Seventy Seven Energy Inc. - FORM 10-Q

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EX-31.1 - EX-31.1 - Seventy Seven Energy Inc.	a20140930ex311.htm

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 SEPTEMBER 30, 2014



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

FOR THE TRANSITION PERIOD FROM TO

Commission File No. 001-36354

Seventy Seven Energy Inc.

(Exact name of registrant as specified in its charter)



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

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

(405) 608-7777

(Registrant’s telephone number, including area code)

______________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

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

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

As of October 27, 2014, there were 50,867,348 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	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	74
Item 4.	Controls and Procedures	75

PART II. OTHER INFORMATION		76
Item 1.	Legal Proceedings	76
Item 1A.	Risk Factors	76
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	76
Item 5.	Other Information	76
Item 6.	Exhibits	78

SIGNATURES		79

PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Balance Sheets

(unaudited)



	September 30, 2014			December 31, 2013
	(in thousands)
Assets:
Current Assets:
Cash	$	5,333		$	1,678
Accounts receivable, net of allowance of $2,588 and $524 at September 30, 2014 and December 31, 2013, respectively	497,707			375,439
Inventory	30,457			45,035
Deferred income tax asset	7,912			5,318
Prepaid expenses and other	22,388			20,301
Total Current Assets	563,797			447,771
Property and Equipment:
Property and equipment, at cost	2,690,486			2,241,350
Less: accumulated depreciation	(958,251		)	(773,282		)
Property and equipment held for sale, net	6,000			29,408
Total Property and Equipment, Net	1,738,235			1,497,476
Other Assets:
Equity method investment	7,684			13,236
Goodwill	27,434			42,447
Intangible assets, net	5,575			7,429
Deferred financing costs	26,004			14,080
Other long-term assets	6,785			4,454
Total Other Assets	73,482			81,646
Total Assets	$	2,375,514		$	2,026,893
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	38,925		$	64,866
Current portion of long-term debt	4,000			—
Other current liabilities	297,050			210,123
Total Current Liabilities	339,975			274,989
Long-Term Liabilities:
Deferred income tax liabilities	153,998			145,747
Long-term debt, excluding current maturities	1,588,600			1,055,000
Other long-term liabilities	2,347			3,965
Total Long-Term Liabilities	1,744,945			1,204,712
Commitments and Contingencies (Note 6)
Equity:
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 50,750,941 shares at September 30, 2014	508			—
Paid-in capital	291,856			—
Accumulated deficit	(1,770		)	—
Owner’s equity	—			547,192
Total Equity	290,594			547,192
Total Liabilities and Stockholders’/Owner’s Equity	$	2,375,514		$	2,026,893

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Operations

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except per share data)
Revenues:
Revenues	$	526,773		$	550,403		$	1,585,948		$	1,677,354
Operating Expenses:
Operating costs	392,138			451,532			1,208,312			1,323,964
Depreciation and amortization	73,855			72,983			218,149			215,584
General and administrative	32,723			18,863			72,977			60,276
Net losses (gains) on sales of property and equipment	454			(265		)	(7,532		)	(1,636		)
Impairments and other	7,751			23,626			30,731			30,367
Total Operating Expenses	506,921			566,739			1,522,637			1,628,555
Operating Income (Loss)	19,852			(16,336		)	63,311			48,799
Other Income (Expense):
Interest expense	(23,606		)	(14,028		)	(55,913		)	(42,177		)
(Loss) income and impairment from equity investees	(347		)	262			(5,764		)	(910		)
Other (expense) income	(134		)	123			623			584
Total Other Expense	(24,087		)	(13,643		)	(61,054		)	(42,503		)
(Loss) Income Before Income Taxes	(4,235		)	(29,979		)	2,257			6,296
Income Tax (Benefit) Expense	(2,465		)	(11,295		)	873			3,571
Net (Loss) Income	$	(1,770	)	$	(18,684	)	$	1,384		$	2,725

Earnings Per Common Share (Note 2)
Basic	$	(0.04	)	$	(0.40	)	$	0.03		$	0.06
Diluted	$	(0.04	)	$	(0.40	)	$	0.03		$	0.06

Weighted Average Common Shares Outstanding
Basic	47,331			46,932			47,139			46,932
Diluted	47,331			46,932			47,143			46,932

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statement of Changes in Equity

(unaudited)



	Common Stock	Common Stock		Paid-in Capital			Owner's Equity			Accumulated Deficit			Total Stockholders’/ Owner’s Equity
	(Shares)	(in thousands)
Balance at December 31, 2013	—	$	—	$	—		$	547,192		$	—		$	547,192
Net income (loss)	—	—		—			3,154			(1,770		)	1,384
Contributions from Chesapeake	—	—		—			190,297			—			190,297
Distributions to Chesapeake	—	—		—			(472,998		)	—			(472,998		)
Reclassification of owner’s equity to paid-in capital	—	—		267,645			(267,645		)	—			—
Issuance of common stock at spin-off	46,932,433	469		(469		)	—			—			—
Share-based compensation	3,818,508	39		24,680			—			—			24,719
Balance at September 30, 2014	50,750,941	$	508	$	291,856		$	—		$	(1,770	)	$	290,594

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Nine Months Ended September 30,
	2014			2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	1,384		$	2,725
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization	218,149			215,584
Amortization of sale/leaseback gains	(5,401		)	(4,613		)
Amortization of deferred financing costs	5,048			2,191
Net gains on sales of property and equipment	(7,532		)	(1,636		)
Impairments	21,030			30,260
Loss from equity investees	5,764			910
Provision for doubtful accounts	2,062			—
Non-cash compensation	27,763			—
Deferred income tax expense	(1,197		)	2,918
Other	106			1,106
Changes in operating assets and liabilities	(115,130		)	27,130
Net cash provided by operating activities	152,046			276,575
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment	(313,441		)	(174,324		)
Proceeds from sales of assets	68,537			42,955
Proceeds from sale of investment	—			2,790
Additions to investments	(213		)	(387		)
Other	63			—
Net cash used in investing activities	(245,054		)	(128,966		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Chesapeake	(421,920		)	(14,261		)
Proceeds from issuance of senior notes, net of offering costs	493,825			—
Proceeds from issuance of term loan, net of issuance costs	393,879			—
Payments on term loan	(1,000		)	—
Deferred financing costs	(3,546		)	—
Borrowings from revolving credit facility	930,900			824,600
Payments on revolving credit facility	(1,292,300		)	(957,300		)
Other	(3,175		)	470
Net cash provided by (used in) financing activities	96,663			(146,491		)
Net increase in cash	3,655			1,118
Cash, beginning of period	1,678			1,227
Cash, end of period	$	5,333		$	2,345

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Increase (decrease) in other current liabilities related to purchases of property and equipment	$	39,197		$	(52,984	)
Property and equipment distributed to Chesapeake at spin-off	$	(792	)	$	—
Property and equipment contributed from Chesapeake at spin-off	$	190,297		$	—
SUPPLEMENTAL DISCLOSURE OF CASH PAYMENTS:
Interest paid, net of amount capitalized	$	28,930		$	30,576

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

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Spin-Off

On June 9, 2014, Chesapeake Energy Corporation (“Chesapeake”) 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 Seventy Seven Energy Inc. (“SSE,” “we,” “us,” “our” or “ours”) to Chesapeake’s shareholders of record as of the close of business on June 19, 2014, the record date. On June 30, 2014, each Chesapeake shareholder received one share of SSE common stock for every fourteen shares of Chesapeake 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 Chesapeake. Following the spin-off, Chesapeake 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 U.S. Securities and Exchange Commission (“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”. See Note 12 for further discussion of agreements entered into as part of the spin-off, including a master separation agreement, a transition services agreement, an employee matters agreement and a tax sharing agreement, among others. As part of the spin-off, we completed the following transactions, among others, which we refer to as the “Transactions”:


•	we entered into a new $275.0 million senior secured revolving credit facility (the "New Credit Facility") and a $400.0 million secured term loan (the “Term Loan”). We used the proceeds from borrowings under these new facilities to repay in full and terminate our $500.0 million senior secured revolving credit facility (the "Old Credit Facility").


•	we issued new 6.50% senior unsecured notes due 2022 (the “2022 Notes”) and used the net proceeds of approximately $493.8 million to make a cash distribution of approximately $391.0 million to Chesapeake, to repay a portion of outstanding indebtedness under the New Credit Facility and for general corporate purposes.


•	we distributed our compression unit manufacturing business and our geosteering business to Chesapeake.


•	we sold our crude hauling assets to a third party and used a portion of the net proceeds received to make a $30.9 million cash distribution to Chesapeake.


•	Chesapeake transferred to us buildings and real estate used in our business, including property and equipment, at cost of approximately $212.5 million and accumulated depreciation of $22.2 million as of the date of the spin-off.


•	COO transferred all of its existing assets, operations and liabilities, including our 6.625% senior unsecured notes due 2019 (the “2019 Notes”), to Seventy Seven Operating LLC (“SSO”). SSO is an Oklahoma limited liability company, our direct wholly-owned subsidiary and, after giving effect to the Transactions, the owner of all our operating subsidiaries.


•	COO was renamed SSE and converted from a limited liability company to a corporation.

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As part of the spin-off, we distributed our compression unit manufacturing and geosteering businesses to Chesapeake. The following table presents the carrying value of the major categories of assets and liabilities of the businesses distributed to Chesapeake on June 26, 2014, and as reflected on our consolidated balance sheets as of December 31, 2013.



	June 26, 2014		December 31, 2013
	(in thousands)
Current Assets:
Accounts receivable	$	15,094	$	7,061
Affiliate accounts receivable	9,514		8,777
Inventory	26,137		19,672
Deferred income tax asset	165		416
Prepaid expenses and other	—		27
Total current assets	50,910		35,953

Property and equipment, net	792		803
Goodwill	15,013		15,013
Total assets	$	66,715	$	51,769

Current Liabilities:
Accounts payable	$	7,861	$	3,315
Affiliate accounts payable	1,316		2,279
Other current liabilities	20,409		5,393
Total current liabilities	29,586		10,987
Deferred income tax liabilities	2,221		4,429
Total liabilities	$	31,807	$	15,416

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes present SSE’s financial position as of September 30, 2014 and December 31, 2013, results of operations for the three and nine months ended September 30, 2014 and 2013, changes in equity for the nine months ended September 30, 2014 and cash flows for the nine months ended September 30, 2014 and 2013. These notes relate to the three and nine months ended September 30, 2014 (the “Current Quarter” and “Current Period,” respectively) and the three and nine months ended September 30, 2013 (the “Prior Quarter” and “Prior Period,” respectively ). All significant intercompany accounts and transactions within SSE have been eliminated.

Seventy Seven Finance Inc. (“SSF”) is a 100% owned finance subsidiary of SSE that was incorporated for the purpose of facilitating the offering of SSE’s 2019 Notes (see Note 4). 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, 2013 contained in our Annual Report on Form 10-K (Commission File No. 333-187766) filed with the SEC on March 14, 2014.

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 September 30, 2014, our primary owned assets consisted of 89 drilling rigs, nine hydraulic fracturing fleets, 261 rig relocation trucks, 68 cranes and forklifts and 148 water transport trucks. Additionally, we had 12 rigs leased under contracts at September 30, 2014 (see Note 6). Our reportable business segments are drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations (see Note 13).

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2. Earnings Per Share

Basic income per share is based on the weighted average number of shares of common stock outstanding. Diluted income per share assumes exercises of stock options and full vesting of participating restricted stock awards, provided the effect is dilutive. Potentially dilutive stock options representing 11,384 shares of common stock for the Current Quarter were excluded from the computation of diluted weighted average common shares outstanding due to their antidilutive effect.

On June 30, 2014, we distributed 46,932,433 shares of our common stock to Chesapeake 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. SSE grants certain incentive compensation awards to employees and non-employee directors that are considered to be participating securities. There was no material impact to basic or diluted earnings per share for the Current Quarter or Current Period due to participating securities.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014		2013
	(in thousands, except per share data)
Basic earnings per share:
Allocation of earnings:
Net (loss) income	$	(1,770	)	$	(18,684	)	$	1,384	$	2,725

Weighted average common shares outstanding	47,331			46,932			47,139		46,932
Basic (loss) earnings per share	$	(0.04	)	$	(0.40	)	$	0.03	$	0.06

Diluted earnings per share:
Allocation of earnings:
Net (loss) income	$	(1,770	)	$	(18,684	)	$	1,384	$	2,725

Weighted average common shares outstanding	47,331			46,932			47,139		46,932
Effect of dilutive securities	—			—			4		—
Weighted average common shares, including dilutive effect	47,331			46,932			47,143		46,932
Diluted (loss) earnings per share	$	(0.04	)	$	(0.40	)	$	0.03	$	0.06

3. Asset Sales, Assets Held for Sale and Impairments and Other

Asset Sales

During the Current Period, we sold 15 drilling rigs and ancillary equipment that were not being utilized in our business for $24.7 million, net of selling expenses. During the Current Period, we also sold our crude hauling assets, which included 124 fluid handling trucks and 122 trailers, for $43.8 million. We used a portion of the net proceeds received to make a $30.9 million cash distribution to Chesapeake. During the Prior Period, we sold 13 drilling rigs and ancillary equipment that were not being utilized in our business for $43.0 million, net of selling expenses. We recorded net losses (gains) on sales of property and equipment of approximately $0.5 million, ($0.3) million, ($7.5) million and ($1.6) million related to these asset sales during the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. These assets were part of our drilling and oilfield trucking segments. The distribution of our compression unit manufacturing and geosteering businesses as part of our spin-off and the sale of our crude hauling assets do not qualify as discontinued operations because the disposals did not represent a strategic shift that had or will have a major effect on our operations or financial results.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Assets Held for Sale and Impairments and Other

A summary of our impairments and other is as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)
Drilling rigs held for sale	$	5,523	$	19,291	$	11,237	$	22,683
Drilling rigs held for use	—		4,263		8,366		4,263
Lease termination costs	1,253		—		9,701		107
Other	975		72		1,427		3,314
Total impairments and other	$	7,751	$	23,626	$	30,731	$	30,367

During the Current Period and Prior Period, we recognized $11.2 million and $22.7 million, respectively, of impairment charges 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 they meet the criteria for held-for-sale accounting. Estimated fair value was based on the expected sales price, less costs to sell. Included in property and equipment held for sale on our consolidated balance sheet was $6.0 million and $29.4 million as of September 30, 2014 and December 31, 2013, respectively. These assets were included in our drilling segment.

We also identified certain drilling rigs during the Current Period and Prior Period 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. We recorded impairment charges of $8.4 million and $4.3 million during the Current Period and Prior Period, respectively, related to these drilling rigs. Estimated fair value for these drilling rigs was determined using significant unobservable inputs (Level 3) based on a market approach. During the Current Period, we also purchased 33 of our leased drilling rigs for approximately $134.0 million and paid lease termination costs of approximately $9.7 million. During the Prior Period, we purchased two leased drilling rigs for approximately $0.4 million and paid lease termination costs of approximately $0.1 million.

We identified certain other property and equipment during the Current Quarter, Prior Quarter, Current Period and Prior Period that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $1.0 million, $0.1 million, $1.4 million and $3.3 million during the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively, related to these assets. Estimated fair value for this property and equipment was determined using significant unobservable inputs (Level 3) based on an income approach.

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 reductions in capital expenditures by Chesapeake 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.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

4. Debt

As of September 30, 2014 and December 31, 2013, our long-term debt consisted of the following:



	September 30, 2014		December 31, 2013
	(in thousands)
6.625% Senior Notes due 2019	$	650,000	$	650,000
6.50% Senior Notes due 2022	500,000		—
Term Loan	399,000		—
Credit Facilities	43,600		405,000
Total debt	1,592,600		1,055,000
Less: Current portion of long-term debt	4,000		—
Total long-term debt	$	1,588,600	$	1,055,000

Credit Facilities

In November 2011, we entered into a five-year senior secured revolving bank credit facility with total commitments of $500.0 million. In connection with the spin-off, we repaid in full borrowings outstanding and terminated this credit facility.

On June 25, 2014, we, through SSO, entered into a five-year senior secured revolving bank credit facility with total commitments of $275.0 million. We incurred $2.2 million in financing costs related to entering into the New Credit Facility, which have been deferred and are being amortized over the life of the New Credit Facility. The maximum amount that we may borrow under the New 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 September 30, 2014, the New Credit Facility had availability of $225.6 million, net of letters of credit of $5.8 million. All obligations under the New 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 New 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 New 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 New 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 New 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 New 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 New Credit Facility could be terminated and any outstanding borrowings under the New Credit Facility may be declared immediately due and payable. The New Credit Facility also contains cross default provisions that apply to our other indebtedness.

Term Loan

On June 25, 2014, we entered into a $400.0 million seven-year term loan credit agreement. We incurred $7.3 million in financing costs related to entering into the Term Loan, which have been deferred and are being amortized over the life of the Term Loan. We used the net proceeds of $393.9 million to repay and terminate the Old Credit Facility. 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 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 Standard & Poor’s Rating Services

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(“S&P”) and Moody’s Investors Service, Inc. (“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.

2022 Senior Notes

On June 26, 2014, we issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 (the “2022 Notes”) in a private placement. We incurred $7.5 million in financing costs related to the 2022 Notes issuance, which have been deferred and are being amortized over the life of the 2022 Notes. We used the net proceeds of $493.8 million from the 2022 Notes issuance to make a distribution of approximately $391.0 million to Chesapeake to repay in full indebtedness outstanding under our New Credit Facility, and for general corporate purposes. 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) SSO or (iii) subsidiaries of SSO. We do not have any such subsidiaries currently; therefore, the 2022 Notes are not guaranteed. Upon the full repayment of the 2019 Notes, the 2022 Notes will be fully and unconditionally guaranteed on a senior unsecured basis by each of our domestic subsidiaries that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million.

