Seventy Seven Energy 10-Q 2015 Q1 Quarterly report

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 MARCH 31, 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.

Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý

As of May 1, 2015, there were 56,207,319 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	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44
PART II. OTHER INFORMATION		45
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 5.	Other Information	45
Item 6.	Exhibits	46
SIGNATURES		47

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Balance Sheets

(unaudited)

	March 31, 2015			December 31, 2014
	(in thousands, except share amounts)
Assets:
Current Assets:
Cash	$	3,974		$	891
Accounts receivable, net of allowance of $5,891 and $3,311 at March 31, 2015 and December 31, 2014, respectively	454,735			421,555
Inventory	32,164			25,073
Deferred income tax asset	1,093			7,463
Prepaid expenses and other	22,634			19,072
Total Current Assets	514,600			474,054
Property and Equipment:
Property and equipment, at cost	2,754,464			2,749,886
Less: accumulated depreciation	(1,054,861		)	(982,833		)
Total Property and Equipment, Net	1,699,603			1,767,053
Other Assets:
Equity method investment	8,875			7,816
Goodwill	27,434			27,434
Intangible assets, net	5,265			5,420
Deferred financing costs	22,823			23,851
Other long-term assets	6,705			6,924
Total Other Assets	71,102			71,445
Total Assets	$	2,285,305		$	2,312,552
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	24,879		$	45,657
Current portion of long-term debt	4,000			4,000
Other current liabilities	241,898			215,752
Total Current Liabilities	270,777			265,409
Long-Term Liabilities:
Deferred income tax liabilities	136,670			159,273
Long-term debt, excluding current maturities	1,609,300			1,594,500
Other long-term liabilities	2,040			2,347
Total Long-Term Liabilities	1,748,010			1,756,120
Commitments and Contingencies (Note 7)
Stockholders’ Equity:
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 55,186,059 and 51,158,968 shares at March 31, 2015 and December 31, 2014, respectively	552			512
Paid-in capital	314,700			301,644
Accumulated deficit	(48,734		)	(11,133		)
Total Stockholders’ Equity	266,518			291,023
Total Liabilities and Stockholders’ Equity	$	2,285,305		$	2,312,552

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

1

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Operations

(unaudited)

	Three Months Ended March 31,
	2015			2014
	(in thousands, except per share data)
Revenues:
Revenues	$	429,787		$	509,710
Operating Expenses:
Operating costs	331,611			409,589
Depreciation and amortization	84,975			72,465
General and administrative	33,912			20,887
Losses on sales of property and equipment, net	4,210			977
Impairments and other	6,272			19,808
Total Operating Expenses	460,980			523,726
Operating Loss	(31,193		)	(14,016		)
Other (Expense) Income:
Interest expense	(23,516		)	(14,692		)
Income (loss) from equity investees	972			(917		)
Other (expense) income	(96		)	371
Total Other Expense	(22,640		)	(15,238		)
Loss Before Income Taxes	(53,833		)	(29,254		)
Income Tax Benefit	(16,232		)	(10,697		)
Net Loss	$	(37,601	)	$	(18,557	)
Loss Per Common Share (Note 3)
Basic	$	(0.78	)	$	(0.40	)
Diluted	$	(0.78	)	$	(0.40	)
Weighted Average Common Shares Outstanding
Basic	48,275			46,932
Diluted	48,275			46,932

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

2

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statement of Changes in Equity

(unaudited)

	Common Stock			Paid-in Capital		Accumulated Deficit			Total Stockholders’ Equity
	Shares	Amount
	(in thousands)
Balance at December 31, 2014	51,159	$	512	$	301,644	$	(11,133	)	$	291,023
Net loss	—	—		—		(37,601		)	(37,601		)
Share-based compensation	4,027	40		13,056		—			13,096
Balance at March 31, 2015	55,186	$	552	$	314,700	$	(48,734	)	$	266,518

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

3

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Three Months Ended   March 31,
	2015			2014
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET LOSS	$	(37,601	)	$	(18,557	)
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization	84,975			72,465
Amortization of sale/leaseback gains	—			(4,214		)
Amortization of deferred financing costs	1,028			737
Losses on sales of property and equipment, net	4,210			977
Impairments	6,272			11,430
(Income) loss from equity investees	(972		)	917
Provision for doubtful accounts	2,580			83
Non-cash compensation	18,355			146
Deferred income tax expense	(16,232		)	(11,030		)
Changes in operating assets and liabilities	(35,102		)	1,628
Net cash provided by operating activities	27,513			54,582
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment	(40,607		)	(118,571		)
Proceeds from sales of assets	1,988			6,375
Additions to investments	(88		)	(88		)
Other	14			15
Net cash used in investing activities	(38,693		)	(112,269		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facility	109,300			281,500
Payments on revolving credit facility	(94,500		)	(222,200		)
Other	(537		)	—
Net cash provided by financing activities	14,263			59,300
Net increase in cash	3,083			1,613
Cash, beginning of period	891			1,678
Cash, end of period	$	3,974		$	3,291
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Increase (decrease) in other current liabilities related to purchases of property and equipment	$	(8,405	)	$	1,446
SUPPLEMENTAL DISCLOSURE OF CASH PAYMENTS:
Interest paid, net of amount capitalized	$	21,744		$	3,184

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

4

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation, Spin-off and Nature of Business

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 March 31, 2015 and December 31, 2014, results of operations for the three months ended March 31, 2015 and 2014, changes in equity for the three months ended March 31, 2015 and cash flows for the three months ended March 31, 2015 and 2014. These notes relate to the three months ended March 31, 2015 (the “Current Quarter”) and the three months ended March 31, 2014 (the “Prior Quarter”). 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 5). 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, the record date. 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.

Nature of Business

We provide a wide range of wellsite services and equipment, including drilling, hydraulic fracturing, oilfield rentals, rig relocation and water transport and disposal. We conduct our operations in Kansas, Louisiana, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, Wisconsin and Wyoming. As of March 31, 2015, our primary owned assets consisted of 92 drilling rigs, 10 hydraulic fracturing fleets, 263 rig relocation trucks, 67 cranes and forklifts and 151 water transport trucks. Our reportable business segments are drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations (see Note 14).

