Seventy Seven Energy Inc. - FORM 10-Q

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EX-10.14 - EX-10.14 - Seventy Seven Energy Inc.	ex1014.htm
EX-10.9 - EX-10.9 - Seventy Seven Energy Inc.	ex109.htm
EX-10.17 - EX-10.17 - Seventy Seven Energy Inc.	ex1017.htm
EX-10.8 - EX-10.8 - Seventy Seven Energy Inc.	ex108.htm
EX-10.16 - EX-10.16 - Seventy Seven Energy Inc.	ex1016.htm
EX-10.11 - EX-10.11 - Seventy Seven Energy Inc.	ex1011.htm
EX-10.10 - EX-10.10 - Seventy Seven Energy Inc.	ex1010.htm
EX-10.12 - EX-10.12 - Seventy Seven Energy Inc.	ex1012.htm
EX-32.1 - EX-32.1 - Seventy Seven Energy Inc.	ex32131.htm
EX-32.2 - EX-32.2 - Seventy Seven Energy Inc.	ex32231.htm
EX-10.7 - EX-10.7 - Seventy Seven Energy Inc.	ex107.htm
EX-31.1 - EX-31.1 - Seventy Seven Energy Inc.	ex31131.htm
EX-31.2 - EX-31.2 - Seventy Seven Energy Inc.	ex31231.htm
EX-12.1 - EX-12.1 - Seventy Seven Energy Inc.	ex12131.htm
EX-10.15 - EX-10.15 - Seventy Seven Energy Inc.	ex1015.htm
EXCEL - IDEA: XBRL DOCUMENT - Seventy Seven Energy Inc.	Financial_Report.xls
EX-10.13 - EX-10.13 - Seventy Seven Energy Inc.	ex1013.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 JUNE 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 August 1, 2014, there were 48,178,891 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	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	69
Item 4.	Controls and Procedures	70

PART II. OTHER INFORMATION		71
Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	71
Item 5.	Other Information	71
Item 6.	Exhibits	74

SIGNATURES		77

PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Balance Sheets

(unaudited)



	June 30, 2014			December 31, 2013
	(in thousands)
Assets:
Current Assets:
Cash	$	8,476		$	1,678
Accounts receivable, net of allowance of $1,647 and $524 at June 30, 2014 and December 31, 2013, respectively	68,714			62,959
Accounts receivable with Chesapeake	308,940			312,480
Inventory	30,041			45,035
Deferred income tax asset	8,119			5,318
Prepaid expenses and other	15,575			20,301
Total Current Assets	439,865			447,771
Property and Equipment:
Property and equipment, at cost	2,631,774			2,241,350
Less: accumulated depreciation	(900,801		)	(773,282		)
Property and equipment held for sale, net	—			29,408
Total Property and Equipment, Net	1,730,973			1,497,476
Other Assets:
Equity method investment	7,949			13,236
Goodwill	27,434			42,447
Intangible assets, net	5,730			7,429
Deferred financing costs	27,086			14,080
Other long-term assets	7,716			4,454
Total Other Assets	75,915			81,646
Total Assets	$	2,246,753		$	2,026,893
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	54,305		$	30,666
Accounts payable to Chesapeake	8,279			34,200
Current portion of long-term debt	4,000			—
Other current liabilities	182,477			210,123
Total Current Liabilities	249,061			274,989
Long-Term Liabilities:
Deferred income tax liabilities	158,045			145,747
Long-term debt, excluding current maturities	1,568,400			1,055,000
Other long-term liabilities	3,601			3,965
Total Long-Term Liabilities	1,730,046			1,204,712
Commitments and Contingencies (Note 6)
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 46,932,433 shares at June 30, 2014	469			—
Paid-in capital	267,177			—
Owner’s Equity	—			547,192
Total Liabilities and Stockholders’/Owner’s Equity	$	2,246,753		$	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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands, except per share data)
Revenues:
Revenues from Chesapeake	$	447,085		$	544,301		$	877,922		$	1,057,736
Revenues from other third parties	102,381			38,763			181,254			69,215
Total Revenues	549,466			583,064			1,059,176			1,126,951
Operating Expenses:
Operating costs	406,586			457,383			816,174			872,433
Depreciation and amortization	71,829			72,490			144,294			142,601
General and administrative, including expenses from Chesapeake (Notes 1 and 12)	19,368			20,922			40,254			41,413
Net gains on sales of property and equipment	(8,964		)	(1,746		)	(7,986		)	(1,371		)
Impairments and other	3,172			6,718			22,980			6,741
Total Operating Expenses	491,991			555,767			1,015,716			1,061,817
Operating Income	57,475			27,297			43,460			65,134
Other Income (Expense):
Interest expense	(17,615		)	(14,138		)	(32,307		)	(28,149		)
Loss and impairment from equity investees	(4,500		)	(1,053		)	(5,417		)	(1,173		)
Other income (loss)	386			(63		)	757			461
Total Other Expense	(21,729		)	(15,254		)	(36,967		)	(28,861		)
Income Before Income Taxes	35,746			12,043			6,493			36,273
Income Tax Expense	14,036			4,867			3,338			14,866
Net Income	$	21,710		$	7,176		$	3,155		$	21,407

Earnings Per Common Share (Note 2)
Basic	$	0.46		$	0.15		$	0.07		$	0.46
Diluted	$	0.46		$	0.15		$	0.07		$	0.46

Weighted Average Common Shares Outstanding
Basic	46,932			46,932			46,932			46,932
Diluted	46,932			46,932			46,932			46,932

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statement of Stockholders’/Owner’s Equity

(unaudited)



	Common Stock	Common Stock		Paid-in Capital			Owner’s Equity			Total Stockholders’/ Owner’s Equity
	(Shares)	(in thousands)
Balance at December 31, 2013	—	$	—	$	—		$	547,192		$	547,192
Net income	—	—		—			3,155			3,155
Contributions from Chesapeake	—	—		—			190,297			190,297
Distributions to Chesapeake	—	—		—			(472,998		)	(472,998		)
Reclassification of owner’s equity to paid-in capital	—	—		267,646			(267,646		)	—
Issuance of common stock at spin-off	46,932,433	469		(469		)	—			—
Balance at June 30, 2014	46,932,433	$	469	$	267,177		$	—		$	267,646

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

SEVENTY SEVEN ENERGY INC.

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Six Months Ended June 30,
	2014			2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	3,155		$	21,407
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization	144,294			142,601
Amortization of sale/leaseback gains	(5,139		)	(3,079		)
Amortization of deferred financing costs	3,972			1,455
Gains on sales of property and equipment	(7,986		)	(1,371		)
Impairments	14,531			6,634
Loss from equity investees	5,417			1,173
Deferred income tax expense	2,642			14,428
Other	1,202			609
Changes in operating assets and liabilities	(40,154		)	(38,987		)
Net cash provided by operating activities	121,934			144,870
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment	(256,778		)	(147,487		)
Proceeds from sales of assets	60,939			35,771
Additions to investments	(131		)	(262		)
Other	35			—
Net cash used in investing activities	(195,935		)	(111,978		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to Chesapeake	(421,920		)	(12,961		)
Proceeds from issuance of senior notes, net of offering costs	493,825			—
Proceeds from issuance of term loan, net of issuance costs	393,879			—
Deferred financing costs	(2,385		)	—
Borrowings from revolving credit facility	716,500			545,700
Payments on revolving credit facility	(1,099,100		)	(565,000		)
Other	—			(212		)
Net cash provided by (used in) financing activities	80,799			(32,473		)
Net increase in cash	6,798			419
Cash, beginning of period	1,678			1,227
Cash, end of period	$	8,476		$	1,646

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Increase (decrease) in other current liabilities related to purchases of property and equipment	$	4,601		$	(45,124	)
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	$	28,083		$	27,985

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 now 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 existing $500.0 million senior secured revolving credit facility (the “Existing 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, which includes 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.

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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

The results of operations associated with the businesses distributed to Chesapeake are presented in the following table.



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)
Revenues	$	41,244	$	41,365	$	78,651	$	77,962
Income before income taxes	$	7,008	$	6,212	$	13,801	$	11,930

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes present SSE’s financial position as of June 30, 2014 and December 31, 2013, results of operations for the three and six months ended June 30, 2014 and 2013, changes in equity for the six months ended June 30, 2014 and cash flows for the six months ended June 30, 2014 and 2013. These notes relate to the three and six months ended June 30, 2014 (the “Current Quarter” and “Current Period,” respectively) and the three and six months ended June 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

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

Transactions between SSE and Chesapeake prior to the spin-off are identified in the financial statements as transactions with affiliates (see Note 12). The accompanying condensed consolidated financial statements include charges from Chesapeake for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, environmental, safety, information technology and other corporate services. These charges from Chesapeake were $14.0 million, $15.7 million, $26.8 million and $28.7 million for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Management believes that the allocated charges are representative of the costs and expenses incurred by Chesapeake on behalf of SSE. See Note 12 for a discussion of the methods of allocation. Subsequent to the spin-off, we will perform these functions using internal resources or services provided by third parties, certain of which may be provided by Chesapeake during a transition period pursuant to a transition services agreement (see Note 12).

Nature of Business

We provide a wide range of wellsite services and equipment, including drilling, hydraulic fracturing, oilfield rentals, rig relocation and fluid handling and disposal. We conduct our operations in Kansas, Louisiana, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, Wisconsin and Wyoming. As of June 30, 2014, our primary owned assets consisted of 85 drilling rigs, nine hydraulic fracturing fleets, 260 rig relocation trucks, 67 cranes and forklifts and 150 water transport trucks. Additionally, we had 14 rigs leased under contracts at June 30, 2014 (see Note 6). Our reportable business segments are drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations (see Note 13).

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2. Earnings Per Share

On June 30, 2014, 46,932,433 shares of our common stock were distributed 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 as of the beginning of each period presented in the calculation of basic weighted average shares. We had no dilutive securities outstanding for any of the periods presented.



	Three Months Ended June 30,
	2014				2013
	Basic		Diluted		Basic		Diluted
	(in thousands, except per share data)
Net income	$	21,710	$	21,710	$	7,176	$	7,176
Weighted average common shares outstanding	46,932		46,932		46,932		46,932

Earnings per share	$	0.46	$	0.46	$	0.15	$	0.15



	Six Months Ended June 30,
	2014				2013
	Basic		Diluted		Basic		Diluted
	(in thousands, except per share data)
Net income	$	3,155	$	3,155	$	21,407	$	21,407
Weighted average common shares outstanding	46,932		46,932		46,932		46,932

Earnings per share	$	0.07	$	0.07	$	0.46	$	0.46

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 $22.0 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 and had a total carrying amount of $20.7 million, for $43.8 million. During the Prior Period, we sold eight drilling rigs and ancillary equipment that were not being utilized in our business for $35.8 million, net of selling expenses. We recorded net gains on sales of property and equipment of approximately $9.0 million, $1.7 million, $8.0 million and $1.4 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 June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)
Drilling rigs held for sale	$	—	$	3,392	$	5,714	$	3,392
Drilling rigs held for use	2,940		—		8,366		—
Lease termination costs	70		108		8,449		108
Other	162		3,218		451		3,241
Total impairments and other	$	3,172	$	6,718	$	22,980	$	6,741

During the Current Period and Prior Period, we recognized $5.7 million and $3.4 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 $29.4 million as of December 31, 2013, related to drilling rigs and spare equipment that were sold during the Current Period. These assets were included in our drilling segment.

