COO-2014.03.31-10Q

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10-Q 1 coo-20140331x10q.htm 10-Q COO-2014.03.31-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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. 333-187766

Chesapeake Oilfield Operating, L.L.C.

(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.)

6100 North Western Avenue Oklahoma City, Oklahoma		73118
(Address of principal executive offices)		(Zip Code)

(405) 848-8000

(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

Chesapeake Oilfield Operating, L.L.C., a wholly-owned subsidiary of Chesapeake Energy Corporation, meets the conditions set forth in General Instructions H(1)(a) and (b) to Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format contemplated by paragraph (b) of General Instruction H(2) of Form 10-Q.

Table of Contents

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	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	33

PART II. OTHER INFORMATION		34
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 6.	Exhibits	34

SIGNATURES		35

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PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements

CHESAPEAKE OILFIELD OPERATING, L.L.C.

Condensed Consolidated Balance Sheets

(unaudited)



	March 31, 2014			December 31, 2013
	(in thousands)
Assets:
Current Assets:
Cash	$	3,291		$	1,678
Accounts receivable, net of allowance of $624 and $524 at March 31, 2014 and December 31, 2013, respectively	68,386			62,959
Affiliate accounts receivable	314,987			312,480
Inventory	47,979			45,035
Deferred income tax asset	4,879			5,318
Prepaid expenses and other	17,063			20,301
Total Current Assets	456,585			447,771
Property and Equipment:
Property and equipment, at cost	2,283,493			2,241,350
Less: accumulated depreciation	(814,548		)	(773,282		)
Property and equipment held for sale, net	58,302			29,408
Total Property and Equipment, Net	1,527,247			1,497,476
Other Assets:
Investments	12,405			13,236
Goodwill	42,447			42,447
Intangible assets, net	6,441			7,429
Deferred financing costs	13,343			14,080
Other long-term assets	4,622			4,454
Total Other Assets	79,258			81,646
Total Assets	$	2,063,090		$	2,026,893
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	28,593		$	30,666
Affiliate accounts payable	43,430			34,200
Other current liabilities	211,728			210,123
Total Current Liabilities	283,751			274,989
Long-Term Liabilities:
Deferred income tax liabilities	133,929			145,747
Senior notes	650,000			650,000
Revolving credit facility	464,300			405,000
Other long-term liabilities	2,475			3,965
Total Long-Term Liabilities	1,250,704			1,204,712
Commitments and Contingencies (Note 5)
Owner’s Equity	528,635			547,192
Total Liabilities and Equity	$	2,063,090		$	2,026,893

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

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

Condensed Consolidated Statements of Operations

(unaudited)



	Three Months Ended March 31,
	2014			2013
	(in thousands)
Revenues:
Revenues from Chesapeake	$	430,835		$	513,434
Revenues from third parties	78,875			30,453
Total Revenues	509,710			543,887
Operating Expenses:
Operating costs	409,589			415,049
Depreciation and amortization	72,465			70,112
General and administrative, including expenses from affiliates (Notes 1 and 10)	20,887			20,491
Losses on sales of property and equipment	977			374
Impairments and other	19,808			24
Total Operating Expenses	523,726			506,050
Operating (Loss) Income	(14,016		)	37,837
Other Income (Expense):
Interest expense	(14,692		)	(14,010		)
Loss from equity investees	(917		)	(119		)
Other income	371			524
Total Other Expense	(15,238		)	(13,605		)
(Loss) Income Before Income Taxes	(29,254		)	24,232
Income Tax (Benefit) Expense	(10,697		)	9,999
Net (Loss) Income	$	(18,557	)	$	14,233

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

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

Condensed Consolidated Statement of Changes in Equity

(unaudited)



	Owner’s Equity
	(in thousands)
Balance at December 31, 2013	$	547,192
Net loss	(18,557		)
Balance at March 31, 2014	$	528,635

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

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

Condensed Consolidated Statements of Cash Flows

(unaudited)



	Three Months Ended March 31,
	2014			2013
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET (LOSS) INCOME	$	(18,557	)	$	14,233
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization	72,465			70,112
Amortization of sale/leaseback gains	(4,214		)	(1,530		)
Amortization of deferred financing costs	737			726
Losses on sales of property and equipment	977			374
Impairments	11,430			24
Loss from equity investees	917			119
Deferred income tax (benefit) expense	(11,030		)	9,783
Other	229			266
Changes in operating assets and liabilities	1,628			(6,714		)
Net cash provided by operating activities	54,582			87,393
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment	(118,571		)	(92,496		)
Proceeds from sales of assets	6,375			29,357
Other	(73		)	(175		)
Net cash used in investing activities	(112,269		)	(63,314		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to owner	—			(12,961		)
Borrowings from revolving credit facility	281,500			237,300
Payments on revolving credit facility	(222,200		)	(247,900		)
Net cash provided by (used in) financing activities	59,300			(23,561		)
Net increase in cash	1,613			518
Cash, beginning of period	1,678			1,227
Cash, end of period	$	3,291		$	1,745

SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Increase in other current liabilities related to purchases of property and equipment	$	1,446		$	1,008
SUPPLEMENTAL DISCLOSURE OF CASH PAYMENTS:
Interest paid, net of amount capitalized	$	3,184		$	2,678

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

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization, Basis of Presentation and Nature of Business

Organization

Chesapeake Oilfield Operating, L.L.C. (“COO,” “we,” “us,” “our” or “ours”) is an Oklahoma limited liability company formed to own and operate the oilfield services companies of Chesapeake Energy Corporation (“Chesapeake”). We conduct operations through the following wholly-owned and consolidated subsidiaries: Nomac Drilling, L.L.C., Nomac Services, L.L.C., Performance Technologies, L.L.C., PTL Prop Solutions, L.L.C., Western Wisconsin Sand Company, LLC (“WWS”), Thunder Oilfield Services, L.L.C., Hodges Trucking Company, L.L.C., Oilfield Trucking Solutions, L.L.C., Great Plains Oilfield Rental, L.L.C., Keystone Rock & Excavation, L.L.C., Compass Manufacturing, L.L.C. and Mid-States Oilfield Supply LLC.

Basis of Presentation

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

Chesapeake Oilfield Finance, Inc. (“COF”) is a 100% owned finance subsidiary of COO that was incorporated for the purpose of facilitating the offering of COO’s 6.625% Senior Notes due 2019 (see Note 3). COF does not have any operations or revenues.

The accompanying condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States (“GAAP”) for interim financial information. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. Certain footnote disclosures normally included in the financial statements prepared in accordance with GAAP have been appropriately condensed or omitted. Therefore, these interim condensed consolidated financial statements should be read in conjunction with COO’s 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 Securities and Exchange Commission (“SEC”) on March 14, 2014.

Chesapeake provides cash management services to COO through a centralized treasury system. Transactions between COO and Chesapeake have been identified in the financial statements as transactions with affiliates (see Note 10).