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



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

The indenture governing the 2022 Notes subjects us 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

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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.

Under a registration rights agreement, we agreed to file a registration statement within 365 days after the closing of the 2022 Notes offering enabling holders of the 2022 Notes to exchange the privately placed 2022 Notes for publicly registered exchange notes with substantially the same terms. We filed the registration statement on September 30, 2014 and the first amendment to the registration statement on October 23, 2014. The registration statement is not yet effective, but we are required to use our commercially reasonable best efforts to cause the registration statement to become effective as soon as practicable and to consummate the exchange offer on the earliest practicable date after the registration statement has become effective, but in no event later than 60 days after the date the registration statement has become effective.

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 Senior Notes”). The 2019 Senior 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 Senior Notes are guaranteed by all of our existing subsidiaries, other than certain immaterial subsidiaries and SSF, which is a co-issuer of the 2019 Senior Notes.

We may redeem up to 35% of the 2019 Senior Notes with proceeds of certain equity offerings at a redemption price of 106.625% of the principal amount plus accrued and unpaid interest prior to November 15, 2014, subject to certain conditions. Prior to November 15, 2015, we may redeem some or all of the 2019 Senior 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 indenture governing the 2019 Senior Notes subjects us 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 or S&P, our obligation to comply with certain of these covenants will be suspended, and if the 2019 Senior Notes achieve an investment grade rating from both Moody’s and S&P, then all such covenants will terminate.

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5. Other Current Liabilities

Other current liabilities as of September 30, 2014 and December 31, 2013 are detailed below:



	September 30, 2014		December 31, 2013
	(in thousands)
Other Current Liabilities:
Accrued expenses	$	132,336	$	101,007
Payroll related	58,323		47,796
Insurance reserves	15,038		27,245
Interest	27,798		5,862
Income, property, sales, use and other taxes	16,205		17,904
Property and equipment	46,207		7,010
Deferred gain on sale/leasebacks	13		3,299
Other	1,130		—
Total Other Current Liabilities	$	297,050	$	210,123

6. Commitments and Contingencies

Rent expense for rigs, real property and rail cars for the Current Quarter, Prior Quarter, Current Period and Prior Period was $5.6 million, $28.8 million, $33.2 million and $87.7 million, respectively, and was included in operating costs in our condensed consolidated statements of operations.

Rig Leases

As of September 30, 2014, we leased 12 rigs under master lease agreements. Under the leases, we can purchase the rigs at expiration of the lease for the fair market value at the time of expiration. In addition, in most cases, we have the option to renew a lease on negotiated new terms at the expiration of the lease. These leases are accounted for as operating leases. (See Note 16)

Rail Car Leases

As of September 30, 2014, we were party to seven lease agreements with various third parties to lease rail cars for initial terms of three 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. These leases are accounted for as operating leases.

Aggregate undiscounted minimum future lease payments under our operating leases are presented below:



	September 30, 2014
	Rigs		Rail Cars		Total

Remainder of 2014	$	3,395	$	1,528	$	4,923
2015	—		7,263		7,263
2016	—		7,263		7,263
2017	—		3,608		3,608
2018	—		2,885		2,885
After 2018	—		2,162		2,162
Total	$	3,395	$	24,709	$	28,104

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Other Commitments

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of September 30, 2014, we had $218.3 million of purchase commitments related to future capital expenditures that we expect to incur in 2014 and 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, $4.1 million, $7.6 million and $11.7 million during the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

7. Share-Based Compensation

Prior to the spin-off, our employees participated in the Chesapeake share-based compensation program and received restricted stock, and in the case of senior management, stock options. Effective July 1, 2014, our employees participate in the SSE 2014 Incentive Plan (the “2014 Plan”).

The 2014 Plan authorizes the Compensation Committee of our Board of Directors to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, cash awards and performance awards. No more than 8.4 million shares of SSE common stock may be issued under the 2014 Plan.

In connection with the spin-off, unvested awards granted under the Chesapeake share-based compensation program were cancelled and substituted as follows:


•	Each outstanding award of options to purchase shares of Chesapeake common stock was replaced with a substitute award of options to purchase shares of SSE common stock. The substitute awards of options are intended to preserve the intrinsic value of the original option and the ratio of the exercise price to the fair market value of the stock subject to the option.


•	The Chesapeake restricted stock awards and restricted stock unit awards were replaced with substitute awards in SSE common stock, each of which generally preserved the value of the original award.

Awards granted in connection with the substitution of awards originally issued under the Chesapeake share-based compensation program are a part of the 2014 Plan and reduce the maximum number of shares of common stock available for delivery under the 2014 Plan.

Equity-Classified Awards

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

A summary of the status and changes of unvested shares of restricted stock under the 2014 Plan is presented below.

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	Number of Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of July 1, 2014	2,097		$	25.06
Granted	2,473		$	23.38
Vested	(334	)	$	25.06
Forfeited	(136	)	$	24.94
Unvested shares as of September 30, 2014	4,100		$	24.05

The aggregate intrinsic value of restricted stock vested for the Current Quarter, as reflected in the table above, was approximately $8.5 million based on the market price of SSE’s common stock at the time of vesting.

As of September 30, 2014, there was $85.9 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. Our 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 Chesapeake award, in the case of a replacement award. Our non-replacement stock option awards have an exercise price equal to the closing price of SSE’s common stock on the grant date. Outstanding options expire ten years from the date of grant of the original Chesapeake award, in the case of a replacement award.

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 July 1, 2014	348	$	16.19	9.24	$	3,463
Granted	—	$	—
Exercised	—	$	—
Outstanding at September 30, 2014	348	$	16.19	8.49	$	2,631
Exercisable at September 30, 2014	35	$	15.29	8.33	$	295


(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 September 30, 2014, there was $2.2 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.

Through the date of the spin-off we were charged by Chesapeake for share-based compensation expense related to our direct employees. Pursuant to the employee matters agreement with Chesapeake, our employees received a new award under the 2014 Plan in substitution for each unvested Chesapeake award then held (which were cancelled). We recorded a non-recurring credit of $10.5 million to operating costs and general and administrative costs on our condensed consolidated income statement during the second quarter of 2014 as a result of the cancellation of the unvested Chesapeake awards.

Included in operating costs and general and administrative expenses is stock-based compensation expense of $21.2 million, $3.8 million, $16.2 million and $9.9 million for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Prior to the spin-off, we reimbursed Chesapeake for these costs in accordance with the administrative services agreement. To the extent compensation cost relates 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.

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8. 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 Chesapeake. 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 58%, 38%, 39% and 57% for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Our effective tax rate can fluctuate as a result of the impact of state income taxes, permanent differences and changes in pre-tax income. Effective with the spin-off, we entered into a tax sharing agreement with Chesapeake 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 $162.2 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 Chesapeake related to the spin-off in the tax affected amount of approximately $189.0 million.

A valuation allowance for deferred tax assets 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 September 30, 2014 and December 31, 2013.

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 September 30, 2014 and December 31, 2013.

9. Investments

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 $7.7 million as of September 30, 2014. We recorded equity method adjustments to our investment of ($0.3), a nominal amount, ($1.3) million and $0.2 million for our share of Maalt’s (loss) income for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. We also made additional investments of $0.2 million and $0.4 million in the Current Period and Prior Period, respectively. As of September 30, 2014, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $7.7 million. This excess is attributable to goodwill recorded on Maalt’s financial statements and is not being amortized.

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

10. 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

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techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are:

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

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

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

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 3 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.



	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value (Level 2)		Carrying Amount		Fair Value (Level 2)
	(in thousands)
Financial liabilities:
Credit Facilities	$	43,600	$	42,318	$	405,000	$	399,592
Term Loan	$	399,000	$	395,509	$	—	$	—
2022 Notes	$	500,000	$	496,250	$	—	$	—
2019 Notes	$	650,000	$	686,920	$	650,000	$	679,660

11. 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 Chesapeake and its affiliates were $408.1 million and $312.5 million as of September 30, 2014 and December 31, 2013, or 82% and 83%, respectively, of our total accounts receivable. Revenues from Chesapeake and its affiliates were $418.7 million, $477.0 million, $1.297 billion and $1.535 billion for the Current Quarter, Prior Quarter, Current Period and Prior Period, or 79%, 87%, 82% and 91%, 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 12 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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12. Transactions with Chesapeake

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

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

On June 25, 2014, we entered into a tax sharing agreement with Chesapeake, which governs the respective rights, responsibilities and obligations of Chesapeake 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 Chesapeake 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 Chesapeake employees, treatment of holders of Chesapeake stock options, restricted stock, restricted stock units and performance share units, and cooperation between us and Chesapeake in the sharing of employee information and maintenance of confidentiality.

On June 25, 2014, we entered into a transition services agreement with Chesapeake under which Chesapeake 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 Chesapeake fees, a portion of which is a flat fee, generally in amounts intended to allow Chesapeake 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 Chesapeake were $9.3 million for the Current Quarter. The services that Chesapeake is providing to us include:

•marketing and corporate communication services;

•human resources services;

•information technology services;

•security services;

•risk management services;

•tax services;

•HSE services;

•maintenance services;

•internal audit services;

•accounting services;

•treasury services; and

•certain other services specified in the agreement.

We are party to a master services agreement with Chesapeake pursuant to which we provide drilling and other services and supply materials and equipment to Chesapeake. 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 Chesapeake’s business, and allocates certain operational risks between Chesapeake and us through indemnity provisions. The master services agreement will remain in effect until we or Chesapeake 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 Chesapeake under which Chesapeake 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 Chesapeake which supplements the master services agreement.

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Under the new services agreement, Chesapeake 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 Chesapeake in all its operating regions during the respective year. Chesapeake is required to utilize our pressure pumping services for a minimum number of stages as set forth in the agreement. Chesapeake 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, Chesapeake’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 Chesapeake or as a result of a force majeure event.

In connection with the spin-off, we entered into rig-specific daywork drilling contracts with Chesapeake 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. Chesapeake has the right to terminate the drilling agreements under certain circumstances.

Prior to the spin-off, we were party to a facilities lease agreement with Chesapeake pursuant to which we leased a number of the storage yards and physical facilities out of which we conduct our operations. We incurred $3.9 million, $8.2 million and $12.3 million of lease expense for the Prior Quarter, Current Period and Prior Period, respectively, under this facilities lease agreement. In connection with the spin-off, we acquired the property subject to the facilities lease agreement, and the facilities lease agreement was terminated.

Prior to the spin-off, Chesapeake 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 Chesapeake, we reimbursed Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake 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 Chesapeake employees who perform services on our behalf. The administrative expense allocation was determined by multiplying revenues by a percentage determined by Chesapeake 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 Chesapeake were $13.8 million, $26.8 million and $42.5 million for the Prior Quarter, Current Period and Prior Period, respectively. In connection with the spin-off, we terminated the administrative services agreement and entered into the transition services agreement.

13. 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 September 30, 2014, we owned or leased a fleet of 101 land drilling rigs. In conjunction with the spin-off, we distributed our geosteering business to Chesapeake.

Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation services. Hydraulic fracturing involves pumping fluid down a well casing or tubing under high pressure to cause the underground formation to crack, allowing the oil or natural gas to flow more freely. As of September 30, 2014, we owned nine hydraulic fracturing fleets with an aggregate of 360,000 horsepower.

Oilfield Rentals. Our oilfield rentals segment provides premium rental tools for land-based oil and natural gas drilling, completion and workover activities. We offer a full line of rental tools, including drill pipe, drill collars, tubing, blowout preventers, frac tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions.

Oilfield Trucking. Our oilfield trucking segment provides drilling rig relocation and logistics services as well as fluid handling services. Our trucks move drilling rigs and other fluids and construction materials to and from the wellsite and also

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transport produced water from the wellsite. As of September 30, 2014, we owned a fleet of 261 rig relocation trucks, 68 cranes and forklifts and 148 water transport trucks. Prior to the spin-off, we sold our crude hauling assets to a third party.

Other Operations. Our other operations consist primarily of our compression unit manufacturing business and corporate functions, including our 2019 Notes, 2022 Notes, Term Loan and credit facilities. In conjunction with the spin-off, we distributed our compression unit manufacturing business to Chesapeake.

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	Drilling			Hydraulic Fracturing			Oilfield Rentals			Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
For The Three Months Ended September 30, 2014:
Revenues	$	197,082		$	245,128		$	39,139		$	42,865		$	12,049		$	(9,490	)	$	526,773
Intersegment revenues	3,312			—			(221		)	(1,664		)	(10,917		)	9,490			—
Total revenues	$	200,394		$	245,128		$	38,918		$	41,201		$	1,132		$	—		$	526,773
Depreciation and amortization	36,062			17,524			12,812			5,230			2,227			—			73,855
Losses (gains) on sales of property and equipment	331			(19		)	(771		)	907			6			—			454
Impairments and other^(a)	6,796			—			955			—			—			—			7,751
Interest expense	—			—			—			—			(23,606		)	—			(23,606		)
Loss and impairment from equity investees	—			(347		)	—			—			—			—			(347		)
Other income (expense)	(146		)	6			135			96			(225		)	—			(134		)
Income( Loss) Before Income Taxes	$	24,234		$	37,076		$	(1,096	)	$	(5,636	)	$	(58,813	)	$	—		$	(4,235	)

For The Three Months Ended September 30, 2013:
Revenues	$	189,373		$	226,922		$	36,192		$	64,275		$	41,854		$	(8,213	)	$	550,403
Intersegment revenues	(1,333		)	—			(371		)	(1,023		)	(5,486		)	8,213			—
Total revenues	$	188,040		$	226,922		$	35,821		$	63,252		$	36,368		$	—		$	550,403
Depreciation and amortization	33,670			18,156			14,553			6,372			232			—			72,983
Losses (gains) on sales of property and equipment	52			—			(253		)	(65		)	1			—			(265		)
Impairments and other^(a)	23,626			—			—			—			—			—			23,626
Interest expense	—			—			—			—			(14,028		)	—			(14,028		)
(Loss) income and impairment from equity investees	—			(28		)	—			290			—			—			262
Other (expense) income	(71		)	47			81			79			(13		)	—			123
(Loss) Income Before Income Taxes	$	(14,891	)	$	2,138		$	(3,211	)	$	2,421		$	(16,436	)	$	—		$	(29,979	)

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	Drilling			Hydraulic Fracturing			Oilfield Rentals			Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
For The Nine Months Ended September 30, 2014:
Revenues	$	570,147		$	672,860		$	114,743		$	156,626		$	100,263		$	(28,691	)	$	1,585,948
Intersegment revenues	(143		)	—			(906		)	(3,779		)	(23,863		)	28,691			—
Total revenues	$	570,004		$	672,860		$	113,837		$	152,847		$	76,400		$	—		$	1,585,948
Depreciation and amortization	105,362			53,484			39,527			16,588			3,188			—			218,149
Losses (gains) on sales of property and equipment	16,126			(19		)	(1,696		)	(21,964		)	21			—			(7,532		)
Impairments and other^(a)	29,569			207			955			—			—			—			30,731
Interest expense	—			—			—			—			(55,913		)	—			(55,913		)
Loss and impairment from equity investees	—			(5,764		)	—			—			—			—			(5,764		)
Other income (expense)	399			42			162			133			(113		)	—			623
Income (Loss) Before Income Taxes	$	36,028		$	57,445		$	(3,905	)	$	8,929		$	(96,240	)	$	—		$	2,257

For The Nine Months Ended September 30, 2013:
Revenues	$	566,194		$	692,213		$	125,899		$	191,880		$	125,718		$	(24,550	)	$	1,677,354
Intersegment revenues	(3,919		)	—			(788		)	(4,508		)	(15,335		)	24,550			—
Total revenues	$	562,275		$	692,213		$	125,111		$	187,372		$	110,383		$	—		$	1,677,354
Depreciation and amortization	99,680			50,469			45,300			19,456			679			—			215,584
Losses (gains) on sales of property and equipment	231			—			(730		)	(1,121		)	(16		)	—			(1,636		)
Impairments and other^(a)	27,153			—			1			—			3,213			—			30,367
Interest expense	—			—			—			—			(42,177		)	—			(42,177		)
Income (loss) and impairment from equity investees	—			207			—			(1,117		)	—			—			(910		)
Other (expense) income	(167		)	198			340			159			54			—			584
(Loss) Income Before Income Taxes	$	(5,002	)	$	57,058		$	(528	)	$	6,983		$	(52,215	)	$	—		$	6,296

As of September 30, 2014:
Total Assets	$	1,285,744		$	521,174		$	169,042		$	147,326		$	258,619		$	(6,391	)	$	2,375,514
As of December 31, 2013:
Total Assets	$	1,134,026		$	454,559		$	184,285		$	204,386		$	55,432		$	(5,795	)	$	2,026,893


(a)	Includes lease termination costs of $1.3 million, $0.0 million, $9.7 million and $0.1 million for the Current Quarter, Prior Quarter, Current Period and Prior Period.