We also identified certain drilling rigs during the Current Quarter and Current 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 $2.9 million and $8.4 million during the Current Quarter and Current 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 31 of our leased drilling rigs for approximately $131.0 million and paid lease termination costs of approximately $8.4 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 $0.2 million, $3.2 million, $0.5 million and $3.2 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 June 30, 2014 and December 31, 2013, our long-term debt consisted of the following:



	June 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	400,000		—
New Credit Facility	22,400		—
Existing Credit Facility	—		405,000
Total debt	1,572,400		1,055,000
Less: Current portion of long-term debt	4,000		—
Total long-term debt	$	1,568,400	$	1,055,000

Existing Credit Facility

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 the Existing Credit Facility.

New 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 will be subject to the borrowing base, which will be based on a percentage of eligible accounts receivable, subject to reserves and other adjustments. As of June 30, 2014, the New Credit Facility had availability of $252.6 million. All obligations under the New Credit Facility will be 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 will range 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 should fail to perform our obligations under the agreement, the New Credit Facility could be terminated and any outstanding borrowings under the New Credit Facility could 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 Existing 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.

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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 will be 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 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. Initially, the 2022 Notes will not be guaranteed. 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. 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 and 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	%

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consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2022 Notes also have cross default provisions that apply to other indebtedness of SSE and certain of our subsidiaries. If the 2022 Notes achieve an investment grade rating from either Moody’s or S&P, our obligation to comply with certain of these covenants will be suspended, and if the 2022 Notes achieve an investment grade rating from both Moody’s and S&P, then 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 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.

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 and 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 such covenants will terminate.

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5. Other Current Liabilities

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



	June 30, 2014		December 31, 2013
	(in thousands)
Other Current Liabilities:
Operating expenditures	$	77,744	$	101,007
Payroll related	56,155		47,796
Insurance reserves	16,370		27,245
Interest	6,114		5,862
Property, sales, use and other taxes	11,911		17,904
Property and equipment	11,611		7,010
Deferred gain on sale/leasebacks	275		3,299
Other	2,297		—
Total Other Current Liabilities	$	182,477	$	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 $12.6 million, $28.9 million, $27.6 million and $58.9 million, respectively, and was included in operating costs in our condensed consolidated statements of operations.

Rig Leases

As of June 30, 2014, we leased 14 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 being accounted for as operating leases.

Rail Car Leases

As of June 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 being accounted for as operating leases.

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



	June 30, 2014
	Rigs		Rail Cars		Total

2014	$	8,153	$	3,091	$	11,244
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	$	8,153	$	26,272	$	34,425

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Other Commitments

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of June 30, 2014, we had $191.9 million of purchase commitments related to future inventory and 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 $2.7 million, $5.6 million, $5.1 million and $7.5 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 available to employees and stock options available to a member of senior management. Effective July 1, 2014, our employees participate in the SSE 2014 Incentive Plan (the “2014 Plan”). See Note 16.

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 canceled). We recorded a one-time credit of $10.5 million to operating costs and general and administrative costs on our condensed consolidated income statement for the Current Quarter as a result of the cancellation of the unvested Chesapeake awards. Also as result of the canceled unvested awards, we had no unrecognized compensation cost related to unvested restricted stock or stock options as of June 30, 2014. Compensation expense associated with the new awards will be amortized beginning in the quarter ended September 30, 2014. See Note 16 for more information.

Included in operating costs and general and administrative expenses is stock-based compensation (credits) expense of ($8.2) million, $2.9 million, ($5.0) million and $6.1 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 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. 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 included in 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 June 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 June 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 $7.9 million as of June 30, 2014. We recorded equity method adjustments to our investment of a nominal amount, $0.3 million, $0.9 million and $0.2 million for our share of Maalt’s loss for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. We also made additional investments of $0.1 million and $0.3 million in the Current Period and Prior Period, respectively. As of June 30, 2014, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $7.6 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 estimate 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 Quarter, which is included in loss from equity investees on our condensed consolidated statements of operations. Estimated fair value for our investment in Maalt was determined using significant unobservable inputs (Level 3) based on an income approach.

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 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:

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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.



	June 30, 2014				December 31, 2013
	Carrying Amount		Fair Value (Level 2)		Carrying Amount		Fair Value (Level 2)
	(in thousands)
Financial liabilities:
Existing Credit Facility	$	—	$	—	$	405,000	$	399,592
New Credit Facility	$	22,400	$	22,148	$	—	$	—
Term Loan	$	400,000	$	392,329	$	—	$	—
2022 Notes	$	500,000	$	513,750	$	—	$	—
2019 Notes	$	650,000	$	690,625	$	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 $308.9 million and $312.5 million as of June 30, 2014 and December 31, 2013, or 82% and 83%, respectively, of our total accounts receivable. Revenues from Chesapeake and its affiliates were $447.1 million, $544.3 million, $877.9 million and $1.058 billion for the Current Quarter, Prior Quarter, Current Period and Prior Period, or 81%, 93%, 83% and 94%, 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. Transactions between us and Chesapeake and its subsidiaries were considered to be transactions with affiliates. Subsequent to June 30, 2014, Chesapeake and its subsidiaries will not be 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 subsequent 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.

As of June 25, 2014, we were party to 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.

As of June 25, 2014, we were party to 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.

As of June 25, 2014, we were party to a transition services agreement with Chesapeake under which Chesapeake will provide or make available to us various administrative services and assets for specified periods beginning on the distribution date. In consideration for such services, we will pay Chesapeake fees, a portion of which will be 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. The services Chesapeake intends to provide 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 will supplement the master services agreement. Under the new services agreement, Chesapeake is required to utilize the lesser of (i) seven, five and three of our pressure

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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 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 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 will have the right to terminate the drilling agreements in 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 $4.1 million, $4.1 million, $8.2 million and $8.3 million of lease expense for the Current Quarter, 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, accordingly, 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 $14.0 million, $15.7 million, $26.8 million and $28.7 million for the Current Quarter, 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, depreciation and amortization, non-cash stock compensation, as further adjusted to add back nonrecurring items. The following is a description of the segments and other operations:

Drilling. Our drilling segment provides land drilling and drilling-related services, including directional drilling for oil and natural gas exploration and development activities. As of June 30, 2014, we owned or leased a fleet of 99 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 June 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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

transport produced water from the wellsite. As of June 30, 2014, we owned a fleet of 260 rig relocation trucks, 67 cranes and forklifts and 150 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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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



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

For The Three Months Ended June 30, 2013:
Revenues	$	190,231		$	250,345		$	41,971		$	64,409		$	44,778		$	(8,670	)	$	583,064
Intersegment revenues	(1,369		)	—			(195		)	(1,700		)	(5,406		)	8,670			—
Total revenues	$	188,862		$	250,345		$	41,776		$	62,709		$	39,372		$	—		$	583,064
Depreciation and amortization	33,822			16,417			15,476			6,529			246			—			72,490
Gains on sales of property and equipment	(352		)	(17		)	(572		)	(787		)	(18		)	—			(1,746		)
Impairments and other^(a)	3,505			—			—			—			3,213			—			6,718
Interest expense	—			—			—			—			(14,138		)	—			(14,138		)
Loss and impairment from equity investees	—			329			—			(1,382		)	—			—			(1,053		)
Other (expense) income	(167		)	(143		)	201			27			19			—			(63		)
Income (Loss) Before Income Taxes	$	1,972		$	24,911		$	(733	)	$	3,537		$	(17,644	)	$	—		$	12,043

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



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

For The Six Months Ended June 30, 2013:
Revenues	$	376,821		$	465,291		$	89,707		$	127,605		$	83,864		$	(16,337	)	$	1,126,951
Intersegment revenues	(2,586		)	—			(417		)	(3,485		)	(9,849		)	16,337			—
Total revenues	$	374,235		$	465,291		$	89,290		$	124,120		$	74,015		$	—		$	1,126,951
Depreciation and amortization	66,010			32,313			30,747			13,084			447			—			142,601
Losses (gains) on sales of property and equipment	180			—			(477		)	(1,056		)	(18		)	—			(1,371		)
Impairments and other^(a)	3,528			—			—			—			3,213			—			6,741
Interest expense	—			—			—			—			(28,149		)	—			(28,149		)
Loss and impairment from equity investees	—			234			—			(1,407		)	—			—			(1,173		)
Other (expense) income	(95		)	151			259			80			66			—			461
Income (Loss) Before Income Taxes	$	9,888		$	54,920		$	2,683		$	4,562		$	(35,780	)	$	—		$	36,273

As of June 30, 2014:
Total Assets	$	1,229,416		$	446,518		$	175,749		$	147,023		$	252,931		$	(4,884	)	$	2,246,753
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 $0.1 million, $0.1 million, $8.4 million and $0.1 million for the Current Quarter, Prior Quarter, Current Period and Prior Period.

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 June 30, 2014 and December 31, 2013 and for the three and six months ended June 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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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF JUNE 30, 2014

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	7,418	$	1,008		$	50		$	—		$	8,476
Accounts receivable	—		—			68,714			—			68,714
Accounts receivable with Chesapeake	—		3,393			308,533			(2,986		)	308,940
Inventory	—		—			30,041			—			30,041
Deferred income tax asset	—		2,091			6,028			—			8,119
Prepaid expenses and other	—		4,382			11,193			—			15,575
Total Current Assets	7,418		10,874			424,559			(2,986		)	439,865
Property and Equipment:
Property and equipment, at cost	—		10,653			2,621,121			—			2,631,774
Less: accumulated depreciation	—		(450		)	(900,351		)	—			(900,801		)
Total Property and Equipment, Net	—		10,203			1,720,770			—			1,730,973
Other Assets:
Equity method investment	—		—			7,949			—			7,949
Goodwill	—		—			27,434			—			27,434
Intangible assets, net	—		—			5,730			—			5,730
Deferred financing costs, net	7,468		19,618			—			—			27,086
Other long-term assets	—		2,939			6,172			(1,395		)	7,716
Investments in subsidiaries and intercompany advances	755,718		1,801,203			—			(2,556,921		)	—
Total Other Assets	763,186		1,823,760			47,285			(2,558,316		)	75,915
Total Assets	$	770,604	$	1,844,837		$	2,192,614		$	(2,561,302	)	$	2,246,753
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	1,214	$	107		$	52,984		$	—		$	54,305
Accounts payable to Chesapeake	—		—			11,265			(2,986		)	8,279
Current portion of long-term debt	—		4,000			—			—			4,000
Other current liabilities	1,744		15,068			165,665			—			182,477
Total Current Liabilities	2,958		19,175			229,914			(2,986		)	249,061
Long-Term Liabilities:
Deferred income tax liabilities	—		—			159,440			(1,395		)	158,045
Long-term debt, excluding current maturities	500,000		1,068,400			—			—			1,568,400
Other long-term liabilities	—		1,544			2,057			—			3,601
Total Long-Term Liabilities	500,000		1,069,944			161,497			(1,395		)	1,730,046
Total Equity	267,646		755,718			1,801,203			(2,556,921		)	267,646
Total Liabilities and Stockholders’/Owner’s Equity	$	770,604	$	1,844,837		$	2,192,614		$	(2,561,302	)	$	2,246,753

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SEVENTY SEVEN ENERGY INC.

