Seventy Seven Energy Inc. - FORM 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

Commission File No. 001-36354

Seventy Seven Energy Inc.

(Exact name of registrant as specified in its charter)



Oklahoma		45-3338422
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

777 N.W. 63rd Street Oklahoma City, Oklahoma		73116
(Address of principal executive offices)		(Zip Code)

(405) 608-7777

(Registrant’s telephone number, including area code)

______________________________

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 ý 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, non-accelerated filer, or smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 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 ý

As of July 27, 2015, there were 56,909,613 shares of our $0.01 par value common stock outstanding.

TABLE OF CONTENTS



		Page
PART I. FINANCIAL INFORMATION		1
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	1
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Changes in Equity	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 4.	Controls and Procedures	64

PART II. OTHER INFORMATION		66
Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	66
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
Item 5.	Other Information	66
Item 6.	Exhibits	67

SIGNATURES		70

PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Balance Sheets

(Unaudited)



	June 30, 2015			December 31, 2014
	(In thousands, except share amounts)
Assets:
Current Assets:
Cash	$	118,335		$	891
Accounts receivable, net of allowance of $5,319 and $3,311 at June 30, 2015 and December 31, 2014, respectively	261,061			421,555
Inventory	22,895			25,073
Deferred income tax asset	4,031			7,463
Prepaid expenses and other	13,468			19,072
Total Current Assets	419,790			474,054
Property and Equipment:
Property and equipment, at cost	2,596,251			2,749,886
Less: accumulated depreciation	(1,006,500		)	(982,833		)
Total Property and Equipment, Net	1,589,751			1,767,053
Other Assets:
Equity method investment	9,036			7,816
Goodwill	27,434			27,434
Intangible assets, net	—			5,420
Deferred financing costs	27,508			23,851
Other long-term assets	33,684			6,924
Total Other Assets	97,662			71,445
Total Assets	$	2,107,203		$	2,312,552
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	37,239		$	45,657
Current portion of long-term debt	5,000			4,000
Other current liabilities	156,471			215,752
Total Current Liabilities	198,710			265,409
Long-Term Liabilities:
Deferred income tax liabilities	98,930			159,273
Long-term debt, excluding current maturities	1,600,750			1,594,500
Other long-term liabilities	1,928			2,347
Total Long-Term Liabilities	1,701,608			1,756,120
Commitments and Contingencies (Note 8)
Stockholders’ Equity:
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 56,248,249 and 51,158,968 shares at June 30, 2015 and December 31, 2014, respectively	563			512
Paid-in capital	329,726			301,644
Accumulated deficit	(123,404		)	(11,133		)
Total Stockholders’ Equity	206,885			291,023
Total Liabilities and Stockholders’ Equity	$	2,107,203		$	2,312,552

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Operations

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands, except per share data)
Revenues:
Revenues	$	295,128		$	549,466		$	724,915		$	1,059,176
Operating Expenses:
Operating costs	239,127			406,586			570,738			816,174
Depreciation and amortization	72,950			71,829			157,925			144,294
General and administrative	34,815			19,368			68,727			40,254
Loss on sale of a business	34,989			—			34,989			—
Losses (gains) on sales of property and equipment, net	9,010			(8,964		)	13,220			(7,986		)
Impairments and other	8,882			3,172			15,154			22,980
Total Operating Expenses	399,773			491,991			860,753			1,015,716
Operating (Loss) Income	(104,645		)	57,475			(135,838		)	43,460
Other (Expense) Income:
Interest expense	(24,968		)	(17,615		)	(48,484		)	(32,307		)
Gains on early extinguishment of debt	13,085			—			13,085			—
Income (loss) from equity investees	136			(4,500		)	1,108			(5,417		)
Other income	1,043			386			947			757
Total Other Expense	(10,704		)	(21,729		)	(33,344		)	(36,967		)
(Loss) Income Before Income Taxes	(115,349		)	35,746			(169,182		)	6,493
Income Tax (Benefit) Expense	(40,679		)	14,036			(56,911		)	3,338
Net (Loss) Income	$	(74,670	)	$	21,710		$	(112,271	)	$	3,155

(Loss) Earnings Per Common Share (Note 4)
Basic	$	(1.50	)	$	0.46		$	(2.30	)	$	0.07
Diluted	$	(1.50	)	$	0.46		$	(2.30	)	$	0.07

Weighted Average Common Shares Outstanding (Note 4)
Basic	49,788			46,932			48,869			46,932
Diluted	49,788			46,932			48,869			46,932

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statement of Changes in Equity

(Unaudited)



	Common Stock			Paid-in Capital		Accumulated Deficit			Total Stockholders’ Equity
	Shares	Amount		Paid-in Capital		Accumulated Deficit			Total Stockholders’ Equity
	(In thousands)
Balance at December 31, 2014	51,159	$	512	$	301,644	$	(11,133	)	$	291,023
Net loss	—	—		—		(112,271		)	(112,271		)
Share-based compensation	5,089	51		28,082		—			28,133
Balance at June 30, 2015	56,248	$	563	$	329,726	$	(123,404	)	$	206,885

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended June 30,
	2015			2014
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET (LOSS) INCOME	$	(112,271	)	$	3,155
ADJUSTMENTS TO RECONCILE NET (LOSS) INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization	157,925			144,294
Amortization of sale/leaseback gains	—			(5,139		)
Amortization of deferred financing costs	2,135			3,972
Gains on extinguishment of debt	(13,085		)	—
Loss on sale of a business	34,989			—
Losses (gains) on sales of property and equipment, net	13,220			(7,986		)
Impairments and other	15,154			14,531
(Income) loss from equity investees	(1,108		)	5,417
Provision for doubtful accounts	2,584			1,115
Non-cash compensation	31,486			—
Deferred income tax (benefit) expense	(56,911		)	2,642
Other	(810		)	87
Changes in operating assets and liabilities	86,369			(40,154		)
Net cash provided by operating activities	159,677			121,934
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment	(90,724		)	(256,778		)
Proceeds from sales of assets	16,367			60,939
Proceeds from sale of a business	15,000			—
Additions to investments	(112		)	(131		)
Other	3,392			35
Net cash used in investing activities	(56,077		)	(195,935		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facility	160,100			716,500
Payments on revolving credit facility	(210,600		)	(1,099,100		)
Proceeds from issuance of senior notes, net of offering costs	—			493,825
Payments to extinguish senior notes	(26,405		)	—
Proceeds from issuance of term loan, net of issuance costs	94,481			393,879
Payments on term loan	(2,250		)	—
Deferred financing costs	(784		)	(2,385		)
Distributions to CHK	—			(421,920		)
Other	(698		)	—
Net cash provided by financing activities	13,844			80,799
Net increase in cash	117,444			6,798
Cash, beginning of period	891			1,678
Cash, end of period	$	118,335		$	8,476

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Cash Flows — (Continued)

(Unaudited)

Supplemental disclosures to the condensed consolidated financial statements of cash flows are presented below:



SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
(Decrease) increase in other current liabilities related to purchases of property and equipment	$	(8,991	)	$	4,601
Note receivable received as consideration for sale of a business	$	27,000		$	—
Property and equipment distributed to CHK at spin-off	$	—		$	(792	)
Property and equipment contributed from CHK at spin-off	$	—		$	190,297
SUPPLEMENTAL DISCLOSURE OF CASH PAYMENTS:
Interest paid, net of amount capitalized	$	48,146		$	28,083

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

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Spin-off

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes present the financial position of Seventy Seven Energy Inc. (“SSE,” “we,” “us,” “our” or “ours”) as of June 30, 2015 and December 31, 2014, results of operations for the three and six months ended June 30, 2015 and 2014, changes in equity for the six months ended June 30, 2015 and cash flows for the six months ended June 30, 2015 and 2014. These notes relate to the three and six months ended June 30, 2015 (the “Current Quarter” and “Current Period,” respectively) and the three and six months ended June 30, 2014 (the “Prior Quarter” and “Prior Period,” respectively). All significant intercompany accounts and transactions within SSE have been eliminated.

Seventy Seven Finance Inc. (“SSF”) is a 100% owned finance subsidiary of SSE that was incorporated for the purpose of facilitating the offering of SSE’s 2019 Notes (see Note 6). SSF does not have any operations or revenues.

The accompanying condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States (“GAAP”) for interim financial information. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. Certain footnote disclosures normally included in the financial statements prepared in accordance with GAAP have been appropriately condensed or omitted. Therefore, these interim condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2014 contained in our Annual Report on Form 10-K (Commission File No. 001-36354) filed with the U.S. Securities and Exchange Commission (“SEC”) on March 2, 2015.

Spin-off

On June 9, 2014, Chesapeake Energy Corporation (“CHK”) announced that its board of directors approved the spin-off of its oilfield services division through the pro rata distribution of 100% of the shares of common stock of SSE to CHK’s shareholders of record as of the close of business on June 19, 2014. On June 30, 2014, each CHK shareholder received one share of SSE common stock for every fourteen shares of CHK common stock held by such shareholder on the record date, and SSE became an independent, publicly traded company as a result of the distribution. The transactions in which SSE became an independent, publicly traded company, including the distribution, are referred to collectively as the “spin-off”. Prior to the spin-off, we conducted our business as Chesapeake Oilfield Operating, L.L.C. (“COO”), a wholly owned subsidiary of CHK. Following the spin-off, CHK retained no ownership interest in SSE, and each company has separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness, describing the spin-off was filed by SSE with the SEC and was declared effective on June 17, 2014. On July 1, 2014, SSE stock began trading the “regular-way” on the New York Stock Exchange under the ticker symbol of “SSE”. For a detailed description of the transactions completed and agreements entered into as part of the spin-off, please read Note 1 to our consolidated financial statements contained in our Annual Report on Form 10-K.

2. Sale of Hodges Trucking Company, L.L.C.

On June 14, 2015, we sold Hodges Trucking Company, L.L.C. (“Hodges”), our previously wholly-owned subsidiary that provided drilling rig relocation and logistics services, to Aveda Transportation and Energy Services Inc. (“Aveda”) for aggregate consideration of $42.0 million. At the time of the sale, Hodges owned 270 rig relocation trucks and 65 cranes and forklifts. The sale did not include the land and buildings used in Hodges’ operations.

The consideration received consisted of $15.0 million in cash and a $27.0 million secured promissory note due June 15, 2020 (the “Note Receivable”). The Note Receivable bears a fixed interest rate of 9.00% per annum, which is payable quarterly in arrears beginning on June 30, 2015. Aveda can, at any time, make prepayments of principal before the maturity date without premium or penalty. The Note Receivable is secured by a second lien on substantially all of Aveda’s fixed assets and accounts receivable. The Note Receivable is presented in other long-term assets on our condensed consolidated balance sheet. During the Current Quarter, we recognized interest income of $0.1 million related to the Note Receivable.

We recognized a loss of $35.0 million on the sale of Hodges during the Current Quarter. Additionally, during the Current Quarter, we recognized $2.1 million of additional stock-based compensation expense related to the vesting of restricted stock held by Hodges employees and $0.6 million of severance-related costs.

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Hodges was included in our oilfield trucking segment. The sale of Hodges did not qualify as discontinued operations because the sale did not represent a strategic shift that had or will have a major effect on our operations or financial results.

3. Change in Accounting Estimate

We review the estimated useful lives of our property and equipment on an ongoing basis. Based on this review in the first quarter of 2015, we concluded that the estimated useful lives of certain drilling rig components and certain drilling rigs were shorter than the estimated useful lives used for depreciation in our consolidated financial statements. As a result, effective January 1, 2015, we changed our estimate of the useful lives of these components and the drilling rigs to better reflect the estimated periods during which these drilling rig components and drilling rigs will remain in service. The effect of the drilling rig component change in estimate resulted in an increase to depreciation expense of $10.9 million, pre-tax, during the Current Period. The effect of the change in estimate of certain drilling rigs was an increase of $1.1 million and $2.2 million, pre-tax, to depreciation expense during the Current Quarter and Current Period, respectively. For the Current Quarter and the Current Period, these changes increased our net loss by $0.7 million and $8.6 million, respectively, and increased our basic and diluted loss per share by $0.01 and $0.18, respectively.

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

4. Earnings Per Share

Basic earnings per share is computed using the weighted average number of shares of common stock outstanding and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide nonforfeitable dividend rights and are required to be included in the computation of our basic earnings per share using the two-class method. The two-class method is an earnings allocation formula that determines earnings per share for common stock and participating securities according to dividends declared and participation rights in undistributed earnings. Diluted earnings per share is computed using the weighted average shares outstanding for basic earnings per share, plus the dilutive effect of stock options. The dilutive effect of unvested restricted stock and stock options is determined using the treasury stock method, which assumes the amount of unrecognized compensation expense related to unvested share-based compensation awards is used to repurchase shares at the average market price for the period.



	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	(In thousands, except per share data)
Basic earnings per share^(a):
Allocation of earnings:
Net (loss) income	$	(74,670	)	$	21,710	$	(112,271	)	$	3,155

Weighted average shares outstanding:
Weighted average shares outstanding, excluding unvested shares of restricted stock	49,788			46,932		48,869			46,932
Restricted stock^(b)	—			—		—			—
Weighted average shares outstanding, basic	49,788			46,932		48,869			46,932

Basic (loss) earnings per share	$	(1.50	)	$	0.46	$	(2.30	)	$	0.07

Diluted earnings per share^(a):
Allocation of earnings:
Net (loss) income	$	(74,670	)	$	21,710	$	(112,271	)	$	3,155

Weighted average shares outstanding:
Weighted average shares outstanding, basic	49,788			46,932		48,869			46,932
Stock options^(c)	—			—		—			—
Weighted average shares outstanding, diluted	49,788			46,932		48,869			46,932

Diluted (loss) earnings per share	$	(1.50	)	$	0.46	$	(2.30	)	$	0.07


(a)	46,932,433 shares of our common stock were distributed to CHK shareholders on June 30, 2014 in conjunction with the spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount to be outstanding for periods prior to the spin-off presented in the calculation of weighted average shares.


(b)	3,863,324 and 2,296,081 unvested restricted shares were excluded from the computation of basic earnings per share for the Current Quarter and Current Period, respectively, as these shares are not obligated to participate in our losses.


(c)	The exercise price of stock options exceeded the average market price of our common stock during the Current Quarter and Current Period. Therefore, the stock options were not dilutive.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Asset Sales and Impairments and Other

Asset Sales

During the Current Quarter, we sold our water hauling assets, which consisted of property and equipment that had a total carrying amount of $12.3 million, for $6.5 million. During the Prior Period, we sold 15 drilling rigs and ancillary equipment that were not being utilized in our business for $13.7 million, net of selling expenses. During the Prior Period, we sold our crude hauling assets, which included 124 fluid handling trucks and 122 trailers that had a total carrying amount of $20.7 million, for $43.8 million. During the Current Period and Prior Period, we sold other ancillary equipment for $9.9 million and $3.4 million, respectively. We recorded net losses (gains) on sales of property and equipment of approximately $13.2 million and ($8.0) million related to these asset sales during the Current Period and Prior Period, respectively.

Impairments and Other

A summary of our impairments and other is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(In thousands)
Drilling rigs held for use	$	—	$	2,940	$	3,290	$	8,366
Drilling rigs held for sale	—		—		—		5,714
Lease termination costs	—		70		—		8,449
Drilling-related services equipment	8,687		—		8,687		—
Trucking and fluid disposal equipment	195		—		2,737		—
Other	—		162		440		451
Total impairments and other	$	8,882	$	3,172	$	15,154	$	22,980

We recognized impairment charges of $8.7 million during the Current Quarter for drilling-related services equipment that we deemed to be impaired based on expected future cash flows of this equipment. Estimated fair values for drilling-related services equipment were determined using significant unobservable inputs (Level 3) based on a market approach.

We recognized $2.9 million, $3.3 million and $8.4 million of impairment charges during the Prior Quarter, Current Period and Prior Period, respectively, for certain drilling rigs that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. Estimated fair value for these drilling rigs was determined using significant unobservable inputs (Level 3) based on a market approach.

We recognized $0.2 million and $2.7 million of impairment charges during the Current Quarter and Current Period, respectively, for certain trucking and fluid disposal equipment that we deemed impaired based on expected future cash flows of this equipment. Estimated fair value for the trucking and fluid disposal equipment was determined using significant unobservable inputs (Level 3) based on an income approach.

We recognized $5.7 million of impairment charges during the Prior Period for certain drilling rigs and spare equipment we had identified to sell as part of our broader strategy to divest of non-essential drilling rigs. We are required to present such assets at the lower of carrying amount or fair value less the anticipated costs to sell at the time that they met the criteria for held-for-sale accounting. Estimated fair value was based on the expected sales price, less costs to sell.

During the Prior Quarter and the Prior Period, we purchased 11 and 31 of our leased drilling rigs for approximately $54.1 million and $131.0 million, respectively, and paid lease termination costs of approximately $0.1 million and $8.4 million, respectively. We subsequently sold eight of these drilling rigs.