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14. 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 4). 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 material subsidiaries, other than SSF, which is a co-issuer of the 2019 Notes. 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 September 30, 2014 and December 31, 2013 and for the three and nine months ended September 30, 2014 and 2013. 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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2014

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	89	$	5,159		$	85		$	—		$	5,333
Accounts receivable	—		747			497,695			(735		)	497,707
Inventory	—		—			30,457			—			30,457
Deferred income tax asset	—		2,091			6,029			(208		)	7,912
Prepaid expenses and other	—		9,606			12,782			—			22,388
Total Current Assets	89		17,603			547,048			(943		)	563,797
Property and Equipment:
Property and equipment, at cost	—		12,454			2,678,032			—			2,690,486
Less: accumulated depreciation	—		(508		)	(957,743		)	—			(958,251		)
Property and equipment held for sale, net	—		—			6,000			—			6,000
Total Property and Equipment, Net	—		11,946			1,726,289			—			1,738,235
Other Assets:
Equity method investment	—		—			7,684			—			7,684
Goodwill	—		—			27,434			—			27,434
Intangible assets, net	—		—			5,575			—			5,575
Deferred financing costs, net	7,227		18,777			—			—			26,004
Other long-term assets	5,649		20,379			5,630			(24,873		)	6,785
Investments in subsidiaries and intercompany advances	788,143		1,858,614			—			(2,646,757		)	—
Total Other Assets	801,019		1,897,770			46,323			(2,671,630		)	73,482
Total Assets	$	801,108	$	1,927,319		$	2,319,660		$	(2,672,573	)	$	2,375,514
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	—	$	8,323		$	31,337		$	(735	)	$	38,925
Current portion of long-term debt	—		4,000			—			—			4,000
Other current liabilities	10,514		37,098			249,646			(208		)	297,050
Total Current Liabilities	10,514		49,421			280,983			(943		)	339,975
Long-Term Liabilities:
Deferred income tax liabilities	—		—			178,871			(24,873		)	153,998
Long-term debt, excluding current maturities	500,000		1,088,600			—			—			1,588,600
Other long-term liabilities	—		1,155			1,192			—			2,347
Total Long-Term Liabilities	500,000		1,089,755			180,063			(24,873		)	1,744,945
Total Equity	290,594		788,143			1,858,614			(2,646,757		)	290,594
Total Liabilities and Stockholders’/Owner’s Equity	$	801,108	$	1,927,319		$	2,319,660		$	(2,672,573	)	$	2,375,514

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2013

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	—	$	1,615		$	63		$	—		$	1,678
Accounts receivable	—		1,142			374,297			—			375,439
Inventory	—		—			45,035			—			45,035
Deferred income tax asset	—		—			5,318			—			5,318
Prepaid expenses and other	—		851			19,450			—			20,301
Total Current Assets	—		3,608			444,163			—			447,771
Property and Equipment:
Property and equipment, at cost	—		3,103			2,238,247			—			2,241,350
Less: accumulated depreciation	—		(133		)	(773,149		)	—			(773,282		)
Property and equipment held for sale, net	—		—			29,408			—			29,408
Total Property and Equipment, Net	—		2,970			1,494,506			—			1,497,476
Other Assets:
Equity method investment	—		—			13,236			—			13,236
Goodwill	—		—			42,447			—			42,447
Intangible assets, net	—		—			7,429			—			7,429
Deferred financing costs, net	—		14,080			—			—			14,080
Other long-term assets	—		54,958			4,454			(54,958		)	4,454
Investments in subsidiaries and intercompany advances	547,192		1,542,365			—			(2,089,557		)	—
Total Other Assets	547,192		1,611,403			67,566			(2,144,515		)	81,646
Total Assets	$	547,192	$	1,617,981		$	2,006,235		$	(2,144,515	)	$	2,026,893
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	—	$	2,889		$	61,977		$	—		$	64,866
Other current liabilities	—		11,669			198,454			—			210,123
Total Current Liabilities	—		14,558			260,431			—			274,989
Long-Term Liabilities:
Deferred income tax liabilities	—		—			200,705			(54,958		)	145,747
Long-term debt	—		1,055,000			—			—			1,055,000
Other long-term liabilities	—		1,231			2,734			—			3,965
Total Long-Term Liabilities	—		1,056,231			203,439			(54,958		)	1,204,712
Total Equity	547,192		547,192			1,542,365			(2,089,557		)	547,192
Total Liabilities and Equity	$	547,192	$	1,617,981		$	2,006,235		$	(2,144,515	)	$	2,026,893

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2014

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—		$	1,264		$	526,754		$	(1,245	)	$	526,773
Operating Expenses:				—			—			—
Operating costs	—			1,037			392,344			(1,243		)	392,138
Depreciation and amortization	—			86			73,769			—			73,855
General and administrative	148			32,149			426			—			32,723
Net losses on sales of property and equipment	—			6			448			—			454
Impairments and other	—			—			7,751			—			7,751
Total Operating Expenses	148			33,278			474,738			(1,243		)	506,921
Operating (Loss) Income	(148		)	(32,014		)	52,016			(2		)	19,852
Other (Expense) Income:
Interest expense	(8,358		)	(15,248		)	—			—			(23,606		)
Loss and impairment from equity investees	—			—			(347		)	—			(347		)
Other (expense) income	—			(284		)	150			—			(134		)
Equity in net earnings (loss) of subsidiary	2,669			32,387			—			(35,056		)	—
Total Other (Expense) Income	(5,689		)	16,855			(197		)	(35,056		)	(24,087		)
(Loss) Income Before Income Taxes	(5,837		)	(15,159		)	51,819			(35,058		)	(4,235		)
Income Tax (Benefit) Expense	(4,067		)	(17,829		)	19,432			(1		)	(2,465		)
Net (Loss) Income	$	(1,770	)	$	2,670		$	32,387		$	(35,057	)	$	(1,770	)

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2013

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—		$	2,176		$	550,338		$	(2,111	)	$	550,403
Operating Expenses:
Operating costs	—			2,407			451,378			(2,253		)	451,532
Depreciation and amortization	—			9			72,974			—			72,983
General and administrative	—			4,728			14,135			—			18,863
Net gains on sales of property and equipment	—			—			(265		)	—			(265		)
Impairments	—			—			23,626			—			23,626
Total Operating Expenses	—			7,144			561,848			(2,253		)	566,739
Operating (Loss) Income	—			(4,968		)	(11,510		)	142			(16,336		)
Other (Expense) Income:
Interest expense	—			(14,028		)	—			—			(14,028		)
Income from equity investees	—			—			262			—			262
Other income	—			—			123			—			123
Equity in net loss of subsidiary	(18,571		)	(5,643		)	—			24,214			—
Total Other (Expense) Income	(18,571		)	(19,671		)	385			24,214			(13,643		)
Loss Before Income Taxes	(18,571		)	(24,639		)	(11,125		)	24,356			(29,979		)
Income Tax Expense (Benefit)	113			(5,955		)	(5,369		)	(84		)	(11,295		)
Net Loss	$	(18,684	)	$	(18,684	)	$	(5,756	)	$	24,440		$	(18,684	)

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2014

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—		$	3,527		$	1,585,885		$	(3,464	)	$	1,585,948
Operating Expenses:
Operating costs	—			4,644			1,208,359			(4,691		)	1,208,312
Depreciation and amortization	—			152			217,997			—			218,149
General and administrative	148			44,366			28,463			—			72,977
Net gains (losses) on sales of property and equipment	—			6			(7,538		)	—			(7,532		)
Impairments and other	—			—			30,731			—			30,731
Total Operating Expenses	148			49,168			1,478,012			(4,691		)	1,522,637
Operating (Loss) Income	(148		)	(45,641		)	107,873			1,227			63,311
Other (Expense) Income:
Interest expense	(8,810		)	(47,103		)	—			—			(55,913		)
Loss and impairment from equity investees	—			—			(5,764		)	—			(5,764		)
Other (expense) income	—			(136		)	759			—			623
Equity in net earnings of subsidiary	6,104			63,374			—			(69,478		)	—
Total Other (Expense) Income	(2,706		)	16,135			(5,005		)	(69,478		)	(61,054		)
(Loss) Income Before Income Taxes	(2,854		)	(29,506		)	102,868			(68,251		)	2,257
Income Tax (Benefit) Expense	(4,238		)	(34,849		)	39,494			466			873
Net Income	$	1,384		$	5,343		$	63,374		$	(68,717	)	$	1,384

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2013

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—	$	6,191		$	1,677,171		$	(6,008	)	$	1,677,354
Operating Expenses:
Operating costs	—		7,355			1,323,604			(6,995		)	1,323,964
Depreciation and amortization	—		16			215,568			—			215,584
General and administrative	—		14,022			46,254			—			60,276
Net gains on sales of property and equipment	—		—			(1,636		)	—			(1,636		)
Impairments and other	—		—			30,367			—			30,367
Total Operating Expenses	—		21,393			1,614,157			(6,995		)	1,628,555
Operating (Loss) Income	—		(15,202		)	63,014			987			48,799
Other (Expense) Income:
Interest expense	—		(42,177		)	—			—			(42,177		)
Loss from equity investees	—		—			(910		)	—			(910		)
Other income	—		4			580			—			584
Equity in net earnings of subsidiary	3,337		38,418			—			(41,755		)	—
Total Other Income (Expense)	3,337		(3,755		)	(330		)	(41,755		)	(42,503		)
Income (Loss) Before Income Taxes	3,337		(18,957		)	62,684			(40,768		)	6,296
Income Tax Expense (Benefit)	612		(21,682		)	24,878			(237		)	3,571
Net Income	$	2,725	$	2,725		$	37,806		$	(40,531	)	$	2,725

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2014

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	60,339		$	(14,288	)	$	207,622		$	(101,627	)	$	152,046
Cash Flows From Investing Activities:
Additions to property and equipment	—			(9,351		)	(304,090		)	—			(313,441		)
Proceeds from sale of assets	—			—			68,537			—			68,537
Additions to investments and other	(127,999		)	(70,422		)	(150		)	198,421			(150		)
Cash used in investing activities	(127,999		)	(79,773		)	(235,703		)	198,421			(245,054		)
Cash Flows From Financing Activities:
Distributions to Chesapeake	(421,920		)	—			—			—			(421,920		)
Contributions from affiliates	—			68,691			28,103			(96,794		)	—
Proceeds from issuance of senior notes, net of offering costs	493,825			—			—			—			493,825
Proceeds from issuance of term loan, net of issuance costs	—			393,879			—			—			393,879
Payments on term loan	—			(1,000		)	—			—			(1,000		)
Deferred financing costs	(981		)	(2,565		)	—			—			(3,546		)
Borrowings from revolving credit facility	—			930,900			—			—			930,900
Payments on revolving credit facility	—			(1,292,300		)	—			—			(1,292,300		)
Other	(3,175		)	—			—			—			(3,175		)
Net cash provided by financing activities	67,749			97,605			28,103			(96,794		)	96,663
Net increase (decrease) in cash	89			3,544			22			—			3,655
Cash, beginning of period	—			1,615			63			—			1,678
Cash, end of period	$	89		$	5,159		$	85		$	—		$	5,333

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2013

(in thousands)



			Subsidiary Issuer			Guarantor
	Parent		Subsidiary Issuer			Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	—	$	136,741		$	317,177		$	(177,343	)	$	276,575
Cash Flows From Investing Activities:
Additions to property and equipment	—		(3,065		)	(171,259		)	—			(174,324		)
Proceeds from sale of assets	—		—			42,955			—			42,955
Proceeds from sale of investment	—		—			2,790			—			2,790
Other	—		—			(387		)	—			(387		)
Cash used in investing activities	—		(3,065		)	(125,901		)	—			(128,966		)
Cash Flows From Financing Activities:
Distributions to affiliates	—		—			(191,604		)	177,343			(14,261		)
Borrowings from revolving credit facility	—		824,600			—			—			824,600
Payments on revolving credit facility	—		(957,300		)	—			—			(957,300		)
Other	—		470			—			—			470
Net cash used in financing activities	—		(132,230		)	(191,604		)	177,343			(146,491		)
Net increase (decrease) in cash	—		1,446			(328		)	—			1,118
Cash, beginning of period	—		863			364			—			1,227
Cash, end of period	$	—	$	2,309		$	36		$	—		$	2,345

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15. Recently Issued Accounting Standards

Recently Issued Accounting Standards

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 April 2014, the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 2014-08 raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. It is effective for annual periods beginning on or after December 15, 2014. Early adoption is permitted but only for disposals that have not been reported in financial statements previously issued. We early adopted ASU 2014-08 in the Current Period. We applied this standard in our evaluation of the distributions of businesses and assets sales completed in the Current Period and concluded that these disposals did not qualify as discontinued operations.

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. We are currently evaluating what impact this standard will have on our consolidated financial statements.

16. Subsequent Events

Subsequent to September 30, 2014, we purchased 11 leased drilling rigs for approximately $22.9 million described in Note 6. In conjunction with the purchases, we also terminated approximately $3.0 million of remaining lease commitments associated with these drilling rigs.



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

The following discussion and analysis of our financial condition and results of operations relates to the three and nine months ended September 30, 2014 (the “Current Quarter” and “Current Period,” respectively), the three and nine months ended September 30, 2013 (the “Prior Quarter” and “Prior Period,” respectively) and the three months ended June 30, 2014 (the “Previous Quarter”) and should be read in conjunction with our condensed consolidated financial statements and related notes appearing elsewhere in this quarterly report on Form 10-Q and with our Annual Report on Form 10-K for the year ended December 31, 2013.

Comparability of Historical Results

The historical results discussed in this section prior to June 30, 2014 are those of Chesapeake Oilfield Operating, L.L.C. (“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 basis of presentation of the historical financial statements, please read Note 1 to our unaudited condensed consolidated financial statements.

In particular, the historical results for periods prior to the spin-off discussed in this section do not reflect the effects of the following transactions, which impact our results of operations subsequent to the spin-off:


•	the entrance into our new $275.0 million senior secured revolving credit facility (the “New Credit Facility”) and a $400.0 million secured term loan (the “Term Loan”). We used the proceeds from borrowings under these new facilities to repay in full and terminate our existing $500.0 million senior secured revolving credit facility (the “Old Credit Facility”);


•	the issuance of new 6.50% senior unsecured notes due 2022 (the “2022 Notes”);


•	the distribution to Chesapeake of our compression unit manufacturing business and geosteering business;


•	the sale of our crude hauling assets to a third party;


•	the transfer to us by Chesapeake of certain land and buildings used in our business, most of which were previously leased by us; and


•	the potential increase in our cash requirements as an independent public company, including tax obligations and incremental public company expenses.

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. Our services include drilling, hydraulic fracturing, oilfield rentals, rig relocation and water transport and disposal. 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.

We conduct our business through four operating segments:

Drilling. Our drilling segment is operated through our wholly-owned subsidiary, Nomac Drilling, L.L.C., and provides land drilling and drilling-related services, including directional drilling for oil and natural gas E&P activities. According to Rig Data, we have the 4th largest active U.S. land-based drilling rig fleet, which we categorize into three operational “Tiers.” All of our Tier 1 and Tier 2 rigs are equipped with electric drives and top drives. Both our AC powered Tier 1 and DC powered Tier 2 rigs are predominantly equipped with 1,600 horsepower mud pumps. Approximately 71% of our Tier 1 and Tier 2 rigs are multi-well pad capable, equipped with skidding or walking systems. Our Tier 3 rigs are legacy, mechanical drive rigs.

As of September 30, 2014, our marketed fleet consisted of 22 Tier 1 rigs, including 12 proprietary PeakeRigs™, 57 Tier 2 rigs and eight Tier 3 rigs. We also have 14 contracted PeakeRigs™ under construction. Our PeakeRigs™ are designed for

long lateral drilling of multiple wells from a single location, which makes them well suited for unconventional resource development. We are aggressively pursuing a strategy of upgrading our fleet to better align with the market’s demand for multi-well pad drilling in unconventional resource plays. In connection therewith, we plan to upgrade or sell all of the Tier 3 rigs that we own and expect that our fleet will primarily include only Tier 1 and Tier 2 rigs by the end of 2014.

For the quarter ended September 30, 2014, our drilling operating segment generated revenues of $200.4 million and Adjusted EBITDA of $82.4 million. “Adjusted EBITDA” is a non-GAAP financial measure that 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. For a description of our calculation of Adjusted EBITDA and a reconciliation to net income by operating segment, see “—How We Evaluate Our Operations.” As of September 30, 2014, approximately 42% of our active rigs were contracted by non-Chesapeake customers including a drilling backlog of $265.2 million with an average duration of nine months. As of September 30, 2014, our drilling backlog with Chesapeake was $925.6 million with an average duration of 27 months. We compute duration as the average number of months remaining for our drilling rigs under contract.

As of September 30, 2014, all of our drilling contracts were rig-specific daywork contracts. A rig-specific daywork contract generally provides for a basic rate per day when drilling (the dayrate for our providing a rig and crew) and for lower rates when the rig is moving between locations, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or certain other conditions beyond our control. In addition, daywork contracts may provide for a lump-sum fee for the mobilization and demobilization of the rig, which in most cases approximates our incurred costs.

Hydraulic Fracturing. Our hydraulic fracturing segment is operated through our wholly-owned subsidiary, Performance Technologies, L.L.C. (“PTL”), and provides high-pressure hydraulic fracturing (or frac) services and other well stimulation services. Hydraulic fracturing involves pumping fluid down a well casing or tubing under high pressure to cause the underground formation to crack, allowing the oil or natural gas to flow more freely. As of September 30, 2014, we owned nine hydraulic fracturing fleets with an aggregate of 360,000 horsepower and eight of these fleets were contracted by Chesapeake in the Anadarko Basin, Barnett and the Eagle Ford and Utica Shales. We currently expect our tenth fleet to begin operating later in the fourth quarter of 2014. Our equipment had an average age of 26 months as of September 30, 2014, which we believe to be among the newest in the industry. We averaged approximately 84 and 75 stages per fleet per month for the three and nine months ended September 30, 2014, respectively. For the quarter ended September 30, 2014, our hydraulic fracturing operating segment generated revenues of $245.1 million and Adjusted EBITDA of $56.5 million. As of September 30, 2014, our hydraulic fracturing backlog with Chesapeake was $1.4 billion with an average duration of 23 months. We compute duration as the average number of months remaining for our fleets under contract.