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	—		—			62,959			—			62,959
Accounts receivable with Chesapeake	—		1,142			311,338			—			312,480
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	$	—	$	2,051		$	28,615		$	—		$	30,666
Accounts payable to Chesapeake	—		838			33,362			—			34,200
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
Senior notes	—		650,000			—			—			650,000
Revolving credit facility	—		405,000			—			—			405,000
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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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2014

(in thousands)



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

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2013

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—	$	2,167		$	582,995		$	(2,098	)	$	583,064
Operating Expenses:
Operating costs	—		2,521			457,241			(2,379		)	457,383
Depreciation and amortization	—		7			72,483			—			72,490
General and administrative	—		3,106			17,816			—			20,922
Losses on sales of property and equipment	—		—			(1,746		)	—			(1,746		)
Impairments	—		—			6,718			—			6,718
Total Operating Expenses	—		5,634			552,512			(2,379		)	555,767
Operating (Loss) Income	—		(3,467		)	30,483			281			27,297
Other (Expense) Income:
Interest expense	—		(14,138		)	—			—			(14,138		)
Loss from equity investees	—		—			(1,053		)	—			(1,053		)
Other expense	—		—			(63		)	—			(63		)
Equity in net earnings of subsidiary	7,343		17,667			—			(25,010		)	—
Total Other Income (Expense)	7,343		3,529			(1,116		)	(25,010		)	(15,254		)
Income Before Income Taxes	7,343		62			29,367			(24,729		)	12,043
Income Tax (Benefit) Expense	167		(7,114		)	11,867			(53		)	4,867
Net Income	$	7,176	$	7,176		$	17,500		$	(24,676	)	$	7,176

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2014

(in thousands)



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

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2013

(in thousands)



	Parent		Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	—	$	4,015		$	1,126,833		$	(3,897	)	$	1,126,951
Operating Expenses:
Operating costs	—		4,948			872,227			(4,742		)	872,433
Depreciation and amortization	—		7			142,594			—			142,601
General and administrative	—		9,295			32,118			—			41,413
Gains on sales of property and equipment	—		—			(1,371		)	—			(1,371		)
Impairments and other	—		—			6,741			—			6,741
Total Operating Expenses	—		14,250			1,052,309			(4,742		)	1,061,817
Operating (Loss) Income	—		(10,235		)	74,524			845			65,134
Other (Expense) Income:
Interest expense	—		(28,149		)	—			—			(28,149		)
Loss from equity investees	—		—			(1,173		)	—			(1,173		)
Other income	—		4			457			—			461
Equity in net earnings of subsidiary	21,906		44,060			—			(65,966		)	—
Total Other Income (Expense)	21,906		15,915			(716		)	(65,966		)	(28,861		)
Income Before Income Taxes	21,906		5,680			73,808			(65,121		)	36,273
Income Tax (Benefit) Expense	499		(15,727		)	30,247			(153		)	14,866
Net Income	$	21,407	$	21,407		$	43,561		$	(64,968	)	$	21,407

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SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2014

(in thousands)



	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	57,184		$	(4,589	)	$	167,476		$	(98,137	)	$	121,934
Cash Flows From Investing Activities:
Additions to property and equipment	—			(7,550		)	(249,228		)	—			(256,778		)
Proceeds from sale of assets	—			—			60,939			—			60,939
Additions to investments and other	(121,670		)	(63,994		)	(96		)	185,664			(96		)
Cash used in investing activities	(121,670		)	(71,544		)	(188,385		)	185,664			(195,935		)
Cash Flows From Financing Activities:
Distributions to Chesapeake	(421,920		)	—			—			—			(421,920		)
Contributions from affiliates	—			66,632			20,895			(87,527		)	—
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
Deferred financing costs	—			(2,385		)	—			—			(2,385		)
Borrowings from revolving credit facility	—			716,500			—			—			716,500
Payments on revolving credit facility	—			(1,099,100		)	—			—			(1,099,100		)
Net cash provided by financing activities	71,905			75,526			20,895			(87,527		)	80,799
Net increase (decrease) in cash	7,419			(607		)	(14		)	—			6,798
Cash, beginning of period	—			1,615			63			—			1,678
Cash, end of period	$	7,419		$	1,008		$	49		$	—		$	8,476

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

SIX MONTHS ENDED JUNE 30, 2013

(in thousands)



			Subsidiary Issuer			Guarantor
	Parent		Subsidiary Issuer			Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	—	$	23,137		$	177,504		$	(55,771	)	$	144,870
Cash Flows From Investing Activities:
Additions to property and equipment	—		(3,028		)	(144,459		)	—			(147,487		)
Proceeds from sale of assets	—		—			35,771			—			35,771
Other	—		—			(262		)	—			(262		)
Cash used in investing activities	—		(3,028		)	(108,950		)	—			(111,978		)
Cash Flows From Financing Activities:
Distributions to affiliates	—		—			(68,732		)	55,771			(12,961		)
Borrowings from revolving credit facility	—		545,700			—			—			545,700
Payments on revolving credit facility	—		(565,000		)	—			—			(565,000		)
Other	—		(212		)	—			—			(212		)
Net cash used in financing activities	—		(19,512		)	(68,732		)	55,771			(32,473		)
Net increase (decrease) in cash	—		597			(178		)	—			419
Cash, beginning of period	—		863			364			—			1,227
Cash, end of period	$	—	$	1,460		$	186		$	—		$	1,646

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 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 that were completed in the Current Period and concluded that these disposals did not qualify as a discontinued operation.

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

Prior to the spin-off, our employees participated in the Chesapeake share-based compensation program and received restricted stock available to employees and stock options available to senior management. Effective July 1, 2014, our employees participate in 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 adjustments are generally 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 adjustment and 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 the shares of SSE common stock on the date of the grant. This value is amortized over the vesting period.

Stock Options. The incentive-based stock options vest ratably over a three-year period and the 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. The stock option awards, not including the replacement 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.

Table of Contents

SEVENTY SEVEN ENERGY INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A summary of the outstanding awards issued July 1, 2014, under the 2014 Plan as a result of the substitution of the Chesapeake share-based compensation program is presented below.



	Restricted Stock			Stock Options
	Awards	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Exercise Price
	(in thousands)			(in thousands)
Outstanding as of July 1, 2014	2,097	$	25.06	348	$	16.19



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

The following discussion and analysis of our financial condition and results of operations relates to the three and six months ended June 30, 2014 (the “Current Quarter” and “Current Period,” respectively), the three and six months ended June 30, 2013 (the “Prior Quarter” and “Prior Period,” respectively) and the three months ended March 31, 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 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, are referred to collectively as the “spin-off”. These financial statements 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 during the periods presented 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 discussed in this section do not give effect to the following transactions, which will impact our future results of operations:


•	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 “Existing 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 5th largest U.S. land-based drilling rig fleet, which we categorize into three operational “Tiers.” Our Tier 1 rigs are equipped with AC electric drives and top drives and nearly all have 1,600 horsepower mud pumps. Our Tier 2 rigs are equipped with DC electric drives and top drives and nearly all have 1,300 horsepower mud pumps. Approximately 85% of our Tier 1 and Tier 2 rigs are multi-well pad capable, being equipped with skidding or walking systems. Our Tier 3 rigs are legacy, mechanical drive rigs.

As of June 30, 2014, our marketed fleet consisted of 20 Tier 1 rigs, including 10 proprietary PeakeRigs™, 57 Tier 2 rigs and 13 Tier 3 rigs. We also have 16 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 June 30, 2014, our drilling operating segment generated revenues of $189.2 million and Adjusted EBITDA of $68.9 million, representing 34% and 57% of our total revenues and Adjusted EBITDA, respectively. “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 June 30, 2014, approximately 39% of our active rigs were contracted by non-Chesapeake customers.

As of June 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 other certain 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 June 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 and the Eagle Ford and Utica Shales. We have a tenth hydraulic fracturing fleet under construction, which will add another 40,000 horsepower by late fall 2014. Our equipment had an average age of 25 months as of June 30, 2014, which we believe to be among the newest in the industry. We averaged over 69 stages per fleet per month for the six months ended June 30, 2014. For the quarter ended June 30, 2014, our hydraulic fracturing operating segment generated revenues of $226.1 million and Adjusted EBITDA of $41.7 million, representing 41% and 34% of our total revenues and Adjusted EBITDA, respectively.

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 a lump sum equipment charge determined by the rate per stage that each contract specifies and 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 June 30, 2014, we offered oilfield rental services in the Anadarko and Permian Basins and the Eagle Ford, 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 June 30, 2014, our oilfield rentals operating segment generated revenues of $39.0 million and Adjusted EBITDA of $13.8 million, representing 7% and 11% of our total revenues and Adjusted EBITDA, respectively.

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 June 30, 2014, Hodges owned a fleet of 260 rig relocation trucks and 67 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 June 30, 2014, our subsidiaries owned a fleet of 150 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 hours and volume and recognize revenue as services are performed. For the quarter ended June 30, 2014, our oilfield trucking operating segment generated revenues of $55.5 million and Adjusted EBITDA of $6.0 million, representing 10% and 5% of our total revenues and Adjusted EBITDA, respectively.

Recent Developments

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 a the New Credit Facility and Term Loan. We used the proceeds from borrowings under these new facilities to repay in full and terminate our Existing 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, which includes 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 $4.1 million, $4.1 million, $8.2 million and $8.3 million for the Current Quarter, 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 19 existing non-Chesapeake drilling customers and our reputation for quality to provide additional services that are in demand, such as hydraulic fracturing and oilfield 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, 90% of our Tier 1 rigs and 61% of our Tier 2 rigs are, multi-well pad-ready and able to meet the robust demands of E&P customers focused on unconventional resource development. Additionally, we are fabricating six additional proprietary 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) safety record even as our employee base has increased by almost 50% over the past three years. From the beginning of 2011 to 2013, our TRIR dropped by approximately 59% and our lost time incidents have decreased by 83%. In addition, all of our field-based employees are eligible to receive incentive pay based on satisfying safety standards, which we believe motivates them to continually maintain quality and safety. We have adopted rigorous processes and procedures to facilitate our compliance with environmental regulations and policies and expect to regularly conduct third party assessments to identify areas for improvement. We work diligently to meet or exceed applicable safety and environmental regulations and we intend to continue to enhance our safety monitoring function 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.

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 July 1, 2014 was approximately $1.5 billion and $1.3 billion,

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 July 1, 2014, we expect to recognize revenues from backlog as follows (in approximate millions):




	2014		2015		Thereafter
Backlog	$	665.0	$	1,060.0	$	1,101.0

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 July 1, 2014 was approximately $1.5 billion and $1.0 billion, respectively, related to these agreements with Chesapeake.