2. Change in Accounting Estimate

We review the estimated useful lives of our property and equipment on an ongoing basis. Based on this review, we concluded that the estimated useful lives of certain drilling rig components and the estimated useful lives of 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 Quarter. The effect of the change in estimate of certain drilling rigs was a $1.1 million increase, pre-tax, to depreciation expense

5

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

during the Current Quarter. These changes decreased net income for the Current Quarter by $8.4 million and decreased basic and diluted earnings per share by $0.17.

3. 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 March 31,
	2015			2014
	(in thousands, except per share data)
Basic earnings per share(a):
Allocation of earnings:
Net loss	$	(37,601	)	$	(18,557	)
Weighted average shares outstanding:
Weighted average shares outstanding, excluding unvested shares of restricted stock	48,275			46,932
Restricted stock(b)	—			—
Weighted average shares outstanding, basic	48,275			46,932
Basic loss per share	$	(0.78	)	$	(0.40	)
Diluted earnings per share(a):
Allocation of earnings:
Net loss	$	(37,601	)	$	(18,557	)
Weighted average shares outstanding:
Weighted average shares outstanding, basic	48,275			46,932
Stock options(c)	—			—
Weighted average shares outstanding, diluted	48,275			46,932
Diluted loss per share	$	(0.78	)	$	(0.40	)

(a) On June 30, 2014, we distributed 46,932,433 shares of our common stock to CHK shareholders 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) 41,124 unvested restricted shares were excluded from the computation of basic earnings per share for the Current Quarter 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 therefore, the stock options were not dilutive.

6

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

4. Asset Sales and Impairments and Other

Asset Sales

During the Current Quarter and Prior Quarter, we sold ancillary equipment for $3.4 million and $6.4 million, respectively. We recorded net losses on sales of property and equipment of approximately $4.2 million and $1.0 million related to these asset sales during the Current Quarter and Prior Quarter, respectively.

Impairments and Other

A summary of our impairments and other is as follows:

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Drilling rigs held for use	$	3,290	$	5,426
Drilling rigs held for sale	—		5,714
Lease termination costs	—		8,379
Trucking and fluid disposal equipment	2,543		—
Other	439		289
Total impairments and other	$	6,272	$	19,808

During the Current Quarter, we identified certain drilling rigs and trucking and fluid disposal equipment that we deemed impaired based on expected future cash flows of these rigs and equipment. We recorded impairment charges of $3.3 million and $2.5 million related to these drilling rigs and trucking and fluid disposal equipment, respectively. Estimated fair values for these drilling rigs and trucking and fluid disposal equipment were determined using significant unobservable inputs (Level 3) based on an income approach.

We recognized $5.4 million of impairment charges during the Prior Quarter 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 $5.7 million of impairment charges during the Prior Quarter 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, we purchased 20 of our leased drilling rigs for approximately $76.9 million and paid lease termination costs of approximately $8.4 million. We subsequently sold six of these drilling rigs.

We identified certain other property and equipment during the Current Quarter and Prior Quarter 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 $0.3 million during the Current Quarter and Prior Quarter, 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.

The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management’s judgment. A prolonged period of lower oil and natural gas prices or continued reductions in capital expenditures by CHK or our other customers, and the potential impact of these factors on our utilization and dayrates, could result in the recognition of future impairment charges on the same or additional rigs and other property and equipment if future cash flow estimates, based upon information then available to management, indicate that their carrying value may not be recoverable.

7

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Debt

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

	March 31, 2015		December 31, 2014
	(in thousands)
6.625% Senior Notes due 2019	$	650,000	$	650,000
6.50% Senior Notes due 2022	500,000		500,000
Term Loan	398,000		398,000
Credit Facility	65,300		50,500
Total debt	1,613,300		1,598,500
Less: Current portion of long-term debt	4,000		4,000
Total long-term debt	$	1,609,300	$	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.

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

8

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

Term Loan

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 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.

9

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 March 31, 2015, the Credit Facility had availability of $203.9 million, net of letters of credit of $5.8 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.

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.

6. Other Current Liabilities

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

	March 31, 2015		December 31, 2014
	(in thousands)
Other Current Liabilities:
Accrued expenses	$	137,579	$	88,538
Payroll related	39,635		47,711
Insurance reserves	14,424		14,521
Interest	25,779		25,035
Income, property, sales, use and other taxes	6,876		13,937
Property and equipment	17,605		26,010
Total Other Current Liabilities	$	241,898	$	215,752

7. Commitments and Contingencies

Operating Leases

As of March 31, 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 March 31, 2015, we were also party to various lease agreements for other property and equipment with varying terms.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Aggregate undiscounted minimum future lease payments under our operating leases at March 31, 2015 are presented below:

	Rail Cars		Other		Total
	(in thousands)
Remainder of 2015	$	4,085	$	1,521	$	5,606
2016	5,447		992		6,439
2017	2,168		591		2,759
2018	1,445		170		1,615
2019	722		3		725
Total	$	13,867	$	3,277	$	17,144

Rent expense for rail cars, real property and rigs for the Current Quarter and Prior Quarter was $1.8 million and $15.0 million, respectively, and was included in operating costs in our condensed consolidated statements of operations.

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 March 31, 2015, we had $168.4 million of purchase commitments related to future capital expenditures that we expect to incur in 2015.

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 $2.5 million and $2.3 million during the Current Quarter and Prior Quarter, respectively.

8. Share-Based Compensation

Our share-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 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 of $12.5 million and $3.2 million for the Current Quarter and Prior Quarter, 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.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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	3,900		$	4.55
Vested	(387	)	$	25.04
Forfeited	(94	)	$	24.49
Unvested shares as of March 31, 2015	7,352		$	13.63

The aggregate intrinsic value of restricted stock vested for the Current Quarter, as reflected in the table above, was approximately $9.7 million based on the market price of SSE’s common stock at the time of vesting.

As of March 31, 2015, there was $72.6 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 three years.

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 March 31, 2015	348	$	16.19	7.99	$	—
Exercisable at March 31, 2015	89	$	16.46	8.03	$	—

(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 March 31, 2015, there was $1.0 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately two years.

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 ($0.9) million and $0.1 million for the Current Quarter and Prior Quarter, respectively.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. 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 30% and 37% for the Current Quarter and Prior Quarter, 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.

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 March 31, 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 effect 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 March 31, 2015 and December 31, 2014.

