Edgar Filing: SOUTHWESTERN ENERGY CO

SWN Q3 2014 10-Q



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


Form 10-Q

(Mark One)
[X] Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 2014

Or

[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from __________ to __________

Commission file number: 1-08246


Southwestern Energy Company
(Exact name of registrant as specified in its charter)




Delaware		71-0205415
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2350 North Sam Houston Parkway East, Suite 125, Houston, Texas		77032
(Address of principal executive offices)		(Zip Code)

(281) 618-4700
(Registrant’s telephone number, including area code)

Not Applicable
(Former name, former address and former fiscal year, if changed since last report)
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☒ 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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Class		Outstanding as of October 21, 2014
Common Stock, Par Value $0.01		353,114,947

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SOUTHWESTERN ENERGY COMPANY

INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2014

PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	41

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	44

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials);

our ability to fund our planned capital investments;

our ability to transport our production to the most favorable markets or at all;

the timing and extent of our success in discovering, developing, producing and estimating reserves;

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the economic viability of, and our success in drilling, our large acreage position in the Fayetteville Shale and the Marcellus Shale overall as well as relative to other productive shale gas plays and our competitors;

the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over the counter derivatives;

the costs and availability of oilfield personnel, services and drilling supplies, raw materials and equipment, including pressure pumping equipment and crews;

our future property acquisition or divestiture activities;

the impact of the adverse outcome of any material litigation against us;

the effects of weather;

increased competition and regulation;

the financial impact of accounting regulations and critical accounting policies;

the comparative cost of alternative fuels;

the different risks and uncertainties associated with Canadian exploration and production;

conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed;

credit risk relating to the risk of loss as a result of non-performance by our counterparties; and

any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”).

We caution you that forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, third-party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in our Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto, including this Form 10-Q (“Form 10-Qs”).

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.


SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

	For the three months ended				For the nine months ended
	September 30,				September 30,
	2014		2013		2014		2013

	(in millions, except share/per share amounts)
Operating Revenues:
Gas sales	$	645	$	617	$	2,155	$	1,736
Gas marketing		227		201		765		582
Oil sales		6		4		13		12
Gas gathering		50		46		143		134
		928		868		3,076		2,464
Operating Costs and Expenses:
Gas purchases – midstream services		220		195		752		575
Operating expenses		108		90		309		237
General and administrative expenses		54		51		162		136
Depreciation, depletion and amortization		238		205		693		571
Taxes, other than income taxes		22		18		72		59
		642		559		1,988		1,578
Operating Income		286		309		1,088		886
Interest Expense:
Interest on debt		25		25		75		74
Other interest charges		2		1		4		3
Interest capitalized		(14)		(15)		(40)		(48)
		13		11		39		29

Other Gain, Net		–		–		1		–
Gain (Loss) on Derivatives		78		12		(29)		75

Income Before Income Taxes		351		310		1,021		932
Provision (Benefit) for Income Taxes:
Current		32		(16)		34		–
Deferred		108		140		375		373
		140		124		409		373
Net Income	$	211	$	186	$	612	$	559

Earnings Per Share:
Basic	$	0.60	$	0.53	$	1.74	$	1.60
Diluted	$	0.60	$	0.53	$	1.74	$	1.59

Weighted Average Common Shares Outstanding:
Basic		351,457,043		350,517,337		351,357,913		350,334,634
Diluted		352,327,250		351,222,830		352,334,546		351,014,974

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)


	For the three months ended					For the nine months ended
	September 30,					September 30,
	2014		2013			2014		2013
	(in millions)

Net income	$	211	$	186	$	612	$	559

Change in derivatives:
Settlements (1)		(11)		(56)		29		(131)
Ineffectiveness (2)		(2)		1		(1)		1
Change in fair value of derivative instruments (3)		48		7		(1)		30
Total change in derivatives		35		(48)		27		(100)

Change in value of pension and other postretirement liabilities:
Amortization of prior service cost included in net periodic pension cost (4)		–		–		–		1

Change in currency translation adjustment		(4)		1		(4)		(2)

Comprehensive income	$	242	$	139	$	635	$	458

⁽¹⁾

Net of $(7), $(37), $19 and $(87) million in taxes for the three months ended September 30, 2014 and 2013, and nine months ended September 30, 2014 and 2013, respectively.

⁽²⁾

Net of $(1), $0, $0 and $1 million in taxes for the three months ended September 30, 2014 and 2013, and nine months ended September 30, 2014 and 2013, respectively.

⁽³⁾

Net of $32, $5, $(1) and $21 million in taxes for the three months ended September 30, 2014 and 2013, and nine months ended September 30, 2014 and 2013, respectively.

⁽⁴⁾

Net of $0, $0, $0 and $1 million in taxes for the three months ended September 30, 2014 and 2013, and nine months ended September 30, 2014 and 2013, respectively.

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30,		December 31,
	2014		2013
ASSETS	(in millions)
Current assets:
Cash and cash equivalents	$	20	$	23
Accounts receivable		457		464
Inventories		37		38
Derivative assets		117		71
Other current assets		29		48
Total current assets		660		644
Natural gas and oil properties, using the full cost method, including $1,037 million in 2014 and $957 million in 2013 excluded from amortization		14,945		13,294
Gathering systems		1,415		1,306
Other		685		703
Less: Accumulated depreciation, depletion and amortization		(8,652)		(8,006)
Total property and equipment, net		8,393		7,297
Other long-term assets		124		107
TOTAL ASSETS	$	9,177	$	8,048

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	690	$	507
Taxes payable		69		68
Interest payable		14		33
Current deferred income taxes		32		24
Derivative liabilities		36		7
Other current liabilities		47		49
Total current liabilities		888		688
Long-term debt		1,806		1,950
Deferred income taxes		1,913		1,532
Pension and other postretirement liabilities		17		16
Other long-term liabilities		260		240
Total long-term liabilities		3,996		3,738
Commitments and contingencies (Note 10)
Equity:
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 353,125,665 shares in 2014 and 352,938,584 in 2013		4		4
Additional paid-in capital		1,005		969
Retained earnings		3,265		2,653
Accumulated other comprehensive income (loss)		19		(4)
Total equity		4,293		3,622
TOTAL LIABILITIES AND EQUITY	$	9,177	$	8,048

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

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	For the nine months ended
	September 30,
	2014		2013
	(in millions)
Cash Flows From Operating Activities
Net income	$	612	$	559
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		693		571
Amortization of debt issuance cost		3		3
Deferred income taxes		375		373
(Gain) loss on derivatives excluding derivatives, settled		7		(72)
Stock-based compensation		13		9
Other		(3)		3
Change in assets and liabilities:
Accounts receivable		7		(67)
Inventories		2		(13)
Accounts payable		52		45
Taxes payable (receivable)		1		(15)
Interest payable		(10)		(8)
Advances from partners		–		(65)
Other assets and liabilities		22		55
Net cash provided by operating activities		1,774		1,378

Cash Flows From Investing Activities
Capital investments		(1,713)		(1,728)
Proceeds from sale of property and equipment		20		3
Transfers from restricted cash		–		9
Other		6		4
Net cash used in investing activities		(1,687)		(1,712)

Cash Flows From Financing Activities
Payments on current portion of long-term debt		(1)		(1)
Payments on revolving long-term debt		(3,573)		(2,135)
Borrowings under revolving long-term debt		3,429		2,378
Change in bank drafts outstanding		45		50
Proceeds from exercise of common stock options		10		7
Net cash (used in) provided by financing activities		(90)		299

Decrease in cash and cash equivalents		(3)		(35)
Cash and cash equivalents at beginning of year		23		54
Cash and cash equivalents at end of period	$	20	$	19

The accompanying notes are an integral part of these

unaudited condensed financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)

								Accumulated
	Common Stock			Additional				Other
	Shares			Paid-In		Retained		Comprehensive
	Issued	Amount		Capital		Earnings		Income (Loss)		Total
	(in millions)

Balance at December 31, 2013	353	$	4	$	969	$	2,653	$	(4)	$	3,622
Comprehensive income:
Net income	–		–		–		612		–		612
Other comprehensive income	–		–		–		–		23		23
Total comprehensive income	–		–		–		612		23		635

Stock-based compensation	–		–		26		–		–		26
Exercise of stock options	–		–		10		–		–		10
Balance at September 30, 2014	353	$	4	$	1,005	$	3,265	$	19	$	4,293

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Southwestern Energy Company (including its subsidiaries, collectively, “we”, “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production. The Company engages in natural gas and oil exploration and production, natural gas gathering and natural gas marketing through its subsidiaries. Southwestern’s exploration, development and production (“E&P”) activities are focused within the United States. The Company is actively engaged in exploration and production activities in Arkansas, where we are targeting the unconventional gas reservoir known as the Fayetteville Shale, in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Colorado, Louisiana, Texas and the Arkoma Basin in Arkansas and Oklahoma. The Company also actively seeks to find and develop new oil and natural gas plays with significant exploration and exploitation potential. Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania, Louisiana and Texas.