Revenues from non-Chesapeake customers increased 30% from the Previous Quarter to the Current Quarter to 19% of total revenues. Revenues from Chesapeake and its affiliates were $447.1 million, $544.3 million, $877.9 million and $1.058 billion for the Current Quarter, Prior Quarter, Current Period and Prior Period, or 81%, 93%, 83% and 94%, 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, rig lease expenses and product and material costs. We also plan to make expenditures for equipment acquisitions 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 have historically reimbursed Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake on our behalf in accordance with its current allocation policy, which includes 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, in return for the use of certain yards and other physical facilities out of which we conduct our operations, we paid rent and our proportionate

share of maintenance, operating expenses, taxes and insurance to Chesapeake on a monthly basis. 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 six areas: (a) Adjusted EBITDA, (b) Segment Gross Margin, (c) equipment maintenance performance, (d) customer satisfaction, (e) asset utilization, and (f) safety performance.

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. Our management uses Adjusted EBITDA to evaluate our performance and liquidity and believes Adjusted EBITDA is useful to investors in evaluating our operating performance and liquidity. The table below shows our Adjusted EBITDA for the three and six months ended June 30, 2014 and 2013.




	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(unaudited) (in thousands)
Adjusted EBITDA	$	120,866	$	122,061	$	206,356	$	247,349

Non-GAAP Financial Measure

“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. Adjusted EBITDA, as used and defined by us may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. 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.

For each of our operating segments, the following table presents a reconciliation of the Non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and cash provided by operating activities.

Consolidated



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Net income	$	21,710		$	7,176		$	3,155		$	21,407
Add:
Interest expense	17,615			14,138			32,307			28,149
Income tax expense	14,036			4,867			3,338			14,866
Depreciation and amortization	71,829			72,490			144,294			142,601
Impairments and other	3,172			6,718			22,980			6,741
Gains on sales of property and equipment	(8,964		)	(1,746		)	(7,986		)	(1,371		)
Impairment of equity method investment	4,500			1,789			4,500			1,789
Rent expense on buildings and real estate transferred from Chesapeake	4,081			4,079			8,187			8,331
Rig rent expense	6,016			22,570			15,075			45,551
Less:
Compression unit manufacturing Adjusted EBITDA	6,357			5,244			13,073			10,302
Geosteering Adjusted EBITDA	763			1,074			957			1,850
Crude hauling Adjusted EBITDA	(4,521		)	3,702			(5,066		)	8,563
One-time credit to stock compensation expense	10,530			—			10,530			—
Adjusted EBITDA	$	120,866		$	122,061		$	206,356		$	247,349



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Cash provided by operating activities	$	67,352		$	57,477		$	121,934		$	144,870
Add:
Changes in assets and liabilities	41,782			32,273			40,154			38,987
Interest expense	17,615			14,139			32,307			28,149
Lease termination costs	70			108			8,449			108
Amortization of sale/leaseback gains	925			1,549			5,139			3,079
Amortization of deferred financing costs	(3,235		)	(729		)	(3,972		)	(1,455		)
Loss from equity investees	—			735			(917		)	616
Current tax expense	363			221			696			437
Rent expense on buildings and real estate transferred from Chesapeake	4,081			4,079			8,187			8,331
Rig rent expense	6,016			22,570			15,075			45,551
Other	(974		)	(341		)	(1,202		)	(609		)
Less:
Compression unit manufacturing Adjusted EBITDA	6,357			5,244			13,073			10,302
Geosteering Adjusted EBITDA	763			1,074			957			1,850
Crude hauling Adjusted EBITDA	(4,521		)	3,702			(5,066		)	8,563
One-time credit to stock compensation expense	10,530			—			10,530			—
Adjusted EBITDA	$	120,866		$	122,061		$	206,356		$	247,349

Drilling



	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014		2013
	(In thousands)
Net income	$	9,541	$	1,162		$	7,182	$	5,719
Add:
Income tax expense	5,941		810			4,612		4,169
Depreciation and amortization	34,398		33,822			69,301		66,010
Impairments and other	3,171		3,504			22,772		3,528
Losses (gains) on sales of property and equipment	14,086		(352		)	15,795		180
Rent expense on buildings and real estate transferred from Chesapeake	809		913			1,688		1,815
Rig rent expense	6,016		22,570			15,075		45,551
Less:
Geosteering Adjusted EBITDA	763		1,074			957		1,850
One-time credit to stock compensation expense	4,318		—			4,318		—
Adjusted EBITDA	$	68,881	$	61,355		$	131,150	$	125,122

Hydraulic Fracturing



	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014		2013
	(In thousands)
Net income	$	11,722	$	15,417		$	12,317	$	34,005
Add:
Income tax expense	7,443		9,494			8,052		20,915
Depreciation and amortization	17,851		16,417			35,960		32,313
Impairments	—		—			207		—
Gains on sales of property and equipment	—		(17		)	—		—
Impairment of equity method investment	4,500		—			4,500		—
Rent expense on buildings and real estate transferred from Chesapeake	630		502			1,259		1,120
Less:
One-time credit to stock compensation expense	477		—			477		—
Adjusted EBITDA	$	41,669	$	41,813		$	61,818	$	88,353

Oilfield Rentals



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Net (loss) income	$	340		$	(477	)	$	(1,796	)	$	1,558
Add:
Income tax expense (benefit)	225			(256		)	(1,013		)	1,125
Depreciation and amortization	13,368			15,476			26,715			30,747
Gains on sales of property and equipment	(183		)	(572		)	(925		)	(477		)
Rent expense on buildings and real estate transferred from Chesapeake	695			586			1,415			1,173
Less:
One-time credit to stock compensation expense	601			—			601			—
Adjusted EBITDA	$	13,844		$	14,757		$	23,795		$	34,126

Oilfield Trucking



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Net income	$	12,218		$	2,076		$	8,821		$	2,518
Add:
Income tax expense	7,614			1,461			5,744			2,044
Depreciation and amortization	5,429			6,529			11,357			13,084
Gains on sales of property and equipment	(22,863		)	(787		)	(22,871		)	(1,056		)
Impairment of equity method investment	—			1,789			—			1,789
Rent expense on buildings and real estate transferred from Chesapeake	861			863			1,724			1,759
Less:
Crude hauling Adjusted EBITDA	(4,521		)	3,702			(5,066		)	8,563
One-time credit to stock compensation expense	1,826			—			1,826			—
Adjusted EBITDA	$	5,954		$	8,229		$	8,015		$	11,575

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 99%, 97%, 98% and 96% for the three months ended June 30, 2014 and 2013 and the six months ended June 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.

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.

Existing Credit Facility

New Credit Facility

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 will be subject to the borrowing base, which will be based on a percentage of eligible accounts receivable, subject to reserves and other adjustments. As of June 30, 2014, the New Credit Facility had availability of approximately $252.6 million. All obligations under the New Credit Facility will be 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 will range 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.

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 Existing 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 will be 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.

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. Initially, the 2022 Notes will not be guaranteed. 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. 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 and 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 SSE and certain of our subsidiaries. If the 2022 Notes achieve an investment grade rating from either Moody’s or S&P, our obligation to comply with certain of these covenants will be suspended, and if the 2022 Notes achieve an investment grade rating from both Moody’s and S&P, then such covenants will terminate.

2019 Senior Notes



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 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 such covenants will terminate.

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 $256.8 million and $147.5 million for the Current Period and Prior Period, respectively. During the Current Period, we purchased 31 of our leased drilling rigs for approximately $131.0 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. We expect our total capital expenditures will be funded by cash flow from operations and borrowings under our New Credit Facility. We expect the growth capital expenditures for 2014 and 2015 will be allocated approximately 71% for our drilling segment and approximately 13% for our oilfield rental segment. Our planned capital expenditures for 2014 and 2015 include 16 new PeakeRigs™ and one new hydraulic fracturing fleet. 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, to the extent 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.



	Six Months Ended June 30,
	2014			2013
	(in thousands) (unaudited)
Cash Flow Statement Data:
Net cash provided by operating activities	$	121,934		$	144,870
Net cash used in investing activities	$	(195,935	)	$	(111,978	)
Net cash provided by (used in) financing activities	$	80,799		$	(32,473	)
Cash, beginning of period	$	1,678		$	1,227
Cash, end of period	$	8,476		$	1,646

Operating Activities. Cash provided by operating activities was $121.9 million and $144.9 million for the Current Period and Prior Period, respectively. Changes in working capital items decreased cash flow provided by operating activities by $40.2 million and $39.0 million for the Current Period and Prior Period, respectively. 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 and deferred income taxes.

Investing Activities. Cash used in investing activities was $195.9 million and $112.0 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 31 leased drilling rigs for approximately $131.0 million during the Current Period and two leased drilling rigs for approximately $0.5 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 $60.9 million and $35.8 million for the Current Period and Prior Period, respectively.

Financing Activities. Net cash provided by (used in) financing activities was $80.8 million and ($32.5) 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 $122.4 million and $100.0 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 Existing 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 $2.4 million in deferred financing costs related to our New Credit Facility, Term Loan and 2022 Notes. We had borrowings and repayments under our Existing Credit Facility of $594.1 million and $999.1 million, respectively, during the Current Period. We had borrowings and repayments under our Existing Credit Facility of $545.7 million and $565.0 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 $13.0 million, respectively.

Results of Operations—Three Months Ended June 30, 2014 vs. March 31, 2014

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



	Three Months Ended June 30,			Three Months Ended March 31,
	2014
	(in thousands)
Revenues:
Revenues from Chesapeake	$	447,085		$	430,835
Revenues from other third parties	102,381			78,875
Total Revenues	549,466			509,710
Operating Expenses:
Operating costs	406,586			409,589
Depreciation and amortization	71,829			72,465
General and administrative, including expenses from Chesapeake	19,368			20,887
(Gains) losses on sales of property and equipment	(8,964		)	977
Impairments and other	3,172			19,808
Total Operating Expenses	491,991			523,726
Operating Income (Loss)	57,475			(14,016		)
Other Income (Expense):
Interest expense	(17,615		)	(14,692		)
Loss and impairment from equity investees	(4,500		)	(917		)
Other income	386			371
Total Other Expense	(21,729		)	(15,238		)
Income (Loss) Before Income Taxes	35,746			(29,254		)
Income Tax Expense (Benefit)	14,036			(10,697		)
Net Income (Loss)	$	21,710		$	(18,557	)

Revenues. For the Current Quarter and Previous Quarter, revenues were $549.5 million and $509.7 million, respectively. We experienced 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 30% from the Previous Quarter to the Current 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 for the Current Quarter and Previous Quarter are detailed below:



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands)
Drilling	$	189,177	$	180,434
Hydraulic fracturing	226,112		201,620
Oilfield rentals	38,977		35,942
Oilfield trucking	55,451		56,195
Other operations	39,749		35,519
Total	$	549,466	$	509,710

Operating Costs. Operating costs for the Current Quarter and Previous Quarter were $406.6 million and $409.6 million, respectively. The decrease was primarily the result of a one-time credit to stock compensation expense of $7.3 million as a result of the cancellation of the unvested Chesapeake awards, partially offset by an overall increase in drilling and completion activity by our customers. As a percentage of revenues, operating costs were 74% and 80% for the Current Quarter and Previous Quarter, respectively. The decrease in operating costs as a percentage of revenue was primarily attributable to higher utilization rates and reductions in labor-related costs, repairs and maintenance and supplies expense. Our operating costs for the Current Quarter and Previous Quarter are detailed below:



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands)
Drilling	$	118,354	$	124,460
Hydraulic fracturing	179,283		177,012
Oilfield rentals	24,534		25,949
Oilfield trucking	51,451		53,614
Other operations	32,964		28,554
Total	$	406,586	$	409,589

Drilling



	Three Months Ended June 30,			Three Months Ended March 31,
	2014
	(in thousands, except average rigs, utilization, revenue day and per revenue day amounts)
Revenues	$	189,177		$	180,434
Operating costs^(a)	118,354			124,460
Gross margin	$	70,823		$	55,974
Revenue days^(b)	7,396			7,036
Average revenue per revenue day^(b)	$	23,219		$	23,421
Average operating costs per revenue day^{(a) (b)}	$	14,031		$	15,590
Average margin per revenue day^(b)	$	9,188		$	7,831
Average rigs operating	81			80
Utilization	99		%	98		%

Adjusted operating costs:
Operating costs^(b)	$	103,776		$	109,689
Add:
One-time credit to stock compensation expense	4,318			—
Less:
Rig rent expense	6,016			9,059
Adjusted operating costs^(b)	$	102,078		$	100,630
Adjusted average operating costs per day^(b)	$	13,802		$	14,302


(a)	Our operating costs and average operating costs per revenue day include $6.0 million and $9.1 million of rig rent expense associated with our lease of drilling rigs for the Current Quarter and Previous Quarter, respectively.


