Southwestern Energy (SWN) 8-K/A Financial Statements and Exhibits

Independent Auditor’s Report

To the Board of Directors of Southwestern Energy Company:

We have audited the accompanying financial statements of the Acquired West Virginia and Southwest Pennsylvania Properties (the “Properties”), which comprise the statements of revenues and direct operating expenses for each of the three years in the period ended December 31, 2013.

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Properties for each of the three years in the period ended December 31, 2013 in accordance with accounting principles generally accepted in the United States of America, using the basis of presentation described in Note 1.  

Emphasis of Matter

The accompanying financial statements reflect the revenues and direct operating expenses of the Properties using the basis of presentation described in Note 1 and are not intended to be a complete presentation of the financial position, results of operations or cash flows of the Properties. 

/s/ PricewaterhouseCoopers LLP

Houston, Texas

December 22, 2014

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ACQUIRED WEST VIRGINIA AND SOUTHWEST PENNSYLVANIA PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

							Nine Months Ended
	Years Ended						September 30,
	December 31,						(Unaudited)
	2013		2012		2011		2014		2013
	($ in millions)
Revenues	$	342	$	147	$	181	$	340	$	235
Direct operating expenses		65		47		55		57		40
Revenues in excess of direct operating expenses	$	277	$	100	$	126	$	283	$	195

See accompanying notes to the Statements of Revenues and Direct Operating Expenses.

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ACQUIRED WEST VIRGINIA AND SOUTHWEST PENNSYLVANIA PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

(1)  BASIS OF PRESENTATION

On December 23, 2014, Southwestern Energy Company (the “Company”) filed a Current Report on Form 8-K (the “Closing Report”) to report that a subsidiary of the Company completed the acquisition of certain oil and gas assets from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, natural gas liquids (“NGLs”) and crude oil contained in the Upper Devonian, Marcellus and Utica Shales for approximately $4.975 billion, subject to customary closing adjustments. The accompanying Statements of Revenues and Direct Operating Expenses represent the direct undivided interests in the revenue and direct operating expenses associated with the Properties. 

The Statements of Revenues and Direct Operating Expenses have been derived from the historical financial records of Chesapeake.  For purposes of these statements, all properties identified in the purchase and sale agreement are included herein. During the periods presented, the Properties were not accounted for or operated as a separate subsidiary or division by Chesapeake. The accompanying Statements of Revenues and Direct Operating Expenses vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain expenses incurred in connection with the ownership and operation of the Properties, including but not limited to depreciation, depletion and amortization, impairments, accretion of asset retirement obligations, general and administrative expenses, interest expense and federal and state income taxes. These costs were not separately allocated to the working interests of the Properties in Chesapeake’s accounting records. In addition, these allocations, if made using historical general and administrative structures and tax burdens would not produce allocations indicative of the historical performance of the Properties had they been the Company’s properties due to the differing size, structure, specifications and accounting policies of Chesapeake as compared to the Company. Furthermore, no balance sheet has been presented for the Properties because the Properties were not accounted for as or operated as a separate subsidiary or division of Chesapeake and complete financial statements are not available, nor has information about the Properties’ operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statements of Revenues and Direct Operating Expenses of the Properties are presented in lieu of the full financial statements required under Item 3-05 of the Securities and Exchange Commission’s Regulation S-X. In addition, these Statements of Revenues and Direct Operating Expenses are not indicative of the results of operations for the Properties on a go forward basis.

The accompanying Statements of Revenues and Direct Operating Expenses for the nine months ended September 30, 2014 and 2013 are unaudited, and have been prepared on the same basis as the annual Statements of Revenues and Direct Operating Expenses and, in the opinion of management, reflect all adjustments necessary to fairly present the Properties’ excess of revenue over direct operating expenses for the nine months ended September 30, 2014 and 2013.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates –The Statements of Revenues and Direct Operating Expenses are derived from the historical operating statements of Chesapeake. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statements of Revenues and Direct Operating Expenses. Actual results could be different from those estimates. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Properties.

Revenue Recognition – Revenue from the sale of natural gas, oil and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges. Chesapeake uses the “sales method” of accounting for their natural gas, oil, and NGL revenue whereby sales revenue is recognized on all natural gas, oil, and NGL sold to purchasers, regardless of whether the sales are proportionate to their ownership in the property. There were no significant imbalances with other revenue interest owners during the three years ended December 31, 2013 and the nine months ended September 30, 2014 and 2013.