We are generally compensated based on the number of fracturing stages we complete, and we recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day during the course of a job. A stage is considered complete when the customer requests that pumping discontinue for that stage. Invoices typically include service charges that are determined by hydraulic horsepower requirements and achieved rate of barrels per minute along with product charges for sand, chemicals and other products actually consumed during the course of providing our services.

Oilfield Rentals. Our oilfield rentals segment is operated through our wholly-owned subsidiary, Great Plains Oilfield Rental, L.L.C. (“GPOR”), and provides premium rental tools and specialized services for land-based oil and natural gas drilling, completion and workover activities. We offer an extensive line of rental tools, including a full line of tubular products specifically designed for horizontal drilling and completion, with high-torque, premium-connection drill pipe, drill collars and tubing for rent that is supported through a sophisticated inspection, repair and refurbishment capability. Additionally, we offer surface rental equipment including blowout preventers, frac tanks, mud tanks and environmental containment that leverage all phases of the hydrocarbon extraction and production process. Our air drilling equipment and services enable extraction in select basins where segments of certain formations preclude the use of drilling fluid, permitting operators to drill through problematic zones without the risk of fluid absorption and damage to the wellbore. We also provide critical frac-support services, including rental and rig-up/rig-down of wellhead pressure control equipment (frac stacks), delivery of on-site frac water through a robust water transfer operation (including an industry-leading water transfer school) and monitoring and controlling of production returns through our testing and flowback business. As of September 30, 2014, we offered oilfield rental services in the Anadarko and Permian Basins and the Eagle Ford, Barnett, Haynesville, Marcellus, Niobrara and Utica Shales. This broad geographic footprint gives us exposure to the preponderance of unconventional plays in the U.S., and allows us to optimize deployment of our equipment to regions of the greatest demand. We price our rentals and services based on the type of equipment being rented and the services being performed. Substantially all rental revenue we earn is based

upon a charge for the actual period of time the rental is provided to our customer on a market-based fixed per-day or per-hour fee. For the quarter ended September 30, 2014, our oilfield rentals operating segment generated revenues of $38.9 million and Adjusted EBITDA of $13.7 million.

Oilfield Trucking. Our oilfield trucking segment is operated through our wholly-owned subsidiaries, Hodges Trucking Company, L.L.C. (“Hodges”), Oilfield Trucking Solutions, L.L.C. (“OTS”) and GPOR. Hodges provides drilling rig relocation and logistics services. As of September 30, 2014, Hodges owned a fleet of 261 rig relocation trucks and 68 cranes and forklifts, which were operating in the Anadarko and Permian Basins and the Barnett, Eagle Ford, Haynesville, Marcellus and Utica Shales. OTS and GPOR provide water transport and disposal services. As of September 30, 2014, our subsidiaries owned a fleet of 148 water transport trucks that transport water to and from wells in the Anadarko Basin and the Eagle Ford, Marcellus and Utica Shales. We price these services by the hour and volume and recognize revenue as services are performed. For the quarter ended September 30, 2014, our oilfield trucking operating segment generated revenues of $41.2 million and Adjusted EBITDA of $3.8 million.

Spin-Off

On June 9, 2014, the board of directors of Chesapeake 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 Chesapeake’s shareholders of record as of the close of business on June 19, 2014, the record date. On June 30, 2014, each Chesapeake shareholder received one share of SSE common stock for every fourteen shares of Chesapeake common stock held by such shareholder on the record date, and SSE became an independent, publicly traded company as a result of the distribution. See “—Agreements Between Chesapeake and Us” for further discussion of agreements entered into at the time of the spin-off, including a master separation agreement, a transition services agreement, an employee matters agreement and a tax sharing agreement, among others. 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 COO. As part of the spin-off, we completed the following transactions, among others, which we refer to as the “Transactions”:


•	we entered into the New Credit Facility and Term Loan. We used the proceeds from borrowings under these new facilities to repay in full and terminate our Old Credit Facility.


•	we issued the 2022 Notes and used the net proceeds of approximately $493.8 million to make a cash distribution of approximately $391.0 million to Chesapeake, to repay a portion of outstanding indebtedness under the New Credit Facility and for general corporate purposes.


•	we distributed our compression unit manufacturing business and our geosteering business to Chesapeake. See “—Results of Operations” for further discussion of the financial impact of these businesses to our historical financial results.


•	we sold our crude hauling assets to a third party and used a portion of the net proceeds received to make a $30.9 million cash distribution to Chesapeake.

•

Chesapeake transferred to us buildings and real estate used in our business, including property and equipment, at cost of approximately $212.5 million and accumulated depreciation of $22.2 million as of the spin-off date. Prior to the spin-off, we leased these buildings and real estate from Chesapeake and incurred lease expense of $3.9 million, $8.2 million and $12.3 million for the Prior Quarter, Current Period and Prior Period, respectively.


•	COO transferred all of its existing assets, operations and liabilities, including our 6.625% senior unsecured notes due 2019 (the “2019 Notes”), to Seventy Seven Operating LLC (“SSO”). SSO is an Oklahoma limited liability company, our direct wholly-owned subsidiary and, after giving effect to the Transactions, the direct owner of all our operating subsidiaries.


•	COO was renamed SSE and converted from a limited liability company to a corporation.

Our Strategies

Our principal business objective is to profitably grow our business and to increase shareholder value. We expect to achieve this objective through execution of the following strategies:

Expand and develop relationships with existing and new third party customers. We intend to utilize our deep understanding of the needs of unconventional resource developers and our strategic position in some of the most active unconventional resource plays in the United States to continue to obtain new third party customers. We also intend to leverage

our drilling relationships with our 18 existing non-Chesapeake drilling customers and our reputation for quality to provide additional services that are in demand, such as hydraulic fracturing and oilfield rental and trucking. We believe the uniquely broad range of services we offer, as well as our diverse geographic footprint, positions us well to attract new customers and cross-sell services to existing customers. We intend to devote significant business development resources to market all of our services, leverage existing relationships and expedite our growth potential. Moreover, we plan to continue to invest capital and move resources to meet our customers’ needs as drilling and well completion activity increases. We believe this strategy will strengthen our overall relationships with our customers and increase our market share.

Grow and enhance our asset base. As an independent company, we have increased operational control of our business and no longer compete for capital with other Chesapeake businesses. We intend to accelerate the pace at which we upgrade our rigs and order new Tier 1 rigs. Currently, 20 of our 22 Tier 1 rigs and 36 of our 57 Tier 2 rigs are multi-well pad-ready and able to meet the robust demands of E&P customers focused on unconventional resource development. We took delivery of two proprietary PeakeRigs^TMduring the Current Quarter. Additionally, we are fabricating four additional PeakeRigs^TM, which are expected to be delivered by the fourth quarter of 2014, and an additional ten by the fourth quarter of 2015. In our hydraulic fracturing segment, we are vertically integrating our operations through the acquisition of sand reserves and sand processing operations. In response to customer demand, we invested in innovative lay flat pipe for water transfer as an alternative to more expensive and time-consuming steel tubing. We currently expect to spend approximately $450.0 million in aggregate growth capital expenditures in 2014 and 2015. We believe that targeting the development of high margin services through geographic expansion, vertical integration and asset additions will provide us with greater returns on our investments and support future growth. We also intend to pursue opportunistic acquisitions, particularly within our hydraulic fracturing segment, in a manner that is complementary to our existing asset base.

Increase utilization of our oilfield rental assets. We plan to devote significant local business development resources to deploy unused capacity in our oilfield rental business. We believe we can leverage our relationships with existing drilling and hydraulic fracturing customers to increase the utilization of our oilfield rental assets in the near term. We will also devote significant marketing and other resources to attract new and retain existing oilfield rental customers. This type of asset provides our highest margins and highest returns on invested capital relative to our other services.

Leverage our unique asset base to build a highly efficient, integrated service model. We believe we are the only U.S. land-based oilfield service company that can leverage its asset base to provide an integrated, single-source drilling and completion solution for companies focused on unconventional resource plays. The experience gained as an integrated part of Chesapeake, one of the most active developers of unconventional resources in the United States, makes us unique, allowing us to offer an integrated solution that provides high service and efficiency levels across the drilling and completion lifecycle. This experience and knowledge allows us to offer our customers a significant cost and cycle time advantage by providing or coordinating the wide array of services and logistics required to drill and complete their wells. We also believe that over time our integrated service model will allow us to move from transactional supplier to strategic partner for a significant number of our customers.

Continue our industry leading safety performance. We are committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is key to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We have a strong and improving Total Recordable Incidence Rate (TRIR) even as our employee base has increased by almost 50% over the past three years. From the beginning of 2011 to the end of the Current Quarter, our TRIR dropped by approximately 59%. In addition, our business goals include safety metrics, which drives continuous improvement regarding quality and safety. We have adopted and developed a management system that requires rigorous processes and procedures to facilitate our compliance with environmental regulations and policies. We also conduct internal and external assessments to verify compliance and identify areas for improvement. We work diligently to meet or exceed applicable safety and environmental regulations and we intend to continue to incorporate safety, environmental and quality principals into our operating procedures as our business grows and operating conditions change.

Continue our strong business relationship with Chesapeake. We have built a strong partnership with Chesapeake from the field level up to the senior management level. Our regional offices and equipment yards are often located near Chesapeake field operations. We believe we can continue to leverage these relationships as an independent company. Even while growing the percentage of our business attributable to non-Chesapeake customers, we expect to continue to benefit from our strong relationship with Chesapeake as a valued customer. See “—Agreements Between Chesapeake and Us” for further discussion of our new services agreements (the “New Services Agreements”) governing our provision of hydraulic fracturing, oilfield trucking and oilfield rental services. We also entered into rig-specific daywork drilling contracts (the “Drilling Agreements”) with respect to drilling services to be provided to Chesapeake following the spin-off.

Improve flexibility in our balance sheet. As an independent company, we have increased financial control of our business and intend to manage our balance sheet to enhance our financial flexibility. Once we have completed our planned growth capital expenditures through 2015, we intend to shift our focus toward using excess cash flows from operations to reduce outstanding long-term debt. We believe that the successful execution of our growth strategies together with a reduction in long-term debt over time will enhance our financial flexibility and better position us to take advantage of future business opportunities.

Backlog

We maintain a backlog of contract revenues under our contracts for the provision of drilling and hydraulic fracturing services. Our hydraulic fracturing and drilling backlog as of September 30, 2014 was approximately $1.4 billion and $1.2 billion with average durations of 23 months and 19 months, respectively. We calculate our contract 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 rate per stage by the number of guaranteed stages remaining under the contract. 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. As a result, revenues could differ materially from the backlog amounts presented.

As of September 30, 2014, we expect to recognize revenues from backlog as follows (in approximate millions):




	2014		2015		Thereafter
Backlog	$	343.1	$	1,101.2	$	1,110.0

Customers and Competition

The markets in which we operate are highly competitive. Our customers pay us market-based rates for the services we provide. To the extent that competitive conditions increase and market prices for the services and products we provide decrease, the amount we are able to charge our customers for such products and services may decrease.

We are party to a master services agreement (the “Master Services Agreement”) with Chesapeake, pursuant to which we provide drilling and other services and supply materials and equipment to Chesapeake. In connection with the spin-off, we supplemented the Master Services Agreement with new services agreements (the “New Services Agreements”) governing our provision of hydraulic fracturing, oilfield trucking and oilfield rental services. We also entered into rig-specific daywork drilling contracts (the “Drilling Agreements”) with respect to drilling services to be provided to Chesapeake following the spin-off. See “—Agreements Between Chesapeake and Us” for further discussion of these agreements. Our hydraulic fracturing and drilling backlog as of September 30, 2014 was approximately $1.4 billion and $925.6 million, respectively, related to these agreements with Chesapeake.

Revenues from non-Chesapeake customers increased 6% from the Previous Quarter to the Current Quarter to 21% of total revenues. Revenues from Chesapeake and its affiliates were $418.7 million, $477.0 million, $1.297 billion and $1.535 billion for the Current Quarter, Prior Quarter, Current Period and Prior Period, or 79%, 87%, 82% and 91%, respectively, of our total revenues. Pursuant to our Master Services Agreement with Chesapeake, we provide drilling and other services to Chesapeake. The Master Services Agreement contains general terms and provisions, specifies payment terms, audit rights and insurance requirements and allocates certain operational risks through indemnity and similar provisions. The specific terms of each drilling services request are typically provided pursuant to drilling contracts on a well-by-well basis or for a term of a certain number of days or wells. The specific terms of each request for other services are typically set forth in a field ticket or purchase or work order.

The Costs of Conducting Our Business

The principal expenses involved in conducting our business are labor costs, the costs of maintaining and repairing our equipment and product and material costs. We also plan to make expenditures for equipment purchases and are required to make expenditures to service our debt.

Prior to the spin-off, we had an administrative services agreement (the “Administrative Services Agreement”) with Chesapeake pursuant to which Chesapeake allocated certain expenses to us. Under the Administrative Services Agreement, in return for the general and administrative services provided by Chesapeake, we reimbursed Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake on our behalf in accordance with its allocation policy, which included actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of Chesapeake employees who performed services on our behalf. In connection with the spin-off, we terminated the Administrative Services Agreement and entered into a transition services agreement (the “Transition Services Agreement”). See “—Agreements Between Chesapeake and Us” for further discussion of these agreements.

Prior to the spin-off, we had a facilities lease agreement (the “Facilities Lease Agreement”) with Chesapeake pursuant to which we leased certain yards and other physical facilities out of which we conduct our operations. In connection with the spin-off, we acquired the property subject to the Facilities Lease Agreement, and, accordingly, the Facilities Lease Agreement was terminated.

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, and (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 and exclude depreciation and amortization, general and administrative expenses, net gains on sales of property and equipment and impairments and other. We view segment gross margin as one of our primary 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. Our drilling rig utilization rate was 100%, 93%, 99% and 95% for the three months ended September 30, 2014 and 2013 and the nine months ended September 30, 2014 and 2013, respectively.

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. A key 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. The table below shows our Adjusted EBITDA for the three and nine months ended September 30, 2014 and 2013.




	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(unaudited) (in thousands)
Adjusted EBITDA	$	132,802	$	97,268	$	339,157	$	344,623

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 our geosteering business that were distributed to Chesapeake 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 and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled in the Previous Quarter and reissued in the Current Quarter as part of the spin-off.

Non-GAAP Financial Measures

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

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

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


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


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


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

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

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

Consolidated



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Net (loss) income	$	(1,770	)	$	(18,684	)	$	1,384		$	2,725
Add:
Interest expense	23,606			14,028			55,913			42,177
Income tax (benefit) expense	(2,465		)	(11,295		)	873			3,571
Depreciation and amortization	73,855			72,983			218,149			215,584
Impairments and other	7,751			23,626			30,731			30,367
Net losses (gains) on sales of property and equipment	454			(265		)	(7,532		)	(1,636		)
Non-cash compensation	27,763			—			27,763			—
Impairment of equity method investment	—			—			4,500			1,789
Rent expense on buildings and real estate transferred from Chesapeake	—			3,940			8,187			12,270
Rig rent expense	3,608			22,454			18,683			68,006
Less:
Compression unit manufacturing Adjusted EBITDA	—			4,703			13,073			15,005
Geosteering Adjusted EBITDA	—			668			957			2,518
Crude hauling Adjusted EBITDA	—			4,148			(5,066		)	12,707
Non-recurring credit to stock compensation expense	—			—			10,530			—
Adjusted EBITDA	$	132,802		$	97,268		$	339,157		$	344,623



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Cash provided by operating activities	$	30,112		$	131,705		$	152,046		$	276,575
Add:
Changes in assets and liabilities	74,976			(66,117		)	115,130			(27,130		)
Interest expense	23,606			14,028			55,913			42,177
Lease termination costs	1,253			—			9,701			107
Amortization of sale/leaseback gains	262			1,534			5,401			4,613
Amortization of deferred financing costs	(1,076		)	(736		)	(5,048		)	(2,191		)
Loss from equity investees	(347		)	263			(1,264		)	879
Provision for doubtful accounts	(2,062		)	—			(2,062		)	—
Current tax expense	1,374			213			2,070			653
Rent expense on buildings and real estate transferred from Chesapeake	—			3,940			8,187			12,270
Rig rent expense	3,608			22,454			18,683			68,006
Other	1,096			(497		)	(106		)	(1,106		)
Less:
Compression unit manufacturing Adjusted EBITDA	—			4,703			13,073			15,005
Geosteering Adjusted EBITDA	—			668			957			2,518
Crude hauling Adjusted EBITDA	—			4,148			(5,066		)	12,707
Non-recurring credit to stock compensation expense	—			—			10,530			—
Adjusted EBITDA	$	132,802		$	97,268		$	339,157		$	344,623

Drilling



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014		2013
	(In thousands)
Net income (loss)	$	15,146	$	(9,262	)	$	22,328	$	(3,543	)
Add:
Income tax expense (benefit)	9,088		(5,629		)	13,700		(1,459		)
Depreciation and amortization	36,062		33,670			105,362		99,680
Impairments and other	6,796		23,626			29,569		27,153
Net losses on sales of property and equipment	331		52			16,126		231
Non-cash compensation	11,331		—			11,331		—
Rent expense on buildings and real estate transferred from Chesapeake	—		912			1,688		2,727
Rig rent expense	3,608		22,454			18,683		68,006
Less:
Geosteering Adjusted EBITDA	—		668			957		2,518
Non-recurring credit to stock compensation expense	—		—			4,318		—
Adjusted EBITDA	$	82,362	$	65,155		$	213,512	$	190,277

Hydraulic Fracturing



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
	(In thousands)
Net income	$	23,173		$	584	$	35,490		$	34,589
Add:
Income tax expense	13,904			1,554		21,956			22,469
Depreciation and amortization	17,524			18,156		53,484			50,469
Impairments	—			—		207			—
Net gains on sales of property and equipment	(19		)	—		(19		)	—
Non-cash compensation	1,922			—		1,922			—
Impairment of equity method investment	—			—		4,500			—
Rent expense on buildings and real estate transferred from Chesapeake	—			395		1,259			1,516
Less:
Non-recurring credit to stock compensation expense	—			—		477			—
Adjusted EBITDA	$	56,504		$	20,689	$	118,322		$	109,043

Oilfield Rentals



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Net (loss) income	$	(686	)	$	(1,249	)	$	(2,481	)	$	310
Add:
Income tax benefit	(411		)	(1,962		)	(1,424		)	(838		)
Depreciation and amortization	12,812			14,553			39,527			45,300
Impairments	955			—			955			—
Net gains on sales of property and equipment	(771		)	(253		)	(1,696		)	(730		)
Non-cash compensation	1,792			—			1,792			—
Rent expense on buildings and real estate transferred from Chesapeake	—			685			1,415			1,858
Less:
Non-recurring credit to stock compensation expense	—			—			601			—
Adjusted EBITDA	$	13,691		$	11,774		$	37,487		$	45,900

Oilfield Trucking



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Net (loss) income	$	(3,522	)	$	1,365		$	5,299		$	3,883
Add:
Income tax (benefit) expense	(2,113		)	1,056			3,631			3,101
Depreciation and amortization	5,230			6,372			16,588			19,456
Net losses (gains) on sales of property and equipment	907			(65		)	(21,964		)	(1,121		)
Non-cash compensation	3,258			—			3,258			—
Impairment of equity method investment	—			—			—			1,789
Rent expense on buildings and real estate transferred from Chesapeake	—			857			1,724			2,617
Less:
Crude hauling Adjusted EBITDA	—			4,148			(5,066		)	12,707
Non-recurring credit to stock compensation expense	—			—			1,826			—
Adjusted EBITDA	$	3,760		$	5,437		$	11,776		$	17,018

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 New 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 to meet our cash requirements.