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 $12.8 million and $13.0 million for the Current Quarter and Prior Quarter, respectively. Management believes that the allocated charges are representative of the costs and expenses incurred by Chesapeake on behalf of COO. See Note 10 for a discussion of the methods of allocation.

Nature of Business

We provide a wide range of wellsite services and equipment, including drilling, hydraulic fracturing, oilfield rentals, rig relocation, fluid handling and disposal and manufacturing of natural gas compressor packages. We conduct our operations in Kansas, Louisiana, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, Wisconsin and Wyoming. As of March 31, 2014, our primary owned assets consisted of 89 drilling rigs, nine hydraulic fracturing fleets, 260 rig relocation trucks, 67 cranes and forklifts and 247 fluid hauling trucks. Additionally, we had 25 rigs leased under contracts at March 31, 2014 (see Note 5). Our reportable business segments are drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations (see Note 11).

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

Asset Sales

During the Current Quarter, we sold ancillary equipment that was not being utilized in our business for $6.4 million, net of selling expenses. During the Prior Quarter, we sold eight drilling rigs and ancillary equipment that were not being utilized in our business for $29.4 million, net of selling expenses. We recorded losses on sales of property and equipment of approximately $1.0 million and $0.4 million related to these asset sales during the Current Quarter and Prior Quarter, respectively.

Assets Held for Sale and Impairments and Other

A summary of our impairments and other is as follows:



	Three Months Ended March 31,
	2014		2013
	(in thousands)
Drilling rigs held for sale	$	5,714	$	—
Drilling rigs held for use	5,426		—
Lease termination costs	8,379		—
Other	289		24
Total impairments and other	$	19,808	$	24

During the Current 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 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 $40.4 million and $29.4 million as of March 31, 2014 and December 31, 2013, respectively, related to drilling rigs and spare equipment. These assets are included in our drilling segment. The assets classified as held for sale as of December 31, 2013 were still held for sale at March 31, 2014.

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 $5.4 million during the Current Quarter 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 Quarter, we also 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 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 $0.3 million during the Current Quarter 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.

During the Current Quarter, Chesapeake determined it would sell our crude hauling fleet, which includes 94 fluid handling trucks and 121 trailers. 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. We did not recognize an impairment for these assets during the Current Quarter due to the expected sales price, less costs to sell, being greater than the carrying amount of the assets. Included in property and equipment held for sale on our consolidated balance sheet was $17.9 million as of March 31, 2014 related to the crude hauling assets. These assets are included in our oilfield trucking segment.

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 additional reduction in capital expenditures by Chesapeake or our third-party 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

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

recoverable. As we apply available cash from future asset sales and operations towards reducing our financial leverage, we may incur various cash and noncash charges, including impairments of fixed assets or lease termination costs.

3. Debt

2019 Senior Notes

In October 2011, we issued $650.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 (the “2019 Senior Notes”) in a private placement. We incurred $14.8 million in financing costs related to the 2019 Senior Notes issuance which have been deferred and are being amortized over the life of the 2019 Senior Notes. We used the net proceeds of $637.0 million from the 2019 Senior Notes issuance to pay down a portion of our affiliate debt with Chesapeake. 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 COF, 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 (the “Indenture”), 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 COO or any of its guarantor subsidiaries may have from time to time with an outstanding principal amount of $50.0 million or more. If the 2019 Senior Notes achieve an investment grade rating from either Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Rating Services (“S&P”), our obligation to comply with certain of these covenants will be suspended, and if the 2019 Senior Notes achieve an investment grade rating from both Moody’s and S&P, then such covenants will terminate.

Revolving Credit Facility

In November 2011, we entered into a five-year senior secured revolving bank credit facility (the “Credit Facility”) with total commitments of $500.0 million. We incurred $5.4 million in financing costs related to entering into the Credit Facility which have been deferred and are being amortized over the life of the Credit Facility. The borrowing capacity of the Credit Facility may be increased to $900.0 million at our option, subject to compliance with the restrictive covenants in the Credit Facility and in the Indenture governing our 2019 Senior Notes, as well as lender approval. The maximum amount that we may borrow under the Credit Facility may be subject to limitations due to certain covenants contained in the Credit Facility. As of March 31, 2014, the Credit Facility was not subject to any such limitations and had availability of approximately $35.7 million. Borrowings under the Credit Facility are secured by liens on our equity interests and the equity interests of our current and future guarantor subsidiaries and all of our guarantor subsidiaries’ assets, including real and personal property, and bear interest at our option at either (i) the greater of the reference rate of Bank of America, N.A., the federal funds effective rate plus 0.50%, and one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% per annum, according to our leverage ratio, or (ii) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

annum, according to our leverage ratio. The unused portion of the Credit Facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum, according to our leverage ratio. We recorded commitment fee expense of $0.1 million and $0.1 million for the Current Quarter and Prior Quarter, respectively. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals. COO is the borrower under the Credit Facility.

The Credit Facility contains various covenants and restrictive provisions which limit our and our restricted subsidiaries’ ability to enter into asset sales, incur additional indebtedness, make investments or loans and create liens. The Credit Facility requires maintenance of a leverage ratio based on the ratio of lease-adjusted indebtedness to earnings before interest, taxes, depreciation, amortization and rental expense (EBITDAR), a senior secured leverage ratio based on the ratio of secured indebtedness to EBITDA and a fixed charge coverage ratio based on the ratio of EBITDAR to lease-adjusted interest expense, in each case as defined in the Credit Facility agreement. If we, or our restricted subsidiaries, should fail to perform our obligations under the agreement, the Credit Facility could be terminated and any outstanding borrowings under the Credit Facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $50.0 million or more, would constitute an event of default under the Indenture, which could in turn result in the acceleration of our 2019 Senior Notes. The Credit Facility also contains cross default provisions that apply to other indebtedness, including our 2019 Senior Notes, that we and our restricted subsidiaries may have from time to time with an outstanding principal amount in excess of $15.0 million.

No scheduled principal payments are required on any of our long-term debt until November 2016, when our Credit Facility becomes due.

4. Other Current and Long-Term Liabilities

Other current and long-term liabilities as of March 31, 2014 and December 31, 2013 are detailed below:



	March 31, 2014		December 31, 2013
	(in thousands)
Other Current Liabilities:
Operating expenditures	$	107,203	$	101,007
Payroll related	37,445		47,796
Self-insurance reserves	24,637		27,245
Interest	16,633		5,862
Property, sales, use and other taxes	13,043		17,904
Property and equipment	8,456		7,010
Deferred revenue	2,411		—
Deferred gain on sale/leasebacks	1,150		3,299
Other	750		—
Total Other Current Liabilities	$	211,728	$	210,123
Other Long-Term Liabilities:
Payroll related	$	1,431	$	1,231
Deferred gain on sale/leasebacks	50		2,115
Other	994		619
Total Other Long-Term Liabilities	$	2,475	$	3,965

5. Commitments and Contingencies

Rent expense for rigs, real property and rail cars for the Current Quarter and Prior Quarter was $15.0 million and $30.0 million, respectively, and was included in operating costs in our condensed consolidated statements of operations.