(b)	These metrics exclude results from our drilling-related services, including directional drilling, mudlogging and geosteering.

Drilling revenues for the Current Quarter increased $8.7 million, or 5%, from the Previous Quarter. This increase was primarily due to a 5% increase in revenue days. Average revenue per revenue day for the Current Quarter was down 1% from the Previous Quarter due to lower non-drilling revenue associated with the drilling rigs. Revenues from non-Chesapeake customers increased $6.9 million from the Previous Quarter to the Current Quarter to 31% of total segment revenues compared to 29% for the Previous Quarter.

Drilling operating costs for the Current Quarter decreased $6.1 million or 5%, from the Previous Quarter. As a percentage of drilling revenues, drilling operating costs were 63% and 69% for the Current Quarter and the Previous Quarter, respectively. We also experienced a 3% decrease in Adjusted average operating costs per revenue day from the Previous Quarter to the Current Quarter primarily due to a reduction in labor-related costs.

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



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands)
Revenues	$	2,014	$	1,926
Operating costs	1,208		1,687
Gross margin	$	806	$	239

Hydraulic Fracturing



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands, except stages, average fleets and per stage amounts)
Revenues	$	226,112	$	201,620
Operating costs	179,283		177,012
Gross margin	$	46,829	$	24,608
Stages completed	2,054		1,722
Average revenue per stage	$	110,084	$	117,085
Average operating costs per stage	$	87,285	$	102,794
Average margin per stage	$	22,799	$	14,291
Average fleets operating	9		9

Hydraulic fracturing revenues for the Current Quarter increased $24.5 million, or 12%, from the Previous Quarter. This increase was due to an 19% increase in completed stages from the Previous Quarter to the Current Quarter, partially offset by a 6% decrease in revenue per stage from the Previous Quarter to the Current Quarter. Revenue per stage decreased in the Current Quarter primarily as a result of rate differences due to the geographic relocation of a frac spread. Revenues from non-Chesapeake customers increased $4.5 million from the Previous Quarter to the Current Quarter to 2% of total segment revenues compared to 0% for the Previous Quarter.

Hydraulic fracturing operating costs for the Current Quarter increased $2.3 million, or 1% from the Previous Quarter, primarily due to a 19% increase in the number of completed stages, partially offset by a 15% decrease in average operating costs per stage from the Previous Quarter to the Current Quarter. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs decreased from 88% in the Previous Quarter to 79% in the Current Quarter. This decrease was primarily attributable to lower expendables, repairs and maintenance and product costs. As a percentage of hydraulic fracturing revenues, maintenance and supplies expense were 11% in the Current Quarter and 17% in the Previous Quarter.

Oilfield Rental



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands)
Revenues	$	38,977	$	35,942
Operating costs	24,534		25,949
Gross margin	$	14,443	$	9,993

Oilfield rental revenues for the Current Quarter increased $3.0 million, or 8%, from the Previous Quarter. The increase was primarily due to higher utilization as a result of increased activity with unaffiliated third parties. Revenues from non-Chesapeake customers increased $2.6 million from the Previous Quarter to the Current Quarter to 16% of total segment revenues compared to 10% for the Previous Quarter.

Oilfield rental operating costs for the Current Quarter decreased $1.4 million, or 5%, from the Previous Quarter. The decrease was primarily due to lower labor-related costs, freight and inspection expenses. As a percentage of oilfield rental revenues, oilfield rental operating costs were 63% and 72% for the Current Quarter and Previous Quarter, respectively. The decrease in oilfield rental operating costs as a percentage of oilfield rental revenues from the Previous Quarter to the Current Quarter was primarily attributable to a decrease in labor-related costs resulting from targeted, segment-wide overtime management efforts initiated during the Current Quarter and an intentional reduction in use of third-party labor. As a percentage of oilfield rental revenues, labor-related costs were 28% and 34% in the Current Quarter and Previous Quarter, respectively. We also experienced a decrease in repairs and maintenance expense and supplies expense.

Oilfield Trucking



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands)
Revenues	$	55,451	$	56,195
Operating costs	51,451		53,614
Gross margin	$	4,000	$	2,581

Oilfield trucking revenues for the Current Quarter decreased $0.7 million, or 1%, from the Previous Quarter. The decrease was primarily due to a reduction in revenues from our fluid hauling services of $2.8 million from the Previous Quarter to the Current Quarter. Revenues from non-Chesapeake customers increased $3.2 million from the Previous Quarter to the Current Quarter to 28% of total segment revenues compared to 22% for the Previous Quarter.

Oilfield trucking operating costs for the Current Quarter decreased $2.2 million from the Previous Quarter. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 93% and 95% for the Current Quarter and Previous Quarter, respectively. We had a one-time credit to stock compensation expense of $1.8 million during the Current Quarter related to unvested restricted stock cancelled as part of the spin-off.

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



	Three Months Ended June 30,			Three Months Ended March 31,
	2014
	(in thousands)
Revenues	$	10,530		$	13,299
Operating costs	14,495			12,761
Gross margin	$	(3,965	)	$	538

Other Operations



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands)
Revenues	$	39,749	$	35,519
Operating costs	32,964		28,554
Gross margin	$	6,785	$	6,965

Our other operations consist primarily of our compression unit manufacturing business and corporate functions. For the Current Quarter, revenues from our other operations increased $4.2 million, or 12%, from the Previous Quarter. The increase in revenue from the Previous Quarter to the Current Quarter was primarily attributable to a 14% increase in compression horsepower manufactured from the Previous Quarter to the Current Quarter.

For the Current Quarter, operating costs for our other operations increased $4.4 million, or 15%, from the Previous Quarter. As a percentage of compression manufacturing revenues, compression manufacturing costs were 82% and 80% in the Current Quarter and Previous Quarter, respectively. The increase in costs as a percentage of revenues was due to an increase in production of lower margin large natural gas compressors.

As part of the spin-off, we distributed our compression manufacturing business to Chesapeake. This business has historically been included in our other operations results and the associated revenues and operating costs are detailed below:



	Three Months Ended June 30,		Three Months Ended March 31,
	2014
	(in thousands)
Revenues	$	39,230	$	35,420
Operating costs	32,244		28,357
Gross margin	$	6,986	$	7,063

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Previous Quarter was $71.8 million and $72.5 million, respectively. As a percentage of revenues, depreciation and amortization expense was 13% and 14% for the Current Quarter and Previous Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Previous Quarter were $19.4 million and $20.9 million, respectively. Prior to the spin-off, we were allocated corporate overhead from Chesapeake which covers costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. The administrative expense allocation was determined by multiplying revenues by a percentage determined by Chesapeake based on the estimated costs incurred on our behalf. These charges from Chesapeake were $14.0 million and $12.8 million for the Current Quarter and Previous Quarter, respectively. We had a one-time credit to stock compensation expense of $3.2 million during the Current Quarter related to unvested restricted stock cancelled as part of the spin-off. As a percentage of revenues, general and administrative expenses were 4% for both the Current Quarter and Previous Quarter.

(Gains) Losses on Sales of Property and Equipment. During the Current Quarter, we sold 14 drilling rigs and ancillary equipment that were not being utilized in our business as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers. During the Previous Quarter, we sold ancillary equipment that was not being utilized in our business. We recorded (gains) losses on sales of property and equipment of approximately ($9.0) million and $1.0 million related to these asset sales during the Current Quarter and Previous Quarter, respectively.

Impairments and Other. During the Previous Quarter, we recognized $5.7 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 Current Quarter and 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 and $5.4 million during the Current Quarter and Previous Quarter, respectively, related to these drilling rigs. During the Current Quarter, we purchased 11 of our leased drilling rigs for approximately $54.1 million and paid lease termination costs of approximately $0.1 million. During the Previous Quarter, we purchased 20 of our leased drilling rigs for approximately $76.9 million and paid lease termination costs of approximately $8.4 million.

We 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 $0.2 million and $0.3 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 $17.6 million and $14.7 million, respectively, related to borrowings under our Existing Credit Facility, 2019 Notes, 2022 Notes, Term Loan and New Credit Facility.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $4.5 million and $0.9 million for the Current Quarter and Previous Quarter, respectively, which was a result of our investment in 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 Income. Other income was $0.4 million and $0.4 million for the Current Quarter and Previous Quarter, respectively.

Income Tax Expense (Benefit) . We recorded income tax expense (benefit) of $14.0 million and ($10.7) million for the Current Quarter and Previous Quarter, respectively. The $24.7 million increase in income tax expense recorded for the Current

Quarter was primarily the result of an increase in net income before taxes of $65.0 million from the Previous Quarter to the Current Quarter. Our effective income tax rate for the Current Quarter and Previous Quarter was 39% and 37%, respectively. Our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences.