Credit Facilities

On June 25, 2014, we entered into a five-year senior secured revolving bank credit facility with total commitments of $275.0 million. We incurred $2.2 million in financing costs related to entering into the New Credit Facility which have been deferred and are being amortized over the life of the New Credit Facility. The maximum amount that we may borrow under the New 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 September 30, 2014, the New Credit Facility had availability of approximately $225.6 million, net of letters of credit of $5.8 million. As of October 28, 2014, the New Credit Facility had availability of approximately $251.8 million. All obligations under the New 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 New 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, 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 New 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.

coverage ratio based on the ratio of consolidated EBITDA (minus unfinanced capital expenditures) to fixed charges, in each case as defined in the New 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 New Credit Facility could be terminated and any outstanding borrowings under the New Credit Facility may be declared immediately due and payable. We were in compliance with all covenants as of September 30, 2014. The New Credit Facility also contains cross default provisions that apply to other indebtedness.

Term Loan

On June 25, 2014, we entered into a $400.0 million seven-year term loan credit agreement. We incurred $7.3 million in financing costs related to entering into the Term Loan which have been deferred and are being amortized over the life of the Term Loan. We used the net proceeds of $393.9 million to repay and terminate the Old Credit Facility. 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 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 Standard & Poor’s Rating Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), such margins will be reduced by 0.25%. The Term Loan is repayable in 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 SSE and 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.

2022 Senior Notes

On June 26, 2014, we issued $500.0 million in aggregate principal amount of 6.50% Senior Notes due 2022 (the “2022 Notes”) in a private placement. We incurred $7.5 million in financing costs related to the 2022 Notes issuance which have been deferred and are being amortized over the life of the 2022 Notes. We used the net proceeds of $493.8 million from the 2022 Notes issuance to make a distribution of approximately $391.0 million to Chesapeake to repay in full indebtedness outstanding under our New Credit Facility, and for general corporate purposes. 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) SSO or (iii) subsidiaries of SSO. We do not have any such subsidiaries currently; therefore, the 2022 Notes are not guaranteed. Upon the full repayment of the 2019 Notes, the 2022 Notes will be fully and unconditionally guaranteed on a senior unsecured basis by each of our domestic subsidiaries that has outstanding indebtedness or guarantees in an aggregate principal amount greater than $15.0 million.



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

Under a registration rights agreement, we agreed to file a registration statement within 365 days after the closing of the 2022 Notes offering enabling holders of the 2022 Notes to exchange the privately placed 2022 Notes for publicly registered exchange notes with substantially the same terms. We are required to use our commercially reasonable best efforts to cause the registration statement to become effective as soon as practicable after filing and to consummate the exchange offer on the earliest practicable date after the registration statement has become effective, but in no event later than 60 days after the date the registration statement has become effective.

2019 Senior Notes



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

subsidiaries as unrestricted subsidiaries. The 2019 Senior Notes also have cross default provisions that apply to other indebtedness SSE or any of our guarantor subsidiaries. If the 2019 Senior 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 2019 Senior Notes achieve an investment grade rating from both Moody’s and S&P, then all such covenants will terminate. We were in compliance with all covenants as of September 30, 2014.

Capital Expenditures

Our business is capital-intensive, requiring significant investment to maintain, upgrade and purchase equipment to meet our customers’ needs and industry demand. To date, 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 made to extend the useful life of partially or fully depreciated assets; and


•	the purchase of leased drilling rigs.

We anticipate that our capital requirements going forward 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 $313.4 million and $174.3 million for the Current Period and Prior Period, respectively. During the Current Period, we purchased 33 of our leased drilling rigs for approximately $134.0 million. We currently expect our growth capital expenditures to be approximately $450.0 million in aggregate for 2014 and 2015, and we expect these expenditures to target the development of high margin service offerings through geographic expansion, vertical integration and asset additions including the fabrication of 16 new PeakeRigs™ and one new hydraulic fracturing fleet. We expect our total capital expenditures will be funded by cash flow from operating activities and borrowings under our New Credit Facility. We believe this equipment will provide us with greater returns on our investments and support future growth. We also intend to pursue opportunistic acquisitions, particularly within our hydraulic fracturing segment, in a manner that is complementary to our existing asset base. 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 Period and Prior Period.



	Nine Months Ended September 30,
	2014			2013
	(in thousands) (unaudited)
Cash Flow Statement Data:
Net cash provided by operating activities	$	152,046		$	276,575
Net cash used in investing activities	$	(245,054	)	$	(128,966	)
Net cash provided by (used in) financing activities	$	96,663		$	(146,491	)
Cash, beginning of period	$	1,678		$	1,227
Cash, end of period	$	5,333		$	2,345

Operating Activities. Cash provided by operating activities was $152.0 million and $276.6 million for the Current Period and Prior Period, respectively. Changes in working capital items (decreased) increased cash flow provided by operating activities by ($115.1) million and $27.1 million for the Current Period and Prior Period, respectively. During the Current Period we experienced an increase in accounts receivable of approximately $122.3 million due to changes in invoice processing procedures at the time of the spin-off that delayed payment of certain invoices resulting in an increase in our days sales

outstanding. We believe these delays are temporary and that invoice processing and payments will be normalized by the end of 2014. 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, losses from equity investees, non-cash compensation and deferred income taxes.

Investing Activities. Cash used in investing activities was $245.1 million and $129.0 million for the Current Period and Prior Period, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the Current Period and Prior Period were related to our investment in new PeakeRigs^™and the purchase of certain leased drilling rigs. We purchased 33 leased drilling rigs for approximately $134.0 million during the Current Period and two leased drilling rigs for approximately $0.4 million during the Prior Period, which is part of our ongoing strategic positioning process and includes an evaluation of our drilling rig fleet for marketability based on the specifications and condition of each evaluated asset as well as the future plans of our customers. Cash used in investing activities was partially offset by proceeds from asset sales in the amounts of $68.5 million and $43.0 million for the Current Period and Prior Period, respectively.

Financing Activities. Net cash provided by (used in) financing activities was $96.7 million and ($146.5) million for the Current Period and Prior Period, respectively. On June 25, 2014, we entered into our New Credit Facility with total commitments of $275.0 million. We had borrowings and repayments under our New Credit Facility of $336.8 million and $293.2 million, respectively, during the Current Period. On June 25, 2014, we entered into our Term Loan and used the net proceeds of approximately $393.9 million to repay and terminate the Old Credit Facility. On June 26, 2014, we issued our 2022 Notes and used the net proceeds of approximately $493.8 million to make a distribution of approximately $391.0 million to Chesapeake, to repay a portion of indebtedness outstanding under our New Credit Facility and for general corporate purposes. We incurred $3.5 million in deferred financing costs related to our New Credit Facility, Term Loan and 2022 Notes. We had borrowings and repayments under our Old Credit Facility of $594.1 million and $999.1 million, respectively, during the Current Period. We had borrowings and repayments under our Old Credit Facility of $824.6 million and $957.3 million, respectively, during the Prior Period. During the Current Period and Prior Period, we made cash distributions to Chesapeake, our former owner, of $421.9 million and $14.3 million, respectively.

Results of Operations—Three Months Ended September 30, 2014 vs. June 30, 2014

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



	Three Months Ended September 30,			Three Months Ended June 30,
	2014
	(in thousands)
Revenues:
Revenues	$	526,773		$	549,466
Operating Expenses:
Operating costs	392,138			406,586
Depreciation and amortization	73,855			71,829
General and administrative	32,723			19,368
Net losses (gains) on sales of property and equipment	454			(8,964		)
Impairments and other	7,751			3,172
Total Operating Expenses	506,921			491,991
Operating Income	19,852			57,475
Other Income (Expense):
Interest expense	(23,606		)	(17,615		)
Loss and impairment from equity investees	(347		)	(4,500		)
Other (expense) income	(134		)	386
Total Other Expense	(24,087		)	(21,729		)
(Loss) Income Before Income Taxes	(4,235		)	35,746
Income Tax (Benefit) Expense	(2,465		)	14,036
Net (Loss) Income	$	(1,770	)	$	21,710

Revenues. For the Current Quarter and Previous Quarter, revenues were $526.8 million and $549.5 million, respectively. Our revenues decreased by approximately $22.7 million from the Previous Quarter to the Current Quarter due to the distribution to Chesapeake of our compression unit manufacturing business and geosteering business and the sale of our crude hauling assets to a third party. Adjusted revenues were $497.7 million for the Previous Quarter, which excludes the impact of the compression unit manufacturing, geosteering and crude hauling assets. The increase in revenues for the Current Quarter compared to adjusted revenues for the Previous Quarter was due to an increase in demand for both our hydraulic fracturing and drilling segments which resulted in a higher number of completed stages and revenue days in the Current Quarter compared to the Previous Quarter. The majority of our revenues historically have been derived from Chesapeake and its working interest partners. Revenues from non-Chesapeake customers increased $5.7 million to 21% of total revenues in the Current Quarter compared to 19% for the Previous Quarter. See “—Agreements Between Chesapeake and Us” for further discussion of agreements entered into as part of the spin-off, including a new services agreement and rig-specific daywork drilling contracts. Our revenues and adjusted revenues for the Current Quarter and Previous Quarter are detailed below:



	Three Months Ended September 30,		Three Months Ended June 30,
	2014
	(in thousands)
Drilling	$	200,394	$	189,177
Hydraulic fracturing	245,128		226,112
Oilfield rentals	38,918		38,977
Oilfield trucking	41,201		55,451
Other operations	1,132		39,749
Total	$	526,773	$	549,466

Adjusted Revenue⁽¹⁾:
Revenue	$	526,773	$	549,466
Less:
Compression unit manufacturing revenues	—		39,230
Geosteering revenues	—		2,014
Crude hauling revenues	—		10,530
Adjusted Revenue	$	526,773	$	497,692

(1)

“Adjusted revenue” is a non-GAAP financial measure that we define as revenues before revenues associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake 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 reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Operating Costs. Operating costs for the Current Quarter and Previous Quarter were $392.1 million and $406.6 million, respectively. Our operating costs decreased by approximately $14.5 million from the Previous Quarter to the Current Quarter primarily due to the distribution to Chesapeake of our compression unit manufacturing business and geosteering business and the sale of our crude hauling assets to a third party. Adjusted operating costs were $382.4 million and $359.9 million for the Current Quarter and Previous Quarter, respectively, which excludes operating costs associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake and crude hauling assets sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled in the Previous Quarter and reissued in the Current Quarter as part of the spin-off. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.” The increase in adjusted operating costs in the Current Quarter compared to the Previous Quarter was due to an overall increase in drilling and completion activity by our customers. As a percentage of adjusted revenues, adjusted operating costs were 73% and 72% for the Current Quarter and Previous Quarter, respectively. This increase was primarily due to an increase in labor-related costs and repairs and maintenance expense. Our operating costs and adjusted operating costs for the Current Quarter and Previous Quarter are detailed below:



	Three Months Ended September 30,		Three Months Ended June 30,
	2014
	(in thousands)
Drilling	$	133,042	$	118,354
Hydraulic fracturing	190,730		179,283
Oilfield rentals	26,963		24,534
Oilfield trucking	40,264		51,451
Other operations	1,139		32,964
Total	$	392,138	$	406,586

Adjusted Operating Costs:
Operating Costs	$	392,138	$	406,586
Add:
Non-recurring credit to stock compensation expense⁽¹⁾	—		7,314
Less:
Rig rent expense⁽²⁾	3,608		6,016
Non-recurring debit to stock compensation expense⁽¹⁾	6,178		—
Compression unit manufacturing operating costs⁽³⁾	—		32,244
Geosteering operating costs⁽³⁾	—		1,208
Crude hauling operating costs⁽³⁾	—		14,495
Adjusted Operating Costs	$	382,352	$	359,937


(1)	We recorded a non-recurring credit to operating costs during the second quarter of 2014 and a non-recurring debit to operating costs during the third quarter of 2014 as a result of the cancellation and reissuance of unvested restricted stock awards.


(2)	Our operating costs include $3.6 million and $6.0 million of rig rent expense associated with our lease of drilling rigs for the Current Quarter and Previous Quarter, respectively. As of October 1, 2014, we had repurchased all but one of the leased drilling rigs.


(3)	As part of the spin-off, SSE distributed its compression unit manufacturing and its geosteering businesses to Chesapeake and sold its crude hauling assets to a third party.

Drilling



	Three Months Ended September 30,			Three Months Ended June 30,
	2014
	(in thousands, except average rigs, utilization, revenue day and per revenue day amounts)
Revenues	$	200,394		$	189,177
Operating costs⁽¹⁾	133,042			118,354
Gross margin	$	67,352		$	70,823
Adjusted EBITDA	$	82,362		$	68,881
Revenue days⁽²⁾	7,772			7,396
Average revenue per revenue day⁽²⁾	$	23,776		$	23,219
Average operating costs per revenue day^{(1) (2)}	$	15,216		$	14,031
Average margin per revenue day⁽²⁾	$	8,560		$	9,188
Average rigs operating	85			81
Utilization	100		%	99		%

Adjusted operating costs⁽³⁾:
Operating costs	$	133,042		$	118,354
Add:
Non-recurring credit to stock compensation expense⁽⁴⁾	—			4,318
Less:
Operating costs for drilling-related services	14,787			14,578
Rig rent expense⁽¹⁾	3,608			6,016
Non-recurring debit to stock compensation expense⁽⁴⁾	3,726			—
Adjusted operating costs^{(2), (3)}	$	110,921		$	102,078
Adjusted average operating costs per day⁽²⁾	$	14,272		$	13,802


(1)	Our operating costs and average operating costs per revenue day include $3.6 million and $6.0 million of rig rent expense associated with our lease of drilling rigs for the Current Quarter and Previous Quarter, respectively. As of October 1, 2014, we had repurchased all but one of the leased drilling rigs.


(2)	These metrics exclude results from our drilling-related services, including directional drilling, mudlogging and geosteering. Our management excludes drilling-related services from these metrics because as part of the spin-off we distributed our geosteering business to Chesapeake and we do not provide our other drilling-related services on each job.

(3)

“Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake and crude hauling assets sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled in the Previous Quarter and reissued in the Current Quarter as part of the spin-off. For a description of our calculation of adjusted operation 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.”


(4)	We recorded a non-recurring credit to operating costs during the second quarter of 2014 and a non-recurring debit to operating costs during the third quarter of 2014 as a result of the cancellation and reissuance of unvested restricted stock awards.

Drilling revenues for the Current Quarter increased $11.2 million, or 6%, from the Previous Quarter. This increase was primarily due to a 5% increase in revenue days partially aided by two new PeakeRigs delivered in the Current Quarter. In addition, average revenue per revenue day for the Current Quarter was up 2% from the Previous Quarter primarily due to an increase in dayrates. Revenues from non-Chesapeake customers increased $11.2 million to 35% of total segment revenues in the Current Quarter compared to 31% for the Previous Quarter.

Drilling operating costs for the Current Quarter increased $14.7 million or 12%, from the Previous Quarter due primarily to labor-related costs which were partially offset by a reduction in rig rent expense. The increase in labor-related costs was primarily attributable to an $8.0 million increase in non-recurring stock compensation expense in the Current Quarter. We experienced a 3% increase in adjusted average operating costs per revenue day from the Previous Quarter to the Current Quarter primarily due to an increase in rig mobilization costs due to the delivery of two new PeakeRigs^TM during the Current Quarter.