10. 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 $8.9 million as of March 31, 2015. We recorded equity method adjustments to our investment of $1.0 million and ($0.9) million for our share of Maalt’s income (loss) for the Current Quarter and Prior Quarter, respectively. We also made additional investments of $0.1 million and $0.1 million in the Current Quarter and Prior Quarter, respectively. As of March 31, 2015, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $8.2 million. This excess is attributable to goodwill recorded on Maalt’s financial statements and is not being amortized.

11. 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.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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 4 for additional discussion.

Fair Value of Other Financial Instruments

The fair value of debt is the estimated amount a market participant would have to pay to purchase 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.

	March 31, 2015				December 31, 2014
	Carrying Amount		Fair Value (Level 2)		Carrying Amount		Fair Value (Level 2)
	(in thousands)
Financial liabilities:
6.625% Senior Notes due 2019	$	650,000	$	494,000	$	650,000	$	519,188
6.5% Senior Notes due 2022	$	500,000	$	232,500	$	500,000	$	296,250
Term Loan	$	398,000	$	350,988	$	398,000	$	379,095
Credit Facility	$	65,300	$	61,550	$	50,500	$	47,407

12. 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 $344.9 million and $326.7 million as of March 31, 2015 and December 31, 2014, or 75% and 77%, respectively, of our total accounts receivable. Revenues from CHK and its affiliates were $317.3 million and $430.8 million for the Current Quarter and Prior Quarter, or 74% and 85% 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 13 for further discussion of agreements entered into as part of the spin-off, including a new services agreement and rig-specific daywork drilling contracts.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

13. 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.

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. During the term of the transition services agreement, we have the right to request a discontinuation of one or more specific services. The transition services agreement will terminate upon cessation of all services provided thereunder. These charges from CHK were $5.6 million for the Current Quarter. The services that CHK is providing to us as of March 31, 2015 include, among others:

•information technology services;

•accounting services; and

•treasury services;

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.

15

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 of lease expense for the Prior Quarter 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 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 $12.8 million for the Prior Quarter. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement.

14. Segment Information

Our revenues, income (loss) before income taxes and identifiable assets are primarily attributable to four reportable segments. 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 four 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 March 31, 2015, we owned a fleet of 92 land drilling rigs.

Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation services. As of March 31, 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.

Oilfield Trucking. Our oilfield trucking segment provides drilling rig relocation and logistics services as well as fluid handling services. As of March 31, 2015, we owned a fleet of 263 rig relocation trucks, 67 cranes and forklifts and 151 water transport trucks. 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 Loan and Credit Facility. As part of the spin-off, we distributed our compression unit manufacturing business to CHK.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Drilling			Hydraulic Fracturing			Oilfield Rentals			Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
For The Three Months Ended March 31, 2015:
Revenues	$	166,054		$	202,017		$	32,565		$	31,184		$	2,067		$	(4,100	)	$	429,787
Intersegment revenues	—			—			(77		)	(1,956		)	(2,067		)	4,100			—
Total revenues	$	166,054		$	202,017		$	32,488		$	29,228		$	—		$	—		$	429,787
Depreciation and amortization	49,539			16,277			12,172			5,054			1,933			—			84,975
Losses (gains) on sales of property and equipment, net	4,386			(5		)	(171		)	(10		)	10			—			4,210
Impairments and other	3,729			—			—			2,543			—			—			6,272
Interest expense	—			—			—			—			(23,516		)	—			(23,516		)
Income from equity investees	—			972			—			—			—			—			972
Other (expense) income	(42		)	73			(24		)	9			(112		)	—			(96		)
(Loss) Income BeforeIncome Taxes	$	686		$	8,667		$	(5,024	)	$	(18,377	)	$	(39,785	)	$	—		$	(53,833	)
For The Three Months Ended March 31, 2014:
Revenues	$	182,111		$	201,620		$	36,178		$	57,438		$	41,355		$	(8,992	)	$	509,710
Intersegment revenues	(1,677		)	—			(236		)	(1,243		)	(5,836		)	8,992			—
Total revenues	$	180,434		$	201,620		$	35,942		$	56,195		$	35,519		$	—		$	509,710
Depreciation and amortization	34,903			18,109			13,347			5,929			177			—			72,465
Losses (gains) on sales of property and equipment, net	1,710			—			(742		)	(8		)	17			—			977
Impairments and other(a)	19,601			207			—			—			—			—			19,808
Interest expense	—			—			—			—			(14,692		)	—			(14,692		)
(Loss) from equity investees	—			(917		)	—			—			—			—			(917		)
Other (expense) income	332			104			14			18			(97		)	—			371
(Loss) Income Before Income Taxes	$	(3,688	)	$	1,205		$	(3,373	)	$	(5,268	)	$	(18,130	)	$	—		$	(29,254	)
As of March 31, 2015:
Total Assets	$	1,260,632		$	488,890		$	150,062		$	131,149		$	254,572		$	—		$	2,285,305
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 Quarter.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 5). 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 its combined guarantor subsidiaries as of March 31, 2015 and December 31, 2014 and for the three months ended March 31, 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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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Balance Sheet
	March 31, 2015
	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Assets:
Current Assets:
Cash	$	3,353	$	555		$	66		$	—		$	3,974
Accounts receivable, net	—		—			454,735			—			454,735
Inventory	—		—			32,164			—			32,164
Deferred income tax asset	—		—			2,234			(1,141		)	1,093
Prepaid expenses and other	—		7,989			14,645			—			22,634
Total Current Assets	3,353		8,544			503,844			(1,141		)	514,600
Property and Equipment:
Property and equipment, at cost	—		27,590			2,726,874			—			2,754,464
Less: accumulated depreciation	—		(756		)	(1,054,105		)	—			(1,054,861		)
Total Property and Equipment, Net	—		26,834			1,672,769			—			1,699,603
Other Assets:
Equity method investment	—		—			8,875			—			8,875
Goodwill	—		—			27,434			—			27,434
Intangible assets, net	—		—			5,265			—			5,265
Deferred financing costs, net	6,515		16,308			—			—			22,823
Other long-term assets	710		50,221			5,727			(49,953		)	6,705
Investments in subsidiaries and intercompany advances	763,443		1,820,502			—			(2,583,945		)	—
Total Other Assets	770,668		1,887,031			47,301			(2,633,898		)	71,102
Total Assets	$	774,021	$	1,922,409		$	2,223,914		$	(2,635,039	)	$	2,285,305
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	58	$	2,908		$	21,913		$	—		$	24,879
Current portion of long-term debt	—		4,000			—			—			4,000
Other current liabilities	7,445		41,779			193,815			(1,141		)	241,898
Total Current Liabilities	7,503		48,687			215,728			(1,141		)	270,777
Long-Term Liabilities:
Deferred income tax liabilities	—		—			186,623			(49,953		)	136,670
Long-term debt, excluding current maturities	500,000		1,109,300			—			—			1,609,300
Other long-term liabilities	—		979			1,061			—			2,040
Total Long-Term Liabilities	500,000		1,110,279			187,684			(49,953		)	1,748,010
Total Stockholders’ Equity	266,518		763,443			1,820,502			(2,583,945		)	266,518
Total Liabilities and Stockholders’ Equity	$	774,021	$	1,922,409		$	2,223,914		$	(2,635,039	)	$	2,285,305