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Rig Leases

As of March 31, 2014, we leased 25 rigs under master lease agreements with an aggregate undiscounted future lease commitment of $19.7 million. The lease commitments are guaranteed by Chesapeake and certain of its subsidiaries. Under the leases, we can exercise an early purchase option or 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. Subsequent to March 31, 2014, we purchased six leased drilling rigs for approximately $20.1 million and lowered our minimum aggregate undiscounted future rig lease payments by approximately $4.0 million. See Note 15 for further discussion of these purchases.

Real Property Leases

As of March 31, 2014, we were party to a facilities lease agreement with Chesapeake pursuant to which we lease a number of the storage yards, office space and other physical facilities out of which we conduct our operations. The initial term of the lease agreement ends December 31, 2014, after which the agreement is automatically renewed for successive one-year terms until we or Chesapeake terminate it. During the renewal periods, the amount of rent charged by Chesapeake will increase by 2.5% each year. We make monthly payments to Chesapeake under the facilities lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. These leases are being accounted for as operating leases.

Rail Car Leases

As of March 31, 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:



	March 31, 2014
	Rigs		Real Property		Rail Cars		Total
	(in thousands)
2014	$	18,076	$	12,168	$	4,655	$	34,899
2015	1,624		—		7,263		8,887
2016	—		—		7,263		7,263
2017	—		—		3,608		3,608
2018	—		—		2,885		2,885
After 2018	—		—		2,162		2,162
Total	$	19,700	$	12,168	$	27,836	$	59,704

Other Commitments

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of March 31, 2014, we had $117.5 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2014.

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.

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 $2.3 million and $2.9 million during the Current Quarter and Prior Quarter, respectively.

6. Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock available to employees and stock options and performance share units (“PSUs”) available to senior management.

Equity-Classified Awards

Restricted Stock. The fair value of restricted stock awards was determined based on the fair market value of the shares of Chesapeake common stock on the date of the grant. This value is amortized over the vesting period, which is generally at least three years from the date of the grant. To the extent compensation cost relates to employees directly involved in oilfield services operations, such amounts are charged to us and reflected as operating costs or general and administrative expenses. Included in operating costs and general and administrative expenses is stock-based compensation expense of $2.9 million and $2.9 million for the Current Quarter and Prior Quarter, respectively. Effective January 1, 2013, we reimburse Chesapeake for these costs in accordance with our administrative services agreement. To the extent compensation cost relates to employees indirectly involved in oilfield services operations, such amounts are charged to us through an overhead allocation and are reflected as general and administrative expenses.

A summary of the status and changes of the unvested shares of restricted stock related to employees directly involved in oilfield services operations is presented below.



	Number of Unvested Restricted Shares		Weighted Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of January 1, 2014	1,871		$	21.46
Granted	412		$	25.21
Vested	(315	)	$	22.59
Forfeited	(61	)	$	21.42
Unvested shares as of March 31, 2014	1,907		$	22.08

The aggregate intrinsic value of restricted stock vested for the Current Quarter, as reflected in the table above, was approximately $8.3 million based on the market price of Chesapeake’s common stock at the time of vesting.

As of March 31, 2014, there was $35.1 million of total unrecognized compensation cost related to the unvested restricted stock of employees involved directly in oilfield services operations. The cost is expected to be recognized over a weighted average period of approximately three years.

Stock Options. Chesapeake has granted incentive-based and retention-based stock options to a member of COO’s senior management team. The incentive-based stock options will 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. The stock option awards have an exercise price equal to the closing price of Chesapeake’s common stock on the grant date. Outstanding options expire ten years from the date of grant.

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



	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)				(in thousands)
Outstanding at January 1, 2014	235	$	18.97	9.08	$	1,916
Granted	46	$	25.71
Exercised	—	$	—
Outstanding at March 31, 2014	281	$	20.08	8.99	$	1,559
Exercisable at March 31, 2014	28	$	18.97	8.83	$	187


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

As of March 31, 2014, there was $1.7 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately three years.

Performance Share Units. Chesapeake has granted PSUs to a member of COO’s senior management team under a Long Term Incentive Plan that includes both an internal performance measure and an external market condition. The PSUs can only be settled in cash, so they are classified as a liability in our condensed consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. Compensation expense is recognized over the vesting period with a corresponding adjustment to the liability.

As of March 31, 2014, the fair value of the PSUs was $3.0 million. We have recorded $0.1 million as a short-term liability for PSUs that will be settled in January 2015 and $1.4 million as a long-term liability representing the portion of the award that will be settled in January 2016 or thereafter. The remaining $1.5 million relates to PSUs for which the requisite service period has not been completed.

7. 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 $12.4 million as of March 31, 2014. We recorded equity method adjustments to our investment of $0.9 million and $0.1 million for our share of Maalt’s loss for the Current Quarter and Prior Quarter, respectively. We also made additional investments of $0.1 million and $0.2 million in the Current Quarter and Prior Quarter, respectively. As of March 31, 2014, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $12.1 million. This excess is attributable to goodwill recorded on Maalt’s financial statements and is not being amortized.

8. Fair Value Measurements

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

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

Level 2- Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices

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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 2 for additional discussion.

Fair Value of Other Financial Instruments

The fair value of debt is the estimated amount a market participant would have to pay to purchase our debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.



	March 31, 2014				December 31, 2013
	Carrying Amount		Fair Value (Level 2)		Carrying Amount		Fair Value (Level 2)
	(in thousands)
Financial liabilities:
Credit Facility		$464,300		$458,792		$405,000		$399,592
2019 Senior Notes		$650,000		$676,124		$650,000		$679,660

9. 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 $315.0 million and $312.5 million as of March 31, 2014 and December 31, 2013, or 82% and 83%, respectively, of our total accounts receivable. Revenues from Chesapeake and its affiliates were $430.8 million and $513.4 million for the Current Quarter and Prior Quarter, or 85% 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.

10. Transactions with Affiliates

In the normal course of business, we provide wellsite services and equipment, including drilling, hydraulic fracturing, oilfield rentals, rig relocation, fluid handling and disposal services and compressor manufacturing to Chesapeake and its affiliates. Substantially all of our revenues are derived from Chesapeake and its working interest partners (see Note 9).

As of March 31, 2014, we were 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 modified International Association of Drilling Contractors drilling contracts. 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

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notice of termination, although such agreement may not be terminated during the term of the services agreement described below.

As of March 31, 2014, we were party to a services agreement with Chesapeake under which Chesapeake guarantees the utilization of a portion of our drilling rig and hydraulic fracturing fleets during the term of the agreement. Chesapeake guarantees that it will operate, on a daywork basis at market rates, the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet, each referred to as a “committed rig.” However, the number of committed rigs will be ratably reduced for each of our drilling rigs that is operated for a third-party customer. In addition, Chesapeake guarantees that each month it will utilize a number of our operational hydraulic fracturing fleets, up to a maximum of 13, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month times the average number of our operational hydraulic fracturing fleets during such month, each referred to as a “committed stage.” However, the number of committed stages per month will be reduced for each stage that we perform for a third-party customer during such month.