We identified certain other property and equipment during the Current Quarter, Prior Quarter, Current Period, and Prior Period that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $0.2 million, $0.4 million and $0.5 million during the Prior Quarter, Current Period and Prior Period, respectively, related to these assets. Estimated fair value for this property and equipment was determined using significant unobservable inputs (Level 3) based on an income approach.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management’s judgment. A prolonged period of low oil and natural gas prices or continued reductions in capital expenditures by CHK or our other customers would likely have an adverse impact on our utilization and the prices that we receive for our services. This could result in the recognition of future material impairment charges on the same, or additional, property and equipment if future cash flow estimates, based upon information then available to management, indicate that their carrying values are not be recoverable.

6. Debt

As of June 30, 2015 and December 31, 2014, our long-term debt consisted of the following:



	June 30, 2015		December 31, 2014
	(In thousands)
6.625% Senior Notes due 2019	$	650,000	$	650,000
6.50% Senior Notes due 2022	460,000		500,000
Term Loans	495,750		398,000
Credit Facility	—		50,500
Total debt	1,605,750		1,598,500
Less: Current portion of long-term debt	5,000		4,000
Total long-term debt	$	1,600,750	$	1,594,500

2019 Senior Notes

In October 2011, we and SSF co-issued $650.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 (the “2019 Notes”). The 2019 Notes will mature on November 15, 2019 and interest is payable semi-annually in arrears on May 15 and November 15 of each year. The 2019 Notes are guaranteed by all of our existing subsidiaries, other than certain immaterial subsidiaries and SSF, which is a co-issuer of the 2019 Notes.

Prior to November 15, 2015, we may redeem some or all of the 2019 Notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the indenture governing the 2019 Senior Notes, plus accrued and unpaid interest. On or after November 15, 2015, we may redeem all or part of the 2019 Senior Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:



Year	Redemption Price
2015	103.313	%
2016	101.656	%
2017 and thereafter	100.000	%

The 2019 Notes are subject to covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets; (2) declare dividends or make distributions on our equity interests or purchase or redeem our equity interests; (3) make investments or other specified restricted payments; (4) incur or guarantee additional indebtedness and issue disqualified or preferred equity; (5) create or incur certain liens; (6) enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2019 Senior Notes also have cross default provisions that apply to other indebtedness of SSE and any of its guarantor subsidiaries. If the 2019 Senior Notes achieve an investment grade rating from either Moody’s Investor Service, Inc. (“Moody’s”) or Standard & Poor’s Rating Services (“S&P”), our obligation to comply with certain of these covenants will be suspended, and if the 2019 Senior Notes achieve an investment grade rating from both Moody’s and S&P, then all such covenants will terminate.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2022 Senior Notes

In June 2014, we issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 (the “2022 Notes”). The 2022 Notes will mature on July 15, 2022 and interest is payable semi-annually in arrears on July 15 and January 15 of each year. Prior to the full repayment or refinancing of the 2019 Notes, the 2022 Notes will become fully and unconditionally guaranteed on a senior unsecured basis by each of our domestic subsidiaries, if any, that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million, other than (i) guarantors of the 2019 Notes, (ii) Seventy Seven Operating LLC (“SSO”) or (iii) subsidiaries of SSO. We do not have any such subsidiaries currently; therefore, the 2022 Notes are not guaranteed. Upon the full repayment of the 2019 Notes, the 2022 Notes will be fully and unconditionally guaranteed on a senior unsecured basis by each of our domestic subsidiaries that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million.

We may redeem up to 35% of the 2022 Notes with proceeds of certain equity offerings at a redemption price of 106.5% of the principal amount plus accrued and unpaid interest prior to July 15, 2017, subject to certain conditions. Prior to July 15, 2017, we may redeem some or all of the 2022 Notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the indenture governing the 2022 Notes, plus accrued and unpaid interest. On or after July 15, 2017, we may redeem all or part of the 2022 Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on July 15 of the years indicated below:



Year	Redemption Price
2017	104.875	%
2018	103.250	%
2019	101.625	%
2020 and thereafter	100.000	%

The 2022 Notes are subject to covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets; (2) declare dividends or make distributions on our equity interests or purchase or redeem our equity interests; (3) make investments or other specified restricted payments; (4) incur or guarantee additional indebtedness and issue disqualified or preferred equity; (5) create or incur certain liens; (6) enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2022 Notes also have cross default provisions that apply to other indebtedness of SSE and certain of our subsidiaries. If the 2022 Notes achieve an investment grade rating from either Moody’s or S&P, our obligation to comply with certain of these covenants will be suspended, and if the 2022 Notes achieve an investment grade rating from both Moody’s and S&P, then all such covenants will terminate.

During the Current Quarter, we repurchased and cancelled $40.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $26.4 million. We recognized gains on extinguishment of debt of $13.1 million, which included the amortization of unamortized deferred financing costs of $0.5 million.

Term Loans

In June 2014, we entered into a $400.0 million seven-year term loan credit agreement (the “Term Loan”). Borrowings under the Term Loan bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month London Interbank Offered Rate (“LIBOR”) rate adjusted daily plus 1.00% or (ii) LIBOR, with a floor of 0.75%, plus, in each case, an applicable margin. The applicable margin for borrowings is 2.00% for Base Rate loans and 3.00% for LIBOR loans, depending on whether the Base Rate or LIBOR is used, provided that if and for so long as the leverage ratio is less than a certain level and the term loans have certain ratings from each of S&P and Moody’s, such margins will be reduced by 0.25%. The Term Loan is repayable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Term Loan and will mature in full on June 25, 2021.

Obligations under the Term Loan are guaranteed jointly and severally by all of our present and future direct and indirect wholly-owned material domestic subsidiaries, other than certain excluded subsidiaries. Amounts borrowed under the Term

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Loan are secured by liens on all of our equity interests in our current and future subsidiaries, and all of our subsidiaries’ present and future real property, equipment (including drilling rigs and frac spread equipment), fixtures and other fixed assets.

We may prepay all or a portion of our Term Loan at any time, subject to a 1.00% principal premium on the repayment of principal pursuant to a refinancing within six months after the closing date. Borrowings under our Term Loan may be subject to mandatory prepayments with the net cash proceeds of certain issuances of debt, certain asset sales and other dispositions and certain condemnation events, and with excess cash flow in any calendar year in which our leverage ratio exceeds 3.25 to 1.00. The Term Loan contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates.

On May 13, 2015, we entered into an incremental term supplement to the Term Loan and borrowed $100.0 million in aggregate principal amount (the “Incremental Term Loan”) and received net proceeds of $94.5 million. Borrowings under the Incremental Term Loan bear interest at our option at either (i) LIBOR, with a floor of 1.00% or (ii) the Base Rate, calculated as the greatest of (1) the Bank of America, N.A. prime rate, (2) the federal funds rate plus 0.50% and (3) a one-month LIBOR rate adjusted daily plus 1.00%, plus, in each case, an applicable margin. The applicable margin for borrowings is 9.00% for LIBOR loans and 8.00% for Base Rate loans, depending on whether the Base Rate or LIBOR is used. The Incremental Term Loan is payable in equal consecutive quarterly installments equal to 0.25% (1.00% per annum) of the original principal amount of the Incremental Term Loan and will mature in full on June 25, 2021.

Obligations under the Incremental Term Loan are guaranteed jointly and severally by all of our present and future direct and indirect wholly-owned material domestic subsidiaries, other than certain excluded subsidiaries. Amounts borrowed under the Incremental Term Loan are secured by liens on all of our equity interests in our current and future subsidiaries, and all of our subsidiaries’ present and future real property, equipment (including drilling rigs and frac spread equipment), fixtures and other fixed assets.

We may prepay all or a portion of our Incremental Term Loan at any time. Borrowings under our Incremental Term Loan may be subject to mandatory prepayments with the net cash proceeds of certain issuances of debt, certain asset sales and other dispositions and certain condemnation events, and with excess cash flow in any calendar year in which our leverage ratio exceeds 3.25 to 1.00. The Incremental Term Loan contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates. All prepayments of the Incremental Term Loan, except for mandatory prepayments described above, if made on or prior to the 42-month anniversary of the Incremental Term Loan, are subject to a prepayment premium equal to (i) a make-whole premium determined pursuant to a formula set forth in the Incremental Term Loan if made on or prior to the 18-month anniversary of the Incremental Term Loan, (ii) 5.00% of such principal amount if made after the 18-month anniversary and on or prior to the 30-month anniversary of the Incremental Term Loan, or (iii) 3.00% of such principal amount if made after the 30-month anniversary and on or prior to the 42-month anniversary of the Incremental Term Loan.

Credit Facility

In June 2014, we, through SSO, entered into a five-year senior secured revolving bank credit facility (the “Credit Facility”) with total commitments of $275.0 million. The maximum amount that we may borrow under the Credit Facility is subject to the borrowing base, which is based on a percentage of eligible accounts receivable, subject to reserves and other adjustments. As of June 30, 2015, the Credit Facility had availability of $264.8 million, net of letters of credit of $10.2 million. All obligations under the Credit Facility are fully and unconditionally guaranteed jointly and severally by SSE, and all of our present and future direct and indirect material domestic subsidiaries. Borrowings under the Credit Facility are secured by liens on cash and accounts receivable of the borrowers and the guarantors, and bear interest at our option at either (i) the Base Rate, calculated as the greatest of (1) the rate of interest publicly announced by Wells Fargo Bank, National Association, as its “prime rate,” subject to each increase or decrease in such prime rate effective as of the date such change occurs, (2) the federal funds effective rate plus 0.50% and (3) the one-month LIBOR Rate plus 1.00%, each of which is subject to an applicable margin, or (ii) LIBOR, plus, in each case, an applicable margin. The applicable margin ranges from 0.50% to 1.00% per annum for Base Rate loans and 1.50% to 2.00% per annum for LIBOR loans. The unused portion of the Credit Facility is subject to a commitment fee that varies from 0.250% to 0.375% per annum, according to average unused amounts. Interest on LIBOR loans is payable at the end of the selected interest period, but no less frequently than quarterly. Interest on Base Rate loans is payable monthly in arrears.

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The Credit Facility contains various covenants and restrictive provisions which limit our ability to (1) enter into asset sales; (2) incur additional indebtedness; (3) make investments or loans and create liens; (4) pay certain dividends or make other distributions and (5) engage in transactions with affiliates. The Credit Facility requires maintenance of a fixed charge coverage ratio based on the ratio of consolidated EBITDA (minus unfinanced capital expenditures) to fixed charges, in each case as defined in the Credit Facility agreement, at any time availability is below a certain threshold and for a certain period of time thereafter. If we fail to perform our obligations under the agreement, the Credit Facility could be terminated and any outstanding borrowings under the Credit Facility may be declared immediately due and payable. The Credit Facility also contains cross default provisions that apply to our other indebtedness.

7. Other Current Liabilities

Other current liabilities as of June 30, 2015 and December 31, 2014 are detailed below:



	June 30, 2015		December 31, 2014
	(In thousands)
Other Current Liabilities:
Accrued expenses	$	59,122	$	88,538
Payroll related	34,805		47,711
Insurance reserves	14,558		14,521
Interest	23,237		25,035
Income, property, sales, use and other taxes	7,730		13,937
Property and equipment	17,019		26,010
Total Other Current Liabilities	$	156,471	$	215,752

8. Commitments and Contingencies

Operating Leases

As of June 30, 2015, we were party to five lease agreements with various third parties to lease rail cars for initial terms of five to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreement.

As of June 30, 2015, we were also party to various lease agreements for other property and equipment with varying terms.

Aggregate undiscounted minimum future lease payments under our operating leases at June 30, 2015 are presented below:



	Rail Cars		Other		Total
	(In thousands)
Remainder of 2015	$	2,723	$	1,029	$	3,752
2016	5,447		984		6,431
2017	2,168		426		2,594
2018	1,445		170		1,615
2019	722		3		725
Total	$	12,505	$	2,612	$	15,117

Rent expense for drilling rigs, real property, rail cars and other property and equipment for the Current Quarter, Prior Quarter, Current Period and Prior Period was $2.2 million, $12.6 million, $4.1 million and $27.6 million, respectively, and was included in operating costs in our condensed consolidated statements of operations.

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Other Commitments

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of June 30, 2015, we had $141.8 million of purchase commitments related to future capital expenditures that we expect to incur in the second half of 2015 and 2016.

Litigation

We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, property damage claims and contract actions. We record an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to our business operations is likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued and actual results could differ materially from management’s estimates.

Self-Insured Reserves

We are self-insured up to certain retention limits with respect to workers’ compensation and general liability matters. We maintain accruals for self-insurance retentions that we estimate using third-party data and claims history. Included in operating costs is workers’ compensation expense of $2.2 million, $2.7 million, $4.8 million and $5.1 million during the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

9. Stock-Based Compensation

Our stock-based compensation program consists of restricted stock available to employees and stock options. The restricted stock awards and stock options are equity-classified awards. We also recognize compensation expense (benefit) related to performance share units granted by CHK to our chief executive officer.

Included in operating costs and general and administrative expenses is stock-based compensation expense (credit) of $10.1 million, ($8.2) million, $22.6 million and ($5.0) million for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Prior to the spin-off, we reimbursed CHK for these costs in accordance with the administrative services agreement. To the extent compensation cost related to employees indirectly involved in oilfield services operations, such amounts were charged to us through an overhead allocation and are reflected as general and administrative expenses.

Equity-Classified Awards

Restricted Stock. The fair value of restricted stock awards is determined based on the fair market value of SSE common shares on the date of the grant. This value is amortized over the vesting period.

A summary of the status and changes of unvested shares of restricted stock is presented below.



	Number of Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested shares as of January 1, 2015	3,933		$	24.02
Granted	4,003		$	4.58
Vested	(714	)	$	19.69
Forfeited	(293	)	$	21.51
Unvested shares as of June 30, 2015	6,929		$	13.34

The aggregate intrinsic value of restricted stock vested for the Current Quarter, as reflected in the table above, was approximately $4.7 million based on the market price of SSE’s common stock at the time of vesting.

As of June 30, 2015, there was $59.1 million of total unrecognized compensation cost related to the unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately 31 months.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Stock Options. CHK granted stock options to our chief executive officer under CHK’s Long-Term Incentive Plan for incentive and retention purposes. The incentive-based stock options vest ratably over a three-year period and our retention-based stock options will vest one-third on each of the third, fourth and fifth anniversaries of the grant date of the original CHK award, in the case of a replacement award. Outstanding options expire ten years from the date of grant of the original CHK award, in the case of a replacement award. We have not issued any new stock options, other than the replacement awards, since the spin-off.

The following table provides information related to stock option activity for the Current Quarter:



	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)				(in thousands)
Outstanding at January 1, 2015	348	$	16.19	9.24	$	—
Granted	—	$	—	—	$	—
Exercised	—	$	—	—	$	—
Outstanding at June 30, 2015	348	$	16.19	7.74	$	—
Exercisable at June 30, 2015	89	$	16.46	7.78	$	—


(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

As of June 30, 2015, there was $0.7 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately 17 months.

Other

Performance Share Units. CHK granted performance share units (“PSUs”) to our chief executive officer under CHK’s Long-Term Incentive Plan that includes both an internal performance measure and external market condition as it relates to CHK. Following the spin-off, compensation expense is recognized through the changes in fair value of the PSUs over the vesting period with a corresponding adjustment to equity and any related cash obligations are the responsibility of CHK. We recognized (credits) expenses of ($0.4) million, ($1.2) million and $0.1 million for the Current Quarter, Current Period and Prior Period, respectively.

10. Income Taxes

Through the effective date of the spin-off, our operations were included in the consolidated federal income tax return and other state returns for CHK. The income tax provision for the period before the spin-off has been prepared on a separate return basis for us and all of our subsidiaries. Accordingly, we have recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases for all our subsidiaries as if each entity were a corporation, regardless of its actual characterization for U.S. federal income tax purposes. Our effective tax rate was 35%, 39%, 34% and 51% for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Our effective tax rate can fluctuate as a result of the impact of state income taxes, permanent differences and changes in pre-tax income. Effective with the spin-off, we entered into a tax sharing agreement with CHK which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off, with respect to the payment of taxes, filing of tax returns, reimbursement of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes. Following the spin-off, we are not entitled to federal income tax net operating loss (“NOL”) carryforwards that were generated prior to the spin-off and that have historically been reflected in our net deferred income tax liabilities on our consolidated balance sheet. As of the spin-off date, we made an adjustment to our deferred tax liabilities of approximately $178.8 million to reflect the treatment of NOLs under the tax sharing agreement. In connection with the spin-off, we received a one-time step-up in tax basis of our assets due to the tax gain recognized by CHK related to the spin-off in the tax affected amount of approximately $202.6 million.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A valuation allowance for deferred tax assets, including NOLs, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. We had no valuation allowance at June 30, 2015 and December 31, 2014. However, some or all of these NOLs could expire unused if we are unable to generate sufficient taxable income in the future to utilize them or we enter into transactions that limit our right to use them. If it became more-likely-than-not NOLs would expire unused, we would have to record a valuation allowance to reflect this fact, which could materially increase our income tax expense, and therefore, adversely affect our results of operations in the period in which it is recorded. We will continue to assess the need for a valuation allowance in the future.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at June 30, 2015 and December 31, 2014.