The accompanying unaudited condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report on Form 10-Q. The Company believes the disclosures made are adequate to make the information presented not misleading.

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Annual Report on Form 10-K”).

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s Board of Directors, are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s 2013 Annual Report on Form 10-K.

Certain reclassifications have been made to the prior year financial statements to conform to the 2014 presentation. The effects of the reclassifications were not material to the Company’s unaudited condensed consolidated financial statements.

(2) ACQUISITIONS AND DIVESTITURES

In March 2014 and July 2014, the Company entered into several agreements to purchase approximately 380,000 net acres in northwest Colorado principally in the Niobrara formation for approximately $213 million. The Company utilized its Credit Facility to finance these acquisitions. The Company closed the acquisitions in the second and third quarters and accounted for them as asset acquisitions.

In April 2013, the Company entered into a definitive purchase agreement to acquire natural gas properties located in Pennsylvania prospective for the Marcellus Shale for approximately $93 million, subject to closing conditions. The Company utilized its previous revolving credit facility to finance the acquisition. The Company closed on the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.

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(3) INVENTORY

Inventory recorded in current assets includes $33 million at September 30, 2014 and $34 million at December 31, 2013 for tubular and other equipment used in the Company’s E&P segment, and $2 million at September 30, 2014 and $4 million at December 31, 2013 for natural gas in underground storage owned by the E&P segment. Also included at September 30, 2014 was $2 million for natural gas in underground storage owned by Midstream Services segment.

Other long-term assets include $16 million at September 30, 2014 and $15 million at December 31, 2013, for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems.

(4) NATURAL GAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves, net of taxes, discounted at 10 percent plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Companies utilizing the full-cost method must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.24 per MMBtu and $95.56 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at September 30, 2014. Cash flow hedges of natural gas production in place increased the ceiling value by $14 million, net of tax, at September 30, 2014. Decreases in average quoted prices, adjusted for market differentials, from September 30, 2014 levels as well as changes in production rates, levels of reserves, capitalized costs, the evaluation of costs excluded from amortization, future development costs, service costs and taxes could result in future ceiling test impairments.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.60 per MMBtu and $91.56 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at September 30, 2013. Cash flow hedges of natural gas production in place increased the ceiling by $79 million, net of tax, at September 30, 2013.

All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program at September 30, 2014 were unproved and did not exceed the ceiling amount. If the exploration program in Canada is unsuccessful on all or a portion of these properties, including the effects of changes in laws or regulations due to the new government in New Brunswick or otherwise, a ceiling test impairment may result in the future.

(5) EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted earnings per share is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options were exercised and unvested restricted stock and performance unit awards were vested at the end of the applicable period.

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The following table presents the computation of earnings per share for the three and nine month periods ended September 30, 2014 and 2013:


	For the three months ended					For the nine months ended
	September 30,					September 30,
	2014		2013			2014			2013

Net income (in millions)	$	211		$	186		$	612		$	559

Number of common shares:
Weighted average outstanding		351,457,043			350,517,337			351,357,913			350,334,634
Issued upon assumed exercise of outstanding stock options		235,944			373,152			354,940			442,678
Effect of issuance of nonvested restricted common stock		514,668			332,341			484,786			237,662
Effect of issuance of nonvested performance units		119,595			–			136,907			–
Weighted average and potential dilutive outstanding (1)(2)		352,327,250			351,222,830			352,334,546			351,014,974

Earnings per share:
Basic	$	0.60		$	0.53		$	1.74		$	1.60

Diluted	$	0.60		$	0.53		$	1.74		$	1.59

⁽¹⁾

Options for 1,254,842 shares and 27,916 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2014 because they would have had an antidilutive effect. Options for 1,550,838 shares and 15,703 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2013 because they would have had an antidilutive effect.

⁽²⁾

Options for 1,111,128 shares and 24,215 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2014 because they would have had an antidilutive effect. Options for 1,848,566 shares and 169,261 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2013 because they would have had an antidilutive effect.

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(6) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas and crude oil which impacts the predictability of its cash flows related to the sale of natural gas and oil, and is exposed to volatility in interest rates. These risks are managed by the Company’s use of certain derivative financial instruments. At September 30, 2014 and December 31, 2013, the Company’s derivative financial instruments consisted of fixed price swaps, basis swaps, fixed price call options, and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:


Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty.

Basis swaps	Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

Fixed price call options	The Company sells fixed price call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess on sold fixed price call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

Interest rate swaps	Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.

GAAP requires that all derivatives be recognized in the balance sheet as either an asset or liability and be measured at fair value other than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings or as a component of other comprehensive income. Gains and losses on derivatives that are not designated for hedge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings as a component of gain (loss) on derivatives. Within the gain (loss) on derivatives component of the statement of operations are gains (losses) on derivatives excluding derivatives, settled and gains (losses) on derivatives, settled. The Company calculates gains (losses) on derivatives, settled, as the summation of gains and losses on positions which have settled within the period.

The Company utilizes counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

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The balance sheet classification of the assets related to derivative financial instruments are summarized below at September 30, 2014 and December 31, 2013:


	Derivative Assets
	September 30, 2014			December 31, 2013
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value

	(in millions)
Derivatives designated as hedging instruments:
Fixed price swaps	Derivative assets	$	52	Derivative assets	$	21
Fixed price swaps	Other long-term assets		11	Other long-term assets		–
Total derivatives designated as hedging instruments		$	63		$	21

Derivatives not designated as hedging instruments:
Basis swaps	Derivative assets	$	15	Derivative assets	$	13
Fixed price swaps	Derivative assets		50	Derivative assets		37
Basis swaps	Other long-term assets		3	Other long-term assets		–
Fixed price swaps	Other long-term assets		12	Other long-term assets		–
Interest rate swaps	Other long-term assets		3	Other long-term assets		8
Total derivatives not designated as hedging instruments		$	83		$	58

Total derivative assets		$	146		$	79

	Derivative Liabilities
	September 30, 2014			December 31, 2013
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value

	(in millions)
Derivatives designated as hedging instruments:
Fixed price swaps	Derivative liabilities	$	–	Derivative liabilities	$	4
Total derivatives designated as hedging instruments		$	–		$	4
Derivatives not designated as hedging instruments:
Basis swaps	Derivative liabilities	$	20	Derivative liabilities	$	2
Fixed price call options	Derivative liabilities		13	Derivative liabilities		–
Interest rate swaps	Derivative liabilities		3	Derivative liabilities		1
Basis swaps	Other long-term liabilities		3	Other long-term liabilities		–
Fixed price call options	Other long-term liabilities		28	Other long-term liabilities		30
Interest rate swaps	Other long-term liabilities		1	Other long-term liabilities		3
Total derivatives not designated as hedging instruments		$	68		$	36

Total derivative liabilities		$	68		$	40

As of September 30, 2014, the Company had fixed price swap derivatives designated as hedges and not designated as hedges on the following volumes of natural gas production (in Bcf):


Year	Fixed price swaps designated for hedge accounting	Fixed price swaps not designated for hedge accounting	Total
2014	71	46	117
2015	120	120	240

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Cash Flow Hedges

The reporting of gains and losses on cash flow derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gains and losses on the derivative hedging instruments are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from the derivative hedging instrument is recognized in earnings immediately.

As of September 30, 2014, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $36 million net of a deferred income tax liability of $24 million. The amount recorded in accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the physical transactions being hedged occur. Assuming the market prices of natural gas futures as of September 30, 2014 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of $30 million from accumulated other comprehensive income to earnings during the next 12 months. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to natural gas sales in the consolidated statements of operations. Volatility in net income, comprehensive income and accumulated other comprehensive income may occur in the future as a result of the Company’s derivative activities.