If Chesapeake does not meet either the drilling commitment or the stage commitment, it will be required to pay us a non-utilization fee. For each day that a committed rig is not operated, Chesapeake must pay us our average daily operating cost for our operating drilling rigs for the preceding 30 days, plus 20%, and in no event less than $6,600 per day. For each committed stage not performed, Chesapeake must pay us $40,000. The services agreement is subject to the terms of our master services agreement with Chesapeake, has a five-year initial term ending October 25, 2016 and will thereafter automatically extend for successive one-year terms unless we or Chesapeake gives written notice of termination at least 45 days prior to the end of a term; provided, however, that Chesapeake has the right to terminate the agreement, by written notice, within 30 days of our change in control. For purposes of the services agreement, a change of control is deemed to have occurred if Chesapeake no longer beneficially owns at least 51% of our outstanding equity interests. We did not record any revenues for non-utilization in the Current Quarter or Prior Quarter.

As of March 31, 2014, we were party to a facilities lease agreement with Chesapeake pursuant to which we lease a number of the storage yards and physical facilities out of which we conduct our operations. The initial term of the lease agreement ends December 31, 2014, after which the agreement is automatically renewed for successive one-year terms until we or Chesapeake terminate it. During the renewal periods, the amount of rent charged by Chesapeake increases by 2.5% each year. We make monthly payments to Chesapeake under the facilities lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. We incurred $4.1 million and $4.3 million of lease expense for the Current Quarter and Prior Quarter, respectively, under this facilities lease agreement.

Chesapeake provides us with general and administrative services and the services of its employees pursuant to an administrative services agreement. These services include legal, accounting, treasury, environmental, safety, information technology and other corporate services. In return for the general and administrative services provided by Chesapeake, we reimburse Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake on our behalf in accordance with its current allocation policy, which includes 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 is 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 are 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. The administrative services agreement has a five-year initial term and will thereafter automatically extend for successive one-year terms unless we or Chesapeake give written notice of termination at least one year prior to the end of a term. These charges from Chesapeake were $12.8 million and $13.0 million for the Current Quarter and Prior Quarter, respectively.

11. 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, 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, geosteering and mudlogging, for oil and natural gas exploration and development activities. As of March 31, 2014, we owned or leased a fleet of 114 land drilling rigs.

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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 March 31, 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 transport produced water from the wellsite. As of March 31, 2014, we owned a fleet of 260 rig relocation trucks, 67 cranes and forklifts and 247 fluid hauling trucks.

Other Operations. Our other operations consist primarily of our natural gas compression unit and related oil and gas production equipment manufacturing business and corporate functions, including our 2019 Senior Notes and Credit Facility.

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	Drilling			Hydraulic Fracturing			Oilfield Rentals			Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	(in thousands)
For The Three Months Ended March 31, 2014:
Revenues	$	182,111		$	201,620		$	36,178		$	57,438		$	41,355		$	(8,992	)	$	509,710
Intersegment revenues	(1,677		)	—			(236		)	(1,243		)	(5,836		)	8,992			—
Total revenues	$	180,434		$	201,620		$	35,942		$	56,195		$	35,519		$	—		$	509,710
Depreciation and amortization	34,903			18,109			13,347			5,929			177			—			72,465
Losses (gains) on sales of property and equipment	1,710			—			(742		)	(8		)	17			—			977
Impairments and other^(a)	19,601			207			—			—			—			—			19,808
Interest expense	—			—			—			—			(14,692		)	—			(14,692		)
Loss from equity investees	—			(917		)	—			—			—			—			(917		)
Other income (expense)	332			104			14			18			(97		)	—			371
(Loss) Income Before Income Taxes	$	(3,688	)	$	1,205		$	(3,373	)	$	(5,268	)	$	(18,130	)	$	—		$	(29,254	)

For The Three Months Ended March 31, 2013:
Revenues	$	186,590		$	214,946		$	47,736		$	63,196		$	39,087		$	(7,668	)	$	543,887
Intersegment revenues	(1,217		)	—			(223		)	(1,784		)	(4,444		)	7,668			—
Total revenues	$	185,373		$	214,946		$	47,513		$	61,412		$	34,643		$	—		$	543,887
Depreciation and amortization	32,188			15,896			15,272			6,555			201			—			70,112
Losses (gains) on sales of property and equipment	531			18			94			(269		)	—			—			374
Impairments	24			—			—			—			—			—			24
Interest expense	—			—			—			—			(14,010		)	—			(14,010		)
Loss from equity investees	—			(94		)	—			(25		)	—			—			(119		)
Other income (expense)	71			295			58			54			46			—			524
Income (Loss) Before Income Taxes	$	7,917		$	30,009		$	3,416		$	1,026		$	(18,136	)	$	—		$	24,232

As of March 31, 2014:
Total Assets	$	1,192,304		$	443,337		$	173,331		$	183,616		$	75,742		$	(5,240	)	$	2,063,090
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 $8.4 million for the Current Quarter.

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

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12. Condensed Consolidating Financial Information

In October 2011, COO issued and sold the 2019 Senior Notes with an aggregate principal amount of $650.0 million (see Note 3). Pursuant to the Indenture governing the 2019 Senior Notes, such notes are fully and unconditionally and jointly and severally guaranteed by all of COO’s material subsidiaries, other than COF, which is a co-issuer of the 2019 Senior Notes. Each of the subsidiary guarantors is 100% owned by COO and there are no material subsidiaries of COO other than the subsidiary guarantors. COF and WWS are minor non-guarantor subsidiaries whose condensed consolidating financial information is included with the subsidiary guarantors. COO has independent assets and operations. There are no significant restrictions on the ability of COO or any subsidiary guarantor to obtain funds from its subsidiaries by dividend or loan.

Set forth below are condensed consolidating financial statements for COO (“Parent”) on a stand-alone, unconsolidated basis, and its combined guarantor subsidiaries as of March 31, 2014 and December 31, 2013 and for the three months ended March 31, 2014 and 2013. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF MARCH 31, 2014

(in thousands)



	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	3,014		$	277		$	—		$	3,291
Accounts receivable	—			68,386			—			68,386
Affiliate accounts receivable	692			314,295			—			314,987
Inventory	—			47,979			—			47,979
Deferred income tax asset	852			4,027			—			4,879
Prepaid expenses and other	673			16,390			—			17,063
Total Current Assets	5,231			451,354			—			456,585
Property and Equipment:
Property and equipment, at cost	3,903			2,279,590			—			2,283,493
Less: accumulated depreciation	(278		)	(814,270		)	—			(814,548		)
Property and equipment held for sale, net	—			58,302			—			58,302
Total Property and Equipment, Net	3,625			1,523,622			—			1,527,247
Other Assets:
Investments	—			12,405			—			12,405
Goodwill	—			42,447			—			42,447
Intangible assets, net	—			6,441			—			6,441
Deferred financing costs, net	13,343			—			—			13,343
Other long-term assets	53,183			4,622			(53,183		)	4,622
Investments in subsidiaries and intercompany advances	1,592,196			—			(1,592,196		)	—
Total Other Assets	1,658,722			65,915			(1,645,379		)	79,258
Total Assets	$	1,667,578		$	2,040,891		$	(1,645,379	)	$	2,063,090
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	1,338		$	27,255		$	—		$	28,593
Affiliate accounts payable	1,452			41,978			—			43,430
Other current liabilities	20,324			191,404			—			211,728
Total Current Liabilities	23,114			260,637			—			283,751
Long-Term Liabilities:
Deferred income tax liabilities	—			187,112			(53,183		)	133,929
Senior notes	650,000			—			—			650,000
Revolving credit facility	464,300			—			—			464,300
Other long-term liabilities	1,529			946			—			2,475
Total Long-Term Liabilities	1,115,829			188,058			(53,183		)	1,250,704
Equity	528,635			1,592,196			(1,592,196		)	528,635
Total Liabilities and Equity	$	1,667,578		$	2,040,891		$	(1,645,379	)	$	2,063,090