19

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

20

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statement of Operations
	Three Months Ended March 31, 2015
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues:
Revenues	$	—		$	—		$	430,536		$	(749	)	$	429,787
Operating Expenses:
Operating costs	—			—			331,611			—			331,611
Depreciation and amortization	—			67			84,908			—			84,975
General and administrative	68			11,916			22,677			(749		)	33,912
Losses on sales of property and equipment, net	—			—			4,210			—			4,210
Impairments and other	—			—			6,272			—			6,272
Total Operating Expenses	68			11,983			449,678			(749		)	460,980
Operating (Loss) Income	(68		)	(11,983		)	(19,142		)	—			(31,193		)
Other (Expense) Income:
Interest expense	(8,259		)	(15,257		)	—			—			(23,516		)
Income from equity investees	—			—			972			—			972
Other (expense) income	—			(133		)	37			—			(96		)
Equity in net loss of subsidiary	(31,784		)	(12,665		)	—			44,449			—
Total Other (Expense) Income	(40,043		)	(28,055		)	1,009			44,449			(22,640		)
Loss Before Income Taxes	(40,111		)	(40,038		)	(18,133		)	44,449			(53,833		)
Income Tax Benefit	(2,510		)	(8,254		)	(5,468		)	—			(16,232		)
Net Loss	$	(37,601	)	$	(31,784	)	$	(12,665	)	$	44,449		$	(37,601	)

21

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statement of Operations
	Three Months Ended March 31, 2014
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues:
Revenues	$	—		$	1,143		$	509,688		$	(1,121	)	$	509,710
Operating Expenses:
Operating costs	—			1,912			409,499			(1,822		)	409,589
Depreciation and amortization	—			20			72,445			—			72,465
General and administrative	—			7,259			13,628			—			20,887
Losses on sales of property and equipment, net	—			—			977			—			977
Impairments and other	—			—			19,808			—			19,808
Total Operating Expenses	—			9,191			516,357			(1,822		)	523,726
Operating (Loss) Income	—			(8,048		)	(6,669		)	701			(14,016		)
Other (Expense) Income:
Interest expense	—			(14,692		)	—			—			(14,692		)
Loss from equity investees	—			—			(917		)	—			(917		)
Other income	—			—			371			—			371
Equity in net loss of subsidiary	(18,557		)	(4,387		)	—			22,944			—
Total Other (Expense) Income	(18,557		)	(19,079		)	(546		)	22,944			(15,238		)
Loss Before Income Taxes	(18,557		)	(27,127		)	(7,215		)	23,645			(29,254		)
Income Tax Benefit	—			(8,570		)	(2,393		)	266			(10,697		)
Net Loss	$	(18,557	)	$	(18,557	)	$	(4,822	)	$	23,379		$	(18,557	)

22

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows
	Three Months Ended March 31, 2015
	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Cash Flows From Operating Activities:	$	(17,975	)	$	13,463		$	82,508		$	(50,483	)	$	27,513
Cash Flows From Investing Activities:
Additions to property and equipment	—			(7,073		)	(33,534		)	—			(40,607		)
Proceeds from sales of assets	—			—			1,988			—			1,988
Additions to investments	—			—			(88		)	—			(88		)
Distributions from affiliates	21,251			—			—			(21,251		)	—
Other	—			—			14			—			14
Net cash provided by (used in) investing activities	21,251			(7,073		)	(31,620		)	(21,251		)	(38,693		)
Cash Flows From Financing Activities:
Distributions to affiliates	—			(21,251		)	(50,483		)	71,734			—
Borrowings from revolving credit facility	—			109,300			—			—			109,300
Payments on revolving credit facility	—			(94,500		)	—			—			(94,500		)
Other	—			(117		)	(420		)	—			(537		)
Net cash provided by (used in) financing activities	—			(6,568		)	(50,903		)	71,734			14,263
Net increase (decrease) in cash	3,276			(178		)	(15		)	—			3,083
Cash, beginning of period	77			733			81			—			891
Cash, end of period	$	3,353		$	555		$	66		$	—		$	3,974

23

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows
	Three Months Ended March 31, 2014
	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Cash Flows From Operating Activities:	$	—	$	(2,181	)	$	56,763		$	—		$	54,582
Cash Flows From Investing Activities:
Additions to property and equipment	—		(800		)	(117,771		)	—			(118,571		)
Proceeds from sale of assets	—		—			6,375			—			6,375
Additions to investment	—		—			(88		)	—			(88		)
Contributions to affiliates	—		(54,920		)	—			54,920			—
Other	—		—			15			—			15
Net cash used in investing activities	—		(55,720		)	(111,469		)	54,920			(112,269		)
Cash Flows From Financing Activities:
Contributions from affiliates	—		—			54,920			(54,920		)	—
Borrowings from revolving credit facility	—		281,500			—			—			281,500
Payments on revolving credit facility	—		(222,200		)	—			—			(222,200		)
Net cash provided by financing activities	—		59,300			54,920			(54,920		)	59,300
Net increase in cash	—		1,399			214			—			1,613
Cash, beginning of period	—		1,613			65			—			1,678
Cash, end of period	$	—	$	3,012		$	279		$	—		$	3,291

24

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 April 1, 2015, the FASB voted to propose to defer the effective date of the new revenue recognition standard by one year. We are currently evaluating what impact this standard will have on our consolidated financial statements.