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During the three years ended December 31, 2013 and the nine months ended September 30, 2014 and 2013,  over 90% of gas and NGL sales were made to Chesapeake Energy Marketing, Inc (referred to herein as “CEMI”). During the nine months ended September 30, 2014 and 2013, sales to CEMI accounted for approximately 100% and 79%, respectively, of the Properties’ total oil revenues. During 2013, sales to CEMI accounted for approximately 85% of the Properties’ total oil revenues. During 2012, sales to CEMI, Clearfield Appalachian Holdings, Inc, Tyler Mountain Properties, LLC and Ergon Oil Purchasing, Inc. accounted for approximately 41%, 25%, 16%, and 11%, respectively, of the Properties’ total oil revenues. During 2011, sales to Clearfield Appalachian Holdings, Inc and Tyler Mountain Properties, LLC accounted for approximately 58% and 36%, respectively, of the Properties’ total oil revenues. During such periods, no other customers accounted for more than 10% of the Properties’ total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, it is not likely that the loss of any single significant customer or contract would materially affect the Properties in the long-term as such purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Direct Operating Expenses – Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Properties. Direct operating expenses include lease operating expenses, production taxes, and expense workover costs. Lease operating expenses include well repair expenses, saltwater disposal costs, facility maintenance expenses, and other field-related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil,  natural gas, and NGL  production activities. 

(3)  COMMITMENTS AND CONTINGENCIES

The activities of the Properties may become subject to potential claims and litigation in the normal course of operations. The Company does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Properties. 

 (4)  SUBSEQUENT EVENTS

The Company has evaluated subsequent events through December 22, 2014, the date the Statements of Revenues and Direct Operating Expenses were available to be issued, and has concluded that no events need to be reported in relation to this period. 

(5)  SUPPLEMENTAL NATURAL GAS AND OIL RESERVE INFORMATION (UNAUDITED)

The following tables summarize the net ownership interest in the estimated proved reserves and the standardized measure of discounted future net cash flows (“standardized measure”) related to the proved reserves for the Properties. The components of the standardized measure were determined in accordance with the authoritative guidance of the Financial Accounting Standards Board (“FASB”).

Estimated Quantities of Proved Oil and Natural Gas Reserves

Proved reserves are estimated quantities of natural gas, NGLs and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate was made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

The reserve estimates at December 31, 2013, 2012 and 2011 presented in the table below were prepared by Chesapeake’s reserve engineers, in accordance with the authoritative guidance of the FASB on natural gas and oil reserve estimation and disclosures. All of the natural gas, NGL and oil producing activities of the Properties were conducted within the United States.

Reserve estimates are inherently imprecise and are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, Chesapeake’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.

The following table sets forth the Properties’ estimated net proved, proved developed and proved undeveloped oil, natural gas and NGLs reserves:

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			Natural
	Natural		Gas
	Gas	Oil	Liquids	Total
	(MMcf)	(MBbls)	(MBbls)	(MMcfe)
2011
Proved reserves, beginning of year	294,713	530	7,795	344,663
Revisions of previous estimates	64,917	738	3,641	91,191
Extensions, discoveries and other additions	93,495	1,301	3,333	121,300
Production	(33,908)	(166)	(1,122)	(41,636)
Acquisition of reserves in place	5	–	–	5
Disposition of reserves in place	(2)	–	–	(2)
Proved reserves, end of year	419,220	2,403	13,647	515,521
Proved developed reserves:
Beginning of year	194,702	145	4,444	222,236
End of year	297,652	1,942	8,855	362,437
Proved undeveloped reserves:
Beginning of year	100,011	385	3,351	122,427
End of year	121,568	461	4,792	153,084
2012
Proved reserves, beginning of year	419,220	2,403	13,647	515,521
Revisions of previous estimates	26,004	(542)	3,382	43,043
Extensions, discoveries and other additions	192,917	4,076	9,109	272,026
Production	(42,388)	(233)	(1,417)	(52,288)
Acquisition of reserves in place	1	–	–	1
Proved reserves, end of year	595,754	5,704	24,721	778,303
Proved developed reserves:
Beginning of year	297,652	1,942	8,855	362,437
End of year	431,504	4,310	16,730	557,742
Proved undeveloped reserves:
Beginning of year	121,568	461	4,792	153,084
End of year	164,250	1,394	7,991	220,561