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

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



	Three Months Ended June 30,
	2014			2013
	(in thousands)
Revenues:
Revenues from Chesapeake	$	447,085		$	544,301
Revenues from other third parties	102,381			38,763
Total Revenues	549,466			583,064
Operating Expenses:
Operating costs	406,586			457,383
Depreciation and amortization	71,829			72,490
General and administrative, including expenses from Chesapeake	19,368			20,922
Gains on sales of property and equipment	(8,964		)	(1,746		)
Impairments and other	3,172			6,718
Total Operating Expenses	491,991			555,767
Operating Income	57,475			27,297
Other Income (Expense):
Interest expense	(17,615		)	(14,138		)
Loss and impairment from equity investees	(4,500		)	(1,053		)
Other income (expense)	386			(63		)
Total Other Expense	(21,729		)	(15,254		)
Income Before Income Taxes	35,746			12,043
Income Tax Expense	14,036			4,867
Net Income	$	21,710		$	7,176

Revenues. For the Current Quarter and Prior Quarter, revenues were $549.5 million and $583.1 million, respectively. The $33.6 million decrease was primarily due to an overall reduction in drilling activity by Chesapeake and secondarily due to pricing pressure for certain segments, partially offset by an increase in revenues from non-Chesapeake customers. 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 for the Current Quarter and Prior Quarter are detailed below:



	Three Months Ended June 30,
	2014		2013
	(in thousands)
Drilling	$	189,177	$	188,862
Hydraulic fracturing	226,112		250,345
Oilfield rentals	38,977		41,776
Oilfield trucking	55,451		62,709
Other operations	39,749		39,372
Total	$	549,466	$	583,064

Operating Costs. Operating costs for the Current Quarter and Prior Quarter were $406.6 million and $457.4 million, respectively. The decrease in operating costs was due primarily to an overall reduction in drilling and completion activity by our customers and a decrease in rig rent expense. As a percentage of revenues, operating costs were 74% and 78% for the Current Quarter and Prior Quarter, respectively. The decrease in operating costs as a percentage of revenue was primarily attributable to higher utilization rates and lower rig rent expense for our drilling segment. Our operating costs for the Current Quarter and Prior Quarter are detailed below:



	Three Months Ended June 30,
	2014		2013
	(in thousands)
Drilling	$	118,354	$	146,634
Hydraulic fracturing	179,283		199,539
Oilfield rentals	24,534		26,843
Oilfield trucking	51,451		51,045
Other operations	32,964		33,322
Total	$	406,586	$	457,383

Drilling



	Three Months Ended June 30,
	2014			2013
	(in thousands, except average rigs, utilization, revenue day and per revenue day amounts)
Revenues	$	189,177		$	188,862
Operating costs^(a)	118,354			146,634
Gross margin	$	70,823		$	42,228
Revenue days^(b)	7,396			7,142
Average revenue per revenue day^(b)	$	23,219		$	23,506
Average operating costs per revenue day^{(a) (b)}	$	14,031		$	17,746
Average margin per revenue day^(b)	$	9,188		$	5,760
Average rigs operating	81			81
Utilization	99		%	97		%

Adjusted operating costs:
Operating costs^(b)	$	103,776		$	126,743
Add:
One-time credit to stock compensation expense	4,318			—
Less:
Rig rent expense	6,016			22,570
Adjusted operating costs^(b)	$	102,078		$	104,173
Adjusted average operating costs per day^(b)	$	13,802		$	14,586


(a)	Our operating costs and average operating costs per revenue day include $6.0 million and $22.6 million of rig rent expense associated with our lease of drilling rigs for the Current Quarter and Prior Quarter, respectively.


(b)	These metrics exclude results from our drilling-related services, including directional drilling, mudlogging and geosteering.

Drilling revenues for the Current Quarter increased $0.3 million from the Prior Quarter. This increase was primarily due to a 4% increase in revenue days, partially offset by a 1% reduction in average revenue per revenue day. Revenues from non-Chesapeake customers increased $29.1 million from the Prior Quarter to the Current Quarter to 31% of total segment revenues compared to 16% for the Prior Quarter.

Drilling operating costs for the Current Quarter decreased $28.2 million, or 19%, from the Prior Quarter. As a percentage of drilling revenues, drilling operating costs were 63% and 78% for the Current Quarter and the Prior Quarter, respectively. We also experienced a 5% decrease in Adjusted average operating costs per revenue day from the Prior Quarter to the Current Quarter, which was primarily due to a reduction in labor-related costs. As a percentage of drilling revenues, labor-related costs were 38% and 41% for the Current Quarter and Prior Quarter, respectively.



	Three Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	2,014	$	2,355
Operating costs	1,208		1,335
Gross margin	$	806	$	1,020

Hydraulic Fracturing



	Three Months Ended June 30,
	2014		2013
	(in thousands, except stages, average fleets and per stage amounts)
Revenues	$	226,112	$	250,345
Operating costs	179,283		199,539
Gross margin	$	46,829	$	50,806
Stages completed	2,054		1,873
Average revenue per stage	$	110,084	$	133,660
Average operating costs per stage	$	87,285	$	106,534
Average margin per stage	$	22,799	$	27,126
Average fleets operating	9		8

Hydraulic fracturing revenues for the Current Quarter decreased $24.2 million, or 10%, from the Prior Quarter. This decrease was due to a 18% decrease in revenue per stage from the Prior Quarter to the Current Quarter, partially offset by a 10% increase in completed stages 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 $4.5 million from the Prior Quarter to the Current Quarter to 2% of total segment revenues compared to 0% for the Prior Quarter.

Hydraulic fracturing operating costs for the Current Quarter decreased $20.2 million, or 10% from the Prior Quarter, primarily due to a 22% decrease in supplies expense, partially offset by an 10% increase in completed stages. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs were 79% and 80% for Current Quarter and Prior Quarter, respectively.

Oilfield Rental



	Three Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	38,977	$	41,776
Operating costs	24,534		26,843
Gross margin	$	14,443	$	14,933

Oilfield rental revenues for the Current Quarter decreased $2.8 million, or 7%, from the Prior Quarter. The decrease was primarily due to lower utilization as a result of Chesapeake’s reduction in drilling and completion activity and market pricing pressure for certain of our equipment. The utilization of our oilfield rental equipment has historically correlated with the level of Chesapeake’s drilling and completion activity. Revenues from non-Chesapeake customers increased $5.2 million from the Prior Quarter to the Current Quarter to 16% of total segment revenues compared to 3% for the Prior Quarter.

Oilfield rental operating costs for the Current Quarter decreased $2.3 million, or 9%, from the Prior Quarter. The decrease was primarily due to an overall reduction in drilling and completion activity by Chesapeake which resulted in lower labor-

related costs and repairs and maintenance expense. As a percentage of oilfield rental revenues, oilfield rental operating costs were 63% and 64% for the Current Quarter and Prior Quarter, respectively.

Oilfield Trucking



	Three Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	55,451	$	62,709
Operating costs	51,451		51,045
Gross margin	$	4,000	$	11,664

Oilfield trucking revenues for the Current Quarter decreased $7.3 million, or 12%, from the Prior Quarter. The decrease was primarily due to a reduction in revenues from our fluid hauling services of $6.3 million from the Prior Quarter to the Current Quarter. Revenues from non-Chesapeake customers increased $8.3 million from the Prior Quarter to the Current Quarter to 28% of total segment revenues compared to 11% for the Prior Quarter.

Oilfield trucking operating costs for the Current Quarter increased $0.4 million, or 1%, from the Prior Quarter. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 93% and 81% for the Current Quarter and Prior Quarter, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to a decrease in utilization of our assets which resulted in fixed costs being spread over a smaller revenue base.



	Three Months Ended June 30,
	2014			2013
	(in thousands)
Revenues	$	10,530		$	16,665
Operating costs	14,495			11,334
Gross margin	$	(3,965	)	$	5,331

Other Operations



	Three Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	39,749	$	39,372
Operating costs	32,964		33,322
Gross margin	$	6,785	$	6,050

For the Current Quarter, operating costs for our other operations decreased $0.3 million, or 1%, from the Prior Quarter. As a percentage of compression manufacturing revenues, compression manufacturing costs were 82% and 84% in the Current Quarter and Prior Quarter, respectively.



	Three Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	39,230	$	38,937
Operating costs	32,259		32,737
Gross margin	$	6,971	$	6,200

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Prior Quarter was $71.8 million and $72.5 million, respectively. As a percentage of revenues, depreciation and amortization expense was 13% and 12% for the Current Quarter and Prior Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Prior Quarter were $19.4 million and $20.9 million, respectively. Prior to the spin-off, we were allocated corporate overhead from Chesapeake which covers costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. The administrative expense allocation is determined by multiplying revenues by a percentage determined by Chesapeake based on the estimated costs incurred on our behalf. These charges from Chesapeake were $14.0 million and $15.7 million for the Current Quarter and Prior Quarter, respectively. We had a one-time credit to stock compensation expense of $3.2 million during the Current Quarter related to unvested restricted stock cancelled as part of the spin-off. As a percentage of revenues, general and administrative expenses were 4% for both the Current Quarter and Prior Quarter.

Gains on Sales of Property and Equipment. During the Current Quarter, we sold 14 drilling rigs and ancillary equipment that were not being utilized in our business as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers. During the Prior Quarter, we sold ancillary equipment that was not being utilized in our business. We recorded gains on sales of property and equipment of approximately $9.0 million and $1.7 million related to these asset sales during the Current Quarter and Prior Quarter, respectively.

Impairments and Other. During the Prior Quarter, we recognized $3.4 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 Current 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 Current Quarter related to these drilling rigs. During the Current Quarter, we purchased 11 of our leased drilling rigs for approximately $54.1 million and paid lease termination costs of approximately $0.1 million. During the Prior Quarter, we purchased two of our 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 and Prior Quarter that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $0.2 million and $3.2 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 $17.6 million and $14.1 million, respectively, related to borrowings under our Existing Credit Facility, 2019 Notes, 2022 Notes, Term Loan and Credit Facility.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $4.5 million and $1.1 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.

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

Income Tax Expense. We recorded income tax expense of $14.0 million and $4.9 million for the Current Quarter and Prior Quarter, respectively. The $9.1 million increase in income tax expense recorded for the Current Quarter was primarily the result of an increase in net income before taxes of $23.7 million from the Prior Quarter to the Current Quarter. Our effective

income tax rate for the Current Quarter and Prior Quarter was 39% and 40%, respectively. Our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences.

Results of Operations—Six Months Ended June 30, 2014 vs. June 30, 2013

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



	Six Months Ended June 30,
	2014			2013
	(in thousands)
Revenues:
Revenues from Chesapeake	$	877,922		$	1,057,736
Revenues from other third parties	181,254			69,215
Total Revenues	1,059,176			1,126,951
Operating Expenses:
Operating costs	816,174			872,433
Depreciation and amortization	144,294			142,601
General and administrative, including expenses from Chesapeake	40,254			41,413
Gains on sales of property and equipment	(7,986		)	(1,371		)
Impairments and other	22,980			6,741
Total Operating Expenses	1,015,716			1,061,817
Operating Income	43,460			65,134
Other Income (Expense):
Interest expense	(32,307		)	(28,149		)
Loss and impairment from equity investees	(5,417		)	(1,173		)
Other income	757			461
Total Other Expense	(36,967		)	(28,861		)
Income Before Income Taxes	6,493			36,273
Income Tax Expense	3,338			14,866
Net Income	$	3,155		$	21,407

Revenues. For the Current Period and Prior Period, revenues were $1.059 billion and $1.127 billion, respectively. The $67.8 million decrease was primarily due to an overall reduction in drilling activity by Chesapeake and secondarily due to pricing pressure for certain segments, partially offset by an increase in revenues from non-Chesapeake customers. 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 for the Current Period and Prior Period are detailed below:



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Drilling	$	369,610	$	374,235
Hydraulic fracturing	427,732		465,291
Oilfield rentals	74,919		89,290
Oilfield trucking	111,646		124,120
Other operations	75,269		74,015
Total	$	1,059,176	$	1,126,951

Operating Costs. Operating costs for the Current Period and Prior Period were $816.2 million and $872.4 million, respectively. The decrease in operating costs was due primarily to an overall reduction in drilling and completion activity by Chesapeake and a decrease in rig rent expense. As a percentage of revenues, operating costs were 77% and 77% for the Current Period and Prior Period, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to lower utilization rates and pricing pressure for certain segments, which compressed margins. Our operating costs for the Current Period and Prior Period are detailed below:



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Drilling	$	242,814	$	285,371
Hydraulic fracturing	356,295		367,586
Oilfield rentals	50,483		54,460
Oilfield trucking	105,065		102,147
Other operations	61,518		62,869
Total	$	816,175	$	872,433

Drilling



	Six Months Ended June 30,
	2014			2013
	(in thousands, except average rigs, utilization, revenue day and per revenue day amounts)
Revenues	$	369,610		$	374,235
Operating costs^(a)	242,814			285,371
Gross margin	$	126,796		$	88,864
Revenue days^(b)	14,432			13,961
Average revenue per revenue day^(b)	$	23,318		$	23,748
Average operating costs per revenue day^{(a) (b)}	$	14,791		$	17,758
Average margin per revenue day^(b)	$	8,527		$	5,990
Average rigs operating	81			79
Utilization	98		%	96		%

Adjusted operating costs:
Operating costs^(b)	$	213,465		$	247,919
Add:
One-time credit to stock compensation expense	4,318			—
Less:
Rig rent expense	15,075			45,551
Adjusted operating costs^(b)	$	202,708		$	202,368
Adjusted average operating costs per day^(b)	$	14,046		$	14,495


(a)	Our operating costs and average operating costs per revenue day include $15.1 million and $45.6 million of rig rent expense associated with our lease of drilling rigs for the Current Period and Prior Period, respectively.