17. Subsequent Events

Subsequent to March 31, 2015, we made the decision to exit the water hauling and transport business, which we do not consider to be significant to our overall business. In the Current Quarter, we recognized impairment charges of approximately $2.5 million related to certain assets and incurred $1.0 million in severance costs related to the closing of one office. The severance costs are included in general and administrative expenses.

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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 months ended March 31, 2015 (the “Current Quarter) and the three months ended March 31, 2014 (the “Prior 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 that provides 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 four operating segments: Drilling, Hydraulic Fracturing, Oilfield Rentals, and Oilfield Trucking. 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 Barnett, 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 March 31, 2015, our marketed fleet consisted of 26 Tier 1 rigs, including 16 proprietary PeakeRigs™, 57 Tier 2 rigs and seven Tier 3 rigs. As of March 31, 2015, we also owned (a) 10 hydraulic fracturing fleets with an aggregate of 400,000 horsepower; (b) a diversified oilfield rentals business; and (c) an oilfield trucking fleet consisting of 263 rig relocation trucks, 67 cranes and forklifts used in the movement of drilling rigs and other heavy equipment, and 151 water transport trucks. We continue to modernize our asset base and are currently building nine 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 is 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. This is primarily because the industry is driven by commodity demand and corresponding price increases. 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 outpaced growing domestic demand. We believe our modern, high-quality asset base, diversified footprint and strong relationship with CHK will offset the consequences of decreasing drilling and completions activity levels to some extent; 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.

26

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 March 31, 2015 were approximately $717.9 million and $695.3 million, respectively, with average durations of 17 months each. 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. The 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 March 31, 2015, we expect to recognize revenues from backlog as follows (in millions):

	2015		2016		Thereafter
Backlog	$	586.2	$	557.5	$	269.5

As of March 31, 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	$	154.6	$	165.9	$	85.8

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.

27

Safety Performance.  Maintaining a strong safety record is a critical component of our operational success. We maintain a safety database that our management uses to identify negative trends in operational incidents so that appropriate measures can be taken to maintain and enhance our safety standards.

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 distribution of our compression manufacturing and geosteering businesses to CHK and the sale of our crude hauling assets to a third party. The table below shows our Adjusted EBITDA for the three months ended March 31, 2015 and 2014.

	Three Months Ended March 31,
	2015			2014
	(unaudited) (in thousands)
Adjusted EBITDA:
Consolidated	$	84,899		$	85,800
Drilling	$	64,010		$	62,334
Hydraulic Fracturing	$	26,258		$	20,151
Oilfield Rentals	$	7,792		$	9,976
Oilfield Trucking	$	(8,445	)	$	2,064

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 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 is further adjusted to subtract rig rent expense.

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;

28

• 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 March 31,
	2015			2014
	(In thousands)
Net loss	$	(37,601	)	$	(18,557	)
Add:
Interest expense	23,516			14,692
Income tax benefit	(16,232		)	(10,697		)
Depreciation and amortization	84,975			72,465
Impairments and other	6,272			19,808
Losses on sales of property and equipment, net	4,210			977
Non-cash compensation	18,355			146
Severance-related costs	1,404			167
Rent expense on buildings and real estate transferred from CHK(a)	—			4,106
Rig rent expense(b)	—			9,059
Less:
Compression unit manufacturing Adjusted EBITDA	—			6,715
Geosteering Adjusted EBITDA	—			194
Crude hauling Adjusted EBITDA	—			(543		)
Adjusted EBITDA	$	84,899		$	85,800

(a) Rent on buildings and real estate transfered 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. In the Prior Quarter, our operating costs and general and administrative expenses include $4.0 million and $0.1 million, respectively, of rent expense associated with our lease of these facilities.

(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 drilling rigs.

29

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Cash provided by operating activities	$	27,513		$	54,582
Add:
Changes in operating assets and liabilities	35,102			(1,628		)
Interest expense	23,516			14,692
Lease termination costs	—			8,379
Amortization of sale/leaseback gains	—			4,214
Amortization of deferred financing costs	(1,028		)	(737		)
Income (loss) from equity investees	972			(917		)
Provision for doubtful accounts	(2,580		)	(83		)
Current tax expense	—			333
Severance-related costs	1,404			167
Rent expense on buildings and real estate transferred from CHK	—			4,106
Rig rent expense	—			9,059
Other	—			(1		)
Less:
Compression unit manufacturing Adjusted EBITDA	—			6,715
Geosteering Adjusted EBITDA	—			194
Crude hauling Adjusted EBITDA	—			(543		)
Adjusted EBITDA	$	84,899		$	85,800

(a) Rent on buildings and real estate transfered 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. In the Prior Quarter, our operating costs and general and administrative expenses include $4.0 million and $0.1 million, respectively, of rent expense associated with our lease of these facilities.

(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 drilling rigs.

Drilling

	Three Months Ended March 31,
	2015		2014
	(In thousands)
Net income (loss)	$	479	$	(2,359	)
Add:
Income tax expense (benefit)	207		(1,329		)
Depreciation and amortization	49,539		34,903
Impairments and other	3,729		19,601
Losses on sales of property and equipment, net	4,386		1,710
Non-cash compensation	5,326		—
Severance-related costs	344		63
Rent expense on buildings and real estate transferred from CHK	—		880
Rig rent expense	—		9,059
Less:
Geosteering Adjusted EBITDA	—		194
Adjusted EBITDA	$	64,010	$	62,334

30

Hydraulic Fracturing

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Net income	$	6,054		$	595
Add:
Income tax expense	2,613			610
Depreciation and amortization	16,277			18,109
Impairments	—			207
Gains on sales of property and equipment, net	(5		)	—
Non-cash compensation	1,238			—
Severance-related costs	81			—
Rent expense on buildings and real estate transferred from CHK	—			630
Adjusted EBITDA	$	26,258		$	20,151

Oilfield Rentals

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Net loss	$	(3,509	)	$	(2,136	)
Add:
Income tax benefit	(1,515		)	(1,237		)
Depreciation and amortization	12,172			13,347
Gains on sales of property and equipment, net	(171		)	(742		)
Non-cash compensation	861			—
Severance-related costs	(46		)	24
Rent expense on buildings and real estate transferred from CHK	—			720
Adjusted EBITDA	$	7,792		$	9,976

Oilfield Trucking

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Net loss	$	(12,836	)	$	(3,397	)
Add:
Income tax benefit	(5,541		)	(1,871		)
Depreciation and amortization	5,054			5,929
Impairments	2,543			—
Gains on sales of property and equipment, net	(10		)	(8		)
Non-cash compensation	1,320			—
Severance-related costs	1,025			5
Rent expense on buildings and real estate transferred from CHK	—			863
Less:
Crude hauling Adjusted EBITDA	—			(543		)
Adjusted EBITDA	$	(8,445	)	$	2,064

31

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 March 31, 2015, we had cash of $4.0 million and working capital of $243.8 million. As of December 31, 2014, we had cash of $0.9 million and working capital of $208.6 million.