The following tables summarize the before tax effect of all cash flow hedges on the unaudited condensed consolidated financial statements for the three and nine month periods ended September 30, 2014 and 2013:


		Gain (Loss) Recognized in Other Comprehensive Income
		(Effective Portion)
		For the three months ended				For the nine months ended
		September 30,				September 30,
Derivative Instrument		2014		2013		2014		2013
		(in millions)

Fixed price swaps		$	80	$	13	$	(2)	$	51

	Classification of Gain (Loss)	Gain (Loss) Reclassified from Accumulated
	Reclassified from	Other Comprehensive Income
	Accumulated Other	into Earnings (Effective Portion)
	Comprehensive Income	For the three months ended				For the nine months ended
	into Earnings	September 30,				September 30,
Derivative Instrument	(Effective Portion)	2014		2013		2014		2013
		(in millions)
Fixed price swaps	Gas sales	$	18	$	93	$	(48)	$	218

		Gain (Loss) Recognized in Earnings
		(Ineffective Portion)
	Classification of Gain (Loss)	For the three months ended				For the nine months ended
	Recognized in Earnings	September 30,				September 30,
Derivative Instrument	(Ineffective Portion)	2014		2013		2014		2013
		(in millions)
Fixed price swaps	Gas sales	$	3	$	(1)	$	1	$	(2)

Other Derivative Contracts

For other derivative contracts, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately.

Although the Company’s basis swaps meet the objective of managing commodity price exposure, these trades are typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and therefore do not generally qualify for hedge accounting. Basis swap derivative instruments that are not designated for hedge accounting are recorded on the balance sheet at their fair values under derivative assets, other long-term assets,

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other current liabilities, and other long-term liabilities, as applicable and all gains and losses related to these contracts are recognized immediately in the consolidated statement of operations as a component of gain (loss) on derivatives.

As of September 30, 2014, the Company had basis swaps on natural gas production that were not designated for hedge accounting of 10 Bcf, 15 Bcf, and 4 Bcf in 2014, 2015, and 2016, respectively.

As of September 30, 2014, the Company had fixed price call options on 200 Bcf and 120 Bcf of natural gas production in 2015 and 2016, respectively, not designated for hedge accounting and fixed price swaps of 46 Bcf and 120 Bcf of natural gas production in 2014 and 2015, respectively, not designated for hedge accounting.

The Company is a party to interest rate swaps that were entered into in order to mitigate the Company’s exposure to volatility in interest rates related to construction of its new corporate office complex. The interest rate swaps build to a notional amount of $170 million and expire in June 2020. The Company did not designate the interest rate swaps for hedge accounting. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives in the consolidated statements of operations.

The following table summarizes the before tax effect of fixed price swaps, basis swaps, fixed price call options and interest rate swaps not designated for hedge accounting on the condensed consolidated statements of operations for the three and nine month periods ended September 30, 2014 and 2013:


		Gain (Loss) on Derivatives
		Excluding Derivatives, Settled
		Recognized in Earnings
		For the three months ended				For the nine months ended
	Consolidated Statement of Operations	September 30,				September 30,
Derivative Instrument	Classification of Gain (Loss) on Derivatives, Net of Settlement	2014		2013		2014		2013

		(in millions)

Basis swaps	Gain (Loss) on Derivatives	$	(3)	$	(5)	$	(16)	$	2
Fixed price call options	Gain (Loss) on Derivatives	$	11	$	8	$	(11)	$	(27)
Fixed price swaps	Gain (Loss) on Derivatives	$	45	$	8	$	24	$	96
Interest rate swaps	Gain (Loss) on Derivatives	$	1	$	(1)	$	(4)	$	1

		Gain (Loss)
		on Derivatives, Settled (1)
		Recognized in Earnings
	Consolidated Statement of Operations	For the three months ended				For the nine months ended
	Classification of Gain (Loss)	September 30,				September 30,
Derivative Instrument	on Derivatives, Settled (1)	2014		2013		2014		2013

		(in millions)

Basis swaps	Gain (Loss) on Derivatives	$	9	$	2	$	–	$	3
Fixed price swaps	Gain (Loss) on Derivatives	$	15	$	–		(21)		–
Interest rate swaps	Gain (Loss) on Derivatives	$	–	$	–	$	(1)	$	–

⁽¹⁾

The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period reported.

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(7) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects for the nine months ended September 30, 2014:


	For the nine months ended
	September 30, 2014
	(in millions) (1)
	Gains (Losses) on Cash Flow Hedges		Pension and Other Postretirement		Foreign Currency		Total


Balance at December 31, 2013	$	9	$	(9)	$	(4)	$	(4)

Other comprehensive loss before reclassifications		(1)		–		(4)		(5)

Amounts reclassified from accumulated other comprehensive loss (2)		28		–		–		28

Net current-period other comprehensive income (loss)		27		–		(4)		23

Balance at September 30, 2014	$	36	$	(9)	$	(8)	$	19

⁽¹⁾

All amounts are net of tax.

⁽²⁾

See separate table below for details about these reclassifications.

The following table details the amounts reclassified from accumulated other comprehensive income (loss) into earnings for the nine months ended September 30, 2014:


Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statement of Operations		Amount Reclassified from Accumulated Other Comprehensive Loss
			For the nine months ended September 30, 2014
			(in millions)
Gains (losses) on cash flow hedges
Settlements	Gas sales	$	(48)
Ineffectiveness	Gas sales		1
	Loss before income taxes		(47)
	Benefit for income taxes		(19)
	Net loss	$	(28)
Total reclassifications for the period	Net loss	$	(28)

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(8) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of September 30, 2014 and December 31, 2013 were as follows:


	September 30, 2014				December 31, 2013
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value

	(in millions)

Cash and cash equivalents	$	20	$	20	$	23	$	23
Credit facility	$	139	$	139	$	283	$	283
Senior notes	$	1,668	$	1,957	$	1,668	$	1,796
Derivative instruments	$	78	$	78	$	39	$	39

The carrying values of cash and cash equivalents, accounts receivable, accounts payable, other current assets and current liabilities on the unaudited condensed consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt: The fair values of the Company’s senior notes were based on the market for the Company’s publicly traded debt as determined based on yield of the Company’s 7.5% Senior Notes due 2018, which was 2.2% at September 30, 2014 and 2.6% at December 31, 2013, and its 4.10% Senior Notes due 2022, which was 3.6% at September 30, 2014, and 4.2% at December 31, 2013. The carrying value of the borrowings under the Company’s Credit Facility at September 30, 2014, approximates fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy.

Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

The Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s Level 2 fair value measurements include fixed-price swaps and are estimated using internal discounted cash flow calculations using the NYMEX futures index. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of September 30, 2014 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy. The Company’s Level 3 fair value measurements include fixed price call options and basis swaps. The Company’s fixed price call options are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves.

Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.

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Assets and liabilities measured at fair value on a recurring basis are summarized below:


	September 30, 2014
		(in millions)
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	128	$	18	$	146
Derivative liabilities		–		(4)		(64)		(68)
Total	$	–	$	124	$	(46)	$	78


	December 31, 2013
		(in millions)
	Fair Value Measurements Using:
	Quoted Prices		Significant
	in Active		Other		Significant
	Markets		Observable Inputs		Unobservable Inputs		Assets (Liabilities)
	(Level 1)		(Level 2)		(Level 3)		at Fair Value
Derivative assets	$	–	$	66	$	13	$	79
Derivative liabilities		–		(8)		(32)		(40)
Total	$	–	$	58	$	(19)	$	39

The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and nine month periods ended September 30, 2014 and September 30, 2013. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect the assumptions a reasonable marketplace participant would have used at September 30, 2014 and September 30, 2013.