11. Equity Method Investment

We own 49% of the membership interest in Maalt Specialized Bulk, L.L.C. (“Maalt”). We use the equity method of accounting to account for our investment in Maalt, which had a carrying value of $9.0 million as of June 30, 2015. We recorded equity method adjustments to our investment of $0.1 million, a nominal amount, $1.1 million and ($0.9) million for our share of Maalt’s income (loss) for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. We also made additional investments of $0.1 million and $0.1 million in the Current Period and Prior Period, respectively. As of June 30, 2015, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $8.3 million. This excess is attributable to goodwill recorded on Maalt’s financial statements and is not being amortized.

We review our equity method investment for impairment whenever certain impairment indicators exist including the absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment. A loss in value of an investment which is other than a temporary decline should be recognized. We estimated that the fair value of our investment in Maalt was approximately $7.9 million as of June 30, 2014, which was below the carrying value of the investment and resulted in a non-cash impairment charge of $4.5 million in the Prior Quarter, which is included in loss from equity investees on our condensed consolidated statements of operations. Estimated fair value for our investment in Maalt was determined using significant unobservable inputs (Level 3) based on an income approach.

12. Fair Value Measurements

The fair value measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price”). Authoritative guidance on fair value measurements and disclosures clarifies that a fair value measurement for a liability should reflect the entity’s non-performance risk. In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are:

Level 1- Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2- Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3- Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

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Fair Value on Recurring Basis

The carrying values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

Fair Value on Non-Recurring Basis

Fair value measurements were applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which consist primarily of long-lived asset impairments based on Level 3 inputs. See Note 5 for additional discussion.

Fair Value of Other Financial Instruments

The fair values of the Note Receivable and our debt are the estimated amounts a market participant would have to pay to purchase the Note Receivable or our debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. Estimated fair values are determined 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.



	June 30, 2015				December 31, 2014
	Carrying Amount		Fair Value (Level 2)		Carrying Amount		Fair Value (Level 2)
	(In thousands)
Financial assets:
Note Receivable	$	27,000	$	25,358	$	—	$	—

Financial liabilities:
6.625% Senior Notes due 2019	$	650,000	$	537,225	$	650,000	$	519,188
6.5% Senior Notes due 2022	$	460,000	$	285,200	$	500,000	$	296,250
Term Loans	$	495,750	$	456,120	$	398,000	$	379,095
Credit Facility	$	—	$	—	$	50,500	$	47,407

13. Concentration of Credit Risk and Major Customers

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and trade receivables. Accounts receivable from CHK and its affiliates were $177.5 million and $326.7 million as of June 30, 2015 and December 31, 2014, or 68% and 77%, respectively, of our total accounts receivable. Revenues from CHK and its affiliates were $203.2 million, $447.1 million, $520.5 million and $877.9 million for the Current Quarter, Prior Quarter, Current Period, and Prior Period, or 69%, 81%, 72% and 83%, respectively, of our total revenues. We believe that the loss of this customer would have a material adverse effect on our operating results as there can be no assurance that replacement customers would be identified and accessed in a timely fashion. See Note 14 for further discussion of agreements entered into as part of the spin-off, including a new services agreement and rig-specific daywork drilling contracts.

14. Transactions with CHK

Prior to the completion of our spin-off on June 30, 2014, we were a wholly owned subsidiary of CHK, and transactions between us and CHK (including its subsidiaries) were considered to be transactions with affiliates. Subsequent to June 30, 2014, CHK and its subsidiaries are not considered affiliates of us or any of our subsidiaries. We have disclosed below agreements entered into between us and CHK prior to the completion of our spin-off.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On June 25, 2014, we entered into a master separation agreement and several other agreements with CHK as part of the spin-off. The master separation agreement entered into between CHK and us governs the separation of our businesses from CHK, the distribution of our shares to CHK shareholders and other matters related to CHK’s relationship with us, including cross-indemnities between us and CHK. In general, CHK agreed to indemnify us for any liabilities relating to CHK’s business and we agreed to indemnify CHK for any liabilities relating to our business.

On June 25, 2014, we entered into a tax sharing agreement with CHK, which governs the respective rights, responsibilities and obligations of CHK and us with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes.

On June 25, 2014, we entered into an employee matters agreement with CHK providing that each company has responsibility for our own employees and compensation plans. The agreement also contains provisions concerning benefit protection for both SSE and CHK employees, treatment of holders of CHK stock options, restricted stock, restricted stock units and performance share units, and cooperation between us and CHK in the sharing of employee information and maintenance of confidentiality.

On June 25, 2014, we entered into a transition services agreement with CHK under which CHK provides or makes available to us various administrative services and assets for specified periods beginning on the distribution date. In consideration for such services, we pay CHK fees, a portion of which is a flat fee, generally in amounts intended to allow CHK to recover all of its direct and indirect costs incurred in providing those services. These charges from CHK were $2.7 million and $8.3 million for the Current Quarter and Current Period, respectively. This agreement was terminated during the Current Quarter.

We are party to a master services agreement with CHK pursuant to which we provide drilling and other services and supply materials and equipment to CHK. Drilling services are typically provided pursuant to rig-specific daywork drilling contracts similar to those we use for other customers. The specific terms of each request for other services are typically set forth in a field ticket, purchase order or work order. The master services agreement contains general terms and provisions, including minimum insurance coverage amounts that we are required to maintain and confidentiality obligations with respect to CHK’s business, and allocates certain operational risks between CHK and us through indemnity provisions. The master services agreement will remain in effect until we or CHK provides 30 days written notice of termination, although such agreement may not be terminated during the term of the services agreement described below.

Prior to the spin-off, we were party to a services agreement with CHK under which CHK guaranteed the utilization of a portion of our drilling rig and hydraulic fracturing fleets during the term of the agreement. In connection with the spin-off, we entered into new services agreements with CHK which supplements the master services agreement. Under the new services agreement, CHK is required to utilize the lesser of (i) seven, five and three of our pressure pumping crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for CHK in all its operating regions during the respective year. CHK is required to utilize our pressure pumping services for a minimum number of stages as set forth in the agreement. CHK is entitled to terminate the agreement in certain situations, including in the event we fail to materially comply with the overall quality of service provided by similar service providers. Additionally, CHK’s requirement to utilize our services may be suspended under certain circumstances, such as if we are unable to timely accept and supply services ordered by CHK or as a result of a force majeure event.

In connection with the spin-off, we entered into rig-specific daywork drilling contracts with CHK for the provision of drilling services. The drilling agreements have a commencement date of July 1, 2014 and a term ranging from three months to three years. CHK has the right to terminate the drilling agreements under certain circumstances.

Prior to the spin-off, we were party to a facilities lease agreement with CHK pursuant to which we leased a number of the storage yards and physical facilities out of which we conduct our operations. We incurred $4.1 million and $8.2 million of lease expense for the Prior Quarter and Prior Period, respectively, under this facilities lease agreement. In connection with the spin-off, we acquired the property subject to the facilities lease agreement, and the facilities lease agreement was terminated.

Prior to the spin-off, CHK provided us with general and administrative services and the services of its employees pursuant to an administrative services agreement. These services included legal, accounting, treasury, environmental, safety, information technology and other corporate services. In return for the general and administrative services provided by CHK, we reimbursed CHK on a monthly basis for the overhead expenses incurred by CHK on our behalf in accordance with its allocation policy, which included costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of CHK employees who perform services on our behalf. The administrative expense allocation

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was determined by multiplying revenues by a percentage determined by CHK based on the historical average of costs incurred on our behalf. All of the administrative cost allocations were based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operating as a stand-alone entity. These charges from CHK were $14.0 million and $26.8 million for the Prior Quarter and Prior Period, respectively. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement.

15. Segment Information

As of June 30, 2015, our revenues, income (loss) before income taxes and identifiable assets are primarily attributable to three reportable segments. During the Current Quarter, we sold the remaining business and assets included in the oilfield trucking segment. Our former oilfield trucking segment’s historical results for periods prior to the sales continue to be included in our historical financial results as a component of continuing operations as reflected in the tables below.

Each of these segments represents a distinct type of business. These segments have separate management teams which report to our chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. Management evaluates the performance of our segments based upon earnings before interest, taxes and depreciation and amortization. The following is a description of our segments and other operations:

Drilling. Our drilling segment provides land drilling and drilling-related services, including directional drilling for oil and natural gas exploration and development activities. As of June 30, 2015, we owned a fleet of 90 land drilling rigs.

Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation services. As of June 30, 2015, we owned 10 hydraulic fracturing fleets with an aggregate of 400,000 horsepower.

Oilfield Rentals. Our oilfield rentals segment provides premium rental tools for land-based oil and natural gas drilling, completion and workover activities.

Former Oilfield Trucking. Our oilfield trucking segment historically provided drilling rig relocation and logistics services as well as fluid handling services. During the Current Quarter, we sold Hodges, which provided drilling rig relocation and logistics services (see Note 2), and sold our water hauling assets. As part of the spin-off, we sold our crude hauling assets to a third party.

Other Operations. Prior to the spin-off, our other operations consist primarily of our compression unit manufacturing business and corporate functions, including our 2019 Notes, 2022 Notes, Term Loans and Credit Facility. As part of the spin-off, we distributed our compression unit manufacturing business to CHK.

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	Drilling			Hydraulic Fracturing			Oilfield Rentals			Former Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(In thousands)
For The Three Months Ended June 30, 2015:
Revenues	$	100,475		$	163,411		$	18,120		$	14,328		$	2,105		$	(3,311	)	$	295,128
Intersegment revenues	(31		)	—			(358		)	(817		)	(2,105		)	3,311			—
Total revenues	$	100,444		$	163,411		$	17,762		$	13,511		$	—		$	—		$	295,128
Depreciation and amortization	38,202			17,804			10,575			3,733			2,636			—			72,950
Loss on sale of a business	—			—			—			—			34,989			—			34,989
Losses (gains) on sales of property and equipment, net	3,564			4			(277		)	5,738			(19		)	—			9,010
Impairments and other	8,688			—			—			194			—			—			8,882
Interest expense	—			—			—			—			(24,968		)	—			(24,968		)
Gain on extinguishment of debt	—			—			—			—			13,085			—			13,085
Income from equity investees	—			136			—			—			—			—			136
Other income	35			923			29			7			49			—			1,043
Loss Before Income Taxes	$	(14,968	)	$	(705	)	$	(14,957	)	$	(20,042	)	$	(64,677	)	$	—		$	(115,349	)

For The Three Months Ended June 30, 2014:
Revenues	$	190,954		$	226,112		$	39,426		$	56,323		$	46,859		$	(10,208	)	$	549,466
Intersegment revenues	(1,777		)	—			(449		)	(872		)	(7,110		)	10,208			—
Total revenues	$	189,177		$	226,112		$	38,977		$	55,451		$	39,749		$	—		$	549,466
Depreciation and amortization	34,398			17,851			13,368			5,429			783			—			71,829
Losses (gains) on sales of property and equipment, net	14,086			—			(183		)	(22,863		)	(4		)	—			(8,964		)
Impairments and other^(a)	3,172			—			—			—			—			—			3,172
Interest expense	—			—			—			—			(17,615		)	—			(17,615		)
Loss from equity investees	—			(4,500		)	—			—			—			—			(4,500		)
Other income (expense)	213			(67		)	13			19			208			—			386
Income (Loss) Before Income Taxes	$	15,482		$	19,164		$	565		$	19,833		$	(19,298	)	$	—		$	35,746


(a)	Includes lease termination costs of $0.1 million for the Prior Quarter.

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	Drilling			Hydraulic Fracturing			Oilfield Rentals			Former Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(In thousands)
For The Six Months Ended June 30, 2015:
Revenues	$	266,529		$	365,428		$	50,686		$	45,512		$	4,172		$	(7,412	)	$	724,915
Intersegment revenues	(31		)	—			(436		)	(2,773		)	(4,172		)	7,412			—
Total revenues	$	266,498		$	365,428		$	50,250		$	42,739		$	—		$	—		$	724,915
Depreciation and amortization	87,739			34,081			22,747			8,787			4,571			—			157,925
Loss on sale of a business	—			—			—			—			34,989			—			34,989
Losses (gains) on sales of property and equipment	7,951			(1		)	(448		)	5,728			(10		)	—			13,220
Impairments and other	12,417			—			—			2,737			—			—			15,154
Interest expense	—			—			—			—			(48,484		)	—			(48,484		)
Gains on extinguishment of debt	—			—			—			—			13,085			—			13,085
Income from equity investees	—			1,108			—			—			—			—			1,108
Other (expense) income	(7		)	997			5			16			(64		)	—			947
(Loss) Income Before Income Taxes	$	(14,281	)	$	7,961		$	(19,980	)	$	(38,420	)	$	(104,462	)	$	—		$	(169,182	)

For The Six Months Ended June 30, 2014:
Revenues	$	373,065		$	427,732		$	75,604		$	113,761		$	88,215		$	(19,201	)	$	1,059,176
Intersegment revenues	(3,455		)	—			(685		)	(2,115		)	(12,946		)	19,201			—
Total revenues	$	369,610		$	427,732		$	74,919		$	111,646		$	75,269		$	—		$	1,059,176
Depreciation and amortization	69,301			35,960			26,715			11,357			961			—			144,294
Losses (gains) on sales of property and equipment	15,795			—			(925		)	(22,871		)	15			—			(7,986		)
Impairments and other^(a)	22,773			207			—			—			—			—			22,980
Interest expense	—			—			—			—			(32,307		)	—			(32,307		)
Loss from equity investees	—			(5,417		)	—			—			—			—			(5,417		)
Other income	545			37			27			37			111			—			757
Income (Loss) Before Income Taxes	$	11,794		$	20,370		$	(2,808	)	$	14,565		$	(37,428	)	$	—		$	6,493

As of June 30, 2015:
Total Assets	$	1,188,293		$	383,046		$	120,146		$	—		$	415,718		$	—		$	2,107,203
As of December 31, 2014:
Total Assets	$	1,322,160		$	449,966		$	155,683		$	138,909		$	247,013		$	(1,179	)	$	2,312,552


(a)	Includes lease termination costs of $8.4 million for the Prior Period.

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15. Condensed Consolidating Financial Information

In October 2011, we issued and sold the 2019 Notes with an aggregate principal amount of $650.0 million (see Note 6). In connection with the spin-off, COO transferred all of its assets, operations and liabilities, including the 2019 Notes, to SSO, which has been reflected retrospectively in the condensed consolidating financial information. Pursuant to the Indenture governing the 2019 Notes, such notes are fully and unconditionally and jointly and severally guaranteed by SSO’s parent, SSE, and all of SSO’s subsidiaries, other than SSF, which is a co-issuer of the 2019 Notes, and certain immaterial subsidiaries. Each of the subsidiary guarantors is 100% owned by SSO and there are no material subsidiaries of SSO other than the subsidiary guarantors. SSF and Western Wisconsin Sand Company, LLC are minor non-guarantor subsidiaries whose condensed consolidating financial information is included with the subsidiary guarantors. SSE and SSO have independent assets and operations. There are no significant restrictions on the ability of SSO or any subsidiary guarantor to obtain funds from its subsidiaries by dividend or loan.