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CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2013

(in thousands)



	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	1,615		$	63		$	—		$	1,678
Accounts receivable	—			62,959			—			62,959
Affiliate accounts receivable	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:
Investments	—			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	1,542,365			—			(1,542,365		)	—
Total Other Assets	1,611,403			67,566			(1,597,323		)	81,646
Total Assets	$	1,617,981		$	2,006,235		$	(1,597,323	)	$	2,026,893
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	2,051		$	28,615		$	—		$	30,666
Affiliate accounts payable	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
Equity	547,192			1,542,365			(1,542,365		)	547,192
Total Liabilities and Equity	$	1,617,981		$	2,006,235		$	(1,597,323	)	$	2,026,893

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2014

(in thousands)



	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	1,143		$	509,688		$	(1,121	)	$	509,710
Operating Expenses:
Operating costs	1,912			409,499			(1,822		)	409,589
Depreciation and amortization	20			72,445			—			72,465
General and administrative	7,259			13,628			—			20,887
Gains on sales of property and equipment	—			977			—			977
Impairments and other	—			19,808			—			19,808
Total Operating Expenses	9,191			516,357			(1,822		)	523,726
Operating (Loss) Income	(8,048		)	(6,669		)	701			(14,016		)
Other (Expense) Income:
Interest expense	(14,692		)	—			—			(14,692		)
Loss from equity investees	—			(917		)	—			(917		)
Other income	—			371			—			371
Equity in net loss of subsidiary	(4,387		)	—			4,387			—
Total Other (Expense) Income	(19,079		)	(546		)	4,387			(15,238		)
(Loss) Income Before Income Taxes	(27,127		)	(7,215		)	5,088			(29,254		)
Income Tax (Benefit) Expense	(8,570		)	(2,393		)	266			(10,697		)
Net (Loss) Income	$	(18,557	)	$	(4,822	)	$	4,822		$	(18,557	)

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2013

(in thousands)



	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	1,848		$	543,838		$	(1,799	)	$	543,887
Operating Expenses:
Operating costs	2,427			414,985			(2,363		)	415,049
Depreciation and amortization	—			70,112			—			70,112
General and administrative	6,189			14,302			—			20,491
Losses on sales of property and equipment	—			374			—			374
Impairments	—			24			—			24
Total Operating Expenses	8,616			499,797			(2,363		)	506,050
Operating (Loss) Income	(6,768		)	44,041			564			37,837
Other (Expense) Income:
Interest expense	(14,010		)	—			—			(14,010		)
Loss from equity investees	—			(119		)	—			(119		)
Other income	4			520			—			524
Equity in net earnings of subsidiary	27,226			—			(27,226		)	—
Total Other Income (Expense)	13,220			401			(27,226		)	(13,605		)
Income (Loss) Before Income Taxes	6,452			44,442			(26,662		)	24,232
Income Tax (Benefit) Expense	(7,781		)	17,780			—			9,999
Net Income (Loss)	$	14,233		$	26,662		$	(26,662	)	$	14,233

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2014

(in thousands)



	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	(2,181	)	$	56,763		$	—		$	54,582
Cash Flows From Investing Activities:
Additions to property and equipment	(800		)	(117,771		)	—			(118,571		)
Proceeds from sale of assets	—			6,375			—			6,375
Additions to investments and other	(54,920		)	(73		)	54,920			(73		)
Cash used in investing activities	(55,720		)	(111,469		)	54,920			(112,269		)
Cash Flows From Financing Activities:
Contributions from (distributions to) affiliates	—			54,920			(54,920		)	—
Borrowings from revolving credit facility	281,500			—			—			281,500
Payments on revolving credit facility	(222,200		)	—			—			(222,200		)
Net cash provided by financing activities	59,300			54,920			(54,920		)	59,300
Net increase in cash	1,399			214			—			1,613
Cash, beginning of period	1,615			63			—			1,678
Cash, end of period	$	3,014		$	277		$	—		$	3,291

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2013

(in thousands)



				Guarantor
	Parent^(a)			Subsidiaries			Eliminations			Consolidated
Cash Flows From Operating Activities:	$	14,102		$	95,345		$	(22,054	)	$	87,393
Cash Flows From Investing Activities:
Additions to property and equipment	(2,890		)	(89,606		)	—			(92,496		)
Proceeds from sale of assets	—			29,357			—			29,357
Other	—			(175		)	—			(175		)
Cash used in investing activities	(2,890		)	(60,424		)	—			(63,314		)
Cash Flows From Financing Activities:
Contributions from (distributions to) affiliates	—			(35,015		)	22,054			(12,961		)
Borrowings from revolving credit facility	237,300			—			—			237,300
Payments on revolving credit facility	(247,900		)	—			—			(247,900		)
Net cash used in financing activities	(10,600		)	(35,015		)	22,054			(23,561		)
Net increase (decrease) in cash	612			(94		)	—			518
Cash, beginning of period	863			364			—			1,227
Cash, end of period	$	1,475		$	270		$	—		$	1,745

(a) We have revised the Parent column to properly reflect the distributions from Guarantor Subsidiaries as cash flows from operating activities, which were previously presented for the three months ended March 31, 2013 as cash flows from financing activities. We have evaluated this revision and do not consider it material to any previously issued financial statements.

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CHESAPEAKE OILFIELD OPERATING, L.L.C.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

13. 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 have early adopted ASU 2014-08 in the Current Quarter. The adoption of this standard did not have a material impact on our consolidated financial statements.

14. Potential Separation

On February 24, 2014, Chesapeake announced that it is pursuing strategic alternatives for COO, including a potential spin-off to Chesapeake shareholders or an outright sale. On March 17, 2014, we filed with the SEC a registration statement on Form 10 under the Securities Exchange Act of 1934, as amended. The Form 10 contains a preliminary information statement about the potential terms and conditions of a spin-off, including the potential benefits and risks associated with the transaction. Immediately prior to completion of the possible spin-off, COO would convert into a corporation and change its name to Seventy Seven Energy Inc. (SSE). The spin-off would then be effected through the pro rata distribution of SSE common stock to Chesapeake shareholders. After the distribution, we would be an independent, publicly traded company. Any spin-off or sale is subject to several conditions, including approval by Chesapeake’s Board of Directors. In addition, the Form 10 registration statement has not been declared effective by the SEC and may be revised or updated in the future. There can be no assurance that Chesapeake will commit to pursue a spin-off or sale of our company or any other transaction, or that if any transaction is pursued, that it will be consummated.