Long-Term Debt

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

	March 31, 2015		December 31, 2014
	(in thousands)
6.625% Senior Notes due 2019	$	650,000	$	650,000
6.50% Senior Notes due 2022	500,000		500,000
Term Loan	398,000		398,000
Credit Facility	65,300		50,500
Total debt	1,613,300		1,598,500
Less: Current portion of long-term debt	4,000		4,000
Total long-term debt	$	1,609,300	$	1,594,500

We have provided notice to the administrative agent and existing lenders under our Term Loan credit agreement to request incremental term commitments in an aggregate principal amount of $100.0 million to be secured on a junior lien basis with the collateral securing the existing borrowings under the agreement. Pursuant to the accordion feature of the agreement, we may select, in our discretion, incremental term lender(s) from among the existing lenders and any additional banks, financial institutions and other institutional lenders or investors, subject to the consent of (i) such proposed incremental term lender and (ii) the administrative agent. We expect to select the incremental term lender(s) and, subject to market conditions, close on the incremental term loan credit agreement in May 2015.

As of March 31, 2015, we had outstanding borrowings under our revolving bank credit facility of $65.3 million, letters of credit of $5.8 million, and availability of $203.9 million. As of May 1, 2015, we had outstanding borrowings of $30.0 million, letters of credit of $5.8 million, and availability of $239.2 million.

For further information on our long-term debt, please read Note 5 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 have 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.

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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 $40.6 million and $118.6 million for the Current Quarter and Prior Quarter, respectively. During the Prior Quarter, we purchased 20 of our leased drilling rigs for approximately $76.9 million. We currently expect our total capital expenditures to be approximately $200.0 million for 2015. We may increase, decrease or re-allocate 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 Quarter and Prior Quarter.

	Three Months Ended March 31,
	2015			2014
	(in thousands) (unaudited)
Cash Flow Statement Data:
Net cash provided by operating activities	$	27,513		$	54,582
Net cash used in investing activities	$	(38,693	)	$	(112,269	)
Net cash provided by financing activities	$	14,263		$	59,300
Cash, beginning of period	$	891		$	1,678
Cash, end of period	$	3,974		$	3,291

Operating Activities. Cash provided by operating activities was $27.5 million and $54.6 million for the Current Quarter and Prior Quarter, respectively. Changes in working capital items (decreased) increased cash flow provided by operating activities by ($35.1) million and $1.6 million for the Current Quarter and Prior Quarter, respectively. During the Current Quarter, we experienced an increase in our days sales outstanding, which adversely affected cash flows from operations. 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 $38.7 million and $112.3 million for the Current Quarter and Prior Quarter, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the Current Quarter and Prior Quarter were related to our investment in new PeakeRigs™ and the purchase of certain leased rigs. We purchased 20 leased drilling rigs for approximately $76.9 million during the Prior Quarter. Cash used in investing activities was partially offset by proceeds from asset sales in the amounts of $2.0 million and $6.4 million for the Current Quarter and Prior Quarter, respectively.

Financing Activities. Net cash provided by financing activities was $14.3 million and $59.3 million for the Current Quarter and Prior Quarter, respectively. We had borrowings and repayments under our credit facilities of $109.3 million and $94.5 million, respectively, during the Current Quarter, and $281.5 million and $222.2 million, respectively, during the Prior Quarter.

33

Results of Operations

Three Months Ended March 31, 2015 vs. March 31, 2014

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

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Revenues:
Revenues	$	429,787		$	509,710
Operating Expenses:
Operating costs	331,611			409,589
Depreciation and amortization	84,975			72,465
General and administrative	33,912			20,887
Losses on sales of property and equipment, net	4,210			977
Impairments and other	6,272			19,808
Total Operating Expenses	460,980			523,726
Operating Loss	(31,193		)	(14,016		)
Other (Expense) Income:
Interest expense	(23,516		)	(14,692		)
Income (loss) from equity investees	972			(917		)
Other (expense) income	(96		)	371
Total Other Expense	(22,640		)	(15,238		)
Loss Before Income Taxes	(53,833		)	(29,254		)
Income Tax Benefit	(16,232		)	(10,697		)
Net Loss	$	(37,601	)	$	(18,557	)

34

Revenues. For the Current Quarter and Prior Quarter, revenues were $429.8 million and $509.7 million, respectively. Our revenues decreased by approximately $79.9 million primarily due to the distribution to CHK of our compression unit manufacturing and geosteering businesses and the sale of our crude hauling assets to a third party in conjunction with our spin-off. Adjusted revenues were $459.0 million for the Prior Quarter, which excludes the impact of the compression unit manufacturing and geosteering businesses and crude hauling assets. The decrease in revenues for the Current Quarter compared to adjusted revenues for the Prior Quarter was due to decreased utilization and pricing pressure in our drilling and oilfield trucking segments, which resulted from a decline in demand for these services. 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 74% and 85% 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 March 31,
	2015		2014
	(in thousands)
Drilling	$	166,054	$	180,434
Hydraulic fracturing	202,017		201,620
Oilfield rentals	32,488		35,942
Oilfield trucking	29,228		56,195
Other operations	—		35,519
Total	$	429,787	$	509,710
Adjusted Revenue(a):
Revenue	$	429,787	$	509,710
Less:
Compression unit manufacturing revenues	—		35,481
Geosteering revenues	—		1,926
Crude hauling revenues	—		13,299
Adjusted Revenue	$	429,787	$	459,004