Set forth below are condensed consolidating financial statements for SSE (“Parent”) and SSO (“Subsidiary Issuer”) on a stand-alone, unconsolidated basis, and their combined guarantor subsidiaries as of June 30, 2015 and December 31, 2014 and for the three and six months ended June 30, 2015 and 2014. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

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Condensed Consolidating Balance Sheet
	June 30, 2015
	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Assets:
Current Assets:
Cash	$	88	$	118,242		$	5		$	—		$	118,335
Accounts receivable, net	—		—			261,061			—			261,061
Inventory	—		—			22,895			—			22,895
Deferred income tax asset	—		1,005			3,026			—			4,031
Prepaid expenses and other	—		29,927			6,424			(22,883		)	13,468
Total Current Assets	88		149,174			293,411			(22,883		)	419,790
Property and Equipment:
Property and equipment, at cost	—		30,879			2,565,372			—			2,596,251
Less: accumulated depreciation	—		(1,551		)	(1,004,949		)	—			(1,006,500		)
Total Property and Equipment, Net	—		29,328			1,560,423			—			1,589,751
Other Assets:
Equity method investment	—		—			9,036			—			9,036
Goodwill	—		—			27,434			—			27,434
Deferred financing costs, net	5,788		21,720			—			—			27,508
Other long-term assets	—		100,176			5,788			(72,280		)	33,684
Investments in subsidiaries and intercompany advances	675,944		1,557,205			—			(2,233,149		)	—
Total Other Assets	681,732		1,679,101			42,258			(2,305,429		)	97,662
Total Assets	$	681,820	$	1,857,603		$	1,896,092		$	(2,328,312	)	$	2,107,203
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	58	$	2,518		$	34,663		$	—		$	37,239
Current portion of long-term debt	—		5,000			—			—			5,000
Other current liabilities	14,371		32,495			132,488			(22,883		)	156,471
Total Current Liabilities	14,429		40,013			167,151			(22,883		)	198,710
Long-Term Liabilities:
Deferred income tax liabilities	506		—			170,704			(72,280		)	98,930
Long-term debt, excluding current maturities	460,000		1,140,750			—			—			1,600,750
Other long-term liabilities	—		896			1,032			—			1,928
Total Long-Term Liabilities	460,506		1,141,646			171,736			(72,280		)	1,701,608
Total Stockholders’ Equity	206,885		675,944			1,557,205			(2,233,149		)	206,885
Total Liabilities and Stockholders’ Equity	$	681,820	$	1,857,603		$	1,896,092		$	(2,328,312	)	$	2,107,203

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Condensed Consolidating Balance Sheet
	December 31, 2014
	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Assets:
Current Assets:
Cash	$	77	$	733		$	81		$	—		$	891
Accounts receivable, net	—		4			421,551			—			421,555
Inventory	—		—			25,073			—			25,073
Deferred income tax asset	—		2,091			6,029			(657		)	7,463
Prepaid expenses and other	—		5,309			13,763			—			19,072
Total Current Assets	77		8,137			466,497			(657		)	474,054
Property and Equipment:
Property and equipment, at cost	—		22,397			2,727,489			—			2,749,886
Less: accumulated depreciation	—		(643		)	(982,190		)	—			(982,833		)
Total Property and Equipment, Net	—		21,754			1,745,299			—			1,767,053
Other Assets:
Equity method investment	—		—			7,816			—			7,816
Goodwill	—		—			27,434			—			27,434
Intangible assets, net	—		—			5,420			—			5,420
Deferred financing costs, net	6,740		17,111			—			—			23,851
Other long-term assets	—		38,950			5,731			(37,757		)	6,924
Investments in subsidiaries and intercompany advances	803,383		1,853,480			—			(2,656,863		)	—
Total Other Assets	810,123		1,909,541			46,401			(2,694,620		)	71,445
Total Assets	$	810,200	$	1,939,432		$	2,258,197		$	(2,695,277	)	$	2,312,552
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	—	$	6,579		$	39,078		$	—		$	45,657
Current portion of long-term debt	—		4,000			—			—			4,000
Other current liabilities	18,032		29,776			168,601			(657		)	215,752
Total Current Liabilities	18,032		40,355			207,679			(657		)	265,409
Long-Term Liabilities:
Deferred income tax liabilities	1,145		—			195,885			(37,757		)	159,273
Long-term debt, excluding current maturities	500,000		1,094,500			—			—			1,594,500
Other long-term liabilities	—		1,194			1,153			—			2,347
Total Long-Term Liabilities	501,145		1,095,694			197,038			(37,757		)	1,756,120
Total Stockholders’ Equity	291,023		803,383			1,853,480			(2,656,863		)	291,023
Total Liabilities and Stockholders’ Equity	$	810,200	$	1,939,432		$	2,258,197		$	(2,695,277	)	$	2,312,552

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Condensed Consolidating Statement of Operations
	Three Months Ended June 30, 2015
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues:
Revenues	$	—		$	—		$	296,053		$	(925	)	$	295,128
Operating Expenses:
Operating costs	—			—			239,127			—			239,127
Depreciation and amortization	—			796			72,154			—			72,950
General and administrative	(41		)	14,055			21,726			(925		)	34,815
Loss on sale of a business	—			34,989			—			—			34,989
(Gains) losses on sales of property and equipment, net	—			(19		)	9,029			—			9,010
Impairments and other	—			—			8,882			—			8,882
Total Operating Expenses	(41		)	49,821			350,918			(925		)	399,773
Operating Income (Loss)	41			(49,821		)	(54,865		)	—			(104,645		)
Other (Expense) Income:
Interest expense	(8,291		)	(16,677		)	—			—			(24,968		)
Gains on extinguishment of debt	13,085			—			—			—			13,085
Income from equity investees	—			—			136			—			136
Other (expense) income	—			79			964			—			1,043
Equity in net loss of subsidiary	(78,289		)	(37,053		)	—			115,342			—
Total Other (Expense) Income	(73,495		)	(53,651		)	1,100			115,342			(10,704		)
Loss Before Income Taxes	(73,454		)	(103,472		)	(53,765		)	115,342			(115,349		)
Income Tax Expense (Benefit)	1,216			(25,183		)	(16,712		)	—			(40,679		)
Net Loss	$	(74,670	)	$	(78,289	)	$	(37,053	)	$	115,342		$	(74,670	)

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Condensed Consolidating Statement of Operations
	Three Months Ended June 30, 2014
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Revenues	$	—		$	1,120		$	549,444		$	(1,098	)	$	549,466
Operating Expenses:
Operating costs	—			1,695			406,517			(1,626		)	406,586
Depreciation and amortization	—			46			71,783			—			71,829
General and administrative	—			4,958			14,410			—			19,368
Gains on sales of property and equipment, net	—			—			(8,964		)	—			(8,964		)
Impairments and other	—			—			3,172			—			3,172
Total Operating Expenses	—			6,699			486,918			(1,626		)	491,991
Operating (Loss) Income	—			(5,579		)	62,526			528			57,475
Other (Expense) Income:
Interest expense	(451		)	(17,164		)	—			—			(17,615		)
Loss from equity investees	—			—			(4,500		)	—			(4,500		)
Other income	—			147			239			—			386
Equity in net earnings of subsidiary	21,991			35,811			—			(57,802		)	—
Total Other Income (Expense)	21,540			18,794			(4,261		)	(57,802		)	(21,729		)
Income Before Income Taxes	21,540			13,215			58,265			(57,274		)	35,746
Income Tax (Benefit) Expense	(170		)	(8,450		)	22,454			202			14,036
Net Income	$	21,710		$	21,665		$	35,811		$	(57,476	)	$	21,710

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Condensed Consolidating Statement of Operations
	Six Months Ended June 30, 2015
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues:
Revenues	$	—		$	—		$	726,589		$	(1,674	)	$	724,915
Operating Expenses:
Operating costs	—			—			570,738			—			570,738
Depreciation and amortization	—			863			157,062			—			157,925
General and administrative	27			25,971			44,403			(1,674		)	68,727
Loss on sale of a business				34,989			—			—			34,989
(Gains) losses on sales of property and equipment, net	—			(19		)	13,239			—			13,220
Impairments and other	—			—			15,154			—			15,154
Total Operating Expenses	27			61,804			800,596			(1,674		)	860,753
Operating Loss	(27		)	(61,804		)	(74,007		)	—			(135,838		)
Other (Expense) Income:
Interest expense	(16,550		)	(31,934		)	—			—			(48,484		)
Gains on early extinguishment of debt	13,085			—			—			—			13,085
Income from equity investees	—			—			1,108			—			1,108
Other (expense) income	—			(54		)	1,001			—			947
Equity in net loss of subsidiary	(110,074		)	(49,719		)	—			159,793			—
Total Other (Expense) Income	(113,539		)	(81,707		)	2,109			159,793			(33,344		)
Loss Before Income Taxes	(113,566		)	(143,511		)	(71,898		)	159,793			(169,182		)
Income Tax Benefit	(1,295		)	(33,437		)	(22,179		)	—			(56,911		)
Net Loss	$	(112,271	)	$	(110,074	)	$	(49,719	)	$	159,793		$	(112,271	)

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Condensed Consolidating Statement of Operations
	Six Months Ended June 30, 2014
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Revenues	$	—		$	2,263		$	1,059,132		$	(2,219	)	$	1,059,176
Operating Expenses:
Operating costs	—			3,607			816,015			(3,448		)	816,174
Depreciation and amortization	—			66			144,228			—			144,294
General and administrative	—			12,217			28,037			—			40,254
Gains on sales of property and equipment, net	—			—			(7,986		)	—			(7,986		)
Impairments and other	—			—			22,980			—			22,980
Total Operating Expenses	—			15,890			1,003,274			(3,448		)	1,015,716
Operating (Loss) Income	—			(13,627		)	55,858			1,229			43,460
Other (Expense) Income:
Interest expense	(451		)	(31,856		)	—			—			(32,307		)
Loss from equity investees	—			—			(5,417		)	—			(5,417		)
Other income	—			147			610			—			757
Equity in net earnings of subsidiary	3,436			30,991			—			(34,427		)	—
Total Other Income (Expense)	2,985			(718		)	(4,807		)	(34,427		)	(36,967		)
Income (Loss) Before Income Taxes	2,985			(14,345		)	51,051			(33,198		)	6,493
Income Tax (Benefit) Expense	(170		)	(17,020		)	20,060			468			3,338
Net Income	$	3,155		$	2,675		$	30,991		$	(33,666	)	$	3,155

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Condensed Consolidating Statements of Cash Flows
	Six Months Ended June 30, 2015
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash Flows From Operating Activities:	$	(19,080	)	$	118,144		$	289,803		$	(229,190	)	$	159,677
Cash Flows From Investing Activities:
Additions to property and equipment	—			(10,998		)	(79,726		)	—			(90,724		)
Proceeds from sales of assets	—			127			16,240			—			16,367
Proceeds from sale of a business				15,000			—			—			15,000
Additions to investments	—			—			(112		)	—			(112		)
Distributions from affiliates	45,496			—			—			(45,496		)	—
Other	—			—			3,392			—			3,392
Net cash provided by (used in) investing activities	45,496			4,129			(60,206		)	(45,496		)	(56,077		)
Cash Flows From Financing Activities:
Borrowings from revolving credit facility	—			160,100			—			—			160,100
Payments on revolving credit facility	—			(210,600		)	—			—			(210,600		)
Payments to extinguish senior notes	(26,405		)	—			—			—			(26,405		)
Proceeds from issuance of term loan, net of issuance costs	—			94,481			—			—			94,481
Payments on term loan	—			(2,250		)	—			—			(2,250		)
Deferred financing costs	—			(784		)	—			—			(784		)
Distributions to affiliates	—			(45,496		)	(229,190		)	274,686			—
Other	—			(215		)	(483		)	—			(698		)
Net cash (used in) provided by financing activities	(26,405		)	(4,764		)	(229,673		)	274,686			13,844
Net increase (decrease) in cash	11			117,509			(76		)	—			117,444
Cash, beginning of period	77			733			81			—			891
Cash, end of period	$	88		$	118,242		$	5		$	—		$	118,335

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



Condensed Consolidating Statements of Cash Flows
	Six Months Ended June 30, 2014
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash Flows From Operating Activities:	$	57,184		$	(4,589	)	$	167,476		$	(98,137	)	$	121,934
Cash Flows From Investing Activities:
Additions to property and equipment	—			(7,550		)	(249,228		)	—			(256,778		)
Proceeds from sale of assets	—			—			60,939			—			60,939
Additions to investment	—			—			(131		)	—			(131		)
Contributions to affiliates	(121,670		)	(63,994		)	—			185,664			—
Other	—			—			35			—			35
Net cash used in investing activities	(121,670		)	(71,544		)	(188,385		)	185,664			(195,935		)
Cash Flows From Financing Activities:
Borrowings from revolving credit facility	—			716,500			—			—			716,500
Payments on revolving credit facility	—			(1,099,100		)	—			—			(1,099,100		)
Proceeds from issuance of senior notes, net of offering costs	493,825			—			—			—			493,825
Proceeds from issuance of term loan, net of offering costs	—			393,879			—			—			393,879
Deferred financing costs	—			(2,385		)	—			—			(2,385		)
Distributions to CHK	(421,920		)	—			—			—			(421,920		)
Contributions from affiliates	—			66,632			20,895			(87,527		)	—
Net cash provided by financing activities	71,905			75,526			20,895			(87,527		)	80,799
Net increase (decrease) in cash	7,419			(607		)	(14		)	—			6,798
Cash, beginning of period	—			1,613			65			—			1,678
Cash, end of period	$	7,419		$	1,006		$	51		$	—		$	8,476

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

16. Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest—Imputation of Interest,” which simplifies the presentation of debt issuance costs by requiring debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts. ASU 2015-03 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements—Going Concern,” which requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). ASU 2014-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application permitted. We are currently evaluating what impact this standard will have on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Revenue Recognition (Topic 605),” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application not permitted. On July 9, 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. The FASB plans to issue a final ASU to amend ASU 2014-09 by the end of the third quarter of 2015. We are currently evaluating what impact this standard will have on our consolidated financial statements.



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

The following discussion and analysis of our financial condition and results of operations relates to the three and six months ended June 30, 2015 (the “Current Quarter” and “Current Period,” respectively), the three and six months ended June 30, 2014 (the “Prior Quarter” and “Prior Period,” respectively), and the three months ended March 31, 2015 (the “Previous Quarter”) and should be read in conjunction with our condensed consolidated financial statements and related notes appearing elsewhere in this quarterly report on Form 10-Q and with our Annual Report on Form 10-K for the year ended December 31, 2014.

Comparability of Historical Results

The historical results discussed in this section prior to June 30, 2014 are those of COO, which is our predecessor. The transactions in which SSE became an independent, publicly traded company, including the distribution of our common stock on June 30, 2014, are referred to collectively as the “spin-off”. The historical results discussed in this section prior to the spin-off do not purport to reflect what the results of operations, financial position, equity or cash flows would have been had we operated as an independent public company prior to June 30, 2014 and do not give effect to certain spin-off transactions on our consolidated statements of operations. For a detailed description of the transactions completed and agreements entered into as part of the spin-off, please read Note 1 to our consolidated financial statements contained in our Annual Report on Form 10-K.

Overview

We are a diversified oilfield services company providing a wide range of wellsite services to U.S. land-based E&P customers operating in unconventional resource plays. We offer services and equipment that are strategic to our customers’ oil and natural gas operations. We conduct our business through three operating segments: Drilling, Hydraulic Fracturing and Oilfield Rentals. Our operations are geographically diversified across many of the most active oil and natural gas plays in the onshore United States, including the Anadarko and Permian Basins and the Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales.

Since we commenced operations in 2001, we have actively grown our business and modernized our asset base. As of June 30, 2015, our marketed fleet consisted of 28 Tier 1 rigs, including 18 proprietary PeakeRigs™, 57 Tier 2 rigs and three Tier 3 rigs. As of June 30, 2015, we also owned 10 hydraulic fracturing fleets with an aggregate of 400,000 horsepower and a diversified oilfield rentals business. We continue to modernize our asset base and are currently building seven additional PeakeRigs™. For additional information regarding our business and strategies, please read “Business” in Item 1 of our Annual Report on Form 10-K.

Cyclical Nature of Industry

We operate in a highly cyclical industry. The main factor influencing demand for oilfield services is the level of drilling and completions activity by E&P companies, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. The most critical factors in assessing the outlook for the industry are the worldwide supply and demand for oil and the domestic supply and demand for natural gas. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. When oil and natural gas price increases occur, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supply and reduced prices that, in turn, tends to reduce demand for oilfield services. For these reasons, our results of operations may fluctuate from quarter-to-quarter and from year-to-year.

The recent decline in commodity prices has reduced the level of United States drilling and completion activity and, consequently, the demand for our services. Since mid-2014, NYMEX WTI oil prices have declined by more than 50% to their lowest levels since 2009, as global production growth led by unconventional resource development onshore in the United States outpaced demand. In addition, NYMEX natural gas prices have fallen from multi-year highs in early 2014 as sustained production growth has outpaced domestic demand. We believe our modern, high-quality asset base, diversified footprint and strong relationship with CHK will partially offset the consequences of decreasing drilling and completions activity levels; however, we expect to experience reduced equipment utilization and increased market pricing pressure across each of our operating segments in 2015 until there is a sustained recovery in commodity prices and robust demand for our services returns. The extent and length of the current down cycle is uncertain. If it is prolonged or worsens, it would likely have a material adverse impact on our business, financial condition, results of operations, and cash flows.

Backlog

We maintain a backlog of contract revenues under our contracts for the provision of drilling and hydraulic fracturing services. Our drilling and hydraulic fracturing backlogs as of June 30, 2015 were approximately $574.3 million and $560.3 million, respectively, with average durations of 17 months and 14 months, respectively. We calculate our drilling backlog by multiplying the day rate under our contracts by the number of days remaining under the contract. We calculate our hydraulic fracturing backlog by multiplying the estimated rate per stage, based on then current contract pricing, by the number of guaranteed stages remaining under the contract. With respect to our hydraulic fracturing backlog, our contracts provide for periodic adjustments of the rates we may charge for our services thereunder, which will be negotiated based on then-prevailing market pricing and in the future may be higher or lower than the current rates we charge. Our drilling backlog calculation does not include any reduction in revenues related to mobilization or demobilization, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, many of our contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. We calculate our contract drilling early termination value assuming each rig remains stacked for the remainder of the term of the terminated contract. As a result, revenues could differ materially from the backlog and early termination amounts presented.