	For the three months ended				For the nine months ended
	September 30,				September 30,
	2014		2013		2014		2013

	(in millions)

Balance at beginning of period	$	(55)	$	(28)	$	(19)	$	–
Total gains (losses):
Included in earnings		18		5		(27)		(22)
Included in other comprehensive income		–		–		–		–
Purchases, issuances, and settlements:
Purchases		–		–		–		–
Issuances		–		–		–		–
Settlements		(9)		(2)		–		(3)
Transfers into/out of Level 3		–		–		–		–
Balance at end of period	$	(46)	$	(25)	$	(46)	$	(25)
Change in gains (losses) included in earnings relating to derivatives still held as of September 30	$	9	$	3	$	(27)	$	(25)

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(9) DEBT

The components of debt as of September 30, 2014 and December 31, 2013 consisted of the following:


	September 30,		December 31,
	2014		2013
	(in millions)
Short-term debt:
7.15% Senior Notes due 2018	$	1	$	1
Total short-term debt		1		1

Long-term debt:
Variable rate (1.50% and 1.64% at September 30, 2014 and December 31, 2013, respectively) Credit Facility, expires December 2018		139		283
7.35% Senior Notes due 2017		15		15
7.125% Senior Notes due 2017		25		25
7.15% Senior Notes due 2018		28		28
7.5% Senior Notes due 2018		600		600
4.10% Senior Notes due 2022		1,000		1,000
Unamortized discount		(1)		(1)
Total long-term debt		1,806		1,950

Total debt	$	1,807	$	1,951

Credit Facility

Our credit facility provides a borrowing capacity of up to $2.0 billion and matures on December 2018 (“Credit Facility”), with options for two one-year extensions with participating lender approval. The amount available under the Credit Facility may be increased by $500 million upon our agreement with our participating lenders. The interest rate on the Credit Facility is calculated based on our credit rating and is currently 137.5 basis points over the current LIBOR. The Credit Facility is unsecured and is not guaranteed by any of our subsidiaries. The Credit Facility contains covenants that impose certain restrictions on us, including a financial covenant under which we may not issue total debt in excess of 60% of our total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments (after December 31, 2011), certain hedging activities and our pension and other postretirement liabilities. As of September 30, 2014, we were in compliance with the covenants of our Credit Facility and other debt agreements.

(10) COMMITMENTS AND CONTINGENCIES

Commitments

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47 million Canadian dollars in the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of $45 million Canadian dollars. The promissory notes secure the Company’s capital expenditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to perform fully, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration program in 2010 and, as of September 30, 2014 has invested $44 million Canadian dollars, or $44 million US dollars, in New Brunswick towards the Company’s commitment. With extensions, our exploration license agreements are currently scheduled to expire on March 16, 2015. No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of September 30, 2014 and its future investment plans.

The Company enters into natural gas transportation and gathering arrangements with third party pipelines in support of the Company’s production in the Marcellus Shale. As of September 30, 2014, the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $3.8 billion and the Company has guarantee obligations of up to $100 million of that amount.

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Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or reported results of operations of the Company.

Litigation

Tovah Energy

In February 2009, Southwestern Energy Production Company (“SEPCO”) was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al., pending in the 273rd District Court in Shelby County, Texas. By the time of trial in December 2010, Ms. Berry-Helfand (the only remaining plaintiff) alleged that, in 2005, she provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, she alleged various statutory and common law claims, including, but not limited to, claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006. She also sought disgorgement of SEPCO’s profits. A former associate of the plaintiff intervened in the matter claiming to have helped develop the prospect years earlier.

The jury found in favor of the plaintiff and the intervenor with respect to all of the statutory and common law claims and awarded $11 million in compensatory damages but no special, punitive or other damages. Separately, the jury determined that SEPCO’s profits for purposes of disgorgement, if ordered as a remedy, were $382 million. (Disgorgement of profits is an equitable remedy determined by the judge, and it is within the judge’s discretion to award none, some or all of unlawfully obtained profits.) In August 2011, a judgment was entered pursuant to which the plaintiff and the intervenor were entitled to recover approximately $11 million in actual damages and approximately $24 million in disgorgement as well as prejudgment interest and attorneys’ fees, which currently are estimated to be up to $9 million, and all costs of court of the plaintiff and intervenor.

Both sides appealed and in July 2013, the Texas Court of Appeals in Tyler ordered that (1) the judgment awarding the plaintiff and the intervenor $24 million as disgorgement of illicit gains be reversed and judgment rendered that they take nothing, (2) the award of $11 million for actual damages, insofar as it is based on the jury’s findings of breach of fiduciary duty, fraud, breach of contract, and theft of trade secret be reversed and judgment rendered that the plaintiff and the intervenor take nothing under those theories of recovery, (3) the award of $11 million to the plaintiff and the intervenor as damages for misappropriation of trade secret be affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for SEPCO as the prevailing party under the Texas Theft Liability Act, and (5) in all other respects, the judgment is affirmed. All parties petitioned for rehearing. The Court of Appeals denied rehearing in November 2013.

SEPCO filed a petition for review in the Supreme Court of Texas in February 2014. The plaintiff and the intervenor filed cross-petition for review in April 2014, but conditioned their filing on the court’s granting SEPCO’s petition for review; i.e., if the court denies SEPCO’s petition for review, then the plaintiff and the intervenor are not seeking further review of the court of appeals’ judgment. Based on the Company’s understanding and judgment of the facts and merits of this case, including appellate matters, and after considering the advice of counsel, the Company has determined that, although reasonably possible, a materially adverse final outcome to this action is not probable. As such, the Company has not accrued any amounts with respect to this action. If the Supreme Court declines to hear the case or affirms all aspects of the court of appeals’ judgment, then SEPCO would owe the $11 million in damages, plus interest and attorney’s fees, offset by any award of attorneys’ fees for its prevailing on the theft count. The Company’s assessment may change in the future due to occurrence of certain events, such as the result of the petition or petitions for review at the Supreme Court of Texas, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.

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Arkansas Royalty Litigation

The Company is a defendant in three cases, two filed in Arkansas state court and one in federal court, on behalf of putative classes of royalty owners on some of our leases located in Arkansas. The chief complaint in all three cases is that the Company underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases. The Company removed the two cases filed in state court to federal court, but both were remanded to state court during the third quarter of 2014; the appeal of those remand orders is ongoing. Despite the ongoing appeal of the remand, in September and October 2014 the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas. The Company is appealing those orders. Discovery regarding the plantiffs’ theories of liability and amount of claimed damages is in the very early stages. Management believes that the deductions from royalty payments as calculated are permitted and intends to defend the cases vigorously. The Company’s assessment may change in the future due to the occurrence of certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.

Other

The Company is subject to various other litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on the Company’s financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.

(11) SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Supplemental disclosures of cash flow information:


	For the three months ended				For the nine months ended
	September 30,				September 30,
	2014		2013		2014		2013

	(in millions)

Cash paid for interest (1)	$	45	$	45	$	95	$	95
Cash paid for income taxes	$	–	$	1	$	–	$	19
Noncash property and equipment changes	$	57	$	(12)	$	128	$	34

⁽¹⁾

Cash paid for interest includes capitalized interest of $14 million and $15 million for the three months ended September 30, 2014 and 2013, respectively, and capitalized interest of $40 million and $48 million for the nine months ended September 30, 2014 and 2013, respectively.

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(12) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company has defined pension and postretirement benefit plans which cover substantially all of the Company’s employees. Net periodic pension costs include the following components for the three and nine months ended September 30, 2014 and 2013:


	Pension Benefits
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
	(in millions)

Service cost	$	3	$	3	$	10	$	10
Interest cost		1		1		4		3
Expected return on plan assets		(1)		(1)		(5)		(4)
Amortization of prior service cost		–		–		–		–
Amortization of net loss		–		–		–		1

Net periodic benefit cost	$	3	$	3	$	9	$	10

The Company’s postretirement benefit plan had a net periodic benefit cost of $1, $1, $2 and $2 million as of the three months ended September 30, 2014 and 2013 and nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014, the Company has contributed $9 million to the pension plan, and expects to contribute an additional $3 million to the pension plan in 2014.

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are presented as treasury stock and totaled 10,763 shares at September 30, 2014 compared to 9,924 shares at December 31, 2013.

(13) STOCK-BASED COMPENSATION

The Company recognized the following amounts in employee stock-based compensation costs for the three and nine months ended September 30, 2014 and 2013:


	For the three months ended				For the nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
	(in millions)

Stock-based compensation cost – expensed	$	4	$	3	$	13	$	9
Stock-based compensation cost – capitalized	$	4	$	3	$	13	$	9

As of September 30, 2014, there was $64 million of total unrecognized compensation cost related to the Company’s unvested stock option grants, restricted stock grants, and performance units. This cost is expected to be recognized over a weighted-average period of 3 years.