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

35

Operating Costs. Operating costs for the Current Quarter and Prior Quarter were $331.6 million and $409.6 million, respectively. Our costs decreased by approximately $78.0 million from the Prior Quarter to the Current Quarter due to the distribution to CHK of our compression unit manufacturing and geosteering businesses, the sale of our crude hauling assets to a third party, and the decrease in rig rent expense. Adjusted operating costs were $331.6 million and $358.1 million for the Current Quarter and Prior Quarter, respectively, which excludes operating costs associated with the compression unit manufacturing and geosteering businesses distributed to CHK and crude hauling assets sold to a third party as part of the spin-off, further adjusted to 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.” As a percentage of adjusted revenues, adjusted operating costs were 77% and 78% 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 March 31,
	2015		2014
	(in thousands)
Drilling	$	98,140	$	124,460
Hydraulic fracturing	171,305		177,012
Oilfield rentals	23,619		25,949
Oilfield trucking	36,291		53,614
Other operations	2,256		28,554
Total	$	331,611	$	409,589
Adjusted Operating Costs(a):
Operating Costs	$	331,611	$	409,589
Less:
Rig rent expense	—		9,059
Compression unit manufacturing operating costs	—		27,954
Geosteering operating costs	—		1,687
Crude hauling operating costs	—		12,761
Adjusted Operating Costs	$	331,611	$	358,128

(a) “Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with the compression unit manufacturing and geosteering businesses distributed to CHK and crude hauling assets sold to a third party as part of the spin-off, further adjusted to 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.”

36

Drilling

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Revenues	$	166,054	$	180,434
Operating costs(a)	98,140		124,460
Gross margin	$	67,914	$	55,974
Adjusted EBITDA	$	64,010	$	62,334
Adjusted Revenues(b):
Revenues	$	166,054	$	180,434
Less:
Geosteering revenues	—		1,926
Adjusted Revenues(b)	$	166,054	$	178,508
Adjusted Operating Costs(b):
Operating costs	$	98,140	$	124,460
Less:
Geosteering operating costs	—		1,687
Rig rent expense(a)	—		9,059
Adjusted Operating Costs(b)	$	98,140	$	113,714

(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 and average operating costs per revenue day include $9.1 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 to 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 $14.4 million, or 8%, from the Prior Quarter. This decrease was primarily due to a 6% decrease in revenue days associated with rigs under contract being idled. In addition, average revenue per revenue day for the Current Quarter increased 4% from the Prior Quarter primarily due to improvement in the tier mix of our working drilling rigs. Revenues from non-CHK customers increased $14.8 million to 41% of total segment revenues in the Current Quarter compared to 29% for the Prior Quarter.

Drilling operating costs for the Current Quarter decreased $26.3 million, or 21%, from the Prior Quarter, due primarily to a reduction in repairs and maintenance expenses driven by lower fleet utilization, a reduction in labor-related costs and a decrease in rig rent expense. As a percentage of drilling revenues, drilling operating costs were 59% and 69% for the Current Quarter and the Prior Quarter, respectively. As a percentage of drilling revenues, rig rent expense was 5% for the Prior Quarter. Adjusted average operating costs per revenue day, which excludes rig rent expense, increased 1% from the Prior Quarter to the Current Quarter.

37

Hydraulic Fracturing

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Revenues	$	202,017	$	201,620
Operating costs	171,305		177,012
Gross margin	$	30,712	$	24,608
Adjusted EBITDA	$	26,258	$	20,151

Hydraulic fracturing revenues for the Current Quarter increased $0.4 million from the Prior Quarter. This increase was due to a 51% increase in completed stages, partially offset by a 34% decrease in revenue per stage from the Prior Quarter to the Current Quarter. The increase in completed stages is primarily due to higher utilization of two of our crews and the decrease in revenue per stage is primarily due to frac design changes implemented by our principal customer. Revenues from non-CHK customers increased $15.0 million to 7% of total segment revenues in the Current Quarter.

Hydraulic fracturing operating costs for the Current Quarter decreased $5.7 million, or 3% from the Prior Quarter, primarily due to a reduction in repairs and maintenance expenses. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs were 85% and 88% for Current Quarter and Prior Quarter, respectively.

Oilfield Rental

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Revenues	$	32,488	$	35,942
Operating costs	23,619		25,949
Gross margin	$	8,869	$	9,993
Adjusted EBITDA	$	7,792	$	9,976

Oilfield rental revenues for the Current Quarter decreased $3.5 million, or 10%, from the Prior Quarter. The decrease was primarily due to a decline in utilization attributable to a reduction in drilling and completions activity by our customers. Revenues from non-CHK customers increased $10.6 million to 44% of total segment revenues in the Current Quarter compared to 10% for the Prior Quarter.

Oilfield rental operating costs for the Current Quarter decreased $2.3 million, or 9%, from the Prior Quarter. The decrease was primarily due to a reduction in repairs and maintenance expenses. As a percentage of oilfield rental revenues, oilfield rental operating costs were 73% and 72% for the Current Quarter and Prior Quarter, respectively.

38

Oilfield Trucking

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Revenues	$	29,228		$	56,195
Operating costs	36,291			53,614
Gross margin	$	(7,063	)	$	2,581
Adjusted EBITDA	$	(8,445	)	$	2,064
Adjusted Revenue(a):
Revenue	$	29,228		$	56,195
Less:
Crude hauling revenues	—			13,299
Adjusted Revenue	$	29,228		$	42,896
Adjusted Operating Costs(a):
Operating Costs	$	36,291		$	53,614
Less:
Crude hauling operating costs	—			12,761
Adjusted Operating Costs	$	36,291		$	40,853

(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 crude hauling assets sold to a third party as part of the 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.”

Oilfield trucking revenues for the Current Quarter decreased $27.0 million, or 48%, from the Prior Quarter. The decrease was primarily due to the sale of our crude hauling assets to a third party in the second quarter of 2014 and a decline in utilization of our rig relocation and water transportation services resulting from decreased drilling activity. Revenues from non-CHK customers increased to 54% of total segment revenues in the Current Quarter compared to 22% for the Prior Quarter.

Oilfield trucking operating costs for the Current Quarter decreased $17.3 million or 32%, from the Prior Quarter due primarily to the sale of our crude hauling assets to a third party in the second quarter of 2014 as part of the spin-off. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 124% and 95% for the Current Quarter and Prior Quarter, respectively.

Subsequent to March 31, 2015, we made the decision to exit the water hauling and transport business.