15. Subsequent Events

Subsequent to March 31, 2014, we purchased six leased drilling rigs subject to the master lease agreements described in Note 5 for approximately $20.1 million. In conjunction with the purchases, we also terminated approximately $4.0 million of remaining lease commitments associated with these drilling rigs.

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

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

Overview

Oilfield services companies provide services and equipment that are used by E&P companies in connection with the exploration for, and the development and production of, hydrocarbons. 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 fluid handling 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.

Since we commenced operations in 2001, we have actively grown our business and modernized our asset base. As of March 31, 2014, we owned 89 land drilling rigs, including 10 proprietary PeakeRigs™ that utilize advanced electronic drilling technology, and leased 25 land drilling rigs. As of March 31, 2014, we also owned (a) nine hydraulic fracturing fleets with an aggregate of 360,000 horsepower; (b) a diversified oilfield rentals business; and (c) an oilfield trucking fleet consisting of 260 rig relocation trucks, 67 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 247 fluid handling trucks. We continue to modernize our asset base and are building six additional PeakeRigs™.

Recent Developments

How We Generate Our Revenues

We currently derive a substantial majority of our revenues from providing oilfield services and equipment to Chesapeake and its working interest partners. To the extent that Chesapeake shares the costs of our services with its working interest partners, it seeks separate reimbursement of such shared costs through a joint interest billing. In addition, we perform work for third-party customers. Pursuant to our master services agreement (the "Master Services Agreement") with Chesapeake, we provide drilling and other services and supply equipment 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 rates for the services we provide Chesapeake are market-based. A brief description of the ways in which we are compensated for the services we provide appears below. If the potential spin-off is pursued, we expect the Master Services Agreements to be amended, after which our provision of wellsite services for Chesapeake will continue to be governed by such amended agreement.

Drilling Segment. As of March 31, 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

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costs. We expect that all of our future contracts with Chesapeake and third parties will be daywork contracts. Under the Services Agreement, Chesapeake guarantees that it will operate, on a daywork basis at market-based rates, the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet, each referred to as a “committed rig,” subject to reduction for each of our drilling rigs that is operated by a third-party customer. In the event Chesapeake does not meet its rig commitment, it is required to pay us a non-utilization fee. For each day that a committed rig is not operated, Chesapeake is required to pay us our average daily operating cost for our operating drilling rigs for the preceding 30 days, plus 20%, and in no event less than $6,600 per day; however, there is no assurance that any such non-utilization fee would equal or exceed the amount of revenues we could generate or the margins we could realize through normal operations. We did not record any revenues for non-utilization for the Current Quarter and Prior Quarter. If the potential spin-off is pursued, we intend to terminate the Services Agreement and enter into rig-specific daywork drilling contracts with Chesapeake covering a significant portion of our active fleet. These contracts will have durations of up to three years and terms will be similar to those we currently use for unaffiliated customers.

Hydraulic Fracturing Segment. 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. Under the Services Agreement, Chesapeake guarantees that each month it will utilize a number of our operational hydraulic fracturing fleets, up to a maximum of 13 fleets, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month at market-based rates, times the average number of our operational hydraulic fracturing fleets during such month, each referred to as a “committed stage,” subject to reduction for each stage that we perform for a third-party customer during such month. In the event Chesapeake does not meet its stage commitment, it is required to pay us a non-utilization fee equal to $40,000 for each committed stage not performed; however, there is no assurance that any such non-utilization fee would equal or exceed the amount of revenues we could generate or the margins we could realize through normal operations. We did not receive any non-utilization fees pursuant to the agreement for the Current Quarter and Prior Quarter. If the potential spin-off is pursued, in connection with the termination of the Services Agreement, we intend to enter into a minimum utilization agreement pursuant to which Chesapeake will, for the next three years, continue to guarantee certain minimum utilization rates with respect to our hydraulic fracturing services.

Oilfield Rentals Segment. We rent many types of oilfield equipment to Chesapeake and third parties, 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. 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.

Oilfield Trucking Segment. We derive substantially all our oilfield trucking revenues from rig relocation and logistics services and fluid handling services. We price these services by the hours and volume and recognize revenue as services are performed. During the Current Quarter, Chesapeake determined that it would sell our crude hauling fleet, which includes 94 fluid handling trucks and 121 trailers. We expect such disposition to be complete by the end of the second quarter of 2014.

Other Operations. We derive substantially all of our revenues from other operations from our natural gas compression unit and related oil and gas production equipment manufacturing business. If the potential spin-off is pursued, we intend to transfer our natural gas compression unit manufacturing business (and our geosteering business) to Chesapeake.

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.

We have an administrative services agreement (the "Administrative Services Agreement") with Chesapeake pursuant to which Chesapeake allocates 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.

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Under our 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 pay rent and our proportionate share of maintenance, operating expenses, taxes and insurance to Chesapeake on a monthly basis. If the potential spin-off is pursued, we expect to acquire the physical facilities subject to the facilities lease agreement and terminate the facilities lease agreement.

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 revolving bank credit facility ("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.

Our $500.0 million Credit Facility is an important source of liquidity for us. The maximum amount that we may borrow under the Credit Facility may be subject to limitations due to certain covenants contained in the Credit Facility agreement. As of March 31, 2014, the Credit Facility was not subject to any such limitations and had borrowing availability of approximately $35.7 million. We are allowed to request increases in the total commitments under the Credit Facility by up to $400.0 million in the aggregate, in part or in full, at any time during the term of the Credit Facility, with any such increases being subject to compliance with the restrictive covenants in the Credit Facility and in the indenture governing our 6.625% senior notes due 2019 (the "2019 Senior Notes"), as well as lender approval. The Credit Facility matures on November 3, 2016.

In the past we have financed a portion of our capital needs with the issuance of long-term debt. In October 2011, we issued $650.0 million principal amount of our 2019 Senior Notes.

If the potential spin-off is pursued, to provide us with additional liquidity following the spin-off, we intend to enter into a new senior revolving credit facility. This new credit facility would replace the existing credit facility. If the potential spin-off is pursued, we also expect to incur additional debt prior to completion of the spin-off, in part to make a one-time cash distribution to Chesapeake.

Historically, we have provided substantially all of our oilfield services to Chesapeake and its working interest partners. During the Current Quarter and Prior Quarter, Chesapeake and its working interest partners accounted for approximately 85% and 94% of our revenues, respectively.

Capital Expenditures

Total capital expenditures, including maintenance and the purchase of leased drilling rigs, were $118.6 million and $92.5 million for the Current Quarter and Prior Quarter, respectively. We currently expect our growth capital expenditures to be approximately $100.0 million for 2014, and we expect these expenditures to grow our business lines, particularly our drilling rig fleet. 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 we believe that a significant component of our anticipated capital spending is discretionary.