As of June 30, 2015, we expect to recognize revenues from backlog as follows (in millions):



	2015		2016		Thereafter
Backlog	$	346.6	$	533.2	$	254.8

As of June 30, 2015, our total contract early termination value related to our drilling backlog was as follows (in millions):



	2015		2016		Thereafter
Drilling contract early termination value	$	101.1	$	170.7	$	86.6

How We Evaluate Our Operations

Our management team uses a variety of tools to monitor and manage our operations in the following eight areas: (a) segment gross margin, (b) equipment maintenance performance, (c) customer satisfaction, (d) asset utilization, (e) safety performance, (f) Adjusted EBITDA, (g) adjusted revenues and (h) adjusted operating costs.

Segment Gross Margin. We define segment gross margin as segment revenues less segment operating costs, excluding depreciation and amortization, general and administrative expenses, net gains or losses on sales of property and equipment and impairments and other. We view segment gross margin as one of our key management tools for managing costs at the segment level and evaluating segment performance. Our management tracks segment gross margin both as an absolute amount and as a percentage of revenues compared to prior periods.

Equipment Maintenance Performance. Equipment reliability (“uptime”) is an important factor to the success of our business. Uptime is beneficially impacted through preventive maintenance on our equipment. We have formal preventive maintenance procedures which are regularly monitored for compliance. Further, management monitors maintenance expenses as a percentage of revenue. This metric provides a leading indicator with respect to the execution of preventive maintenance and ensures that equipment reliability issues do not negatively impact operational uptime.

Customer Satisfaction. Upon completion of many of our services, we encourage our customers to provide feedback on the services provided. The evaluation of our performance is based on various criteria and our customer comments are indicative of their overall satisfaction level. This feedback provides us with the necessary information to reinforce positive performance and remedy negative issues and trends.

Asset Utilization. By consistently monitoring our operations’ activity levels, pricing and relative performance of each of our rigs and fleets, we can more efficiently allocate our personnel and equipment to maximize revenue generation. We measure our activity levels by the total number of jobs completed by each of our drilling rigs and hydraulic fracturing fleets on a periodic basis. We also monitor the utilization rates of our drilling rigs. We define utilization of our drilling rigs as the number of rigs that have operated in the past 30 days divided by the number of rigs that have operated in the last 90 days.

Safety Performance. Maintaining a safe and incident free workplace is a critical component of our operational success. Our management team uses both lagging and leading indicators to measure and manage safety performance. Total Recordable Incident Rate (“TRIR”), Lost Time Incident Rate (“LTIR”) and Motor Vehicle Crash Rate (“MVCR”) are key lagging indicators reviewed by management. We also review leading indicators such as safety observations, training completion, and action item completion to enhance our view of safety performance. Safety performance data is reported, tracked, and trended in a centralized database, which allows us to efficiently focus our incident prevention efforts.

Adjusted EBITDA. The primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business is Adjusted EBITDA, which we define as net income before interest expense, income tax expense, depreciation and amortization, as further adjusted to add back non-cash stock compensation, impairments and other, gain or loss on sale of property and equipment, rig rent expense and certain non-recurring items, such as the sale of our drilling rig relocation and logistics business, the distribution of our compression manufacturing and geosteering businesses to CHK and the sale of our crude and water hauling assets. The table below shows our Adjusted EBITDA for the three and six months ended June 30, 2015 and 2014 and the three months ended March 31, 2015.



	Three Months Ended							Six Months Ended
	June 30,					March 31,		June 30,
	2015			2014		2015		2015		2014
	(In thousands)
Adjusted EBITDA:
Consolidated	$	44,321		$	114,766	$	93,344	$	137,665	$	198,503
Drilling	$	38,342		$	68,882	$	64,010	$	102,350	$	131,214
Hydraulic Fracturing	$	18,206		$	41,669	$	26,258	$	44,464	$	61,818
Oilfield Rentals	$	(4,102	)	$	13,844	$	7,792	$	3,690	$	23,819

Adjusted Revenues and Adjusted Operating Costs. Key financial and operating measurements that our management uses to analyze and monitor our period-over-period operating performance are “adjusted revenues” and “adjusted operating costs”, which we define as revenues and operating costs before revenues and operating costs associated with our rig relocation and logistics business and water hauling assets that were sold in the Current Quarter, our compression unit manufacturing business and geosteering businesses that were distributed to CHK and our crude hauling assets that were sold to a third party as part of the spin-off. Adjusted operating costs are further adjusted to subtract rig rent expense and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled as part of the spin-off.

Non-GAAP Financial Measures

“Adjusted EBITDA”, “adjusted revenues” and “adjusted operating costs” are non-GAAP financial measures. Adjusted EBITDA, adjusted revenues and adjusted operating costs as used and defined by us, may not be comparable to similarly titled measures employed by other companies and are not measures of performance calculated in accordance with generally accepted accounting principles (“GAAP”).

Adjusted revenues and adjusted operating costs should not be considered in isolation or as a substitute for revenues and operating costs, respectively, prepared in accordance with GAAP. However, our management uses adjusted revenues and adjusted operating costs to evaluate our period over period operating performance because our management believes these measures improve the comparability of our continuing business and for the same reasons believes these measures may be useful to an investor in evaluating our operating performance. A reconciliation of adjusted revenues and adjusted operating costs to the GAAP measures of revenues and operating costs, respectively, is provided below in “—Results of Operations” for each period discussed.

Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. However, our management uses Adjusted EBITDA to evaluate our performance and liquidity and believes Adjusted EBITDA may be useful to an investor in evaluating our operating performance and liquidity because this measure:


•	is widely used by investors in the oilfield services industry to measure a company’s operating performance without regard to items excluded from the calculation of such measure, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;


•	is a financial measurement that is used by rating agencies, lenders and other parties to evaluate our creditworthiness; and


•	is used by our management for various purposes, including as a measure of performance of our operating entities and as a basis for strategic planning and forecasting.

There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss. Additionally, because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

On a consolidated basis, the following tables present a reconciliation of Adjusted EBITDA to the GAAP financial measures of net loss and cash provided by operating activities. The following tables also present a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income or loss for each of our operating segments.

Consolidated



	Three Months Ended									Six Months Ended
	June 30,						March 31,			June 30,
	2015			2014			2015			2015			2014
	(In thousands)
Net (loss) income	$	(74,670	)	$	21,710		$	(37,601	)	$	(112,271	)	$	3,155
Add:
Interest expense	24,968			17,615			23,516			48,484			32,307
Gains on extinguishment of debt	(13,085		)	—			—			(13,085		)	—
Income tax (benefit) expense	(40,679		)	14,036			(16,232		)	(56,911		)	3,338
Depreciation and amortization	72,950			71,829			84,975			157,925			144,294
Loss on sale of a business	34,989			—			—			34,989			—
Losses (gains) on sales of property and equipment, net	9,010			(8,964		)	4,210			13,220			(7,986		)
Impairments and other	8,882			3,172			6,272			15,154			22,980
Impairment of equity method investment	—			4,500			—			—			4,500
Non-cash compensation	13,131			(146		)	18,355			31,486			—
Severance-related costs	3,102			123			1,404			4,506			290
Rent expense on buildings and real estate transferred from CHK^(a)	—			4,081			—			—			8,187
Rig rent expense^(b)	—			6,016			—			—			15,075
Interest income	(108		)	—			—			(108		)	—
Less:
Drilling rig relocation and logistics Adjusted EBITDA	(5,886		)	5,260			(3,859		)	(9,745		)	8,217
Water hauling Adjusted EBITDA	55			817			(4,586		)	(4,531		)	(74		)
Geosteering Adjusted EBITDA	—			763			—			—			957
Crude hauling Adjusted EBITDA	—			(4,521		)	—			—			(5,066		)
Compression unit manufacturing Adjusted EBITDA	—			6,357			—			—			13,073
Non-recurring credit to stock-based compensation expense	—			10,530			—			—			10,530
Adjusted EBITDA	$	44,321		$	114,766		$	93,344		$	137,665		$	198,503

(a)

Rent on buildings and real estate transferred from CHK as part of the spin-off is included in operating costs and general and administrative expenses on the condensed consolidated statements of operations included in Item 1 of this report. Our operating costs include $4.0 million and $8.0 million of rent expense associated with our lease of these facilities for the Prior Quarter and Prior Period, respectively. Our general and administrative expenses include $0.1 million and $0.2 million of rent expense associated with our lease of these facilities for the Prior Quarter and Prior Period, respectively.


(b)	Rig rent expense associated with our lease of drilling rigs is included in operating costs on the condensed consolidated statements of operations included in Item 1 of this report. As of December 31, 2014, we had repurchased all of our leased drilling rigs.



	Three Months Ended									Six Months Ended
	June 30,						March 31,			June 30,
	2015			2014			2015			2015			2014
	(In thousands)
Cash provided by operating activities	$	132,164		$	67,352		$	27,513		$	159,677		$	121,934
Add:
Changes in operating assets and liabilities	(121,471		)	41,782			35,102			(86,369		)	40,154
Interest expense	24,968			17,615			23,516			48,484			32,307
Lease termination costs	—			70			—			—			8,449
Amortization of sale/leaseback gains	—			925			—			—			5,139
Amortization of deferred financing costs	(1,107		)	(3,235		)	(1,028		)	(2,135		)	(3,972		)
Income (loss) from equity investees	136			—			972			1,108			(917		)
Provision for doubtful accounts	(4		)	(1,032		)	(2,580		)	(2,584		)	(1,115		)
Current tax expense	—			363			—			—			696
Severance-related costs	3,102			123			1,404			4,506			290
Rent expense on buildings and real estate transferred from CHK^(a)	—			4,081			—			—			8,187
Rig rent expense^(b)	—			6,016			—			—			15,075
Interest income	(108		)	—			—			(108		)	—
Other	810			(88		)	—			810			(87		)
Less:
Drilling rig relocation and logistics Adjusted EBITDA	(5,886		)	5,260			(3,859		)	(9,745		)	8,217
Water hauling Adjusted EBITDA	55			817			(4,586		)	(4,531		)	(74		)
Geosteering Adjusted EBITDA	—			763			—			—			957
Crude hauling Adjusted EBITDA	—			(4,521		)	—			—			(5,066		)
Compression unit manufacturing Adjusted EBITDA	—			6,357			—			—			13,073
Non-recurring credit to stock-based compensation expense	—			10,530			—			—			10,530
Adjusted EBITDA	$	44,321		$	114,766		$	93,344		$	137,665		$	198,503

(a)


(b)	Rig rent expense associated with our lease of drilling rigs is included in operating costs on the condensed consolidated statements of operations included in Item 1 of this report. As of December 31, 2014, we had repurchased all of our leased drilling rigs.

Drilling



	Three Months Ended							Six Months Ended
	June 30,					March 31,		June 30,
	2015			2014		2015		2015			2014
	(In thousands)
Net (loss) income	$	(9,689	)	$	9,541	$	479	$	(9,210	)	$	7,182
Add:
Income tax (benefit) expense	(5,279		)	5,941		207		(5,072		)	4,612
Depreciation and amortization	38,202			34,398		49,539		87,739			69,301
Losses on sales of property and equipment, net	3,564			14,086		4,386		7,951			15,795
Impairments and other	8,688			3,172		3,729		12,417			22,773
Non-cash compensation	2,344			—		5,326		7,669			—
Severance-related costs	512			—		344		856			63
Rent expense on buildings and real estate transferred from CHK	—			809		—		—			1,688
Rig rent expense	—			6,016		—		—			15,075
Less:
Geosteering Adjusted EBITDA	—			763		—		—			957
Non-recurring credit to stock-based compensation expense	—			4,318		—		—			4,318
Adjusted EBITDA	$	38,342		$	68,882	$	64,010	$	102,350		$	131,214

Hydraulic Fracturing



	Three Months Ended								Six Months Ended
	June 30,					March 31,			June 30,
	2015			2014		2015			2015			2014
	(In thousands)
Net (loss) income	$	(457	)	$	11,722	$	6,054		$	5,597		$	12,317
Add:
Income tax (benefit) expense	(248		)	7,443		2,613			2,365			8,052
Depreciation and amortization	17,804			17,851		16,277			34,081			35,960
Losses (gains) on sales of property and equipment, net	4			—		(5		)	(1		)	—
Impairments and other	—			—		—			—			207
Impairment of equity method investment	—			4,500		—			—			4,500
Non-cash compensation	1,043			—		1,238			2,281			—
Severance-related costs	60			—		81			141			—
Rent expense on buildings and real estate transferred from CHK	—			630		—			—			1,259
Less:
Non-recurring credit to stock-based compensation expense	—			477		—			—			477
Adjusted EBITDA	$	18,206		$	41,669	$	26,258		$	44,464		$	61,818

Oilfield Rentals



	Three Months Ended									Six Months Ended
	June 30,						March 31,			June 30,
	2015			2014			2015			2015			2014
	(In thousands)
Net (loss) income	$	(9,682	)	$	340		$	(3,509	)	$	(13,191	)	$	(1,796	)
Add:
Income tax (benefit) expense	(5,275		)	225			(1,515		)	(6,790		)	(1,013		)
Depreciation and amortization	10,575			13,368			12,172			22,747			26,715
Gains on sales of property and equipment, net	(277		)	(183		)	(171		)	(448		)	(925		)
Non-cash compensation	523			—			861			1,384			—
Severance-related costs (credits)	34			—			(46		)	(12		)	24
Rent expense on buildings and real estate transferred from CHK	—			695			—			—			1,415
Less:
Non-recurring credit to stock-based compensation expense	—			601			—			—			601
Adjusted EBITDA	$	(4,102	)	$	13,844		$	7,792		$	3,690		$	23,819

Liquidity and Capital Resources

We require capital to fund ongoing operations, including operating expenses, organic growth initiatives, investments, acquisitions and debt service. We expect our future capital needs will be provided for by cash flows from operations, borrowings under our Credit Facility, access to capital markets and other financing transactions. We believe we will have adequate liquidity over the next twelve months to operate our business and meet our cash requirements.

As of June 30, 2015, we had cash of $118.3 million and working capital of $221.1 million. As of December 31, 2014, we had cash of $0.9 million and working capital of $208.6 million. As of July 27, 2015, we had cash of $117.5 million.

Long-Term Debt

The following table presents our long-term debt as of June 30, 2015 and December 31, 2014:



	June 30, 2015		December 31, 2014
	(in thousands)
6.625% Senior Notes due 2019	$	650,000	$	650,000
6.50% Senior Notes due 2022	460,000		500,000
Term Loans	495,750		398,000
Credit Facility	—		50,500
Total debt	1,605,750		1,598,500
Less: Current portion of long-term debt	5,000		4,000
Total long-term debt	$	1,600,750	$	1,594,500

During the Current Quarter, we entered into an incremental $100.0 million junior lien financing under the Incremental Term Loan and received net proceeds of $94.5 million.

During the Current Quarter, we repurchased and cancelled $40.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $26.4 million. We recognized gains on extinguishment of debt of $13.1 million, which includes the amortization of unamortized deferred financing costs of $0.5 million.

As of June 30, 2015, we had no outstanding borrowings under our revolving bank credit facility, letters of credit of $10.2 million, and availability of $264.8 million. As of July 27, 2015, we had availability of $188.1 million which included no borrowings and $10.2 million for letters of credit.

For further information on our long-term debt, please read Note 6 to our condensed consolidated financial statements included Item 1 of this report.

Capital Expenditures

Our business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. Prior to 2015, our capital requirements consisted primarily of:


•	growth capital expenditures, which are defined as capital expenditures made to acquire additional equipment and other assets, increase our service lines, expand geographically or advance other strategic initiatives for the purpose of growing our business;


•	maintenance capital expenditures, which are defined as capital expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of components and equipment which are worn or obsolete; and


•	the purchase of leased drilling rigs.

We anticipate that our capital requirements in 2015 will consist primarily of growth capital expenditures and maintenance capital expenditures.

Total capital expenditures, including growth, maintenance and the purchase of leased drilling rigs, were $90.7 million and $256.8 million for the Current Period and Prior Period, respectively. During the Prior Period, we purchased 31 of our leased drilling rigs for approximately $131.0 million. We currently expect our total capital expenditures to be approximately $200.0 million for 2015. We may increase, decrease or reallocate our anticipated capital expenditures during any period based on industry conditions, the availability of capital or other factors, and a significant component of our anticipated capital spending is discretionary.

Cash Flow

Our cash flow depends in large part on the level of spending by our customers on exploration, development and production activities. Sustained increases or decreases in the price of oil or natural gas could have a material impact on these activities, thus materially affecting our cash flows. The following is a discussion of our cash flow for the Current Period and Prior Period.