(b)	These metrics exclude results from our drilling-related services, including directional drilling, mudlogging and geosteering.

Drilling revenues for the Current Period decreased $4.6 million, or 1%, from the Prior Period. This decrease was primarily due to a 2% reduction in average revenue per revenue day, partially offset by a 3% increase in revenue days.

Revenues from non-Chesapeake customers increased $59.2 million from the Prior Period to the Current Period to 30% of total segment revenues compared to 14% for the Prior Period.

Drilling operating costs for the Current Period decreased $42.6 million, or 15%, from the Prior Period. As a percentage of drilling revenues, drilling operating costs were 67% and 76% for the Current Period and the Prior Period, respectively. We also experienced a 3% decrease in Adjusted average operating costs per revenue day from the Prior Quarter to the Current Quarter, which was primarily due to a reduction in labor-related costs. As a percentage of drilling revenues, labor-related costs were 39% and 41% 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 have historically been included in our drilling segment. The geosteering revenues and operating costs are detailed below:



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	3,940	$	4,468
Operating costs	2,895		2,508
Gross margin	$	1,045	$	1,960

Hydraulic Fracturing



	Six Months Ended June 30,
	2014		2013
	(in thousands, except stages, average fleets and per stage amounts)
Revenues	$	427,732	$	465,291
Operating costs	356,295		367,586
Gross margin	$	71,437	$	97,705
Stages completed	3,776		3,372
Average revenue per stage	$	113,276	$	137,987
Average operating costs per stage	$	94,358	$	109,011
Average margin per stage	$	18,918	$	28,976
Average fleets operating	9		8

Hydraulic fracturing revenues for the Current Period decreased $37.6 million, or 8%, from the Prior Period. This decrease was due to an 18% decrease in revenue per stage from the Prior Period to the Current Period, partially offset by a 12% increase in completed stages from the Prior Period to the Current Period. The decrease in revenue per stage was primarily due to industry wide pricing pressure. Revenues from non-Chesapeake customers increased $4.6 million from the Prior Period to the Current Period to 1% of total segment revenues compared to 0% for the Prior Period.

Hydraulic fracturing operating costs for the Current Period decreased $11.3 million or 3% from the Prior Period, primarily due to a 15% decrease in product costs, partially offset by a 12% increase in the number of completed stages. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs increased from 79% in the Prior Period to 83% in the Current Period. This increase was primarily attributable to pricing pressure for our hydraulic fracturing services, partially offset by a decrease in product costs. Revenue per stage decreased 18% from the Prior Period to the Current Period. As a percentage of hydraulic fracturing revenues, product costs were 46% in the Current Period and 50% in the Prior Period.

Oilfield Rental



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	74,919	$	89,290
Operating costs	50,483		54,460
Gross margin	$	24,436	$	34,830

Oilfield rental revenues for the Current Period decreased $14.4 million or 16%, from the Prior Period. The decrease was primarily due to lower utilization as a result of Chesapeake’s reduction in drilling and completion activity and market pricing pressure for certain of our equipment. The utilization of our oilfield rental equipment has historically correlated with the level of Chesapeake’s drilling and completion activity. Revenues from non-Chesapeake customers increased $7.5 million from the Prior Period to the Current Period to 13% of total segment revenues compared to 3% for the Prior Period.

Oilfield rental operating costs for the Current Period decreased $4.0 million or 7%, from the Prior Period. The decrease was primarily due to an overall reduction in drilling and completion activity by Chesapeake which resulted in lower repairs and maintenance expense and freight expense. As a percentage of oilfield rental revenues, oilfield rental operating costs were 67% and 61% for the Current Period and Prior Period, respectively. The increase in oilfield rental operating costs as a percentage of oilfield rental revenues from the Prior Period to the Current Period 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 31% and 27% in the Current Period and Prior Period, respectively.

Oilfield Trucking



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	111,646	$	124,120
Operating costs	105,065		102,147
Gross margin	$	6,581	$	21,973

Oilfield trucking revenues for the Current Period decreased $12.5 million or 10%, from the Prior Period. The decrease was primarily due to lower utilization as a result of Chesapeake’s reduction in drilling and completion activity. Revenues from non-Chesapeake customers increased $14.5 million from the Prior Period to the Current Period to 25% of total segment revenues compared to 10% for the Prior Period.

Oilfield trucking operating costs for the Current Period increased $2.9 million or 3%, from the Prior Period. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 94% and 82% 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 from the Prior Period to the Current Period, 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 45% and 39% for the Current Period and Prior Period, respectively.



	Six Months Ended June 30,
	2014			2013
	(in thousands)
Revenues	$	23,829		$	31,402
Operating costs	27,254			20,599
Gross margin	$	(3,425	)	$	10,803

Other Operations



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	75,269	$	74,015
Operating costs	61,518		62,869
Gross margin	$	13,751	$	11,146

Our other operations consist primarily of our compression unit manufacturing business and corporate functions. For the Current Period, revenues from our other operations increased $1.3 million, or 2%, from the Prior Period.

For the Current Period, operating costs for our other operations decreased $1.4 million, or 2%, from the Prior Period. As a percentage of compression manufacturing revenues, compression manufacturing costs were 81% and 84% in the Current Period and Prior Period, respectively.



	Six Months Ended June 30,
	2014		2013
	(in thousands)
Revenues	$	74,650	$	73,421
Operating costs	60,616		61,970
Gross margin	$	14,034	$	11,451

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Period and Prior Period was $144.3 million and $142.6 million, respectively. The increase reflects the additional investments in our asset base as a result of capital expenditures, primarily to purchase leased drilling rigs. 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 $40.3 million and $41.4 million respectively. Prior to the spin-off, we were allocated corporate overhead from Chesapeake which covers costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. The administrative expense allocation is determined by multiplying revenues by a percentage determined by Chesapeake based on the estimated costs incurred on our behalf. These charges from Chesapeake were $26.8 million and $28.7 million for the Current Period and Prior Period, respectively. We had a one-time credit to stock compensation expense of $3.2 million during the Current Period related to unvested restricted stock cancelled as part of the spin-off. As a percentage of revenues, general and administrative expenses were 4% for both the Current Period and Prior Period.

Gains on Sales of Property and Equipment. During the Current Period, we sold 15 drilling rigs and ancillary equipment that were not being utilized in our business as well as our crude hauling fleet, which included 124 fluid handling trucks and 122 trailers. During the Prior Period, we sold eight drilling rigs and ancillary equipment that were not being utilized in our business. We recorded gains on sales of property and equipment of approximately $8.0 million and $1.4 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 $5.7 million and $3.4 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 also identified certain drilling rigs during the Current 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 during the Current Period related to these drilling rigs. During the Current Period, we purchased 31 of our leased drilling rigs for approximately $131.0 million and paid lease termination costs of approximately $8.4 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 $0.5 million and $3.2 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 $32.3 million and $28.1 million respectively, related to borrowings under our Existing Credit Facility, 2019 Notes, 2022 Notes, Term Loan and New Credit Facility.

Loss and Impairment from Equity Investees. Loss and impairment from equity investees was $5.4 million and $1.2 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.

Other Income. Other income was $0.8 million and $0.5 million for the Current Period and Prior Period, respectively.

Income Tax Expense. We recorded income tax expense of $3.3 million and $14.9 million for the Current Period and Prior Period, respectively. The $11.6 million decrease in income tax expense recorded for the Current Period was primarily the result of a decrease in net income before taxes of $29.8 million from the Prior Period to the Current Period. Our effective income tax rate for the Current Period and Prior Period was 51% and 41% respectively. The increase in our effective tax rate from the Prior Period to the Current Period 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 Period compared to the Prior 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 subsequent 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 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 will pay Chesapeake fees, a portion of which will be 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 will be employees and/or independent contractors of Chesapeake and will not be 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 July 1, 2014 was approximately $1.5 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 July 1, 2014 was approximately $1.0 billion 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 August 1, 2014, we had purchased all of our material active rigs that were subject to these lease arrangements. The remaining drilling rig lease arrangements relate to 12 Tier 3 idle drilling rigs (10 idle and two active) that are not part of our long-term portfolio strategy. The leases for these rigs will expire by the end of 2014, after which we expect to return the rigs to the owner.

Off-Balance Sheet Arrangements

As of June 30, 2014, we leased 14 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 June 30, 2014 under our operating leases are presented below:



	June 30, 2014
	Rigs		Rail Cars		Total
	(in thousands)
2014	$	8,153	$	3,091	$	11,244
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	$	8,153	$	26,272	$	34,425

Other Commitments

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 83% and 94% 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	$	—	—		$	2,000	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	%	404,400		3.76	%
Total	$	1,150,000			$	422,400
Fair value	$	1,204,375			$	414,477

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 June 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 June 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 5.	Other Information

On August 1, 2014, the Board of Directors of the Company approved the compensation arrangements described below for executive officers and non-employee directors in accordance with recommendations from the Compensation Committee of the Board, which was assisted by third-party compensation consultant Pearl Meyer & Partners.

Employment Agreements

On August 4, 2014, the Company entered into employment agreements (the “Employment Agreements”) with the following executive officers of the Company (collectively, the “Officers”):



Jerry L. Winchester		President and Chief Executive Officer
Cary D. Baetz		Chief Financial Officer and Treasurer
Karl Blanchard		Chief Operating Officer
James Minmier		President - Nomac Drilling, L.L.C.
William Stanger		President - Performance Technologies, L.L.C.