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The following table summarizes stock option activity for the nine months ended September 30, 2014 and provides information for options outstanding and options exercisable as of September 30, 2014:


		Weighted
		Average
	Number	Exercise
	of Options	Price
	(in thousands)
Outstanding at December 31, 2013	3,313	$	35.70
Granted	90		46.55
Exercised	(279)		32.07
Forfeited or expired	(102)		38.42
Outstanding at September 30, 2014	3,022		36.27
Exercisable at September 30, 2014	1,844	$	35.39

The following table summarizes restricted stock activity for the nine months ended September 30, 2014 and provides information for unvested shares as of September 30, 2014:


		Weighted
		Average
	Number	Grant Date
	of Shares	Fair Value
	(in thousands)
Unvested shares at December 31, 2013	1,771	$	37.55
Granted	25		45.81
Vested	(22)		36.62
Forfeited	(117)		37.94
Unvested shares at September 30, 2014	1,657	$	37.66

The following table summarizes performance unit activity to be paid out in Company stock for the nine months ended September 30, 2014 and provides information for unvested units as of September 30, 2014. The performance units include a market condition based on Relative Total Shareholder Return (“TSR”) and a performance condition based on the Company's Present Value Index (“PVI”). The fair value of the TSR market condition of the performance units is based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI performance condition of the performance units is based on the closing price of the Company's common stock at the grant date and amortized to compensation expense on a straight line basis over the vesting period of the award.


		Weighted
		Average
	Number	Grant Date
	of Units	Fair Value
	(in thousands)
Unvested units at December 31, 2013	–	$	–
Granted	359		40.44
Vested	–		–
Forfeited	(25)		40.44
Unvested units at September 30, 2014	334	$	40.44

Liability-Classified Performance Units

Certain employees were provided performance units vesting equally over three years. The payout of these units is based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goal. At the end of each performance period, the value of the vested performance units, if any, is paid in cash. As of September 30, 2014 and December 31, 2013, the Company’s liability under the performance unit agreements was $48 million and $45 million, respectively.

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(14) SEGMENT INFORMATION

The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and crude oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas volumes and through gathering fees associated with the transportation of natural gas to market.

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 2013 Annual Report on Form 10-K. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, and other income (loss). The “Other” column includes items not related to the Company’s reportable segments including real estate and corporate items.


	Exploration
	and		Midstream
	Production		Services		Other			Total

	(in millions)
Three months ended September 30, 2014:
Revenues from external customers	$	652	$	276	$	–		$	928
Intersegment revenues		3		707		–			710
Operating income		189		97		–			286
Gain (loss) on derivatives		79		–		(1)			78
Depreciation, depletion and amortization expense		223		15		–			238
Interest expense(1)		10		2		1			13
Provision (benefit) for income taxes(1)		107		34		(1)			140
Assets		7,461		1,494		222	(2)		9,177
Capital investments(3)		531		34		9			574

Three months ended September 30, 2013:
Revenues from external customers	$	622	$	246	$	–		$	868
Intersegment revenues		1		601		–			602
Operating income		223		86		–			309
Gain on derivatives		11		1		–			12
Depreciation, depletion and amortization expense		192		13		–			205
Interest expense(1)		9		2		–			11
Provision for income taxes(1)		88		36		–			124
Assets		6,265		1,388		241	(2)		7,894
Capital investments(3)		496		40		6			542

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	Exploration
	and		Midstream
	Production		Services		Other			Total
	(in millions)
Nine months ended September 30, 2014:
Revenues from external customers	$	2,169	$	907	$	–		$	3,076
Intersegment revenues		13		2,437		–			2,450
Operating income (loss)		817		272		(1)			1,088
Other gain, net		1		–		–			1
Loss on derivatives		(27)		(1)		(1)			(29)
Depreciation, depletion and amortization expense		650		43		–			693
Interest expense(1)		29		9		1			39
Provision (benefit) for income taxes(1)		309		101		(1)			409
Assets		7,461		1,494		222	(2)		9,177
Capital investments(3)		1,706		109		22			1,837

Nine months ended September 30, 2013:
Revenues from external customers	$	1,749	$	715	$	–		$	2,464
Intersegment revenues		4		1,740		–			1,744
Operating income		651		235		–			886
Gain on derivatives		74		1		–			75
Depreciation, depletion and amortization expense		534		37		–			571
Interest expense(1)		21		8		–			29
Provision for income taxes(1)		282		91		–			373
Assets		6,265		1,388		241	(2)		7,894
Capital investments(3)		1,603		135		17			1,755

⁽¹⁾

Interest expense and the provision for income taxes by segment are allocated as they are incurred at the corporate level.

⁽²⁾

Other assets represent corporate assets not allocated to segments and assets for non reportable segments.

⁽³⁾

Capital investments includes increases of $53 million and decreases of $15 million for the three month periods ended September 30, 2014 and 2013, respectively, and increases of $114 million and $26 million for the nine month periods ended September 30, 2014 and 2013, respectively, relating to the change in accrued expenditures between periods.

Included in intersegment revenues of the Midstream Services segment are $612 million and $515 million for the three months ended September 30, 2014 and 2013, respectively, and $2,161 million and $1,494 million for the nine months ended September 30, 2014 and 2013, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures, prepaid debt and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments. At September 30, 2014, E&P segment assets included $78 million and at September 30, 2013, E&P segment assets included $65 million related to the Company’s activities in Canada.

(15) NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. Topic 606 Revenue from Contracts with Customers will supersede the revenue recognition requirements in Topic 605 Revenue Recognition. Update 2014-09 requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled for those goods or services. Entities may apply the amendments in Update 2014-09 either (a) retrospectively to each prior reporting period presented, and the entity may elect a practical expedient per the Update, or (b) retrospectively with the cumulative effect of initially applying Update 2014-09 recognized at the date of initial application - if an entity elects this transition method it also should provide the additional disclosures in reporting periods. For public entities, Update 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. We are currently evaluating the provisions of Update 2014-09 and assessing the impact, if any, it may have on the Company’s consolidated results of operations, financial position or cash flows.

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In June 2014, the FASB issued Accounting Standards Update No. 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period (“Update 2014-12”), which clarifies the accounting treatment of such awards in practice. Update 2014-12 requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. Update 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015, and early adoption is permitted. We are currently evaluating the provisions of Update 2014-12 and assessing the impact, if any, it may have on the Company’s consolidated results of operations, financial position or cash flows.

(16) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

As of December 16, 2013, following the release of all guarantees under the 7.15%, 7.5%, 7.35%, 7.125%, and 4.10% Senior Notes and our former revolving credit facility upon entering into the new Credit Facility, all of our wholly-owned subsidiaries have been released of their guarantees. Prior to that date, the Company’s obligation under registered public debt and outstanding senior notes as listed in Note 9 were fully and unconditionally guaranteed, jointly and severally, by all of our wholly owned subsidiaries, other than minor subsidiaries, on a senior unsecured basis, and the Company, as a parent company, had no independent assets or operations. The subsidiary guarantees (i) ranked equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) ranked senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) were effectively subordinated to any future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) were structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors. In the case of each series of notes, if no default or event of default had occurred and was continuing, these guarantees would have been released (i) automatically upon any sale, exchange or transfer of all the Company’s interest in the guarantor; (ii) automatically upon the liquidation and dissolution of a guarantor; (iii) following delivery of notice to the trustee of the release of the guarantor of its obligation under the Company’s revolving credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes. In addition, there were no significant restrictions on the ability of the Company or a guarantor to obtain funds from its subsidiaries by dividend or loan, and none of the assets of the Company or a guarantor represented restricted net assets pursuant to rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.

The Company is providing condensed consolidating financial information for SEECO, SEPCO, and SES, its subsidiaries that were guarantors of the Company’s registered public debt and outstanding senior notes, and for its other subsidiaries that were not guarantors of such debt for the three and nine months ended September 30, 2013, as applicable. The Company has not provided comparative financial statements for 2014 because all guarantees were released in 2013. The Company has not presented separate financial and narrative information for each of the former subsidiary guarantors because it believes that such financial and narrative financial information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees. The following condensed consolidating financial information summarizes the results of operations and cash flow for the Company’s former guarantors and other subsidiaries.