As part of the spin-off, we distributed our geosteering business to Chesapeake. The geosteering business and its operating results were historically included in our drilling segment. The geosteering revenues and operating costs are detailed below:



	Three Months Ended June 30,
	2014
	(in thousands)
Revenues	$	2,014
Operating costs	1,208
Gross margin	$	806

Hydraulic Fracturing



	Three Months Ended September 30,		Three Months Ended June 30,
	2014
	(in thousands, except stages, average fleets and per stage amounts)
Revenues	$	245,128	$	226,112
Operating costs	190,730		179,283
Gross margin	$	54,398	$	46,829
Adjusted EBITDA	$	56,504	$	41,669
Stages completed	2,270		2,054
Average revenue per stage	$	107,986	$	110,084
Average operating costs per stage	$	84,022	$	87,285
Average margin per stage	$	23,964	$	22,799
Average fleets operating	9		9

Hydraulic fracturing revenues for the Current Quarter increased $19.0 million, or 8%, from the Previous Quarter. This increase was due to an 11% increase in completed stages from the Previous Quarter to the Current Quarter, partially offset by a 2% decrease in revenue per stage from the Previous Quarter to the Current Quarter. The decrease in revenue per stage was primarily due to the geographic relocation of our equipment. Revenues from non-Chesapeake customers increased $8.1 million to 5% of total segment revenues in the Current Quarter compared to 2% for the Previous Quarter.

Hydraulic fracturing operating costs for the Current Quarter increased $11.4 million, or 6% from the Previous Quarter, primarily due to an 11% increase in the number of completed stages and secondarily due to a $1.1 million increase in non-recurring stock compensation expense in the Current Quarter. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs decreased from 79% in the Previous Quarter to 78% in the Current Quarter due to lower product costs, partially offset by non-recurring stock compensation expense. As a percentage of hydraulic fracturing revenues, product costs were 45% in the Current Quarter and 46% in the Previous Quarter.

Oilfield Rental



	Three Months Ended September 30,		Three Months Ended June 30,
	2014
	(in thousands)
Revenues	$	38,918	$	38,977
Operating costs	26,963		24,534
Gross margin	$	11,955	$	14,443
Adjusted EBITDA	$	13,691	$	13,844

Oilfield rental revenues for the Current Quarter decreased $0.1 million from the Previous Quarter. Revenues from non-Chesapeake customers increased $1.5 million to 20% of total segment revenues in the Current Quarter compared to 16% for the Previous Quarter.

Oilfield rental operating costs for the Current Quarter increased $2.4 million, or 10%, from the Previous Quarter. The increase was primarily due to higher labor-related costs attributable to a $1.3 million increase in non-recurring stock compensation expense in the Current Quarter. As a percentage of oilfield rental revenues, oilfield rental operating costs were 69% and 63% for the Current Quarter and Previous Quarter, respectively. As a percentage of oilfield rental revenues, labor-related costs were 35% and 28% in the Current Quarter and Previous Quarter, respectively.

Oilfield Trucking



	Three Months Ended September 30,		Three Months Ended June 30,
	2014
	(in thousands)
Revenues	$	41,201	$	55,451
Operating costs	40,264		51,451
Gross margin	$	937	$	4,000
Adjusted EBITDA	$	3,760	$	5,954

Oilfield trucking revenues for the Current Quarter decreased $14.2 million, or 26%, from the Previous Quarter. The decrease was primarily due to the sale of our crude hauling assets to a third party during the Previous Quarter. Revenues from non-Chesapeake customers increased $1.1 million to 40% of total segment revenues in the Current Quarter compared to 28% for the Previous Quarter.

Oilfield trucking operating costs for the Current Quarter decreased $11.2 million from the Previous Quarter due primarily to the sale of our crude hauling assets to a third party during the Previous Quarter. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 98% and 93% for the Current Quarter and Previous Quarter, respectively. An increase in non-recurring stock compensation expense related to the spin-off resulted in higher oilfield trucking operating costs of approximately $2.9 million in the Current Quarter compared to the Previous Quarter.

During the Previous Quarter we sold our crude hauling assets to a third party. The operating results related to the crude hauling assets were historically included in our oilfield trucking segment and the associated revenues and operating costs are detailed below:



	Three Months Ended June 30,
	2014
	(in thousands)
Revenues	$	10,530
Operating costs	14,495
Gross margin	$	(3,965	)

Other Operations



	Three Months Ended September 30,			Three Months Ended June 30,
	2014
	(in thousands)
Revenues	$	1,132		$	39,749
Operating costs	1,139			32,964
Gross margin	$	(7	)	$	6,785

Our other operations currently consist of corporate functions. As part of the spin-off, we distributed our compression manufacturing business, which historically had been included in our other operations results. For the Current Quarter, revenues from our other operations decreased $38.6 million from the Previous Quarter due to the distribution of our compression manufacturing business to Chesapeake.

For the Current Quarter, operating costs for our other operations decreased $31.8 million from the Previous Quarter, which was primarily attributable to the distribution of our compression manufacturing business to Chesapeake. This business was historically included in our other operations results and the associated revenues and operating costs are detailed below:



	Three Months Ended June 30,
	2014
	(in thousands)
Revenues	$	39,230
Operating costs	32,244
Gross margin	$	6,986

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Previous Quarter was $73.9 million and $71.8 million, respectively. As a percentage of revenues, depreciation and amortization expense was 14% and 13% for the Current Quarter and Previous Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Previous Quarter were $32.7 million and $19.4 million, respectively. The increase was primarily due to an increase in labor-related costs and secondarily, costs of being a stand alone public entity and the implementation of an enterprise resource planning system. Labor-related costs increased approximately $16.3 million from the Prior Quarter to the Previous Quarter, which was primarily attributable to additional stock compensation expense related to unvested restricted stock cancelled as part of the spin-off and reissued during the Current Quarter. Prior to the spin-off, we were allocated corporate overhead from Chesapeake 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 Chesapeake provides or makes available to us various administrative services and assets for specified periods beginning on the distribution date. These charges from Chesapeake were $9.3 million and $14.0 million for the Current Quarter and Previous Quarter, respectively. Charges from Chesapeake prior to the spin-off were allocated to each operating entity and subsequent to the spin-off are recorded at the corporate level. As a percentage of revenues, general and administrative expenses were 6% and 4% for the Current Quarter and Previous Quarter, respectively.

Net Losses (Gains) on Sales of Property and Equipment. During the Current Quarter, we sold ancillary equipment not utilized in our business. During the Previous Quarter, we sold 14 drilling rigs and ancillary equipment not utilized in our business as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers. We recorded losses (gains) on sales of property and equipment of approximately $0.5 million and ($9.0) million related to these asset sales during the Current Quarter and Previous Quarter, respectively.

Impairments and Other. During the Current Quarter we recorded $5.5 million of impairment charges for certain drilling rigs and spare equipment we identified to sell as part of our broader strategy to divest of non-essential drilling rigs. We also identified certain drilling rigs during the Previous Quarter 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. We recorded impairment charges of $2.9 million during the Previous Quarter related to these drilling rigs. During the Current Quarter, we purchased two of our leased drilling rigs for approximately $3.0 million and paid lease termination costs of approximately $1.3 million. During the Previous Quarter, we purchased 11 of our leased drilling rigs for approximately $54.1 million and paid lease termination costs of approximately $0.1 million.

We identified certain other property and equipment during the Current Quarter and Previous 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 $1.0 million and $0.2 million during the Current Quarter and Previous Quarter, respectively, related to these assets.

Interest Expense. Interest expense for the Current Quarter and Previous Quarter was $23.6 million and $17.6 million respectively, related to borrowings under our Old Credit Facility, 2019 Notes, 2022 Notes, Term Loan and New Credit Facility. The increase in interest expense from the Previous Quarter to the Current Quarter was due to the additional debt issued in conjunction with the spin-off.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $0.3 million and $4.5 million for the Current Quarter and Previous Quarter, respectively, which was a result of our investment in Maalt Specialized Bulk, L.L.C. ("Maalt"). We own 49% of the membership interest in Maalt. Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers.

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

Income Tax (Benefit) Expense. We recorded income tax (benefit) expense of ($2.5) million and $14.0 million for the Current Quarter and Previous Quarter, respectively. The $16.5 million decrease in income tax expense recorded for the Current Quarter was primarily the result of a decrease in net income before taxes of $40.0 million from the Previous Quarter to the Current Quarter. Our effective income tax rate for the Current Quarter and Previous Quarter was 58% and 39%, respectively. The increase in our effective tax rate from the Previous Quarter to the Current Quarter was primarily the result of permanent differences, including meals and entertainment, having a greater impact on our effective income tax rate due to lower pre-tax income for the Current Quarter compared to the Previous Quarter.

Results of Operations—Three Months Ended September 30, 2014 vs. September 30, 2013

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



	Three Months Ended September 30,
	2014			2013
	(in thousands)
Revenues:
Revenues	$	526,773		$	550,403
Operating Expenses:
Operating costs	392,138			451,532
Depreciation and amortization	73,855			72,983
General and administrative	32,723			18,863
Net losses (gains) on sales of property and equipment	454			(265		)
Impairments and other	7,751			23,626
Total Operating Expenses	506,921			566,739
Operating Income (Loss)	19,852			(16,336		)
Other Income (Expense):
Interest expense	(23,606		)	(14,028		)
Loss (income) and impairment from equity investees	(347		)	262
Other (expense) income	(134		)	123
Total Other Expense	(24,087		)	(13,643		)
Loss Before Income Taxes	(4,235		)	(29,979		)
Income Tax Benefit	(2,465		)	(11,295		)
Net Loss	$	(1,770	)	$	(18,684	)

Revenues. For the Current Quarter and Prior Quarter, revenues were $526.8 million and $550.4 million, respectively. Our revenues decreased by approximately $23.6 million primarily due to the distribution to Chesapeake of our compression unit manufacturing business and geosteering business and the sale of our crude hauling assets to a third party. Adjusted revenues were $496.7 million for the Prior Quarter, which excludes the impact of the compression unit manufacturing, geosteering and crude hauling assets. The increase in revenues for the Current Quarter compared to adjusted revenues for the Prior Quarter was due to an increase in demand for both our hydraulic fracturing and drilling segments which resulted in a higher number of completed stages and revenue days in the Current Quarter compared to the Prior Quarter. The majority of our revenues historically have been derived from Chesapeake and its working interest partners. See “—Agreements Between Chesapeake and Us” for further discussion of agreements entered into as part of the spin-off, including a new services agreement and rig-specific daywork drilling contracts. Our revenues and adjusted revenues for the Current Quarter and Prior Quarter are detailed below:



	Three Months Ended September 30,
	2014		2013
	(in thousands)
Drilling	$	200,394	$	188,040
Hydraulic fracturing	245,128		226,922
Oilfield rentals	38,918		35,821
Oilfield trucking	41,201		63,252
Other operations	1,132		36,368
Total	$	526,773	$	550,403

Adjusted Revenue⁽¹⁾:
Revenue	$	526,773	$	550,403
Less:
Compression unit manufacturing revenues	—		36,209
Geosteering revenues	—		2,122
Crude hauling revenues	—		15,364
Adjusted Revenue	$	526,773	$	496,708

(1)

“Adjusted revenue” is a non-GAAP financial measure that we define as revenues before revenues associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake 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 why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Operating Costs. Operating costs for the Current Quarter and Prior Quarter were $392.1 million and $451.5 million, respectively. Our costs decreased by approximately $59.4 million from the Prior Quarter to the Current Quarter due to the distribution to Chesapeake of our compression unit manufacturing business and geosteering business and the sale of our crude hauling assets to a third party. Adjusted operating costs were $382.4 million and $385.9 million for the Current Quarter and Prior Quarter, respectively, which excludes operating costs associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake and crude hauling assets sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled in the Previous Quarter and reissued in the Current Quarter as part of the spin-off. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.” As a percentage of adjusted revenues, adjusted operating costs were 73% and 78% for the Current Quarter and Prior Quarter, respectively. The decrease in adjusted operating costs as a percentage of adjusted revenue was primarily attributable to higher utilization rates and lower product costs for our hydraulic fracturing segment. Our operating costs and adjusted operating costs for the Current Quarter and Prior Quarter are detailed below:



	Three Months Ended September 30,
	2014		2013
	(in thousands)
Drilling	$	133,042	$	141,043
Hydraulic fracturing	190,730		201,202
Oilfield rentals	26,963		24,092
Oilfield trucking	40,264		53,730
Other operations	1,139		31,465
Total	$	392,138	$	451,532

Adjusted Operating Costs:
Operating Costs	$	392,138	$	451,532
Less:
Non-recurring debit to stock compensation expense⁽¹⁾	6,178		—
Rig rent expense⁽²⁾	3,608		22,454
Compression unit manufacturing operating costs⁽³⁾	—		30,641
Geosteering operating costs⁽³⁾	—		1,398
Crude hauling operating costs⁽³⁾	—		11,180
Adjusted Operating Costs	$	382,352	$	385,859


(1)	We recorded non-recurring debit to operating costs during the third quarter of 2014 as a result of the cancellation and reissuance of unvested restricted stock awards.


(2)	Our operating costs include $3.6 million and $22.5 million of rig rent expense associated with our lease of drilling rigs for the Current Quarter and Prior Quarter, respectively. As of October 1, 2014, we had repurchased all but one of the leased drilling rigs.


(3)	As part of the spin-off, SSE distributed its compression unit manufacturing and geosteering businesses to Chesapeake and sold its crude hauling assets to a third party.

Drilling



	Three Months Ended September 30,
	2014			2013
	(in thousands, except average rigs, utilization, revenue day and per revenue day amounts)
Revenues	$	200,394		$	188,040
Operating costs⁽¹⁾	133,042			141,043
Gross margin	$	67,352		$	46,997
Adjusted EBITDA	$	82,362		$	65,155
Revenue days⁽²⁾	7,772			7,095
Average revenue per revenue day⁽²⁾	$	23,776		$	23,632
Average operating costs per revenue day^{(1) (2)}	$	15,216		$	17,549
Average margin per revenue day⁽²⁾	$	8,560		$	6,083
Average rigs operating	85			81
Utilization	100		%	93		%

Adjusted operating costs⁽³⁾:
Operating costs	$	133,042		$	141,043
Less:
Operating costs for drilling-related services	14,787			16,533
Rig rent expense⁽¹⁾	3,608			22,454
Non-recurring debit to stock compensation expense⁽⁴⁾	3,726			—
Adjusted operating costs^{(2), (3)}	$	110,921		$	102,056
Adjusted average operating costs per day⁽²⁾	$	14,272		$	14,384


(1)	Our operating costs and average operating costs per revenue day include $3.6 million and $22.5 million of rig rent expense associated with our lease of drilling rigs for the Current Quarter and Prior Quarter, respectively. As of October 1, 2014, we had repurchased all but one of the leased drilling rigs.


(2)	These metrics exclude results from our drilling-related services, including directional drilling, mudlogging and geosteering. Our management excludes drilling-related services from these metrics because as part of the spin-off we distributed our geosteering business to Chesapeake and we do not provide our other drilling-related services on each job.

(3)

“Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake and crude hauling assets sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled in the Previous Quarter and reissued in the Current Quarter as part of the spin-off. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”


(4)	We recorded a non-recurring debit to operating costs during the third quarter of 2014 as a result of the cancellation and reissuance of unvested restricted stock awards.

Drilling revenues for the Current Quarter increased $12.4 million from the Prior Quarter. This increase was primarily due to a 10% increase in revenue days. In addition, average revenue per day for the Current Quarter was up 1% from the Prior Quarter, primarily due to an increase in dayrates. Revenues from non-Chesapeake customers increased $26.9 million to 35% of total segment revenues in the Current Quarter compared to 23% for the Prior Quarter.

Drilling operating costs for the Current Quarter decreased $8.0 million, or 6%, from the Prior Quarter, due primarily to a reduction in rig rent expense. As a percentage of drilling revenues, drilling operating costs were 66% and 75% for the Current Quarter and the Prior Quarter, respectively. As a percentage of drilling revenues, rig rent expense was 2% and 12% for the Current Quarter and Prior Quarter, respectively. Adjusted average operating costs per revenue day were flat from the Prior Quarter to the Current Quarter.



	Three Months Ended September 30,
	2013
	(in thousands)
Revenues	$	2,122
Operating costs	1,398
Gross margin	$	724

Hydraulic Fracturing



	Three Months Ended September 30,
	2014		2013
	(in thousands, except stages, average fleets and per stage amounts)
Revenues	$	245,128	$	226,922
Operating costs	190,730		201,202
Gross margin	$	54,398	$	25,720
Adjusted EBITDA	$	56,504	$	20,689
Stages completed	2,270		1,959
Average revenue per stage	$	107,986	$	115,836
Average operating costs per stage	$	84,022	$	102,706
Average margin per stage	$	23,964	$	13,130
Average fleets operating	9		9

Hydraulic fracturing revenues for the Current Quarter increased $18.2 million, or 8%, from the Prior Quarter. This increase was due to a 16% increase in completed stages, partially offset by a 7% decrease in revenue per stage from the Prior Quarter to the Current Quarter. The decrease in revenue per stage was primarily due to industry-wide pricing pressure. Revenues from non-Chesapeake customers increased $12.7 million to 5% of total segment revenues in the Current Quarter compared to 0% for the Prior Quarter.

Hydraulic fracturing operating costs for the Current Quarter decreased $10.5 million, or 5% from the Prior Quarter, primarily due to an 8% decrease in product costs and an 11% decrease in maintenance and supplies expense, partially offset by a 16% increase in completed stages. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs were 78% and 89% for Current Quarter and Prior Quarter, respectively. As a percentage of hydraulic fracturing revenues, product costs were 45% and 52% for the Current Quarter and Prior Quarter, respectively.

Oilfield Rental



	Three Months Ended September 30,
	2014		2013
	(in thousands)
Revenues	$	38,918	$	35,821
Operating costs	26,963		24,092
Gross margin	$	11,955	$	11,729
Adjusted EBITDA	$	13,691	$	11,774

Oilfield rental revenues for the Current Quarter increased $3.1 million, or 9%, from the Prior Quarter. The increase was primarily due to higher utilization as a result of an increase in drilling and completion activity by our customers. Revenues from non-Chesapeake customers increased $5.5 million to 20% of total segment revenues in the Current Quarter compared to 6% for the Prior Quarter.