39

Other Operations

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Revenues	$	—		$	35,519
Operating costs	2,256			28,554
Gross margin	$	(2,256	)	$	6,965
Adjusted Revenue(a):
Revenue	$	—		$	35,519
Less:
Compression unit manufacturing revenues	—			35,481
Adjusted Revenue	$	—		$	38
Adjusted Operating Costs(b):
Operating Costs	$	2,256		$	28,554
Less:
Compression unit manufacturing operating costs	$	—		$	27,954
Adjusted Operating Costs	$	2,256		$	600

(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. 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 $85.0 million and $72.5 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 2 to our condensed consolidated financial statements in Item 1 of this report. As a percentage of revenues, depreciation and amortization expense was 20% and 14% for the Current Quarter and Prior Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Prior Quarter were $33.9 million and $20.9 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 provides or makes available to us various administrative services and assets for specified periods beginning on the distribution date. We incurred non-cash compensation expenses of $9.5 million and $0.1 million and severance-related costs of $1.4 million and $0.2 million during the Current Quarter and Prior Quarter, respectively. During the Current Quarter, we incurred charges of $5.6 million for services provided by CHK pursuant to the transition services agreement. During the Prior Quarter, we incurred charges of $12.8 million pursuant to the administrative services agreement. As a percentage of revenues, general and administrative expenses were 8% and 4% for the Current Quarter and Prior Quarter, respectively.

40

Losses on Sales of Property and Equipment. During the Current Quarter and Prior Quarter, we sold ancillary equipment not utilized in our business and recognized losses on sales of property and equipment of approximately $4.2 million and $1.0 million related to these asset sales, respectively.

Impairments and Other. During the Current Quarter and Prior Quarter, we recognized impairment charges of $6.3 million and $19.8 million, respectively. In the Current Quarter, we recognized impairment charges of $3.3 million and $2.5 million for certain drilling rigs and trucking and fluid disposal equipment that we impaired based on expected future cash flows of these rigs and equipment. During the Prior Quarter, we recognized impairment charges of $5.7 million for certain drilling rigs and spare equipment we sold in 2014, $5.4 million for drilling rigs that we impaired based on our assessment of future demand and suitability of these drilling rigs in light of this demand, and $8.4 million in lease termination costs related to the purchase of 20 leased drilling rigs. We subsequently sold six of the drilling rigs purchased during the Prior Quarter.

Interest Expense. Interest expense for the Current Quarter and Prior Quarter was $23.5 million and $14.7 million, respectively, related to borrowings under our senior notes, term loan, and credit facility. The increase in interest expense from the Previous Quarter to the Current Quarter was primarily due to the additional debt issued in conjunction with the spin-off.

Income (loss) from Equity Investees. Income (loss) from equity investees was $1.0 million and ($0.9) million for the Current Quarter and Prior Quarter, respectively, which was a result of our investment in Maalt. We own 49% of the membership interest in Maalt.

Other (Expense) Income. Other (expense) income was ($0.1) million and $0.4 million for the Current Quarter and Prior Quarter, respectively.

Income Tax Benefit. We recorded income tax benefit of $16.2 million and $10.7 million for the Current Quarter and Prior Quarter, respectively. The $5.5 million increase in income tax benefit recorded for the Current Quarter was primarily the result of an increase in net loss before taxes of $24.6 million from the Prior Quarter to the Current Quarter. Our effective income tax rate for the Current Quarter and Prior Quarter was 30% and 37%, respectively. The decrease in our effective tax rate from the Prior Quarter to the Current Quarter was primarily the result of permanent differences related to stock compensation in the Current Quarter.

Off-Balance Sheet Arrangements

Operating Leases

As of March 31, 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. We account for these leases as operating leases.

As of March 31, 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 March 31, 2015 under our operating leases are presented below:

	Rail Cars		Other		Total
	(in thousands)
Remainder of 2015	$	4,085	$	1,521	$	5,606
2016	5,447		992		6,439
2017	2,168		591		2,759
2018	1,445		170		1,615
2019	722		3		725
Total	$	13,867	$	3,277	$	17,144

41

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 March 31, 2015, we had $168.4 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2015.

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

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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 74% and 85% of our revenues, respectively. Sustained low 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 Loan. We have borrowings outstanding under 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 Loan.

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 March 31, 2015.

Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
	(in thousands)				(in thousands)
2015	$	—	—		$	4,000	3.750	%
2016	—		—		4,000		3.750	%
2017	—		—		4,000		3.750	%
2018	—		—		4,000		3.750	%
2019	650,000		6.625	%	69,300		3.722	%
After 2019	500,000		6.500	%	378,000		3.750	%
Total	$	1,150,000			$	463,300
Fair value	$	726,500			$	412,538

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, as our hydraulic fracturing operations grow, we will face increased 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.

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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 covered by this report. 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 not effective as of March 31, 2015 because of the material weakness in our internal control over financial reporting described in Item 9A of our Annual Report on Form 10-K.

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 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 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 provider.

In response to the material weakness described above, during the quarter ended March 31, 2015, we implemented new internal controls which we believe will remediate the previously identified material weakness. We are currently testing the operating effectiveness of these new internal controls.

Changes in Internal Control Over Financial Reporting

During the quarter ended March 31, 2015, we implemented a new enterprise resource planning system, SAP, which replaced our previous systems. SAP was operational on January 1, 2015. In conjunction with the implementation, we modified the design, operation and documentation of our internal controls over financial reporting for the business processes impacted by the new system.

Except as described above, there were no other 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.

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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
January 1, 2015 - January 31, 2015	232,957	$	5.23	—	—
February 1, 2015 - February 28, 2015	10,795	6.07		—	—
March 1, 2015 - March 31, 2015	3,259	4.16		—	—
Total	247,011	$	5.26	—	—

(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.

Item 5. Other Information

Not applicable.

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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
10.1	2015 Executive Performance Management Plan*					X
12.1	Schedule of Computation of Ratio of Earnings to Fixed Charges.					X
31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
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.						X
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.						X
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.
*	Management contract or compensatory plan or arrangement.

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SIGNATURES

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

May 5, 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

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INDEX TO EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Commission File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
10.1	2015 Executive Performance Management Plan*					X
12.1	Schedule of Computation of Ratio of Earnings to Fixed Charges.					X
31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
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.						X
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.						X
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.
*	Management contract or compensatory plan or arrangement.

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