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Cash Flow

Our cash flow depends on the level of spending by Chesapeake, its working interest partners and our third-party customers on exploration, development and production activities. Sustained increases or decreases in the price of oil or natural gas could have a material impact on these activities, thus materially affecting our cash flows. The following is a discussion of our cash flow for the Current Quarter and Prior Quarter.



	Three Months Ended March 31,
	2014			2013
	(in thousands) (unaudited)
Cash Flow Statement Data:
Net cash provided by operating activities	$	54,582		$	87,393
Net cash used in investing activities	$	(112,269	)	$	(63,314	)
Net cash provided by (used in) financing activities	$	59,300		$	(23,561	)
Cash, beginning of period	$	1,678		$	1,227
Cash, end of period	$	3,291		$	1,745

Operating Activities. Cash provided by operating activities was $54.6 million and $87.4 million for the Current Quarter and Prior Quarter, respectively. Changes in working capital items increased (decreased) cash flow provided by operating activities by $1.6 million and ($6.7) million for the Current Quarter and Prior Quarter, 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 $112.3 million and $63.3 million for the Current Quarter and Prior Quarter, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the Current Quarter and Prior Quarter were related to our investment in new PeakeRigs^™and the purchase of certain leased drilling rigs. We purchased 20 leased drilling rigs for approximately $76.9 million during the Current Quarter, 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 $6.4 million and $29.4 million for the Current Quarter and Prior Quarter, respectively.

We made investments in equity investees of $0.1 million and $0.2 million in the Current Quarter and Prior Quarter, respectively, related to our investment in Maalt Specialized Bulk, L.L.C. (“Maalt”).

Financing Activities. Net cash provided by (used in) financing activities was $59.3 million and ($23.6) million for the Current Quarter and Prior Quarter, respectively. We had borrowings and repayments under our Credit Facility of $281.5 million and $222.2 million, respectively, during the Current Quarter. We had borrowings and repayments under our Credit Facility of $237.3 million and $247.9 million, respectively, during the Prior Quarter. During the Prior Quarter, we made distributions to our owner of $13.0 million.

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Results of Operations—Three Months Ended March 31, 2014 vs. March 31, 2013

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



	Three Months Ended March 31,
	2014			2013
	(in thousands)
Revenues:
Revenues from Chesapeake	$	430,835		$	513,434
Revenues from third parties	78,875			30,453
Total Revenues	509,710			543,887
Operating Expenses:
Operating costs	409,589			415,049
Depreciation and amortization	72,465			70,112
General and administrative, including expenses from affiliates	20,887			20,491
Losses on sales of property and equipment	977			374
Impairments and other	19,808			24
Total Operating Expenses	523,726			506,050
Operating (Loss) Income	(14,016		)	37,837
Other Income (Expense):
Interest expense	(14,692		)	(14,010		)
Loss from equity investees	(917		)	(119		)
Other income	371			524
Total Other Expense	(15,238		)	(13,605		)
(Loss) Income Before Income Taxes	(29,254		)	24,232
Income Tax (Benefit) Expense	(10,697		)	9,999
Net (Loss) Income	$	(18,557	)	$	14,233

Revenues. For the Current Quarter and Prior Quarter, revenues were $509.7 million and $543.9 million, respectively. The $34.2 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 third parties. The majority of our revenues are derived from Chesapeake and its working interest partners. Our revenues for the Current Quarter and Prior Quarter are detailed below:



	Three Months Ended March 31,
	2014		2013
	(in thousands)
Drilling	$	180,434	$	185,373
Hydraulic fracturing	201,620		214,946
Oilfield rentals	35,942		47,513
Oilfield trucking	56,195		61,412
Other operations	35,519		34,643
Total	$	509,710	$	543,887

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Operating Costs. Operating costs for the Current Quarter and Prior Quarter were $409.6 million and $415.0 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 80% and 76% for the Current Quarter and Prior Quarter, 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 Quarter and Prior Quarter are detailed below:



	Three Months Ended March 31,
	2014		2013
	(in thousands)
Drilling	$	124,460	$	138,736
Hydraulic fracturing	177,012		168,047
Oilfield rentals	25,949		27,616
Oilfield trucking	53,614		51,102
Other operations	28,554		29,548
Total	$	409,589	$	415,049

Drilling

Drilling revenues for the Current Quarter decreased $4.9 million, or 3%, from the Prior Quarter. 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 third parties increased $30.1 million from the Prior Quarter to the Current Quarter to 29% of total segment revenues compared to 12% for the Prior Quarter.

Drilling operating costs for the Current Quarter decreased $14.3 million, or 10%, from the Prior Quarter. As a percentage of drilling revenues, drilling operating costs were 69% and 75% for the Current Quarter and the Prior Quarter, respectively. These decreases were primarily due to the purchase of 43 leased drilling rigs in 2013 and 2014, which resulted in a reduction of rig rent expense of $13.9 million from the Prior Quarter to the Current Quarter.

Hydraulic Fracturing

Hydraulic fracturing revenues for the Current Quarter decreased $13.3 million, or 6%, from the Prior Quarter. This decrease was due to an 18% decrease in revenue per stage from the Prior Quarter to the Current Quarter, partially offset by a 15% increase in completed stages from the Prior Quarter to the Current Quarter. The decrease in revenue per stage was due primarily to pricing pressure.

Hydraulic fracturing operating costs for the Current Quarter increased $9.0 million, or 5% from the Prior Quarter, primarily due to a 15% increase in the number of completed stages. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs increased from 78% in the Prior Quarter to 88% in the Current Quarter. This increase was primarily attributable to pricing pressure for our hydraulic fracturing services and an increase in repairs and maintenance expense, which compressed margins. Revenue per stage decreased 18% from the Prior Quarter to the Current Quarter. As a percentage of hydraulic fracturing revenues, repairs and maintenance were 11% in the Current Quarter and 3% in the Prior Quarter.

Oilfield Rental

Oilfield rental revenues for the Current Quarter decreased $11.6 million, or 24%, 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.

Oilfield rental operating costs for the Current Quarter decreased $1.7 million, or 6%, 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, freight and inspection expenses. As a percentage of oilfield rental revenues, oilfield rental operating costs were 72% and 58% for the Current Quarter and Prior Quarter, respectively. The increase in oilfield rental operating costs as a percentage of oilfield rental revenues from the Prior Quarter to the Current Quarter was primarily attributable to pricing

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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 34% and 26% in the Current Quarter and Prior Quarter, respectively.

Oilfield Trucking

Oilfield trucking revenues for the Current Quarter decreased $5.2 million, or 8%, from the Prior Quarter. The decrease was primarily due to a reduction in revenues from our rig relocation services of $6.2 million from the Prior Quarter to the Current Quarter.

