreased by $4.3 million for the first three months of 2017 compared to the first three months of 2016. The decrease was primarily due to a smaller decrease in borrowings under our credit agreement and a larger decrease in book overdrafts.

At March 31, 2017, we had unrestricted cash totaling $8.5 million and had borrowed $150.0 million of the $475.0 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 March 31, 2017 and 2016 and for the three months ended March 31, 2017 and 2016:

 
 
March 31,
 
%
Change
 
 
2017
 
2016
 
 
 
(In thousands except percentages)
Working capital
 
$
(41,296
)
 
$
(15,319
)
 
(170
)%
Long-term debt less debt issuance costs
 
$
790,653

 
$
898,722

 
(12
)%
Shareholders’ equity
 
$
1,213,046

 
$
1,281,040

 
(5
)%
Net income (loss)
 
$
15,929

 
$
(41,149
)
 
(139
)%

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 $41.3 million and $15.3 million as of March 31, 2017 and 2016, respectively. This is primarily from the change in value of outstanding derivatives and lower accounts receivable due to lower revenues partially offset by the timing of accounts payable associated with our capital expenditures. Our credit agreement is used primarily for working capital and capital expenditures. At March 31, 2017, we had borrowed $150.0 million of the $475.0 million available under our credit agreement. The effect of our derivative contracts decreased working capital by $5.6 million as of March 31, 2017 and increased working capital by $13.9 million as of March 31, 2016.


28


The following table summarizes certain operating information:
 
 
Three Months Ended
 
 
 
 
March 31,
 
%
Change
 
 
2017
 
2016
 
Oil and Natural Gas:
 
 
 
 
 
 
Oil production (MBbls)
 
643

 
803

 
(20
)%
NGLs production (MBbls)
 
1,097

 
1,291

 
(15
)%
Natural gas production (MMcf)
 
12,225

 
14,522

 
(16
)%
Average oil price per barrel received
 
$
48.68

 
$
32.50

 
50
 %
Average oil price per barrel received excluding derivatives
 
$
48.64

 
$
28.54

 
70
 %
Average NGLs price per barrel received
 
$
17.81

 
$
6.59

 
170
 %
Average NGLs price per barrel received excluding derivatives
 
$
17.81

 
$
6.59

 
170
 %
Average natural gas price per Mcf received
 
$
2.68

 
$
1.87

 
43
 %
Average natural gas price per Mcf received excluding derivatives
 
$
2.78

 
$
1.59

 
75
 %
Contract Drilling:
 
 
 
 
 
 
Average number of our drilling rigs in use during the period
 
25.5

 
20.6

 
24
 %
Total number of drilling rigs owned at the end of the period
 
94

 
94

 
 %
Average dayrate
 
$
15,835

 
$
18,392

 
(14
)%
Mid-Stream:
 
 
 
 
 
 
Gas gathered—Mcf/day
 
390,384

 
383,405

 
2
 %
Gas processed—Mcf/day
 
126,559

 
167,048

 
(24
)%
Gas liquids sold—gallons/day
 
497,862

 
519,433

 
(4
)%
Number of natural gas gathering systems
 
25

 
26

 
(4
)%
Number of processing plants
 
13

 
13

 
 %

Oil and Natural Gas Operations

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

Based on our first three months of 2017 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of derivatives, would cause a corresponding $397,000 per month ($4.8 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 three months of 2017 was $2.68 compared to $1.87 for the first three months of 2016. Based on our first three months of 2017 production, a $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $209,000 per month ($2.5 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices, without the effect of derivatives, would have a $357,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow. In the first three months of 2017, our average oil price per barrel received, including the effect of derivatives, was $48.68 compared with an average oil price, including the effect of derivatives, of $32.50 in the first three months of 2016 and our first three months of 2017 average NGLs price per barrel received was $17.81 compared with an average NGLs price per barrel of $6.59 in the first three months of 2016.

Because commodity prices affect the value of our oil, NGLs, and natural gas reserves, declines in those prices can cause a decline in the carrying value of our oil and natural gas properties. At March 31, 2017, the 12-month average unescalated prices were $47.61 per barrel of oil, $23.52 per barrel of NGLs, and $2.73 per Mcf of natural gas, as adjusted for price differentials. We were not required to take a write down in the first quarter of 2017.

It is hard to predict with any reasonable certainty the need for or amount of any future impairments given the many factors that go into the ceiling test calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward oil and gas reserve revisions, oil and gas reserve additions, and tax attributes. Subject to

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these inherent uncertainties, if we hold these same factors constant as they existed at March 31, 2017, and only adjust the 12-month average price to an estimated second quarter ending average (holding April 2017 prices constant for the remaining two months of the second quarter of 2017), our forward looking expectation is that we will not recognize an impairment in the second quarter of 2017. But commodity prices (and other factors) remain volatile and they could negatively impact the 12-month average price resulting in the potential for an impairment in the future.

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

Contract Drilling Operations