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Unaudited)

	Parent		Former Guarantors		Other Subsidiaries		Eliminations		Consolidated
	(in millions)
Three months ended September 30, 2013:
Operating revenues	$	–	$	823	$	131	$	(86)	$	868
Operating costs and expenses:
Gas purchases – midstream services		–		195		–		–		195
Operating expenses		–		140		36		(86)		90
General and administrative expenses		–		44		7		–		51
Depreciation, depletion and amortization		–		192		13		–		205
Taxes, other than income taxes		–		16		2		–		18
Total operating costs and expenses		–		587		58		(86)		559
Operating income		–		236		73		–		309
Gain on derivatives		–		10		2		–		12
Equity in earnings of subsidiaries		186		–		–		(186)		–
Interest expense		–		9		2		–		11
Income before income taxes		186		237		73		(186)		310
Provision for income taxes		–		91		33		–		124
Net income		186		146		40		(186)		186
Comprehensive income	$	139	$	98	$	41	$	(139)	$	139


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Unaudited)

	Parent		Former Guarantors		Other Subsidiaries		Eliminations		Consolidated
	(in millions)
Nine months ended September 30, 2013:
Operating revenues	$	–	$	2,331	$	379	$	(246)	$	2,464
Operating costs and expenses:
Gas purchases – midstream services		–		575		–		–		575
Operating expenses		–		376		107		(246)		237
General and administrative expenses		–		117		19		–		136
Depreciation, depletion and amortization		–		534		37		–		571
Taxes, other than income taxes		–		50		9		–		59
Total operating costs and expenses		–		1,652		172		(246)		1,578
Operating income		–		679		207		–		886
Gain on derivatives		–		74		1		–		75
Equity in earnings of subsidiaries		559		–		–		(559)		–
Interest expense		–		24		5		–		29
Income before income taxes		559		729		203		(559)		932
Provision for income taxes		–		291		82		–		373
Net income		559		438		121		(559)		559
Comprehensive income	$	458	$	337	$	120	$	(457)	$	458

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

	Parent		Former Guarantors		Other Subsidiaries			Eliminations			Consolidated
	(in millions)

Nine months ended September 30, 2013:
Net cash provided by (used in) operating activities	$	(33)	$	1,062		$	349		$	–		$	1,378
Investing activities:
Capital investments		(29)		(1,531)			(168)			–			(1,728)
Proceeds from sale of property and equipment		–		–			3			–			3
Transfers from restricted cash		9		–			–			–			9
Other		(1)		(2)			7			–			4
Net cash used in investing activities		(21)		(1,533)			(158)			–			(1,712)
Financing activities:
Intercompany activities		(275)		465			(190)			–			–
Payments on current portion of long-term debt		(1)		–			–			–			(1)
Payments on revolving long-term debt		(2,135)		–			–			–			(2,135)
Borrowings under revolving long-term debt		2,378		–			–			–			2,378
Other items		57		–			–			–			57
Net cash provided by (used in) financing activities		24		465			(190)			–			299
Increase (decrease) in cash and cash equivalents		(30)		(6)			1			–			(35)
Cash and cash equivalents at beginning of year		48		6			–			–			54
Cash and cash equivalents at end of period	$	18	$	–		$	1		$	–		$	19

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(17) SUBSEQUENT EVENTS

On October 16, 2014, we announced that we have signed a purchase and sale agreement with Chesapeake Energy Corporation to acquire certain oil and gas assets covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, natural gas liquids and crude oil contained in the Upper Devonian, Marcellus and Utica shales for approximately $5.375 billion. The transaction is subject to consent of the principal co-owner of this acreage, which also has a 30-day preferential right to purchase, and to other customary conditions and is currently expected to close by year-end. We have received a commitment from Bank of America, N.A. for a $5.0 billion 364-day senior unsecured bridge term loan credit facility that, together with the Company’s existing revolving credit facility, is available to fund the transaction.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following updates information as to Southwestern Energy Company’s financial condition provided in our 2013 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three and nine months ended September 30, 2014 and 2013. For definitions of commonly used natural gas and oil terms used in this Form 10-Q, please refer to the “Glossary of Certain Industry Terms” provided in our 2013 Annual Report on Form 10-K.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in the “Cautionary Statement About Forward-Looking Statements” in the forepart of this Form 10-Q, in Item 1A, “Risk Factors” in Part I and elsewhere in our 2013 Annual Report on Form 10-K, and Item 1A, “Risk Factors” in Part II in this Form 10-Q and any other Form 10-Q filed during the fiscal year. You should read the following discussion with our unaudited condensed consolidated financial statements and the related notes included in this Form 10-Q.

OVERVIEW

Background

Southwestern Energy Company is an independent energy company engaged in natural gas and oil exploration, development and production, or E&P. We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services. We operate principally in two segments: E&P and Midstream Services.

Our primary business is the exploration for and production of natural gas and oil, with our current operations being focused within the United States. We are actively engaged in exploration and production activities in Arkansas, where we are targeting the unconventional gas reservoir known as the Fayetteville Shale, in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Colorado, Louisiana, Texas and in the Arkoma Basin in Arkansas and Oklahoma. The Company also actively seeks to find and develop new oil and natural gas plays with significant exploration and exploitation potential. In 2010, we commenced an exploration program in New Brunswick, Canada, which represents our first operations outside of the United States.

We are focused on providing long-term growth in the net asset value of our business. We derive the majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future. We expect that growth in our operating income and revenues will depend primarily on natural gas prices and our ability to increase our natural gas production. We expect our natural gas production volumes will continue to increase due to our ongoing development of the Fayetteville Shale and the Marcellus Shale. The price we expect to receive for our natural gas is a critical factor in the capital investments we make in order to develop our properties and increase our production. In recent years, there has been volatility in natural gas prices as evidenced by New York Mercantile Exchange, or NYMEX, natural gas prices ranging from a high of $13.58 per MMBtu in 2008 to a low of $1.91 per MMBtu in 2012. Natural gas prices fluctuate due to a variety of factors we cannot control or predict. These factors, which include increased supplies of natural gas due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which in turn determines the sales prices for our production. In addition to the factors identified above, the prices we realize for our production are affected by our hedging activities, transportation costs, as well as locational differences in market prices.

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Three Months Ended September 30, 2014 Compared with Three Months Ended September 30, 2013

We reported net income of $211 million for the three months ended September 30, 2014, or $0.60 per diluted share, compared to net income of $186 million, or $0.53 per diluted share, for the comparable period in 2013. For the three months ended September 30, 2014, the Company had a mark to market gain on derivatives of $78 million. Excluding mark to market derivatives, settled, this gain was $54 million ($33 million, net of taxes). Net income of $211 million less this tax effected gain of $33 million results in adjusted net income of $178 million for the three months ended September 30, 2014. For the three months ended September 30, 2013, the Company had a mark to market gain on derivatives of $12 million. Excluding mark to market derivatives, settled, this gain was $10 million ($6 million, net of taxes). Net income of $186 million less this tax effected gain of $6 million results in adjusted net income of $180 million for the three months ended September 30, 2013.

Our natural gas and oil production increased to 196 Bcfe for the three months ended September 30, 2014, up 14% from 172 Bcfe for the three months ended September 30, 2013. This 24 Bcfe increase was due to a 21 Bcf increase in net production from our Marcellus Shale properties and a 3 Bcf increase in net production from our Fayetteville Shale properties. The average price realized for our gas production, including the effects of hedges, decreased 5% to $3.43 per Mcf for the three months ended September 30, 2014 compared to $3.61 per Mcf for the same period in 2013.

Operating income for our Midstream Services segment was $97 million for the three months ended September 30, 2014, up from $86 million for the three months ended September 30, 2013, due to an increase of $12 million in gas gathering revenues and an increase of $3 million in the margin generated from our natural gas marketing activities, which was partially offset by a $4 million increase in operating costs and expenses.

Capital investments were $574 million for the three months ended September 30, 2014, of which $531 million was invested in our E&P segment, compared to $542 million for the same period of 2013, of which $496 million was invested in our E&P segment.

Nine Months Ended September 30, 2014 Compared with Nine Months Ended September 30, 2013

We reported net income of $612 million for the nine months ended September 30, 2014, or $1.74 per diluted share, compared to net income of $559 million, or $1.59 per diluted share, for the comparable period in 2013. For the nine months ended September 30, 2014, the Company had a mark to market loss on derivatives of $29 million. Excluding mark to market derivatives, settled, this loss was $7 million ($4 million, net of taxes). Net income of $612 million plus this tax effected loss of $4 million results in adjusted net income of $616 million for the nine months ended September 30, 2014. For the nine months ended September 30, 2013, the Company had a mark to market gain on derivatives of $75 million. Excluding mark to market derivatives, settled, this gain was $72 million ($43 million, net of taxes). Net income of $559 million less this tax effected gain of $43 million results in adjusted net income of $516 million.