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			Natural
	Natural		Gas
	Gas	Oil	Liquids	Total
	(MMcf)	(MBbls)	(MBbls)	(MMcfe)
2013
Proved reserves, beginning of year	595,754	5,704	24,721	778,303
Revisions of previous estimates	8,877	1,043	1,874	26,382
Extensions, discoveries and other additions	374,142	9,231	16,469	528,345
Production	(57,972)	(1,522)	(2,497)	(82,086)
Acquisition of reserves in place	7	–	–	7
Disposition of reserves in place	(864)	–	–	(864)
Proved reserves, end of year	919,944	14,456	40,567	1,250,087
Proved developed reserves:
Beginning of year	431,504	4,310	16,730	557,742
End of year	551,123	10,612	21,599	744,391
Proved undeveloped reserves:
Beginning of year	164,250	1,394	7,991	220,561
End of year	368,821	3,844	18,968	505,696

Reserve additions from revisions of previous estimates, extensions, discoveries and other additions were primarily attributable to Chesapeake’s development drilling of proved acreage during the periods presented. There are numerous uncertainties in estimating quantities of proved reserves, which incorporate estimates of the future rates of production, the timing of development expenditures and other assumptions. The above reserve data represents estimates only, and is inherently imprecise and may be subject to substantial revisions as additional information becomes available, such as reservoir performance, additional drilling, technological advancements and other factors. Decreases in the prices of natural gas, NGLs or oil could have an adverse effect on reserve volumes and discounted future net cash flows related to the proved reserves. Similarly, the standardized measure incorporates various assumptions such as prices, costs, production rates and discount rates that are inherently imprecise. Actual results could be materially different and the results may not be comparable to estimates disclosed by other natural gas and oil companies.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted cash flows as of December 31, 2013, 2012 and 2011 and the changes between periods were derived from Chesapeake’s records. The standardized measure represents the present value of estimated future net cash flows from estimated net proved natural gas, NGLs and oil reserves, less future development, production, plugging and abandonment costs, and income tax expenses, discounted at 10% per annum, to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization or impairments of capitalized acquisition, exploration and development costs. As described in Note 1, the Statements of Revenue and Direct Operating Expenses do not include income tax expense, and therefore income tax expense was omitted from the standardized measure calculation below.

Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure below were $3.67 per Mcf for natural gas and $96.82 per barrel for oil before price differentials in 2013, $2.76 per Mcf for natural gas and $94.84 per barrel of oil before price differentials in 2012, and $4.12 per Mcf for natural gas and $95.97 per barrel for oil before price differentials in 2011. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine future cash inflows.

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The standardized measure does not purport, nor should be interpreted, to present the fair market value of the Properties’ proved reserves. It is intended to present a standardized disclosure concerning possible future net cash flows from proved reserves that would result under the assumptions used and ignores future changes in prices and costs and the risks inherent in reserve estimates, among other things. Further, since prices and costs do not remain static, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other natural gas and oil producers. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results.

The standardized measure of discounted future net cash flows relating to estimated proved reserves, excluding income tax expense, is as follows:

	2013		2012		2011
	(in millions)
Future cash inflows	$	5,081	$	2,857	$	2,483
Future production costs		(942)		(658)		(641)
Future development costs		(547)		(301)		(188)
Future net cash flows		3,592		1,898		1,654
10% annual discount for estimated timing of cash flows		(2,106)		(1,108)		(956)
Standardized measure of discounted future net cash flows	$	1,486	$	790	$	698

Following is an analysis of changes in the standardized measure: 

	2013		2012		2011
	(in millions)
Standardized measure, beginning of year	$	790	$	698	$	402
Sales and transfers of natural gas and oil produced, net of production costs		(277)		(100)		(126)
Net changes in prices and production costs		37		(306)		(26)
Extensions, discoveries, and other additions, net of future production and development costs		688		344		192
Acquisition of reserves in place		–		–		–
Sales of reserves in place		(1)		–		–
Revisions of previous quantity estimates		170		84		216
Accretion of discount		79		70		40
Standardized measure, end of year	$	1,486	$	790	$	698

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