	Six Months Ended June 30,
	2015			2014
	(Unaudited) (In thousands)
Cash Flow Statement Data:
Net cash provided by operating activities	$	159,677		$	121,934
Net cash used in investing activities	$	(56,077	)	$	(195,935	)
Net cash provided by financing activities	$	13,844		$	80,799
Cash, beginning of period	$	891		$	1,678
Cash, end of period	$	118,335		$	8,476

Operating Activities. Cash provided by operating activities was $159.7 million and $121.9 million for the Current Period and Prior Period, respectively. Changes in working capital items increased (decreased) cash provided by operating activities by $86.4 million and ($40.2) million for the Current Period and Prior Period, respectively. During the Current Period, the increase in cash provided by operating activities due to changes in working capital items was impacted by the timing of collection of accounts receivable and the decline in overall operational activity. Factors affecting changes in operating cash flows are largely the same as those that affect net income, with the exception of non-cash expenses such as depreciation and amortization,

amortization of sale-leaseback gains, gains or losses on sales of property and equipment, impairments, non-cash compensation, gains or losses from equity investees and deferred income taxes.

Investing Activities. Cash used in investing activities was $56.1 million and $195.9 million for the Current Period and Prior Period, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the Current Period and Prior Period were related to our investment in new PeakeRigs™ and the purchase of certain leased drilling rigs. We purchased 31 leased drilling rigs for approximately $131.0 million during the Prior Period. Cash used in investing activities was partially offset by proceeds from the sale of Hodges of $15.0 million during the Current Period and proceeds from asset sales in the amounts of $16.4 million and $60.9 million for the Current Period and Prior Period, respectively.

Financing Activities. Net cash provided by financing activities was $13.8 million and $80.8 million for the Current Quarter and Prior Quarter, respectively. During the Current Period, we borrowed $100.0 million under the Incremental Term Loan and received net proceeds of $94.5 million. During the Prior Period, we entered into a $400.0 million seven-year term loan credit agreement and received net proceeds of $393.9 million, which we used to repay and terminate an existing credit facility in connection with the spin-off. We made term loan repayments of $2.3 million during the Current Period. During the Prior Period, we issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 and used the net proceeds of $493.8 million from the 2022 Notes issuance to make a distribution of approximately $391.0 million to Chesapeake and for general corporate purposes. During the Current Period, we repurchased and cancelled $40.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $26.4 million. We had borrowings and repayments under our credit facilities of $160.1 million and $210.6 million, respectively, during the Current Period, and $716.5 million and $1.099 billion, respectively, during the Prior Period. We paid deferred borrowing costs of $0.8 million and $2.4 million during the Current Period and Prior Period, respectively.

Results of Operations

Results of Operations—Three Months Ended June 30, 2015 vs. March 31, 2015

The following table sets forth our condensed consolidated statements of operations for the Current Quarter and Previous Quarter.



	Three Months Ended
	June 30, 2015			March 31, 2015
	(In thousands)
Revenues:
Revenues	$	295,128		$	429,787
Operating Expenses:
Operating costs	239,127			331,611
Depreciation and amortization	72,950			84,975
General and administrative	34,815			33,912
Loss on sale of a business	34,989			—
Losses on sales of property and equipment, net	9,010			4,210
Impairments and other	8,882			6,272
Total Operating Expenses	399,773			460,980
Operating Loss	(104,645		)	(31,193		)
Other (Expense) Income:
Interest expense	(24,968		)	(23,516		)
Gains on extinguishment of debt	13,085			—
Income from equity investees	136			972
Other income (expense)	1,043			(96		)
Total Other Expense	(10,704		)	(22,640		)
Loss Before Income Taxes	(115,349		)	(53,833		)
Income Tax Benefit	(40,679		)	(16,232		)
Net Loss	$	(74,670	)	$	(37,601	)

Revenues. For the Current Quarter and Previous Quarter, revenues were $295.1 million and $429.8 million, respectively. The $134.7 million decrease in revenues was primarily due to decreased utilization and pricing pressure during the Current Quarter. The majority of our revenues have historically been derived from CHK and its working interest partners. The percentage of our revenues derived from CHK was 69% and 74% for the Current Quarter and the Previous Quarter, respectively. Our revenues and adjusted revenues for the Current Quarter and Previous Quarter are detailed below:



	Three Months Ended
	June 30, 2015		March 31, 2015
	(In thousands)
Drilling	$	100,444	$	166,054
Hydraulic fracturing	163,411		202,017
Oilfield rentals	17,762		32,488
Former oilfield trucking	13,511		29,228
Total	$	295,128	$	429,787

Adjusted Revenue^(a):
Revenue	$	295,128	$	429,787
Less:
Drilling rig relocation and logistics revenues	10,578		23,830
Water hauling revenues	2,933		5,398
Adjusted Revenue	$	281,617	$	400,559

(a)

“Adjusted revenue” is a non-GAAP financial measure that we define as revenues before revenues associated with the drilling rig relocation and logistics business and water hauling assets sold during the Current Quarter. For a description of our calculation of adjusted revenues and the reasons why our management uses this measure to evaluate our business, please read “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Operating Costs. Operating costs for the Current Quarter and Previous Quarter were $239.1 million and $331.6 million, respectively. The $92.5 million decrease in operating costs from the Previous Quarter to the Current Quarter was primarily due to a decrease in labor-related costs driven by reductions in headcount, a decrease in repairs and maintenance expenses as a result of lower fleet utilization in our drilling segment and a decrease in product costs in our hydraulic fracturing segment. Adjusted operating costs were $220.7 million and $295.3 million for the Current Quarter and Prior Quarter, respectively, which excludes operating costs associated with our former drilling rig relocation and logistics business and the water hauling assets sold in the Current Quarter. As a percentage of adjusted revenues, adjusted operating costs were 78% and 74% for the Current Quarter and Previous Quarter, respectively. Our operating costs and adjusted operating costs for the Current Quarter and Previous Quarter are detailed below:



	Three Months Ended
	June 30, 2015		March 31, 2015
	(In thousands)
Drilling	$	57,148	$	98,140
Hydraulic fracturing	141,225		171,305
Oilfield rentals	20,224		23,619
Former oilfield trucking	18,382		36,291
Other operations	2,148		2,256
Total	$	239,127	$	331,611

Adjusted Operating Costs^(a):
Operating Costs	$	239,127	$	331,611
Less:
Drilling rig relocation and logistics operating costs	15,596		26,980
Water hauling operating costs	2,786		9,311
Adjusted Operating Costs	$	220,745	$	295,320

(a)

“Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with the drilling rig relocation and logistics business and water hauling assets sold during the Current Quarter. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, please read “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Drilling



	Three Months Ended
	June 30, 2015		March 31, 2015
	(In thousands)
Revenues	$	100,444	$	166,054
Operating costs	57,148		98,140
Gross margin	$	43,296	$	67,914
Adjusted EBITDA	$	38,342	$	64,010

Drilling revenues for the Current Quarter decreased $65.6 million, or 40%, from the Previous Quarter. This decrease was primarily due to a 51% decline in revenue days associated with rigs under contract being idled. Average revenue per revenue day increased 1% due to improvement in the tier mix of our working drilling rigs. Revenues from non-CHK customers decreased $31.1 million to 36% of total segment revenues in the Current Quarter compared to 41% for the Previous Quarter.

Drilling operating costs for the Current Quarter decreased $41.0 million, or 42%, from the Previous Quarter, due to a decrease in labor-related costs driven by a reduction in headcount and a decrease in repairs and maintenance expenses as a result of lower fleet utilization. Average operating costs per revenue day in the Current Quarter increased 17% from the Prior Quarter, which was primarily driven by a 24% increase in labor-related costs per revenue day due to the rapid pace at which

drilling rigs were idled during the Current Quarter. As a percentage of drilling revenues, drilling operating costs were 57% and 59% for the Current Quarter and the Previous Quarter, respectively.

Hydraulic Fracturing



	Three Months Ended
	June 30, 2015		March 31, 2015
	(In thousands)
Revenues	$	163,411	$	202,017
Operating costs	141,225		171,305
Gross margin	$	22,186	$	30,712
Adjusted EBITDA	$	18,206	$	26,258

Hydraulic fracturing revenues for the Current Quarter decreased $38.6 million, or 19%, from the Previous Quarter. This decrease was due to a 16% decline in revenues per stage and a 4% decline in stages completed during the Current Quarter. Revenues from non-CHK customers increased $19.7 million to 21% of total segment revenues in the Current Quarter compared to 7% for the Previous Quarter.

Hydraulic fracturing operating costs for the Current Quarter decreased $30.1 million, or 18% from the Previous Quarter, primarily due to a 19% decrease in product costs per stage, which is the result of leveraging our logistics infrastructure advantage and closely managing our supply chain. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs were 86% and 85% for Current Quarter and Previous Quarter, respectively.

Oilfield Rentals



	Three Months Ended
	June 30, 2015			March 31, 2015
	(In thousands)
Revenues	$	17,762		$	32,488
Operating costs	20,224			23,619
Gross margin	$	(2,462	)	$	8,869
Adjusted EBITDA	$	(4,102	)	$	7,792

Oilfield rental revenues for the Current Quarter decreased $14.7 million, or 45%, from the Previous Quarter. The decrease was primarily due to a decline in utilization attributable to reductions in drilling and completions activity by our customers. Revenues from non-CHK customers decreased $3.4 million during the Current Quarter as compared to the Prior Quarter. However, as a percentage of total segment revenues, revenues from non-CHK customers increased to 62% of total segment revenues in the Current Quarter compared to 44% for the Previous Quarter.

Oilfield rental operating costs for the Current Quarter decreased $3.4 million, or 14%, from the Previous Quarter. The decreased was primarily due a to decline in labor-related costs driven by reductions in headcount. As a percentage of oilfield rental revenues, oilfield rental operating costs were 114% and 73% for the Current Quarter and Previous Quarter, respectively. Labor-related costs as a percentage of revenues increased by 50% during the Current Quarter due to the rapid pace at which CHK reduced its capital spending coupled with the broader reduction in U.S. drilling and completions activity.

Former Oilfield Trucking



	Three Months Ended
	June 30, 2015			March 31, 2015
	(In thousands)
Revenues	$	13,511		$	29,228
Operating costs	18,382			36,291
Gross margin	$	(4,871	)	$	(7,063	)

During the Current Quarter, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in the oilfield trucking segment.

Oilfield trucking revenues for the Current Quarter decreased $15.7 million, or 54%, from the Previous Quarter. Oilfield trucking operating costs for the Current Quarter decreased $17.9 million or 49%, from the Previous Quarter. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 136% and 124% for the Current Quarter and Previous Quarter, respectively.

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Previous Quarter was $73.0 million and $85.0 million, respectively. The decrease is primarily due to a change in accounting estimate for estimated useful lives of certain components of drilling rigs and certain drilling rigs. Please read Note 3 to our condensed consolidated financial statements in Item 1 of this report. As a percentage of revenues, depreciation and amortization expense was 25% and 20% for the Current Quarter and Previous Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Previous Quarter were $34.8 million and $33.9 million, respectively. We incurred non-cash compensation expenses of $8.6 million and $9.5 million and severance-related costs of $3.1 million and $1.4 million during the Current Quarter and Previous Quarter, respectively. Included in the non-cash compensation expenses and severance-related costs for the Current Quarter are $2.1 million and $0.6 million, respectively, related to the sale of Hodges. We incurred charges of $2.7 million and $5.6 million for services provided by CHK pursuant to the transition services agreement during the Current Quarter and Previous Quarter, respectively. As a percentage of revenues, general and administrative expenses were 12% and 8% for the Current Quarter and Prior Quarter, respectively. As of June 30, 2015, we terminated all remaining services being provided by CHK under the transition services agreement.

Loss on Sale of a Business. On June 14, 2015, we sold Hodges, our previously wholly-owned subsidiary that provided drilling rig relocation and logistics services, to Aveda for aggregate consideration of $42.0 million. We recognized a loss of $35.0 million on the sale during the Current Quarter.

Losses on Sales of Property and Equipment, Net. We recorded losses on sales of property and equipment of $9.0 million and $4.2 million during the Current Quarter and Previous Quarter, respectively. During the Current Quarter, we sold our water hauling assets. During the Previous Quarter, we sold ancillary equipment not utilized in our business.

Impairments and Other. During the Current Quarter and Previous Quarter, we recognized impairments of $8.9 million and $6.3 million, respectively. During the Current Quarter, we recognized impairment charges of $8.7 million and $0.2 million related to drilling-related services equipment and trucking and fluid disposal equipment, respectively, that we deemed to be impaired based on expected future cash flows of this equipment. During the Previous Quarter, we recognized impairment charges of $3.3 million and $2.5 million for certain drilling rigs and trucking and fluid disposal equipment, respectively, that we impaired based on expected future cash flows of these rigs and equipment.

Interest Expense. Interest expense for the Current Quarter and Previous Quarter was $25.0 million and $23.5 million, respectively, related to borrowings under our senior notes, term loans, and credit facility. The increase in interest expense from the Previous Quarter to the Current Quarter was primarily due to borrowings under the Incremental Term Loan incurred in the Current Quarter.

Gains on Extinguishment of Debt. During the Current Quarter, we repurchased and cancelled $40.0 million in aggregate principal amount of the 2022 Notes in multiple transactions for $26.4 million. We recognized gains on extinguishment of debt of $13.1 million, which includes amortization of unamortized deferred financing costs of $0.5 million.

Income from Equity Investee. Income from equity investees was $0.1 million and $1.0 million for the Current Quarter and Previous Quarter, respectively, which was a result of our investments in Maalt. We own 49% of the membership interest in Maalt.

Other Income (Expense). Other income (expense) was $1.0 million and ($0.1) million for the Current Quarter and Previous Quarter, respectively.

Income Tax Benefit. We recorded income tax benefit of $40.7 million and $16.2 million for the Current Quarter and Previous Quarter, respectively. The $24.5 million increase in income tax benefit recorded for the Current Quarter was primarily the result of an increase in net loss before taxes of $61.5 million from the Previous Quarter to the Current Quarter. Our effective income tax rate for the Current Quarter and Previous Quarter was 35% and 30%, respectively. The increase in our effective tax

rate from the Previous Quarter to the Current Quarter was primarily the result of permanent differences having a greater impact on our effective income tax rate in the Previous Quarter due to a lower pre-tax loss.

Three Months Ended June 30, 2015 vs. June 30, 2014

The following table sets forth our condensed consolidated statements of operations for the Current Quarter and Prior Quarter.



	Three Months Ended June 30,
	2015			2014
	(In thousands)
Revenues:
Revenues	$	295,128		$	549,466
Operating Expenses:
Operating costs	239,127			406,586
Depreciation and amortization	72,950			71,829
General and administrative	34,815			19,368
Loss on sale of a business	34,989			—
Losses (gains) on sales of property and equipment, net	9,010			(8,964		)
Impairments and other	8,882			3,172
Total Operating Expenses	399,773			491,991
Operating (Loss) Income	(104,645		)	57,475
Other (Expense) Income:
Interest expense	(24,968		)	(17,615		)
Gains on extinguishment of debt	13,085			—
Income (loss) from equity investees	136			(4,500		)
Other income	1,043			386
Total Other Expense	(10,704		)	(21,729		)
(Loss) Income Before Income Taxes	(115,349		)	35,746
Income Tax (Benefit) Expense	(40,679		)	14,036
Net (Loss) Income	$	(74,670	)	$	21,710

Revenues. For the Current Quarter and Prior Quarter, revenues were $295.1 million and $549.5 million, respectively, representing a decrease of $254.4 million. Adjusted revenues were $281.6 million and $452.7 million for the Current Quarter and Prior Quarter, respectively, which excludes the impact of the drilling rig relocation and logistics business and water hauling assets that were sold in the Current Quarter, our compression unit manufacturing business and geosteering businesses that were distributed to CHK and our crude hauling assets that were sold to a third party as part of the spin-off. The $171.1 million decrease in adjusted revenues for the Current Quarter compared to adjusted revenues for the Prior Quarter was primarily due to decreased utilization and pricing pressure. The majority of our revenues have historically been derived from CHK and its working interest partners. The percentage of our revenues derived from CHK was 69% and 81% for the Current Quarter and Prior Quarter, respectively. Our revenues and adjusted revenues for the Current Quarter and Prior Quarter are detailed below:



	Three Months Ended June 30,
	2015		2014
	(In thousands)
Drilling	$	100,444	$	189,177
Hydraulic fracturing	163,411		226,112
Oilfield rentals	17,762		38,977
Former oilfield trucking	13,511		55,451
Other operations	—		39,749
Total	$	295,128	$	549,466

Adjusted Revenue^(a):
Revenue	$	295,128	$	549,466
Less:
Drilling rig relocation and logistics revenues	10,578		32,203
Water hauling revenues	2,933		12,718
Compression unit manufacturing revenues	—		39,320
Geosteering revenues	—		2,014
Crude hauling revenues	—		10,530
Adjusted Revenue	$	281,617	$	452,681

(a)