Our natural gas and oil production increased to 567 Bcfe for the nine months ended September 30, 2014, up 18% from 480 Bcfe for the nine months ended September 30, 2013. This 87 Bcfe increase was due to a 83 Bcf increase in net production from our Marcellus Shale properties and a 6 Bcf increase in net production from our Fayetteville Shale properties, which more than offset a 2 Bcfe decrease in net production from our other properties. The average price realized for our gas production, including the effects of hedges, increased 4% to $3.79 per Mcf for the nine months ended September 30, 2014 compared to $3.64 per Mcf for the same period in 2013.

Our E&P segment reported operating income of $817 million for the nine months ended September 30, 2014, up from an operating income of $651 million for the nine months ended September 30, 2013. This increase was a result of the revenue impact of our 18%, or 87 Bcfe, increase in production and a 4%, or $0.15 per Mcf, increase in our realized natural gas prices, partially offset by an increase in operating costs and expenses of $263 million associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale and Marcellus Shale assets.

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Operating income for our Midstream Services segment was $272 million for the nine months ended September 30, 2014, up from $235 million for the nine months ended September 30, 2013, due to an increase of $39 million in gas gathering revenues and an increase of $10 million in the margin generated from our gas marketing activities, which was partially offset by an $12 million increase in operating costs and expenses associated with an increase in gas volumes gathered, exclusive of gas purchase costs.

Capital investments were $1,837 million for the nine months ended September 30, 2014, of which $1,706 million was invested in our E&P segment, compared to $1,755 million for the same period of 2013, of which $1,603 million was invested in our E&P segment.

RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, income tax expense and stock-based compensation are discussed on a consolidated basis.


Exploration and Production
	For the three months				For the nine months
	ended September 30,				ended September 30,
	2014		2013		2014		2013
	($ in millions, except per unit amounts)

Revenues	$	655	$	623	$	2,182	$	1,753
Operating costs and expenses	$	466	$	400	$	1,365	$	1,102
Operating income	$	189	$	223	$	817	$	651
Gain (loss) on derivatives (1)	$	24	$	2	$	(21)	$	3

Gas production (Bcf)		196		172		566		479
Oil production (MBbls)		51		37		114		102
NGL production (MBbls)		11		12		27		40
Total production (Bcfe)		196		172		567		480

Average realized gas price per Mcf, including hedges (2)	$	3.43	$	3.61	$	3.79	$	3.64
Average realized gas price per Mcf, excluding hedges	$	3.21	$	3.06	$	3.91	$	3.18
Average oil price per Bbl	$	97.71	$	106.72	$	100.39	$	105.05
Average NGL price per Bbl	$	35.57	$	42.05	$	40.73	$	44.20

Average unit costs per Mcfe:
Lease operating expenses	$	0.91	$	0.87	$	0.91	$	0.85
General & administrative expenses	$	0.23	$	0.24	$	0.24	$	0.23
Taxes, other than income taxes	$	0.10	$	0.09	$	0.11	$	0.10
Full cost pool amortization	$	1.09	$	1.07	$	1.10	$	1.07

⁽¹⁾

Represents the gain (loss) on derivatives, settled, associated with derivatives not designated or not qualifying for hedge accounting.

⁽²⁾

Including the gain (loss) on derivatives excluding derivatives, settled effects of commodity hedging contracts not designated for hedge accounting, results in an average price of $3.71, $3.68, $3.78, and $3.79 per Mcf for the three months ended September 30, 2014 and 2013, and the nine months ended September 30, 2014 and 2013, respectively.

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Revenues

Revenues for our E&P segment were $655 million for the three months ended September 30, 2014, up $32 million, or 5%, compared to the same period in 2013. Higher natural gas production volume increased revenues by $85 million and was partially offset by a decrease of $53 million due to a decline in the prices realized from the sale of our natural gas. E&P revenues were $2.2 billion for the nine months ended September 30, 2014, up $429 million, or 24%. The increase in revenue was driven by a $315 million increase from higher natural gas production volumes and a $114 million increase from higher realized prices from the sale of our natural gas production. We expect our natural gas production volumes to continue to increase due to our development and growth of our shale properties. Natural gas prices are difficult to predict and subject to wide price fluctuations. As of September 30, 2014, we had hedged 117 Bcf of our remaining 2014 natural gas production and 240 Bcf of our 2015 natural gas production to limit our exposure to price fluctuations. We refer you to Note 6 to the unaudited condensed consolidated financial statements included in this Form 10-Q and to the discussion of “Commodity Prices” provided below for additional information.

Production

For the three months ended September 30, 2014, our natural gas and oil production increased 14% to 196 Bcfe, up from 172 Bcfe from the same period in 2013, and was produced entirely by our properties in the United States. The 24 Bcfe increase in our 2014 production was due to a 21 Bcf increase in net production from our Marcellus Shale properties and a 3 Bcf increase in net production from our Fayetteville Shale properties. Net production from our Fayetteville Shale and Marcellus Shale properties was 126 Bcf and 66 Bcf, respectively, for the three months ended September 30, 2014 compared to 123 Bcf and 45 Bcf, respectively, for the same period in 2013. For the nine months ended September 30, 2014, our natural gas and oil production increased 18% to 567 Bcfe, up from 480 Bcfe from the same period in 2013, and was produced entirely by our properties in the United States. The 87 Bcfe increase in our 2014 production was due to a 83 Bcf increase in net natural gas production from our Marcellus Shale properties and a 6 Bcf increase in net production from our Fayetteville Shale assets, which more than offset a 2 Bcfe decrease in our other properties. Net production from our Fayetteville Shale and Marcellus Shale properties was 369 Bcf and 185 Bcf, respectively, for the nine months ended September 30, 2014 compared to 363 Bcf and 102 Bcf, respectively, for the same period in 2013.

Commodity Prices

The average price realized for our natural gas production, including the effects of hedges, decreased to $3.43 per Mcf for the three months ended September 30, 2014, as compared to $3.61 for the same period in 2013. The decrease was the result of lower proceeds from our hedge program during the three months ended September 30, 2014 as compared to the same period in 2013, which was partially offset by a $0.15 per Mcf increase in the average natural gas prices, excluding hedges. The average price realized for our natural gas production, excluding the effects of hedges, increased 5% to $3.21 per Mcf for the three months ended September 30, 2014, as compared to the same period in 2013. Our hedges increased the average realized natural gas price $0.22 per Mcf for the three months ended September 30, 2014 compared to an increase of $0.55 per Mcf for the same period in 2013. The average price realized for our natural gas production, including the effects of hedges, increased 4% to $3.79 per Mcf for the nine months ended September 30, 2014, as compared to the same period in 2013. The increase in the average price realized for nine months ended September 30, 2014, as compared to the same period in 2013, primarily reflects the $0.73 per Mcf increase in average gas prices, excluding hedges, which was partially offset by the effect of hedging activities. Our hedging activities decreased the average natural gas price $0.12 per Mcf for the nine months ended September 30, 2014 compared to an increase of $0.46 per Mcf for the same period in 2013. We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude oil production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational basis differentials We refer you to Item 3, “Quantitative and Qualitative Disclosures About Market Risks” and Note 6 to the unaudited condensed consolidated financial statements included in this Form 10-Q for additional discussion.

Our E&P segment typically receives a sales price for our natural gas at a discount to average monthly NYMEX settlement prices due to locational basis differentials, while transportation charges and fuel charges also reduce the price received. Excluding the impact of hedges, the average price received for our natural gas production for the nine months ended September 30, 2014 of $3.91 per Mcf was approximately $0.64 lower than the average monthly NYMEX settlement price, primarily due to locational basis differentials and transportation costs. We protected approximately 50% of our natural gas production for the nine months ended September 30, 2014 from the impact of widening basis differentials through our hedging activities and sales arrangements. At September 30, 2014, we had basis protected on approximately 101 Bcf of our remaining 2014 expected natural gas production through financial hedging activities and

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physical sales arrangements at a differential to NYMEX natural gas prices of approximately $0.01 per Mcf, excluding transportation and fuel charges. Additionally, at September 30, 2014, we had basis protected on approximately 256 Bcf and 130 Bcf of our 2015 and 2016 expected natural gas production, respectively, through financial hedging activities and physical sales arrangements.