Oilfield rental operating costs for the Current Quarter increased $2.9 million, or 12%, from the Prior Quarter. The increase was primarily due to an overall increase in drilling and completion activity by our customers, which resulted in higher labor-related costs. As a percentage of oilfield rental revenues, oilfield rental operating costs were 69% and 67% for the Current Quarter and Prior Quarter, respectively.

Oilfield Trucking



	Three Months Ended September 30,
	2014		2013
	(in thousands)
Revenues	$	41,201	$	63,252
Operating costs	40,264		53,730
Gross margin	$	937	$	9,522
Adjusted EBITDA	$	3,760	$	5,437

Oilfield trucking revenues for the Current Quarter decreased $22.1 million, or 35%, from the Prior Quarter. The decrease was primarily due to the sale of our crude hauling assets to a third party during the Previous Quarter. Revenues from non-Chesapeake customers increased $6.5 million to 40% of total segment revenues in the Current Quarter compared to 16% for the Prior Quarter.

Oilfield trucking operating costs for the Current Quarter decreased $13.5 million or 25%, from the Prior Quarter due primarily to the sale of our crude hauling assets to a third party during the Previous Quarter. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 98% and 85% for the Current Quarter and Prior Quarter, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to an increase in labor-related costs due to higher wages in the competitive market for trucking labor and non-recurring stock compensation expense of $1.1 million during the Current Quarter related to unvested restricted stock cancelled and reissued as part of the spin-off. As a percentage of oilfield trucking revenues, labor-related costs were 50% and 42% for the Current Quarter and Prior Quarter, respectively.



	Three Months Ended September 30,
	2013
	(in thousands)
Revenues	$	15,364
Operating costs	11,180
Gross margin	$	4,184

Other Operations



	Three Months Ended September 30,
	2014			2013
	(in thousands)
Revenues	$	1,132		$	36,368
Operating costs	1,139			31,465
Gross margin	$	(7	)	$	4,903

Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression manufacturing business to Chesapeake. This business historically had been included in our other operations results. For the Current Quarter, revenues from our other operations decreased $35.2 million from the Prior Quarter. The decrease in revenue was primarily attributable to the distribution of our compression manufacturing business to Chesapeake.

For the Current Quarter, operating costs for our other operations decreased $30.3 million from the Prior Quarter. The decrease in operating costs from the Prior Quarter to the Current Quarter was primarily attributable to the distribution of our compression manufacturing business to Chesapeake. This business was historically included in our other operations results and the associated revenues and operating costs are detailed below:



	Three Months Ended September 30,
	2013
	(in thousands)
Revenues	$	36,209
Operating costs	30,641
Gross margin	$	5,568

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Prior Quarter was $73.9 million and $73.0 million, respectively. As a percentage of revenues, depreciation and amortization expense was 14% and 13% for the Current Quarter and Prior Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Prior Quarter were $32.7 million and $18.9 million, respectively. The increase was primarily due to an increase in labor-related costs and secondarily, costs of being a stand alone public entity and the implementation of an enterprise resource planning system. Labor-related costs increased approximately $14.2 million from the Prior Quarter to the Current Quarter, which was primarily attributable to additional stock compensation expense related to unvested restricted stock cancelled as part of the spin-off and reissued during the Current Quarter. Prior to the spin-off, we were allocated corporate overhead from Chesapeake 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 Chesapeake provides or makes available to us various administrative services and assets for specified periods beginning on the distribution date. These charges from Chesapeake were $9.3 million and $13.8 million for the Current Quarter and Prior Quarter, respectively. Charges from Chesapeake prior to the spin-off were allocated to each operating entity and subsequent to the spin-off are recorded at the corporate level. As a percentage of revenues, general and administrative expenses were 6% and 3% for the Current Quarter and Prior Quarter, respectively.

Net Losses (Gains) on Sales of Property and Equipment. During the Current Quarter, we sold ancillary equipment not utilized in our business. During the Prior Quarter, we sold five drilling rigs and ancillary equipment not utilized in our business. We recorded losses (gains) on sales of property and equipment of approximately $0.5 million and ($0.3) million related to these asset sales during the Current Quarter and Prior Quarter, respectively.

Impairments and Other. During the Current Quarter and Prior Quarter, we recognized $5.5 million and $19.3 million of impairment charges 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 also identified certain drilling rigs during the Prior Quarter 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. We recorded impairment charges of $4.3 million during the Prior Quarter related to these drilling rigs. During the Current Quarter, we purchased two of our leased drilling rigs for approximately $3.0 million and paid lease termination costs of approximately $1.3 million.

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 $1.0 million and $0.1 million during the Current Quarter and Prior Quarter, respectively, related to these assets.

Interest Expense. Interest expense for the Current Quarter and Prior Quarter was $23.6 million and $14.0 million, respectively, related to borrowings under our Old Credit Facility, 2019 Notes, 2022 Notes, Term Loan and New Credit Facility. The increase in interest expense from the Previous Quarter to the Current Quarter was due to the additional debt issued in conjunction with the spin-off.

(Loss) Income and Impairment from Equity Investees. Loss and impairment from equity investees was ($0.3) million and $0.3 million for the Current Quarter and Prior Quarter, respectively, which was a result of our investments in Maalt and Big Star Crude Co., L.L.C. (“Big Star”). We own 49% of the membership interest in Maalt. Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers. In August 2011, we entered into an agreement with Big Star Field Services, L.L.C. to form Big Star, a jointly controlled entity that engages in the commercial trucking business.

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

Income Tax Benefit. We recorded income tax benefit of $2.5 million and $11.3 million for the Current Quarter and Prior Quarter, respectively. The $8.8 million increase in income tax expense recorded for the Current Quarter was primarily the result of an increase in net income before taxes of $25.7 million from the Prior Quarter to the Current Quarter. Our effective income tax rate for the Current Quarter and Prior Quarter was 58% and 38%, respectively. The increase in our effective tax rate from the Prior Quarter to the Current Quarter was primarily the result of permanent differences, including meals and entertainment, having a greater impact on our effective income tax rate due to lower pre-tax income for the Current Quarter compared to the Prior Quarter.

Results of Operations—Nine Months Ended September 30, 2014 vs. September 30, 2013

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



	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Revenues:
Revenues	1,585,948			1,677,354
Operating Expenses:
Operating costs	1,208,312			1,323,964
Depreciation and amortization	218,149			215,584
General and administrative	72,977			60,276
Net gains on sales of property and equipment	(7,532		)	(1,636		)
Impairments and other	30,731			30,367
Total Operating Expenses	1,522,637			1,628,555
Operating Income	63,311			48,799
Other Income (Expense):
Interest expense	(55,913		)	(42,177		)
Loss and impairment from equity investees	(5,764		)	(910		)
Other income	623			584
Total Other Expense	(61,054		)	(42,503		)
Income Before Income Taxes	2,257			6,296
Income Tax Expense	873			3,571
Net Income	$	1,384		$	2,725

Revenues. For the Current Period and Prior Period, revenues were $1.586 billion and $1.677 billion, respectively. The $91.4 million decrease was primarily due to the distribution to Chesapeake of our compression unit manufacturing business and geosteering business and the sale of our crude hauling assets to a third party. Adjusted revenues were $1.484 billion and $1.514 billion for the Current Period and Prior Period, respectively, which excludes the impact of the compression unit manufacturing, geosteering and crude hauling assets. The decrease in adjusted revenues was due primarily to a decrease in revenue per stage for our hydraulic fracturing segment. The majority of our revenues historically have been derived from Chesapeake and its working interest partners. See “—Agreements Between Chesapeake and Us” for further discussion of agreements entered into as part of the spin-off, including a new services agreement and rig-specific daywork drilling contracts. Our revenues and adjusted revenues for the Current Period and Prior Period are detailed below:



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Drilling	$	570,004	$	562,275
Hydraulic fracturing	672,860		692,213
Oilfield rentals	113,837		125,111
Oilfield trucking	152,847		187,372
Other operations	76,400		110,383
Total	$	1,585,948	$	1,677,354

Adjusted Revenue⁽¹⁾:
Revenue	$	1,585,948	$	1,677,354
Less:
Compression unit manufacturing revenues	74,650		109,703
Geosteering revenues	3,940		6,590
Crude hauling revenues	23,829		46,765
Adjusted Revenue	$	1,483,529	$	1,514,296

(1)

“Adjusted revenue” is a non-GAAP financial measure that we define as revenues before revenues associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake 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 why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”

Operating Costs. Operating costs for the Current Period and Prior Period were $1.208 billion and $1.324 billion, respectively. The decrease in operating costs was due primarily due to the distribution to Chesapeake of our compression unit manufacturing business and geosteering business and the sale of our crude hauling assets to a third party. Adjusted operating costs for the Current Period and the Prior Period were $1.100 billion and $1.128 billion, respectively, which excludes operating costs associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake and crude hauling assets sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled in the Previous Quarter and reissued in the Current Quarter as part of the spin-off. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.” As a percentage of adjusted revenues, adjusted costs were 74% and 75% for the Current Period and Prior Period, respectively. The decrease in adjusted operating costs as a percentage of adjusted revenue was primarily attributable to higher utilization rates and lower product costs for our hydraulic fracturing segment. Our operating costs and adjusted operating costs for the Current Period and Prior Period are detailed below:



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Drilling	$	375,855	$	426,413
Hydraulic fracturing	547,025		568,788
Oilfield rentals	77,446		78,552
Oilfield trucking	145,328		155,877
Other operations	62,658		94,334
Total	$	1,208,312	$	1,323,964

Adjusted Operating Costs:
Operating Costs	$	1,208,312	$	1,323,964
Add:
Non-recurring credit to stock compensation expense⁽¹⁾	7,314		—
Less:
Non-recurring debit to stock compensation expense⁽¹⁾	6,178		—
Rig rent expense⁽²⁾	18,683		68,006
Compression unit manufacturing operating costs⁽³⁾	60,616		92,058
Geosteering operating costs⁽³⁾	2,895		3,906
Crude hauling operating costs⁽³⁾	27,254		31,785
Adjusted Operating Costs	$	1,100,000	$	1,128,209


(1)	We recorded a non-recurring credit to operating costs during the second quarter of 2014 and a non-recurring debit to operating costs during the third quarter of 2014 as a result of the cancellation and reissuance of unvested restricted stock awards.


(2)	Our operating costs include $18.7 million and $68.0 million of rig rent expense associated with our lease of drilling rigs for the Current Period and Prior Period, respectively. As of October 1, 2014, we had repurchased all but one of the leased drilling rigs.


(3)	As part of the spin-off, SSE distributed its compression unit manufacturing and geosteering businesses to Chesapeake and sold its crude hauling assets to a third party.

Drilling



	Nine Months Ended September 30,
	2014			2013
	(in thousands, except average rigs, utilization, revenue day and per revenue day amounts)
Revenues	$	570,004		$	562,275
Operating costs⁽¹⁾	375,855			426,413
Gross margin	$	194,149		$	135,862
Adjusted EBITDA	$	213,512		$	190,277
Revenue days⁽²⁾	22,204			21,056
Average revenue per revenue day⁽²⁾	$	23,478		$	23,709
Average operating costs per revenue day^{(1) (2)}	$	14,940		$	17,688
Average margin per revenue day⁽²⁾	$	8,538		$	6,021
Average rigs operating	82			80
Utilization	99		%	95		%

Adjusted operating costs⁽³⁾:
Operating costs	$	375,855		$	426,413
Add:
Non-recurring credit to stock compensation expense⁽⁴⁾	4,318			—
Less:
Operating costs for drilling-related services	44,135			53,985
Rig rent expense⁽¹⁾	18,683			68,006
Non-recurring debit to stock compensation expense⁽⁴⁾	3,726			—
Adjusted operating costs^{(2), (3)}	$	313,629		$	304,422
Adjusted average operating costs per day⁽²⁾	$	14,125		$	14,458


(1)	Our operating costs and average operating costs per revenue day include $18.7 million and $68.0 million of rig rent expense associated with our lease of drilling rigs for the Current Period and Previous Period, respectively. As of October 1, 2014, we had repurchased all but one of the leased drilling rigs.


(2)	These metrics exclude results from our drilling-related services, including directional drilling, mudlogging and geosteering. Our management excludes drilling-related services from these metrics because as part of the spin-off we distributed our geosteering business to Chesapeake and we do not provide our other drilling-related services on each job.

(3)

“Adjusted operating costs” is a non-GAAP financial measure that we define as operating costs before operating costs associated with the compression unit manufacturing business and geosteering business distributed to Chesapeake and crude hauling assets sold to a third party as part of the spin-off, further adjusted to subtract rig rent expense and and remove the non-recurring portion of expense related to unvested restricted stock that was cancelled in the Previous Quarter and reissued in the Current Quarter as part of the spin-off. For a description of our calculation of adjusted operating costs and the reasons why our management uses this measure to evaluate our business, see “—How We Evaluate Our Operations” and “—Non-GAAP Financial Measures.”


(4)	We recorded a non-recurring credit to operating costs during the second quarter of 2014 and a non-recurring debit to operating costs during the third quarter of 2014 as a result of the cancellation and reissuance of unvested restricted stock awards.

Drilling revenues for the Current Period increased $7.7 million from the Prior Period. This increase was primarily due to a 5% increase in revenue days, partially offset by a 1% decrease in average revenue per revenue day. Revenues from non-Chesapeake customers increased $86.1 million to 32% of total segment revenues in the Current Period compared to 17% for the Prior Period.

Drilling operating costs for the Current Period decreased $50.6 million, or 12%, from the Prior Period primarily as a result of a reduction in rig rent expense. As a percentage of drilling revenues, drilling operating costs were 66% and 76% for the

Current Period and the Prior Period, respectively. As a percentage of drilling revenues, rig rent expense was 3% and 12% for the Current Period and Prior Period, respectively.

As part of the spin-off, we distributed our geosteering business to Chesapeake. This business and its operating results were historically included in our drilling segment. The geosteering revenues and operating costs are detailed below:



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Revenues	$	3,940	$	6,590
Operating costs	2,895		3,906
Gross margin	$	1,045	$	2,684

Hydraulic Fracturing



	Nine Months Ended September 30,
	2014		2013
	(in thousands, except stages, average fleets and per stage amounts)
Revenues	$	672,860	$	692,213
Operating costs	547,025		568,788
Gross margin	$	125,835	$	123,425
Adjusted EBITDA	$	118,322	$	109,043
Stages completed	6,046		5,331
Average revenue per stage	$	111,290	$	129,847
Average operating costs per stage	$	90,477	$	106,694
Average margin per stage	$	20,813	$	23,153
Average fleets operating	9		8

Hydraulic fracturing revenues for the Current Period decreased $19.4 million from the Prior Period. This decrease was due to a 14% decrease in revenue per stage from the Prior Period to the Current Period, partially offset by a 13% increase in completed stages from the Prior Period to the Current Period. The decrease in revenue per stage was primarily due to activity mix. Revenues from non-Chesapeake customers increased $17.2 million to 3% of total segment revenues in the Current Period compared to 0% for the Prior Period.

Hydraulic fracturing operating costs for the Current Period decreased $21.8 million or 4% from the Prior Period, primarily due to a 13% decrease in product costs, partially offset by a 13% increase in the number of completed stages. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs decreased from 82% in the Prior Period to 81% in the Current Period. This decrease was primarily attributable to the decrease in product costs.

Oilfield Rental



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Revenues	$	113,837	$	125,111
Operating costs	77,446		78,552
Gross margin	$	36,391	$	46,559
Adjusted EBITDA	$	37,487	$	45,900

Oilfield rental revenues for the Current Period decreased $11.3 million or 9%, from the Prior Period. The decrease was primarily due to lower utilization and market pricing pressure for certain of our equipment. Revenues from non-Chesapeake customers increased $13.0 million to 16% of total segment revenues in the Current Period compared to 4% for the Prior Period.

Oilfield rental operating costs for the Current Period decreased $1.1 million or 1%, from the Prior Period. The decrease was primarily due to lower utilization. As a percentage of oilfield rental revenues, oilfield rental operating costs were 68% and 63% for the Current Period and Prior Period, respectively. The increase in oilfield rental operating costs as a percentage of oilfield rental revenues was primarily attributable to pricing pressure for certain services, which compressed margins, and an increase in labor-related costs. As a percentage of oilfield rental revenues, labor-related costs were 32% and 28% in the Current Period and Prior Period, respectively.

Oilfield Trucking



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Revenues	$	152,847	$	187,372
Operating costs	145,328		155,877
Gross margin	$	7,519	$	31,495
Adjusted EBITDA	$	11,776	$	17,018

Oilfield trucking revenues for the Current Period decreased $34.5 million or 18%, from the Prior Period. The decrease was primarily due to the sale of our crude hauling assets to a third party during the Previous Quarter. Revenues from non-Chesapeake customers increased $21.0 million to 29% of total segment revenues in the Current Period compared to 12% for the Prior Period.

Oilfield trucking operating costs for the Current Period decreased $10.5 million or 7%, from the Prior Period. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 95% and 83% for the Current Period and Prior Period, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to an increase in labor-related costs due to higher wages in the competitive market for trucking labor, and secondarily a decrease in utilization of our assets which resulted in fixed costs being spread over a smaller revenue base. As a percentage of oilfield trucking revenues, labor-related costs were 46% and 40% for the Current Period and Prior Period, respectively.