“Adjusted revenue” is a non-GAAP financial measure that we define as revenues before revenues associated with our rig relocation and logistics business and water hauling assets that were sold in the Current Quarter, our compression unit manufacturing and geosteering businesses that were distributed to CHK, and our crude hauling assets that were sold to a third party as part of the spin-off. For a description of our calculation of adjusted revenues and the reasons why our management uses this measure to evaluate our business, please read “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Operating Costs. Operating costs for the Current Quarter and Prior Quarter were $239.1 million and $406.6 million, respectively, a decrease of $167.5 million. Adjusted operating costs were $220.7 million and $323.0 million for the Current Quarter and Prior Quarter, respectively, which excludes operating costs associated with the drilling rig relocation and logistics business and water hauling assets that were sold in the Current Quarter, our compression unit manufacturing and geosteering businesses that were distributed to CHK, and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled as part of the spin-off. The $102.3 million decrease in adjusted operating costs from the Prior Quarter to the Current Quarter was primarily due to reductions in headcount, a decline in utilization in our drilling and oilfield rental segments and a decrease in product costs in our hydraulic fracturing segment. As a percentage of adjusted revenues, adjusted operating costs were 78% and 71% for the Current Quarter and Prior Quarter, respectively. Our operating costs and adjusted operating costs for the Current Quarter and Prior Quarter are detailed below:



	Three Months Ended June 30,
	2015		2014
	(In thousands)
Drilling	$	57,148	$	118,354
Hydraulic fracturing	141,225		179,283
Oilfield rentals	20,224		24,534
Former oilfield trucking	18,382		51,451
Other operations	2,148		32,964
Total	$	239,127	$	406,586

Adjusted Operating Costs^(a):
Operating Costs	$	239,127	$	406,586
Add:
Non-recurring credit to stock-based compensation expense	—		7,360
Less:
Drilling rig relocation and logistics operating costs	15,596		25,295
Water hauling operating costs	2,786		11,661
Rig rent expense	—		6,016
Geosteering operating costs	—		1,208
Crude hauling operating costs	—		14,495
Compression unit manufacturing operating costs	—		32,259
Adjusted Operating Costs	$	220,745	$	323,012

(a)

“Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with our drilling rig relocation and logistics business and water hauling assets that were sold in the Current Quarter, our compression unit manufacturing and geosteering businesses that were distributed to CHK, and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to add a non-recurring credit to share-based compensation expense that resulted from the cancellation of CHK awards at spin-off and subtract rig rent expense. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Drilling



	Three Months Ended June 30,
	2015		2014
	(In thousands)
Revenues	$	100,444	$	189,177
Operating costs^(a)	57,148		118,354
Gross margin	$	43,296	$	70,823
Adjusted EBITDA	$	38,342	$	68,882

Adjusted Revenues^(b):
Revenues	$	100,444	$	189,177
Less:
Geosteering revenues	—		2,014
Adjusted Revenues^(b)	$	100,444	$	187,163

Adjusted Operating Costs^(b):
Operating costs^(a)	$	57,148	$	118,354
Add:
Non-recurring credit to share-based compensation expense	—		4,318
Less:
Geosteering operating costs	—		1,208
Rig rent expense	—		6,016
Adjusted Operating Costs^(b)	$	57,148	$	115,448


(a)	Our drilling operating costs primarily consist of labor-related costs, repairs and maintenance, and direct contract-related expenses, such as mobilization and equipment rentals. Our operating costs include $6.0 million of rig rent expense associated with our lease of drilling rigs for the Prior Quarter.

(b)

“Adjusted revenues” and “Adjusted operating costs” are non-GAAP financial measures that we define as revenues and operating costs before revenues and operating costs associated with the geosteering business distributed to CHK. Operating costs are further adjusted add a non-recurring credit to share-based compensation expense that resulted from the cancellation of CHK awards at spin-off and subtract rig rent expense. For a description of our calculation of adjusted revenues and adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Drilling revenues for the Current Quarter decreased $88.7 million, or 47%, from the Prior Quarter, which was primarily due to a 56% decrease in revenue days associated with rigs under contract being idled. In addition, average revenue per revenue day for the Current Quarter increased 2% from the Prior Quarter primarily due to improvement in the tier mix of our working drilling rigs. Revenues from non-CHK customers increased $23.3 million to 36% of total segment revenues in the Current Quarter compared to 31% for the Prior Quarter.

Drilling operating costs for the Current Quarter decreased $61.2 million, or 52%, from the Prior Quarter, due primarily to reductions in headcount and lower fleet utilization. As a percentage of drilling revenues, drilling operating costs were 57% and 63% for the Current Quarter and the Prior Quarter, respectively. As a percentage of drilling revenues, rig rent expense was 3% for the Prior Quarter.

Hydraulic Fracturing



	Three Months Ended June 30,
	2015		2014
	(In thousands)
Revenues	$	163,411	$	226,112
Operating costs	141,225		179,283
Gross margin	$	22,186	$	46,829
Adjusted EBITDA	$	18,206	$	41,669

Adjusted Operating Costs^(a):
Operating costs	$	141,225	$	179,283
Add:
Non-recurring credit to share-based compensation expense	$	—	$	477
Adjusted Operating Costs^(a)	$	141,225	$	179,760

(a)

“Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs adjusted for a non-recurring credit to share-based compensation expense that resulted from the cancellation of CHK awards at spin-off. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Hydraulic fracturing revenues for the Current Quarter decreased $62.7 million, or 28%, from the Prior Quarter, which was primarily due to a 41% decrease in revenues per stage, partially offset by a 22% increase in completed stages. Revenues from non-CHK customers increased $30.1 million to 21% of total segment revenues in the Current Quarter compared to 2% in the Prior Quarter.

Hydraulic fracturing operating costs for the Current Quarter decreased $38.1 million, or 21% from the Prior Quarter, primarily due to a 26% decrease in product costs and reduced labor-related costs. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs were 86% and 79% for Current Quarter and Prior Quarter, respectively.

Oilfield Rentals



	Three Months Ended June 30,
	2015			2014
	(In thousands)
Revenues	$	17,762		$	38,977
Operating costs	20,224			24,534
Gross margin	$	(2,462	)	$	14,443
Adjusted EBITDA	$	(4,102	)	$	13,844

Adjusted Operating Costs^(a):
Operating costs	$	20,224		$	24,534
Add:
Non-recurring credit to share-based compensation expense	$	—		$	601
Adjusted Operating Costs^(a)	$	20,224		$	25,135

(a)

Oilfield rental revenues for the Current Quarter decreased $21.2 million, or 54%, from the Prior Quarter, which was primarily due to a decline in utilization and pricing pressure. Revenues from non-CHK customers increased $4.6 million to 62% of total segment revenues in the Current Quarter compared to 16% for the Prior Quarter.

Oilfield rental operating costs for the Current Quarter decreased $4.3 million, or 18%, from the Prior Quarter, which was primarily due to lower repairs and maintenance expenses driven by lower utilization and decreases in labor-related costs driven by reductions in headcount. As a percentage of oilfield rental revenues, oilfield rental operating costs were 114% and 63% for the Current Quarter and Prior Quarter, respectively.

Former Oilfield Trucking



	Three Months Ended June 30,
	2015			2014
	(In thousands)
Revenues	$	13,511		$	55,451
Operating costs	18,382			51,451
Gross margin	$	(4,871	)	$	4,000

Oilfield trucking revenues for the Current Quarter decreased $41.9 million, or 76%, from the Prior Quarter. Oilfield trucking operating costs for the Current Quarter decreased $33.1 million or 64%, from the Prior Quarter. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 136% and 93% for the Current Quarter and Prior Quarter, respectively.

Other Operations



	Three Months Ended June 30,
	2015			2014
	(In thousands)
Revenues	$	—		$	39,749
Operating costs	2,148			32,964
Gross margin	$	(2,148	)	$	6,785

Adjusted Revenue^(a):
Revenue	$	—		$	39,749
Less:
Compression unit manufacturing revenues	—			39,320
Adjusted Revenue^(a)	$	—		$	429

Adjusted Operating Costs^(a):
Operating Costs	$	2,148		$	32,964
Add:
Non-recurring credit to share-based compensation expense	—			138
Less:
Compression unit manufacturing operating costs	—			32,259
Adjusted Operating Costs^(a)	$	2,148		$	843

(a)

“Adjusted revenues” and “Adjusted operating costs” are non-GAAP financial measures that we define as revenues and operating costs before revenues and operating costs associated with the compressor manufacturing business distributed to CHK, further adjusted to add a non-recurring credit to share-based compensation expense that resulted from the cancellation of CHK awards at spin-off. For a description of our calculation of adjusted revenues and adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression manufacturing business to CHK. This business historically had been included in our other operations results.

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Prior Quarter was $73.0 million and $71.8 million, respectively. As a percentage of revenues, depreciation and amortization expense was 25% and 13% for the Current Quarter and Prior Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Prior Quarter were $34.8 million and $19.4 million, respectively. The increase was primarily due to an increase in labor-related costs and secondarily, the incremental costs of being a stand-alone public entity. Prior to the spin-off, we were allocated corporate overhead from CHK which covered the costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement under which CHK provided or made available to us various administrative services and assets for specified periods beginning on the distribution date. During the Current Quarter, we incurred charges of $2.7 million for services provided by CHK pursuant to the transition services agreement and terminated all remaining services being provided by CHK. During the Prior Quarter, we incurred charges of $14.0 million pursuant to the administrative services agreement. We incurred non-cash compensation expenses (benefit) of $8.6 million and ($0.1) million and severance-related costs of $3.1 million and $0.1 million during the Current Quarter and Prior Quarter, respectively. Included in the non-cash compensation expenses and severance-related costs for the Current Quarter are $2.1 million and $0.6 million, respectively, related to the sale of Hodges. As a percentage of revenues, general and administrative expenses were 12% and 4% for the Current Quarter and Prior Quarter, respectively.

Losses (Gains) on Sales of Property and Equipment, Net. We recorded losses (gains) on sales of property and equipment of $9.0 million and ($9.0) million during the Current Quarter and Previous Quarter, respectively. During the Current Quarter, we sold our water hauling assets. During the Prior Quarter, we sold 14 drilling rigs and ancillary equipment that were not being utilized in our business as well as our crude hauling fleet, which included 124 fluid handling tricks and 122 trailers.

Impairments and Other. During the Current Quarter and Prior Quarter, we recognized impairments of $8.9 million and $3.2 million, respectively. During the Current Quarter, we recognized impairment charges of $8.7 million and $0.2 million related to drilling-related services equipment and trucking and fluid disposal equipment, respectively, that we deemed to be impaired based on expected future cash flows of this equipment. During the Prior Quarter, we recognized $2.9 million of impairment charges related to certain drilling rigs that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. During the Prior Quarter, we also purchased 11 leased drilling rigs and paid lease termination costs of approximately $0.1 million. We also identified certain other property and equipment during the Prior Quarter that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the related equipment and recognized impairments of $0.2 million related to this equipment.

Interest Expense. Interest expense for the Current Quarter and Prior Quarter was $25.0 million and $17.6 million, respectively, related to borrowings under our senior notes, term loans, and credit facility. The increase in interest expense from the Prior Quarter to the Current Quarter was primarily due to the additional debt issued in conjunction with the spin-off.

Income (loss) from Equity Investee. Income (loss) from equity investees was $0.1 million and ($4.5) million for the Current Quarter and Prior Quarter, respectively, which was a result of our investment in Maalt. We recognized an impairment of $4.5 million during the Prior Quarter. We own 49% of the membership interest in Maalt.

Other Income. Other income was $1.0 million and $0.4 million for the Current Quarter and Prior Quarter, respectively.

Income Tax (Benefit) Expense. We recorded income tax (benefit) expense of ($40.7) million and $14.0 million for the Current Quarter and Prior Quarter, respectively. The $54.7 million decrease in income tax (benefit) expense recorded for the Current Quarter was primarily the result of a decrease in net income before taxes of $151.1 million from the Prior Quarter to the Current Quarter. Our effective income tax rate for the Current Quarter and Prior Quarter was 35% and 39%, respectively. The decrease in our effective tax rate from the Prior Quarter to the Current Quarter was primarily the result of permanent differences in the Current Quarter.

Results of Operations—Six Months Ended June 30, 2015 vs. June 30, 2014

The following table sets forth our condensed consolidated statements of operations for the Current Period and Prior Period.



	Six Months Ended June 30,
	2015			2014
	(In thousands)
Revenues:
Revenues	$	724,915		$	1,059,176
Operating Expenses:
Operating costs	570,738			816,174
Depreciation and amortization	157,925			144,294
General and administrative	68,727			40,254
Loss on sale of a business	34,989			—
Losses (gains) on sales of property and equipment, net	13,220			(7,986		)
Impairments and other	15,154			22,980
Total Operating Expenses	860,753			1,015,716
Operating (Loss) Income	(135,838		)	43,460
Other (Expense) Income:
Interest expense	(48,484		)	(32,307		)
Gains on extinguishment of debt	13,085			—
Income (loss) from equity investees	1,108			(5,417		)
Other income	947			757
Total Other Expense	(33,344		)	(36,967		)
(Loss) Income Before Income Taxes	(169,182		)	6,493
Income Tax (Benefit) Expense	(56,911		)	3,338
Net (Loss) Income	$	(112,271	)	$	3,155

Revenues. For the Current Period and Prior Period, revenues were $724.9 million and $1.059 billion, respectively, reflecting a decrease of $334.3 million. Adjusted revenues were $682.2 million and $868.9 million for the Current Period and Prior Period, respectively, which excludes the impact of the drilling rig relocation and logistics business and water hauling assets that were sold in the Current Period, our compression unit manufacturing and geosteering businesses that were distributed to CHK, and our crude hauling assets that were sold to a third party as part of the spin-off. The $186.7 million decrease in adjusted revenues was due primarily to decreased utilization and pricing pressure. The majority of our revenues historically have been derived from CHK and its working interest partners. The percentage of our revenues derived from CHK was 72% and 83% for the Current Period and Prior Period, respectively. Our revenues and adjusted revenues for the Current Period and Prior Period are detailed below:



	Six Months Ended June 30,
	2015		2014
	(In thousands)
Drilling	$	266,498	$	369,610
Hydraulic fracturing	365,428		427,732
Oilfield rentals	50,250		74,919
Former oilfield trucking	42,739		111,646
Other operations	—		75,269
Total	$	724,915	$	1,059,176

Adjusted Revenue^(a):
Revenue	$	724,915	$	1,059,176
Less:
Drilling rig relocation and logistics revenues	34,408		63,037
Water hauling revenues	8,331		24,780
Compression unit manufacturing revenues	—		74,650
Geosteering revenues	—		3,940
Crude hauling revenues	—		23,829
Adjusted Revenue	$	682,176	$	868,940

(a)

“Adjusted revenue” is a non-GAAP financial measure that we define as revenues before revenues associated with our drilling rig relocation and logistics business and water hauling assets that were sold in the Current Quarter, our compression unit manufacturing and geosteering businesses that were distributed to CHK, and our crude hauling assets that were sold to a third party as part of the spin-off. For a description of our calculation of adjusted revenues and the reasons our why management uses this measure to evaluate our business, please read “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Operating Costs. Operating costs for the Current Period and Prior Period were $570.7 million and $816.2 million, respectively, representing a decrease of $245.5 million. Adjusted operating costs for the Current Period and the Prior Period were $516.1 million and $639.9 million, respectively, which excludes operating costs associated with the drilling rig relocation and logistics business and water hauling assets that were sold in the Current Period, our compression unit manufacturing and geosteering businesses that were distributed to CHK, and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled as part of the spin-off. The $123.8 million decrease in adjusted operating costs from the Prior Period to the Current Period was primarily due to reductions in headcount, a decline in utilization in our drilling and oilfield rental segments and a decrease in product costs in our hydraulic fracturing segment. As a percentage of adjusted revenues, adjusted costs were 76% and 74% for the Current Period and Prior Period, respectively. Our operating costs and adjusted operating costs for the Current Period and Prior Period are detailed below:



	Six Months Ended June 30,
	2015		2014
	(In thousands)
Drilling	$	155,288	$	242,814
Hydraulic fracturing	312,530		356,295
Oilfield rentals	43,843		50,483
Former oilfield trucking	54,674		105,065
Other operations	4,403		61,517
Total	$	570,738	$	816,174

Adjusted Operating Costs^(a):
Operating Costs	$	570,738	$	816,174
Add:
Non-recurring credit to stock compensation expense	—		7,360
Less:
Drilling rig relocation and logistics operating costs	42,577		53,173
Water hauling operating costs	12,097		24,638
Rig rent expense	—		15,075
Geosteering operating costs	—		2,895
Crude hauling operating costs	—		27,254
Compression unit manufacturing operating costs	—		60,616
Adjusted Operating Costs^(a)	$	516,064	$	639,883

(a)

“Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with our rig relocation and logistics business and water hauling assets that were sold in the Current Quarter, our compression unit manufacturing and geosteering businesses that were distributed to CHK, and our crude hauling assets that were sold to a third party as part of the spin-off, further adjusted to add a non-recurring credit to share-based compensation expense that resulted from the cancellation of CHK awards at spin-off and subtract rig rent expense. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Drilling



	Six Months Ended June 30,
	2015		2014
	(In thousands)
Revenues	$	266,498	$	369,610
Operating costs^(a)	155,288		242,814
Gross margin	$	111,210	$	126,796
Adjusted EBITDA	$	102,350	$	131,214

Adjusted Revenues^(b):
Revenues	$	266,498	$	369,610
Less:
Geosteering revenues	—		3,940
Adjusted Revenues^(b)	$	266,498	$	365,670

Adjusted Operating Costs^(b):
Operating costs^(a)	$	155,288	$	242,814
Add:
Non-recurring credit to share-based compensation expense	—		4,318
Less:
Rig rent expense	—		15,075
Geosteering operating costs	—		2,895
Adjusted Operating Costs^(b)	$	155,288	$	229,162


(a)	Our drilling operating costs primarily consist of labor-related costs, repairs and maintenance, and direct contract-related expenses, such as mobilization and equipment rentals. Our operating costs include $15.1 million of rig rent expense associated with our lease of drilling rigs for the Prior Period.