Each of the employment agreements is for an initial term of three years commencing July 1, 2014 and ending July 1, 2017, subject to extension by mutual agreement and an automatic extension in the event a change in control of the Company to the later of the last day of the then current employment term or 24 months following the change in control. Under the terms of the employment agreements, each Officer will receive an annual base salary in the amount set forth below, subject to any adjustments the Board may deem appropriate from time to time.



Officer	Annual Salary
Jerry L. Winchester	$	890,000
Cary D. Baetz	$	475,000
Karl Blanchard	$	600,000
James Minmier	$	450,000
William Stanger	$	400,000

In addition, the Officers will be eligible to receive an annual cash bonus and grants of long-term incentives including equity or equity based awards from the Company’s various equity compensation plans, as determined by the Compensation Committee of the Board and subject to such performance criteria as they may establish, and each is entitled to participate in all

of the Company’s employee benefit plans and programs and to receive any fringe benefits or perquisites that the Company may provide to similarly situated executives. Mr. Blanchard’s employment agreement provides that, among other things, he will receive a minimum cash bonus payment and a minimum value of restricted stock awards, each of which escalate annually, which mirror provisions in the employment agreement the Company previously entered into with Mr. Blanchard.

If an Officer’s employment is terminated for any reason, the Officer will be entitled to any accrued and unpaid portion of the Officer’s base salary, bonus and benefits. In the event of the Officer’s termination of employment due to death, all of his outstanding equity awards will be fully vested. In the event of the Officer’s termination of employment due to disability, termination by the Company without cause (as defined in the employment agreements), or termination by the Officer for good reason (as defined in the agreements) and subject to compliance with restrictive covenants (including prohibitions on competition, soliciting customers of the Company, soliciting of the Company’s employees and disclosure of confidential information) and the execution of a release in favor of the Company, all of his equity awards will become fully vested and he will receive cash severance benefits, outplacement services in an amount not to exceed $25,000 for six months after termination and subsidized COBRA benefits for up to 24 months following termination. The amount of the cash severance payable to the individual Officers is as follows: an amount for Messrs. Winchester, Baetz and Blanchard that is equal to two times his base salary as then in effect, and in the case of Messrs. Minmier and Stanger, 1.75 times his base salary as then in effect, and, for each Officer, one times the greater of his annual bonus for the prior year or his target bonus for the current year; in the event of termination due to disability, the amount of the cash severance for each Officer is one times his base salary as then in effect. The employment agreements also provide that if an Officer’s employment terminates due to a qualified retirement on or after the third anniversary of the effective date of the employment agreement, he will be eligible for continued post-retirement vesting of unvested equity awards.

If an Officer’s employment is terminated by the Company without cause or by the Officer for good reason within a twenty-four month year period following a “change in control” (as defined in the employment agreement), then, subject to compliance with the restrictive covenants and the execution of a release in favor of the Company, in lieu of the base salary multiple stated above, each Officer will instead receive three times that Officer’s respective base salary, together with the other payments and benefits stated above.

The foregoing descriptions are not complete and are qualified in their entirety by reference to the full text of each Officer’s employment agreement, copies of which are attached hereto as Exhibits 10.8 through 10.12.

Officer Incentive Awards

On August 1, 2014 the Company’s Board of Directors approved initial incentive compensation awards for Messrs. Winchester, Baetz, Minmier and Stanger consisting of restricted shares of the Company’s common stock pursuant to the Company’s 2014 Incentive Plan (the “Plan”). The restricted stock awards will vest in equal annual installments on a four year schedule, and so long as such officer is employed by the Company or its affiliates at such time, unless vesting is otherwise accelerated or continues pursuant to the terms of the employment agreements or the Plan. The awards vesting over four years were granted to eligible executives and employees who contributed to the successful spin off of the Company from Chesapeake Energy Corp. on June 30, 2014.

The following table sets forth the number of shares of restricted stock vesting over four years granted to such officers:



		Awards Vesting Over Four Years (shares)
Jerry L. Winchester		469,324
Cary D. Baetz		328,527
James Minmier		281,595
William Stanger		234,662

On August 1, 2014, the Board also approved initial restricted stock awards to Mr. Blanchard pursuant to the Plan and Mr. Blanchard's employment agreement in an amount equal to $1.6 million. The number of shares of restricted stock issued to Mr. Blanchard will be determined by dividing such amount by the closing price of the Company's common stock on August 6, 2014. These restricted stock awards will vest in equal annual installments on a three year schedule, and so long as Mr. Blanchard is employed by the Company or its affiliates at such time unless vesting is otherwise accelerated or continues pursuant to the terms of his employment agreement or the Plan.

Non-Employee Director Compensation and Incentive Awards

On August 1, 2014, the Board approved a compensation program for non-employee directors consisting of the following: cash compensation of $100,000 annually, plus an additional $50,000 annually for the non-executive Chairman of the Board, $25,000 annually for the Chairman of the Audit Committee and $15,000 annually for the Chairman of the Compensation Committee and the Nominating and Governance Committee. The foregoing will be paid in equal quarterly installments. In addition, each of the Company’s non-employee directors will receive restricted stock awards pursuant to the Plan in an amount equal to $100,000. The number of shares of restricted stock to be issued will be determined by dividing such dollar amount by the closing stock price of the Company’s common stock on August 6, 2014 and will vest on the earlier of the first anniversary of the grant date or the day prior to the next regularly scheduled meeting of the Company’s stockholders occurring after the date of grant.



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
4.1	Form of Common Stock Certificate.	10	001-36354	4.1	6/13/2014
4.2	Supplemental Indenture, dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., Seventy Seven Operating LLC and The Bank of New York Mellon Trust Company N.A.	8-K	001-36354	4.1	7/1/2014
4.3	Indenture dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Wells Fargo Bank, National Association.	8-K	001-36354	4.2	7/1/2014
4.4	Form of 6.5% Senior Note due 2022 (included in Exhibit 4.3).	8-K	001-36354	4.2	7/1/2014
4.5	Term Loan Credit Agreement, dated June 25, 2014, by and among Chesapeake Oilfield Operating, L.L.C., Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders named therein.	8-K	001-36354	10.5	7/1/2014
4.6	ABL Credit Agreement, dated June 25, 2014, by and among Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, Wells Fargo Bank, National Association and Bank of America, N.A., as joint lead arrangers and joint book runners, Bank of America, N.A., as syndication agent, Credit Agricole Corporate and Investment Bank and SunTrust Bank, as co-documentation agents, and the lenders named therein.	8-K	001-36354	10.6	7/1/2014
10.1	Tax Sharing Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.1	7/1/2014
10.2	Employee Matters Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.2	7/1/2014

10.3

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

8-K

001-36354

10.3

7/1/2014

10.4

Services Agreement (hydraulic fracturing), dated June 25, 2014, by and between Performance Technologies, L.L.C. and Chesapeake Operating, Inc.

8-K

001-36354

10.4

7/1/2014

10.5

Registration Rights Agreement, dated as of June 2, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Merrill Lynch, Pierce Fenner & Smith Incorporated.

8-K

001-36354

10.7

7/1/2014

10.6

Seventy Seven Energy Inc. 2014 Incentive Plan.

8-K

001-36354

10.8

7/1/2014

10.7

Letter Agreement, dated June 27, 2014, to the Master Services Agreement, dated October 25, 2011, between Chesapeake Operating, Inc. and Chesapeake Oilfield Operating, L.L.C.

10.8

Employment Agreement with Jerry L. Winchester dated August 2014.

10.9

Employment Agreement with Cary D.Baetz dated August 2014.

10.10

Employment Agreement with Karl Blanchard dated August 2014.

10.11

Employment Agreement with James Minmier dated August 2014.

10.12

Employment Agreement with William Stanger dated August 2014.

10.13

Form of Restricted Stock Unit Replacement Agreement under 2014 Incentive Plan.

10.14

Form of 2013 Restricted Stock Replacement Agreement under 2014 Incentive Plan.

10.15

Form of 2003 Restricted Stock Replacement Agreement under 2014 Incentive Plan.

10.16

Form of Director Restricted Stock Agreement under 2014 Incentive Plan.

10.17

Form of Employee Restricted Stock Agreement under 2014 Incentive Plan.

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.



August 4, 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
4.1	Form of Common Stock Certificate.	10	001-36354	4.1	6/13/2014
4.2	Supplemental Indenture, dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., Seventy Seven Operating LLC and The Bank of New York Mellon Trust Company N.A.	8-K	001-36354	4.1	7/1/2014
4.3	Indenture dated June 26, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Wells Fargo Bank, National Association.	8-K	001-36354	4.2	7/1/2014
4.4	Form of 6.5% Senior Note due 2022 (included in Exhibit 4.3).	8-K	001-36354	4.2	7/1/2014
4.5	Term Loan Credit Agreement, dated June 25, 2014, by and among Chesapeake Oilfield Operating, L.L.C., Seventy Seven Operating LLC, as borrower, Bank of America, N.A., as administrative agent and the lenders named therein.	8-K	001-36354	10.5	7/1/2014
4.6	ABL Credit Agreement, dated June 25, 2014, by and among Nomac Drilling, L.L.C., Performance Technologies, L.L.C., Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., as borrowers, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, Wells Fargo Bank, National Association and Bank of America, N.A., as joint lead arrangers and joint book runners, Bank of America, N.A., as syndication agent, Credit Agricole Corporate and Investment Bank and SunTrust Bank, as co-documentation agents, and the lenders named therein.	8-K	001-36354	10.6	7/1/2014
10.1	Tax Sharing Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.1	7/1/2014
10.2	Employee Matters Agreement, dated June 25, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Chesapeake Energy Corporation.	8-K	001-36354	10.2	7/1/2014

10.3

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

8-K

001-36354

10.3

7/1/2014

10.4

Services Agreement (hydraulic fracturing), dated June 25, 2014, by and between Performance Technologies, L.L.C. and Chesapeake Operating, Inc.

8-K

001-36354

10.4

7/1/2014

10.5

Registration Rights Agreement, dated as of June 2, 2014, by and between Chesapeake Oilfield Operating, L.L.C. and Merrill Lynch, Pierce Fenner & Smith Incorporated.

8-K

001-36354

10.7

7/1/2014

10.6

Seventy Seven Energy Inc. 2014 Incentive Plan.

8-K

001-36354

10.8

7/1/2014

10.7

Letter Agreement, dated June 27, 2014, to the Master Services Agreement, dated October 25, 2011, between Chesapeake Operating, Inc. and Chesapeake Oilfield Operating, L.L.C.

10.8

Employment Agreement with Jerry L. Winchester dated August 2014.

10.9

Employment Agreement with Cary D.Baetz dated August 2014.

10.10

Employment Agreement with Karl Blanchard dated August 2014.

10.11

Employment Agreement with James Minmier dated August 2014.

10.12

Employment Agreement with William Stanger dated August 2014.

10.13

Form of Restricted Stock Unit Replacement Agreement under 2014 Incentive Plan.

10.14

Form of 2013 Restricted Stock Replacement Agreement under 2014 Incentive Plan.

10.15

Form of 2003 Restricted Stock Replacement Agreement under 2014 Incentive Plan.

10.16

Form of Director Restricted Stock Agreement under 2014 Incentive Plan.

10.17

Form of Employee Restricted Stock Agreement under 2014 Incentive Plan.

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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