During the Current Period we sold our crude hauling assets to a third party. The operating results related to the crude hauling assets were historically included in our oilfield trucking segment and the associated revenues and operating costs are detailed below:



	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Revenues	$	23,829		$	46,765
Operating costs	27,254			31,785
Gross margin	$	(3,425	)	$	14,980

Other Operations



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Revenues	$	76,400	$	110,383
Operating costs	62,658		94,334
Gross margin	$	13,742	$	16,049

Our other operations currently consists of corporate functions. As part of the spin-off, we distributed our compression manufacturing business to Chesapeake, which was historically included in our other operations results. For the Current Period, revenues from our other operations decreased $34.0 million from the Prior Period, which was primarily attributable to the distribution of our compression manufacturing business to Chesapeake.

For the Current Period, operating costs for our other operations decreased $31.7 million from the Prior Period, which was primarily attributable to the distribution of our compression manufacturing business to Chesapeake. This business was historically included in our other operations results and the associated revenues and operating costs are detailed below:



	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Revenues	$	74,650	$	109,703
Operating costs	60,616		92,058
Gross margin	$	14,034	$	17,645

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Period and Prior Period was $218.1 million and $215.6 million, respectively. As a percentage of revenues, depreciation and amortization expense was 14% and 13% for the Current Period and Prior Period, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Period and Prior Period were $73.0 million and $60.3 million respectively. The increase was primarily due to an increase in labor-related costs and secondarily, costs of being a stand alone public entity and the implementation of an enterprise resource planning system. Labor-related costs increased approximately $15.4 million from the Prior Period to the Current Period. Prior to the spin-off, we were allocated corporate overhead from Chesapeake 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 Chesapeake provides or makes available to us various administrative services and assets for specified periods beginning on the distribution date. These charges from Chesapeake were $36.1 million and $42.5 million for the Current Period and Prior Period, respectively. Charges from Chesapeake prior to the spin-off were allocated to each operating entity and subsequent to the spin-off are recorded at the corporate level. As a percentage of revenues, general and administrative expenses were 5% and 4% for the Current Period and Prior Period, repsectively.

Net Gains on Sales of Property and Equipment. During the Current Period, we sold 15 drilling rigs and ancillary equipment not utilized in our business as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers. During the Prior Period, we sold 13 drilling rigs and ancillary equipment not utilized in our business. We recorded

gains on sales of property and equipment of approximately $7.5 million and $1.6 million related to these asset sales during the Current Period and Prior Period, respectively.

Impairments and Other. During the Current Period and Prior Period, we recognized $11.2 million and $22.7 million, respectively, of impairment charges for certain drilling rigs and spare equipment we identified to sell as part of our broader strategy to divest of non-essential drilling rigs. We also identified certain drilling rigs during the Current Period and Prior Period 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. We recorded impairment charges of $8.4 million and $4.3 million during the Current Period and Prior Period, respectively, related to these drilling rigs. During the Current Period, we purchased 33 of our leased drilling rigs for approximately $134.0 million and paid lease termination costs of approximately $9.7 million. During the Prior Period, we purchased two leased drilling rigs for approximately $0.4 million and paid lease termination costs of approximately $0.1 million.

We identified certain other property and equipment during the Current Period and Prior Period that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $1.4 million and $3.3 million during the Current Period and Prior Period, respectively, related to these assets.

Interest Expense. Interest expense for the Current Period and Prior Period was $55.9 million and $42.2 million respectively, related to borrowings under our Old Credit Facility, 2019 Notes, 2022 Notes, Term Loan and New Credit Facility. The increase in interest expense from the Previous Quarter to the Current Quarter was due to the additional debt issued in conjunction with the spin-off.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $5.8 million and $0.9 million for the Current Period and Prior Period, respectively, which was a result of our investments in Maalt and Big Star. We own 49% of the membership interest in Maalt. Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers. In August 2011, we entered into an agreement with Big Star Field Services, L.L.C. to form Big Star, a jointly controlled entity that engages in the commercial trucking business. During the Prior Period, we sold our membership interest in Big Star and recorded a loss on sale of $1.8 million.

Other Income. Other income was $0.6 million for both the Current Period and Prior Period, respectively.

Income Tax Expense. We recorded income tax expense of $0.9 million and $3.6 million for the Current Period and Prior Period, respectively. The $2.7 million decrease in income tax expense recorded for the Current Period was primarily the result of a decrease in net income before taxes of $4.0 million from the Prior Period to the Current Period. Our effective income tax rate for the Current Period and Prior Period was 39% and 57% respectively. The decrease in our effective tax rate from the Prior Period to the Current Period was primarily the result of permanent differences having a greater impact on our effective income tax rate in the Prior Period compared to the Current Period.

Agreements Between Chesapeake and Us

Master Separation Agreement

The master separation agreement entered into between Chesapeake and us governs the separation of our businesses from Chesapeake, the distribution of our shares to Chesapeake shareholders and other matters related to Chesapeake’s relationship with us, including cross-indemnities between us and Chesapeake. In general, Chesapeake agreed to indemnify us for any liabilities relating the Chesapeake’s business and we agreed to indemnify Chesapeake for any liabilities relating to our business.

Tax Sharing Agreement

In connection with the spin-off, we and Chesapeake entered into a tax sharing agreement that governs our respective rights, responsibilities, and obligations 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. References in this summary description of the tax sharing agreement to the terms “tax” or “taxes” mean taxes as well as any interest, penalties, additions to tax or additional amounts in respect of such taxes.

Under the tax sharing agreement, we generally will be liable for and indemnify Chesapeake against all taxes attributable to our business and will be allocated all tax benefits attributable to such business and Chesapeake generally will be liable for

and indemnify us against all taxes attributable to its other businesses and will be allocated all tax benefits attributable to such businesses.

Chesapeake generally will be responsible for preparing and filing all tax returns that include both taxes or tax benefits allocable to Chesapeake and taxes or tax benefits allocable to us. Chesapeake generally will be responsible for preparing and filing all tax returns that include only taxes or tax benefits allocable to Chesapeake, and we generally will be responsible for preparing and filing all tax returns that include only taxes or tax benefits allocable to us. However, we generally will not be permitted to take a position on any such tax return that is inconsistent with our or Chesapeake’s past practice.

The party responsible for preparing and filing a tax return generally will also have the authority to control all tax proceedings, including tax audits, involving any taxes or adjustment to taxes reported on such tax return, except that we may be entitled, in Chesapeake’s discretion, to control tax proceedings relating to tax returns prepared and filed by Chesapeake to the extent that such taxes or adjustments are allocable exclusively to us. The tax sharing agreement further provides for cooperation between us and Chesapeake with respect to tax matters, including the exchange of information and the retention of records that may affect our respective tax liabilities.

Finally, the tax sharing agreement will require that neither we nor any of our affiliates take or fail to take any action after the effective date of the tax sharing agreement that (i) would be reasonably likely to be inconsistent with or cause to be untrue any material statement, covenant or representation in any representation letters, tax opinions or IRS private letter ruling obtained by Chesapeake or (ii) would be inconsistent with the spin-off generally qualifying as a tax-free transaction described under Sections 355 and 368(a)(1)(D) of the Code.

Moreover, Chesapeake generally will be liable for and indemnify us for any taxes arising from the spin-off or certain related transactions that are imposed on us, Chesapeake or its other subsidiaries. However, we would be liable for and indemnify Chesapeake for any such taxes to the extent such taxes result from certain actions or failures to act by us that occur after the effective date of the tax sharing agreement.

Employee Matters Agreement

In connection with the spin-off, we and Chesapeake entered into an employee matters agreement, which provides that each of Chesapeake and SSE has responsibility for its own employees and compensation plans. The agreement also contains provisions concerning benefit protection for both SSE and Chesapeake employees, treatment of holders of Chesapeake stock options, restricted stock, restricted stock units and performance share units, and cooperation between us and Chesapeake in the sharing of employee information and maintenance of confidentiality.

Transition Services Agreements

We and Chesapeake entered into a Transition Services Agreement under which Chesapeake will provide and/or make available to us various administrative services and assets, for specified periods. The services that Chesapeake provides us include:

•marketing and corporate communication services;

•human resources services;

•information technology services;

•security services;

•risk management services;

•tax services;

•HSE services;

•maintenance services;

•internal audit services;

•accounting services;

•treasury services; and

•certain other services specified in the agreement.

In addition, Chesapeake will continue to allow us access to certain of its facilities and other property for a period of time. In consideration for such services, we pay Chesapeake fees, a portion of which are a flat fee, generally in amounts intended to allow Chesapeake to recover all of its direct and indirect costs incurred in providing those services. The personnel performing services for us under the Transition Services Agreement are employees and/or independent contractors of Chesapeake and are not under our direction or control. The Transition Services Agreement also contains customary indemnification provisions.

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.

Master Services Agreement

We are a party to the Master Services Agreement, pursuant to which we provide drilling and other services and supply materials and equipment to Chesapeake. Drilling services are typically provided pursuant to daywork drilling contracts. The specific terms of each request for other services are typically set forth in a field ticket or purchase 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 Chesapeake’s business, and allocates certain operational risks between Chesapeake and us through indemnity provisions. The agreement will remain in effect until we or Chesapeake provide 30 days written notice of termination. We believe that our drilling contracts, field tickets or purchase or work orders with Chesapeake are substantially similar to those in prevailing industry contracts, specifically as they relate to pricing, liabilities and payment terms.

In connection with the spin-off, we supplemented the Master Services Agreement with the New Services Agreements, described below.

New Services Agreements

In connection with the spin-off, we entered into several services agreements which supplement the Master Services Agreement. Under the New Services Agreement governing our provision of hydraulic fracturing services for Chesapeake, Chesapeake 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) fifty percent (50%) of the total number of all pressure pumping crews working for Chesapeake in all its operating regions during the respective year. Chesapeake is also required to utilize our pressure pumping services for a minimum number of stages as set forth in the agreement. Chesapeake 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, Chesapeake’s requirement to utilize our services may be suspended under certain circumstances, such as when we are unable to timely accept and supply services ordered by Chesapeake or as a result of a force majeure event.

In connection with the spin-off, we also entered into New Services Agreements with Chesapeake governing our provision of oilfield trucking, drilling rig relocation and logistics and oilfield rentals services having terms similar to those we currently use for non-Chesapeake customers, if Chesapeake elects to use such services. Chesapeake is under no obligation to use us to provide such services. Each Agreement is effective from July 1, 2014 through December 31, 2014, with an option to extend for an additional 90 days upon mutual agreement. Under each of such New Services Agreements, Chesapeake has the option to terminate the agreement at any time upon 90 days prior written notice. Our hydraulic fracturing backlog as of September 30, 2014 was approximately $1.4 billion related to the New Services Agreement.

Drilling Agreements

In connection with the spin-off, we entered into rig-specific daywork drilling contracts with Chesapeake for the provision of drilling services having terms similar to those we currently use for unaffiliated customers. The Drilling Agreements have a commencement date of July 1, 2014 and a term ranging from three months to three years. Chesapeake has the right to terminate a Drilling Agreement in certain circumstances. Our drilling backlog as of September 30, 2014 was approximately $925.6 million related to the rig-specific daywork drilling contracts.

Drilling Rig Lease Arrangement

In a series of transactions beginning in 2006, we sold 94 drilling rigs and related equipment to certain third parties, and Chesapeake, through one of its subsidiaries, entered into master lease agreements under which Chesapeake agreed to lease such rigs from the purchasers for initial terms ranging from 5 to 10 years pursuant to a drilling rig lease arrangement. We, in turn, leased such rigs from Chesapeake. In connection with the drilling rig lease arrangement, we obtained the right to repurchase the leased rigs by causing Chesapeake to purchase such rigs from the rig owners and then paying to Chesapeake the greater of the purchase price paid by Chesapeake and the current fair market value of the rig. As of October 30, 2014, we had purchased all of our material active rigs that were subject to these lease arrangements. The remaining drilling rig lease arrangement relates to one Tier 3 drilling rig that is not part of our long-term portfolio strategy.

Off-Balance Sheet Arrangements

As of September 30, 2014, we leased 12 rigs under master lease agreements. For more information regarding the terms of the rig leases, please see Note 6 “Commitments and Contingencies” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

Aggregate undiscounted minimum future lease payments as of September 30, 2014 under our operating leases are presented below:



	September 30, 2014
	Rigs		Rail Cars		Total
	(in thousands)
Remainder of 2014	$	3,395	$	1,528	$	4,923
2015	—		7,263		7,263
2016	—		7,263		7,263
2017	—		3,608		3,608
2018	—		2,885		2,885
After 2018	—		2,162		2,162
Total	$	3,395	$	24,709	$	28,104

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 September 30, 2014, we had $218.3 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2014 and 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. 333-187766) filed with the Securities and Exchange Commission (“SEC”) on March 14, 2014.

Forward-Looking Statements

Certain statements contained in this report constitute forward-looking statements. 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, uncertainties and other facts that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We believe the expectations reflected in these forward-looking statements are reasonable, but we cannot assure you that these expectations will prove to be correct. You should not place undue reliance on the forward-looking statements included 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 and its working interest partners for a majority of our revenues and our ability to secure new customers, provide additional services to existing customers and obtain long-term contracts;


•	our customers’ expenditures for oilfield services;


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


•	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;


•	the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the capital markets;


•	actions by customers, regulators and other third parties;


•	our credit profile;


•	availability 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; and


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

These factors are not necessarily all the factors that could affect us. Unpredictable or unanticipated factors we have not discussed in this report could also have material adverse effects on actual results of matters that are subject of our forward-looking statements.



Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Historically, we have provided substantially all of our oilfield services to Chesapeake and its working interest partners. For the Current Period and Prior Period, Chesapeake accounted for approximately 82% and 91% 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 New 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 New 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 New 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 the reporting date.



Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
	(in thousands)				(in thousands)
2014	$	—	—		$	1,000	3.75	%
2015	—		—		4,000		3.75	%
2016	—		—		4,000		3.75	%
2017	—		—		4,000		3.75	%
2018	—		—		4,000		3.75	%
After 2018	1,150,000		6.57	%	425,600		3.77	%
Total	$	1,150,000			$	442,600
Fair value	$	1,183,170			$	437,827

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.



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 effective as of September 30, 2014 at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the quarter ended September 30, 2014 which materially affected, or was reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION



Item 1.	Legal Proceedings

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



Item 1A.	Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth in the Information Statement included as Exhibit 99.1 to our Form 10 (Commission File No. 001-36354) filed with the SEC on June 16, 2014, 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(1)	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 (2)

July 1, 2014 - July 31, 2014	80,080	$	25.52	—	—

August 1, 2014 - August 31, 2014	863	23.47		—	—

September 1, 2014 - September 30, 2014	988	23.66		—	—

Total	81,931	$	25.48	—

(1) 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

On October 29, 2014, the Board of Directors of the Company approved, upon the recommendation of the Compensation Committee of the Board, a 2014 incentive program for employees of the Company. The incentive program is intended to provide cash incentives to employees, including executive officers, for achieving specified performance targets on a business unit and overall Company basis, such as revenue, increasing customer diversification, earnings before interest, taxes, depreciation and amortization, total recordable incident rate and total stockholder returns. The targets and their relative weighting are specific to each business unit. Each executive’s performance will be determined based upon the relative weighting of business unit performance and overall company performance established for such executive. Under the program, the performance of all executive officers is dependent in some measure on the performance of the Company overall. Performance based incentive compensation target amounts under the program for the named executive officers are as follows:

Jerry L. Winchester $890,000

Karl Blanchard $510,000

Cary D. Baetz $337,500

James Minmier $315,000

William Stanger $260,000

Following the end of the performance period, the Compensation Committee of the Board will determine the payment amount for each award based on the Committee’s evaluation of the achievement level of the pre-established performance objectives. Such payment amount will range from 0% to 200% of each executive officer’s target amount. Payments pursuant to the awards, if any, are expected to be made in the first quarter of 2015.



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

2.1

Master Separation Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C., and Chesapeake Energy Corporation.

8-K

001-36354

2.1

7/1/2014

3.1

Certificate of Incorporation of Seventy Seven Energy Inc.

8-K

001-36354

3.1

7/1/2014

3.2

Bylaws of Seventy Seven Energy Inc.

8-K

001-36354

3.2

7/1/2014

10.1

First Amendment to Employment Agreement with Cary D.Baetz, made effective October 29, 2014.

10.2

First Amendment to Employment Agreement with Karl Blanchard, made effective October 29, 2014.

10.3

First Amendment to Employment Agreement with James Minmier, made effective October 29, 2014.

10.4

First Amendment to Employment Agreement with Bill Stanger, made effective October 29, 2014.

12.1

Schedule of Computation of Ratio of Earnings to Fixed Charges.

31.1

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

31.2

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

32.1

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

32.2

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

101.1

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

†



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

SIGNATURES

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



October 30, 2014	SEVENTY SEVEN ENERGY INC.

	By:	/s/ Jerry L. Winchester
		Jerry L. Winchester
		President and Chief Executive Officer

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

INDEX TO EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Commission

File No.

Exhibit

Filing Date

Filed

Herewith

Furnished

Herewith

2.1

Master Separation Agreement, dated as of June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C., and Chesapeake Energy Corporation.

8-K

001-36354

2.1

7/1/2014

3.1

Certificate of Incorporation of Seventy Seven Energy Inc.

8-K

001-36354

3.1

7/1/2014

3.2

Bylaws of Seventy Seven Energy Inc.

8-K

001-36354

3.2

7/1/2014

10.1

First Amendment to Employment Agreement with Cary D.Baetz, made effective October 29, 2014.

10.2

First Amendment to Employment Agreement with Karl Blanchard, made effective October 29, 2014.

10.3

First Amendment to Employment Agreement with James Minmier, made effective October 29, 2014.

10.4

First Amendment to Employment Agreement with Bill Stanger, made effective October 29, 2014.

12.1

Schedule of Computation of Ratio of Earnings to Fixed Charges.

31.1

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

31.2

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

32.1

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

32.2

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

101.1

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

†



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

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