(b)

Drilling revenues for the Current Period decreased $103.1 million, or 28%, from the Prior Period, which was primarily due to a 32% decrease in revenue days associated with rigs under contract being idled. Average revenue per revenue day for the Current Period increased 1% from the Prior Period primarily due to improvement in the tier mix of our working drilling rigs. Revenues from non-CHK customers decreased $8.5 million during the Current Period as compared to the Prior Period. However, revenues from non-CHK customers increased to 39% of total segment revenues in the Current Period compared to 30% for the Prior Period.

Drilling operating costs for the Current Period decreased $87.5 million, or 36%, from the Prior Period primarily due to a decrease in labor-related costs driven by reductions in headcount, lower repairs and maintenance expense driven by lower fleet utilization and a reduction in rig rent expense. As a percentage of drilling revenues, drilling operating costs were 58% and 66% for the Current Period and the Prior Period, respectively. As a percentage of drilling revenues, rig rent expense was 4% for the Prior Period.

Hydraulic Fracturing



	Six Months Ended June 30,
	2015		2014
	(In thousands)
Revenues	$	365,428	$	427,732
Operating costs	312,530		356,295
Gross margin	$	52,898	$	71,437
Adjusted EBITDA	$	44,464	$	61,818

Adjusted Operating Costs^(a):
Operating costs	$	312,530	$	356,295
Add:
Non-recurring credit to share-based compensation expense	—		477
Adjusted Operating Costs^(a)	$	312,530	$	356,772

(a)

Hydraulic fracturing revenues for the Current Period decreased $62.3 million, or 15%, from the Prior Period, which was primarily due to a 37% decrease in revenues per stage, partially offset by a 35% increase in stages completed. Revenues from non-CHK customers increased $45.1 million to 14% of total segment revenues in the Current Period compared to 1% for the Prior Period.

Hydraulic fracturing operating costs for the Current Period decreased $43.8 million, or 12%, from the Prior Period, which was primarily due to a 12% decrease in product costs. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs were 86% and 83% for Current Period and Prior Period, respectively.

Oilfield Rentals



	Six Months Ended June 30,
	2015		2014
	(In thousands)
Revenues	$	50,250	$	74,919
Operating costs	43,843		50,483
Gross margin	$	6,407	$	24,436
Adjusted EBITDA	$	3,690	$	23,819

Adjusted Operating Costs^(a):
Operating costs	$	43,843	$	50,483
Add:
Non-recurring credit to share-based compensation expense	—		601
Adjusted Operating Costs^(a)	$	43,843	$	51,084

(a)

Oilfield rental revenues for the Current Period decreased $24.7 million, or 33%, from the Prior Period, which was primarily due to a decline in utilization and pricing pressure. Revenues from non-CHK customers increased $15.2 million to 50% of total segment revenues in the Current Period compared to 13% for the Prior Period.

Oilfield rental operating costs for the Current Period decreased $6.6 million, or 13%, from the Prior Period. The decrease was primarily due to a decrease in repairs and maintenance expenses due to lower utilization and a decrease in labor-related costs driven by reductions in headcount. As a percentage of oilfield rental revenues, oilfield rental operating costs were 87% and 67% for the Current Period and Prior Period, respectively.

Former Oilfield Trucking



	Six Months Ended June 30,
	2015			2014
	(In thousands)
Revenues	$	42,739		$	111,646
Operating costs	54,674			105,065
Gross margin	$	(11,935	)	$	6,581

During the Current Period, we sold our drilling rig relocation and logistics business and water hauling assets. As of June 30, 2015, there were no remaining assets or operations in the oilfield trucking segment.

Oilfield trucking revenues for the Current Period decreased $68.9 million, or 62%, from the Prior Period. Oilfield trucking operating costs for the Current Period decreased $50.4 million, or 48%, from the Prior Period. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 128% and 94% for the Current Period and Prior Period, respectively.

Other Operations



	Six Months Ended June 30,
	2015			2014
	(In thousands)
Revenues	$	—		$	75,269
Operating costs	4,403			61,517
Gross margin	$	(4,403	)	$	13,752

Adjusted Revenue^(a):
Revenue	$	—		$	75,269
Less:
Compression unit manufacturing revenues	—			74,650
Adjusted Revenue^(a)	$	—		$	619

Adjusted Operating Costs^(a):
Operating Costs	$	4,403		$	61,517
Add:
Non-recurring credit to share-based compensation expense	—			138
Less:
Compression unit manufacturing operating costs	—			60,616
Adjusted Operating Costs^(a)	$	4,403		$	1,039

Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression manufacturing business to CHK, which was historically included in our other operations results.

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Period and Prior Period was $157.9 million and $144.3 million, respectively. The increase is primarily due to a change in accounting estimate for estimated useful lives of certain components of drilling rigs and certain drilling rigs. Please read Note 3 to our condensed consolidated financial statements in Item 1 of this report. As a percentage of revenues, depreciation and amortization expense was 22% and 14% for the Current Period and Prior Period, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Period and Prior Period were $68.7 million and $40.3 million, respectively. The increase was primarily due to an increase in labor-related costs and secondarily, the incremental costs of being a stand-alone public entity. Prior to the spin-off, we were allocated corporate overhead from CHK which covered costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement under which CHK provided or made available to us various administrative services and assets for specified periods beginning on the distribution date. During the Current Period, we incurred charges of $8.3 million for services provided by CHK pursuant to the transition services agreement and terminated all remaining services being provided by CHK. During the Prior Period, we incurred charges of $26.8 million pursuant to the administrative services agreement. We incurred non-cash compensation expenses of $18.1 million and severance-related costs of $4.5 million and $0.3 million during the Current Period and Prior Period, respectively. Included in the non-cash compensation expenses and severance-related costs for the Current Period are $2.1 million and $0.6 million, respectively, related to the sale of Hodges. As a percentage of revenues, general and administrative expenses were 9% and 4% for the Current Quarter and Prior Quarter, respectively.

Losses (Gains) on Sales of Property and Equipment, Net. We recorded losses (gains) on sales of property and equipment of approximately $13.2 million and ($8.0) million during the Current Period and Prior Period, respectively. During the Current Period, we sold our water hauling assets and ancillary equipment not utilized in our business. During the Prior Period, we sold 14 drilling rigs and ancillary equipment that were not utilized in our business, as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers.

Impairments and Other. During the Current Period and Prior Period, we recognized impairments of $15.2 million and $23.0 million, respectively. During the Current Period, we recognized impairment charges of $8.7 million, $3.3 million and $2.7 million related to drilling-related services equipment, certain drilling rigs and trucking and fluid disposal equipment, respectively, that we impaired based on expected future cash flows of these rigs and equipment. During the Prior Period, we recognized impairment charges of $8.4 million related to drilling rigs we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. We paid lease termination costs of $8.4 million during the Prior Period. During the Prior Period, we recognized impairments of $5.7 million related to certain drilling rigs and spare equipment we had identified as held for sale.

We identified certain other property and equipment during the Current Period and Prior Period that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $0.4 million and $0.5 million during the Current Period and Prior Period, respectively, related to these assets.

Interest Expense. Interest expense for the Current Period and Prior Period was $48.5 million and $32.3 million, respectively, related to borrowings under our senior notes, term loans, and credit facility. The increase in interest expense from the Prior Period to the Current Period was primarily due to additional debt issued in conjunction with the spin-off.

Income (Loss) from Equity Investees. Income (loss) from equity investees was $1.1 million and ($0.9) million for the Current Period and Prior Period, respectively, which was a result of our investment in Maalt. We recognized an impairment of $4.5 million during the Prior Period. We own 49% of the membership interest in Maalt.

Other Income. Other income was $0.9 million and $0.8 million for the Current Period and Prior Period, respectively.

Income Tax (Benefit) Expense. We recorded income tax (benefit) expense of ($56.9) million and $3.3 million for the Current Period and Prior Period, respectively. The ($60.2) million decrease in income tax expense recorded for the Current Period was primarily the result of a decrease in net income before taxes of ($175.7) million from the Prior Period to the Current Period. Our effective income tax rate for the Current Period and Prior Period was 34% and 51%, respectively. The decrease in our effective tax rate from the Prior Period to the Current Period was primarily the result of permanent differences having a greater impact on our effective income tax rate in the Prior Period compared to the Current Period.

Off-Balance Sheet Arrangements

Operating Leases

As of June 30, 2015, we were also party to various lease agreements for other property and equipment with varying terms. We account for these leases as operating leases.

Aggregate undiscounted minimum future lease payments as of June 30, 2015 under our operating leases are presented below:



	Rail Cars		Other		Total
	(In thousands)
Remainder of 2015	$	2,723	$	1,029	$	3,752
2016	5,447		984		6,431
2017	2,168		426		2,594
2018	1,445		170		1,615
2019	722		3		725
Total	$	12,505	$	2,612	$	15,117

Other Commitments

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of June 30, 2015, we had $141.8 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2015 and 2016.

Critical Accounting Policies

We consider accounting policies related to property and equipment, impairment of long-lived assets, goodwill, intangible assets and amortization, revenue recognition and income taxes to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K (Commission File No. 001-36354) filed with the SEC on March 2, 2015.

Forward-Looking Statements

All references in this report to “SSE”, the “Company”, “us”, “we”, and “our” are to Seventy Seven Energy Inc. and its consolidated subsidiaries. Certain statements contained in this report constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Act of 1934. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek,” “anticipate,” “plan,” “continue,” “estimate,” “expect,” “may,” “project,” “predict,” “potential,” “targeting,” “intend,” “could,” “might,” “should,” “believe” and similar expressions. These statements involve known and unknown risks and uncertainties and involve assumptions that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Seventy Seven Energy Inc. believes the expectations reflected in these forward-looking statements are reasonable,

but we cannot assure you that these expectations will prove to be correct. We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of many factors, including the following factors:


•	dependence on Chesapeake Energy Corporation (“CHK”) and its working interest partners for a majority of our revenues and our ability to secure new customers or provide additional services to existing customers;


•	our customers’ expenditures for oilfield services;


•	the limitations that our level of indebtedness may have on our financial flexibility and restrictions in our debt agreements;


•	the cyclical nature of the oil and natural gas industry;


•	market prices for oil and natural gas;


•	changes in supply and demand of drilling rigs, hydraulic fracturing fleets and other equipment;


•	our credit profile;


•	access to and cost of capital;


•	hazards and operational risks that may not be fully covered by insurance;


•	increased labor costs or the unavailability of skilled workers;


•	competitive conditions;


•	legislative or regulatory changes, including changes in environmental regulations, drilling regulations and liability under federal and state environmental laws and regulations; and

If one or more events related to these or other risks and uncertainties materialize, or if our underlying assumptions prove to be incorrect, our actual results may differ materially from what we anticipate. Except as may be required by law, we do not intend, and do not assume any obligation, to update any forward-looking statements.



Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Historically, we have provided substantially all of our oilfield services to CHK and its working interest partners. For the Current Period and Prior Period, CHK accounted for approximately 72% and 83% of our revenues, respectively. Sustained low oil and natural gas prices and volatile commodity prices in general, could have a material adverse effect on our customers’ capital spending, which could adversely impact our cash flows and financial position and thereby adversely affect our ability to comply with financial covenants under our credit facility and term loan and further limit our ability to fund our planned capital expenditures.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our credit facility and term loans. We have borrowings outstanding under our term loans and may in the future borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Our primary exposure to interest rate risk results from outstanding borrowings under our credit facility and term loans.

The following table provides information about our debt instruments that are sensitive to changes in interest rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at June 30, 2015.



Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
	(in thousands)				(in thousands)
2015	$	—	—		$	2,500	5.000	%
2016	—		—		5,000		5.000	%
2017	—		—		5,000		5.000	%
2018	—		—		5,000		5.000	%
2019	650,000		6.625	%	5,000		5.000	%
After 2019	460,000		6.500	%	473,250		5.008	%
Total	$	1,110,000			$	495,750
Fair value	$	822,425			$	456,120

Our fuel costs, which consist primarily of diesel fuel used by our various trucks and other equipment, can expose us to commodity price risk and our hydraulic fracturing operations expose us to risks associated with the prices of materials used in hydraulic fracturing, such as sand and chemicals. The prices for fuel and these materials can be volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. We currently do not hedge our exposure to these risks.



Item 4.	Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at a reasonable level of assurance as of June 30, 2015.

Previously Reported Material Weakness

Our management concluded that our internal control over financial reporting and our disclosure controls and procedures were ineffective as of December 31, 2014 as a result of a control deficiency associated with the change in third party payroll service providers in November 2014 that constituted a material weakness as the Company did not maintain effective controls related to the change in providers used in the processing of its payroll. Specifically, the Company did not design and maintain effective controls with respect to the migration and validation of employee data in conjunction with the change in payroll service providers, nor did it validate that ongoing changes to employee data were completely and accurately reflected in the data provided to and from the payroll service provider.

In response to the material weakness described above, during the quarter ended March 31, 2015, we implemented new internal controls designed to remediate the previously identified material weakness. Specifically, the new controls provide reasonable assurance that existing and ongoing changes in employee data are completely and accurately reflected in the data provided to and from the payroll service provider. During the quarter ended June 30, 2015, we completed the testing of these controls and found them to be effective. Therefore, we have concluded the material weakness has been remediated as of June 30, 2015.

Changes in Internal Control Over Financial Reporting

Except as described above, there were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION



Item 1.	Legal Proceedings

From time to time we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We are not currently a party to any legal proceedings that we believe would have a material adverse effect on our financial position, results of operations or cash flows.



Item 1A.	Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth in our Annual Report on Form 10-K (Commission File No. 001-36354) filed with the SEC on March 2, 2015, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.



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

Issuer Purchases of Equity Securities



Period	Total Number of Shares Purchased^(a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased under the Plans or Program
April 1, 2015 - April 30, 2015	2,507	$	5.00	—	—
May 1, 2015 - May 31, 2015	3,000	5.90		—	—
June 1, 2015 - June 30, 2015	272,879	5.73		—	—
Total	278,386	$	5.72	—	—


(a)	Reflects shares surrendered as payment for statutory withholding taxes upon the vesting of restricted stock issued pursuant to the Seventy Seven Energy Inc. 2014 Incentive Plan and the Seventy Seven Energy Inc. Amended and Restated 2014 Incentive Plan.



Item 5.	Other Information

Not applicable.



Item 6.	Exhibits

The following exhibits are filed as a part of this report:

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Commission

File No.

Exhibit

Filing Date

Filed

Herewith

Furnished

Herewith

4.1

Second Supplemental Indenture, dated June 15, 2015, by and among Seventy Seven Operating LLC, Seventy Seven Finance Inc., the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee.

10.1

Amendment No. 1 to Credit Agreement dated April 23, 2015, by and among Wells Fargo Bank, National Association, as administrative agent and collateral agent, the lenders named therein, Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, and the guarantors named therein.

8-K

001-36354

10.1

5/14/2015

10.2

Consent, dated June 15, 2015, by and among Wells Fargo Bank, National Association, as administrative agent and collateral agent, the lenders named therein, Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, and the guarantors named therein.

10.3

Incremental Term Supplement, dated May 13, 2015, by and among Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders named therein.

8-K

001-36354

10.3

5/14/2015

10.4

Amended and Restated 2014 Incentive Plan

S-8

333-204838

99.1

6/9/2015

12.1

Schedule of Computation of Ratio of Earnings to Fixed Charges.

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.1

Interactive data files pursuant to Rule 405 of Regulation S-T.

†



†	Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections.

SIGNATURES

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



July 29, 2015	SEVENTY SEVEN ENERGY INC.
	By:	/s/ Jerry Winchester
		Jerry Winchester
		Director, President and Chief Executive Officer

	By:	/s/ Cary Baetz
		Cary Baetz
		Chief Financial Officer and Treasurer

INDEX TO EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Commission

File No.

Exhibit

Filing Date

Filed

Herewith

Furnished

Herewith

4.1

10.1

8-K

001-36354

10.1

5/14/2015

10.2

10.3

Incremental Term Supplement, dated May 13, 2015, by and among Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders named therein.

8-K

001-36354

10.3

5/14/2015

10.4

Amended and Restated 2014 Incentive Plan

S-8

333-204838

99.1

6/9/2015

12.1

Schedule of Computation of Ratio of Earnings to Fixed Charges.

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.1

Interactive data files pursuant to Rule 405 of Regulation S-T.

†



†	Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections.

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