Oilfield trucking operating costs for the Current Quarter increased $2.5 million, or 5%, from the Prior Quarter. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 95% and 83% for the Current Quarter and Prior Quarter, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to an increase in labor related costs due to higher wages in the competitive market for trucking labor and an increase in our average employee headcount of 17% from the Prior Quarter to the Current Quarter. As a percentage of oilfield trucking revenues, labor related costs were 48% and 39% for the Current Quarter and Prior Quarter, respectively.

Other Operations

Our other operations consist primarily of our natural gas compression unit and related oil and gas production equipment manufacturing business and corporate functions. For the Current Quarter, revenues from our other operations increased $0.9 million, or 3%, from the Prior Quarter. The increase in revenue from the Prior Quarter to the Current Quarter was primarily attributable to additional revenues from the sale of oil and gas production equipment of approximately $2.7 million.

For the Current Quarter, operating costs for our other operations decreased $1.0 million, or 3%, from the Prior Quarter. As a percentage of compression manufacturing revenues, compression manufacturing costs were 80% and 85% in the Current Quarter and Prior Quarter, respectively. The decrease in costs as a percentage of revenues was due to an increase in production of higher margin small natural gas compressors.

Other Financial Statement Items

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Prior Quarter was $72.5 million and $70.1 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 Quarter and Prior Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Prior Quarter were $20.9 million and $20.5 million, respectively. We are 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 $12.8 million and $13.0 million for the Current Quarter and Prior Quarter, respectively. As a percentage of revenues, general and administrative expenses were 4% for the Current Quarter and Prior Quarter.

Losses on Sales of Property and Equipment. During the Current Quarter, we sold ancillary equipment that was not being utilized in our business for $6.4 million, net of selling expenses. During the Prior Quarter, we sold eight drilling rigs and ancillary equipment that was not being utilized in our business for $29.4 million. We recorded losses on sales of property and equipment of approximately $1.0 million and $0.4 million related to these asset sales during the Current Quarter and Prior Quarter, respectively

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

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Interest Expense. Interest expense for the Current Quarter and Prior Quarter was $14.7 million and $14.0 million, respectively, related to borrowings under our Credit Facility and 2019 Senior Notes.

Loss from Equity Investees. Loss from equity investees was $0.9 million and $0.1 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”).

Other Income. Other income was $0.4 million and $0.5 million for the Current Quarter and Prior Quarter, respectively.

Income Tax (Benefit) Expense. We recorded income tax (benefit) expense of ($10.7) million and $10.0 million for the Current Quarter and Prior Quarter, respectively. The $20.7 million increase in income tax benefit recorded for the Current Quarter was primarily the result of a decrease in net income before taxes of $53.5 million from the Prior Quarter to the Current Quarter. Our effective income tax rate for the Current Quarter and Prior Quarter was 37% and 41%, respectively. Our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences.

Off-Balance Sheet Arrangements

As of March 31, 2014, we leased 25 rigs under master lease agreements with an aggregate undiscounted future lease commitment of $19.7 million. For more information regarding the terms of the rig leases, please see Note 5 “Commitments and Contingencies” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

In October 2011, we entered into a facilities lease agreement with Chesapeake pursuant to which we lease a number of the storage yards and other physical facilities out of which we conduct our operations. The initial term of the lease agreement ends December 31, 2014, after which the agreement is automatically renewed for successive one-year terms until we or Chesapeake terminate it. During the renewal periods, the amount of rent charged by Chesapeake will increase by 2.5% each year. We make monthly payments to Chesapeake under the facilities lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. These leases are being accounted for as operating leases. If the potential spin-off is pursued, we intend to acquire the property subject to the Facilities Lease Agreement, and, accordingly, the facilities lease agreement will be terminated in connection with the potential spin-off.

Aggregate undiscounted minimum future lease payments as of March 31, 2014 under our operating leases are presented below:



	March 31, 2014
	Rigs		Real Property		Rail Cars		Total
	(in thousands)
2014	$	18,076	$	12,168	$	4,655	$	34,899
2015	1,624		—		7,263		8,887
2016	—		—		7,263		7,263
2017	—		—		3,608		3,608
2018	—		—		2,885		2,885
After 2018	—		—		2,162		2,162
Total	$	19,700	$	12,168	$	27,836	$	59,704

Other Commitments

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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. We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date.

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


•	dependence on Chesapeake and its working interest partners for a majority of our revenues and our ability to secure new customers or provide additional services to existing customers;


•	our customers' expenditures for oilfield services;


•	the limitations that Chesapeake’s and our own level of indebtedness may have on our financial flexibility and restrictions in our or Chesapeake's debt agreements;


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


•	market prices for oil and natural gas;


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


•	our and Chesapeake's credit profile;


•	access to and cost of capital;


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


•	increased labor costs or the unavailability of skilled workers;


•	the timing, nature and benefits of the potential spin-off or an outright sale and related transactions;


•	competitive conditions; and


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

If one or more events related to these or other risks and uncertainties, which may be unforseen, materialize, or if our underlying assumptions prove to be incorrect, our actual results may differ materially from what we anticipate. We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date. Except as may be required by law, we do not intend, and do not assume any obligation, to update any forward-looking statements.

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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 Quarter and Prior Quarter, Chesapeake accounted for approximately 85% and 94% of our revenues, respectively. Sustained low natural gas prices, as has been the case recently, and volatile commodity prices in general, could have a material adverse effect on Chesapeake’s and our financial position, results of operations and cash flows, which could adversely impact our ability to comply with financial covenants under our Credit Facility and further limit our ability to fund our planned capital expenditures.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our Credit Facility. We have borrowings outstanding under and may in the future borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility bear interest at our option at either (a) the greater of the reference rate of Bank of America, N.A., the federal funds effective rate plus 0.50%, and one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% per annum, according to our leverage ratio, or (b) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per annum, according to our leverage ratio. A one percentage point increase or decrease in interest rate payable on our Credit Facility would have resulted in a $2.5 million increase or decrease in net income for the year ended December 31, 2013.

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.



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 March 31, 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 March 31, 2014 which materially affected, or was reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION



Item 1.	Legal Proceedings

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



Item 1A.	Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth in our Annual Report on Form 10-K (Commission File No. 333-187766) filed with the SEC on March 14, 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 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

3.1

Articles of Organization of Chesapeake Oilfield Operating, L.L.C.

S-4

333-187766

3.1

5/30/2013

3.2

Operating Agreement of Chesapeake Oilfield Operating, L.L.C.

S-4

333-187766

3.2

5/30/2013

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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SIGNATURES

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



May 9, 2014	Chesapeake Oilfield Operating, L.L.C.

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

	By:	/s/ Cary D. Baetz
		Cary D. Baetz
		Chief Financial Officer
		(Principal Financial Officer)

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INDEX TO EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Commission

File No.

Exhibit

Filing Date

Filed

Herewith

Furnished

Herewith

3.1

Articles of Organization of Chesapeake Oilfield Operating, L.L.C.

S-4

333-187766

3.1

5/30/2013

3.2

Operating Agreement of Chesapeake Oilfield Operating, L.L.C.

S-4

333-187766

3.2

5/30/2013

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.