In addition to the basis hedges discussed above, at September 30, 2014, we had NYMEX fixed price hedges in place on notional volumes of 117 Bcf of our remaining 2014 natural gas production at an average price of $4.35 per MMBtu and notional volumes of 240 Bcf of our 2015 natural gas production at an average price of $4.40 per MMBtu.

Operating Income

Our E&P segment reported operating income of $189 million for the three months ended September 30, 2014, down from operating income of $223 million for the three months ended September 30, 2013. This decrease was as a result of the 5%, or $0.18 per Mcf decrease in our realized natural gas prices and a $66 million increase in operating costs and expenses that resulted from increased activity levels, offset by the revenue impact of our 14%, or 24 Bcfe, increase in production. Our E&P segment reported operating income of $817 million for the nine months ended September 30, 2014, up from an operating income of $651 million for the nine months ended September 30, 2013. This increase was a result of the revenue impact of our 18%, or 87 Bcfe, increase in production and a 4%, or $0.15 per Mcf, increase in our realized natural gas prices, offset by an increase in operating costs and expenses of $263 million primarily associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale and Marcellus Shale assets.

Operating Costs and Expenses

Lease operating expenses per Mcfe for our E&P segment were $0.91 for the three months ended September 30, 2014 compared to $0.87 for the same period in 2013. Lease operating expenses per Mcfe for our E&P segment were $0.91 for the nine months ended September 30, 2014 compared to $0.85 for the same period in 2013. The increase in lease operating expense per unit of production for the three and nine months ended September 30, 2014 as compared to the same period of 2013 was primarily due to an increase in gathering costs and an increase in compression costs in our Fayetteville Shale and Marcellus Shale assets as a result of higher natural gas prices.

General and administrative expenses per Mcfe for our E&P segment were $0.23 for the three months ended September 30, 2014 compared to $0.24 for the same period in 2013 primarily due to an increase in production volumes. General and administrative expenses per Mcfe were $0.24 for the nine months ended September 30, 2014 compared to $0.23 for same period in 2013 primarily due to an increase in personnel costs. In total, general and administrative expenses for our E&P segment were $44 million and $134 million for the three and nine months ended September 30, 2014, compared to $42 million and $112 million for the three and nine months ended September 30, 2013, primarily due to increased personnel costs associated with the expansion of our E&P operations due to the continued development of our Fayetteville Shale and Marcellus Shale assets.

Taxes other than income taxes per Mcfe were $0.10 for the three months ended September 30, 2014 compared to $0.09 for the same period in 2013, and $0.11 and $0.10 for the nine months ended September 30, 2014 and 2013, respectively. Taxes other than income taxes per Mcfe vary from period to period due to changes in severance and ad valorem taxes that result from the mix of our production volumes and fluctuations in commodity prices.

Our full cost pool amortization rate was $1.09 per Mcfe for the three months ended September 30, 2014 compared to $1.07 for the same period in 2013. For the first nine months of 2014, our full cost pool amortization rate was $1.10 per Mcfe compared to $1.07 per Mcfe for the same period in 2013. The amortization rate is impacted by the timing and amount of reserve additions and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserves.

Unevaluated costs excluded from amortization were $1,037 million at September 30, 2014 compared to $957 million at December 31, 2013. The increase in unevaluated costs since December 31, 2013 primarily resulted from our acquisition of acreage in the Sand Wash Basin during 2014 as well as an increase in our wells in progress. Unevaluated costs excluded from amortization at September 30, 2014 included $77 million related to our properties in Canada, compared to $72 million at December 31, 2013.

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Midstream Services
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2014		2013		2014		2013

	($ in millions, except volumes)
Revenues – marketing	$	840	$	716	$	2,927	$	2,077
Revenues – gathering	$	143	$	131	$	417	$	378
Gas purchases – marketing	$	822	$	701	$	2,883	$	2,043
Operating costs and expenses	$	64	$	60	$	189	$	177
Operating income	$	97	$	86	$	272	$	235
Gas volumes marketed (Bcf)		229		206		670		575
Gas volumes gathered (Bcf)		247		230		719		667

Revenues

Revenues from our marketing activities were up 17% to $840 million for the three months ended September 30, 2014 and were up 41% to $2,927 million for the nine months ended September 30, 2014 compared to the same periods in 2013. For the three months ended September 30, 2014, the volumes marketed increased 11% and the price received for volumes marketed increased 5% compared to the same period in 2013. For the nine months ended September 30, 2014, the volumes marketed increased 17% and the price received for volumes marketed increased 21% compared to the same period in 2013. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expenses. Of the total volumes marketed, production from our affiliated E&P operated wells accounted for 95% of the marketed volumes for the three months ended September 30, 2014 and 2013. For the nine months ended September 30, 2014 and 2013, production from our affiliated E&P operated wells accounted for 98% and 96% of the marketed volumes, respectively.

Revenues from our gathering activities were up 9% to $143 million for the three months ended September 30, 2014 and up 10% to $417 million for the nine months ended September 30, 2014 compared to the same periods in 2013. The increase in gathering revenues resulted primarily from a 7% increase in gas volumes gathered for the three months ended September 30, 2014 and 8% in the nine months ended September 30, 2014, compared to the same period in 2013. A majority of the increase in gathering revenues for the three and nine months ended September 30, 2014 resulted from increases in volumes gathered due to our development and growth of our shale properties.

Operating Income

Operating income from our Midstream Services segment increased to $97 million for the three months ended September 30, 2014 compared to $86 million for the same period in 2013 and increased to $272 million for the nine months ended September 30, 2014 compared to $235 million for the same period in 2013. Operating income was higher due to increases in gas volumes gathered which primarily resulted from our increase in E&P production volumes. The $11 million increase in operating income for the three months ended September 30, 2014 was due to an increase of $12 million in gathering revenues and an increase of $3 million in the margin generated from our gas marketing activities, which was partially offset by an increase of $4 million in operating costs and expenses. The $37 million increase in operating income for the nine months ended September 30, 2014 was due to an increase of $39 million in gathering revenues and an increase of $10 million in the margin generated from our gas marketing activities, which was partially offset by a $12 million increase in operating costs and expenses, exclusive of gas purchase costs, associated with the increase in gas volumes gathered.

The margin generated from gas marketing activities was $18 million for the three months ended September 30, 2014 compared to $15 million for the three months ended September 30, 2013. The margin generated from gas marketing activities was $44 million for the nine months ended September 30, 2014 compared to $34 million for the nine months ended September 30, 2013. Margins are primarily driven by volumes of natural gas marketed and may fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. We enter into hedging activities from time to time with respect to our natural gas marketing activities to provide margin protection. We refer you to Item 3, “Quantitative and Qualitative Disclosures About Market Risks” included in this Form 10-Q for additional information.

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Interest Expense

Interest expense, net of capitalization, increased to $13 million for the three months ended September 30, 2014, compared to $11 million for the same period in 2013 and increased to $39 million for the nine months ended September 30, 2014 compared to $29 million for the same period in 2013. The increase in interest expense, net of capitalization, for the three months ended September 30, 2014 was primarily due to a decrease in capitalized interest for the three months ended September 30, 2014. We capitalized interest of $14 and $15 million for the three months ended September 30, 2014 and 2013, respectively. The decrease in capitalized interest for the three months ending September 30, 2014 compared to the same period in 2013 was primarily due to a reduction in the Company’s weighted average interest rate and a decrease in our unevaluated property balance. We capitalized interest of $40 and $48 million for the nine month periods ended September 30, 2014 and 2013, respectively.

Gain (Loss) on Derivatives

At September 30, 2014, our basis swaps, certain fixed price swaps, fixed price call options and interest rate swaps were not designated for hedge accounting treatment. Changes in the fair value of derivatives that were not designated as cash flow hedges are recorded in gain (loss) on derivatives. For the nine months ended September 30, 2014, we recorded a loss on derivatives excluding derivatives, settled of $11 million related to fixed price call options not designated for hedge accounting treatment, a gain on derivatives excluding derivatives, settled of $24 million related to fixed price swaps not designated for hedge accounting, a loss on derivatives excluding derivatives, settled of $16 million related to the basis swaps not designated for hedge accounting treatment, and a loss on derivatives excluding derivatives, settled of $4 million related to interest rate swaps not designated for hedge accounting treatment. Fixed prices swaps that were designated for hedge accounting and settled resulted in a loss of $48 million for the nine months ended September 30, 2014 and a gain of $218 million for the nine months ended September 30, 2013. Derivatives not designated for hedge accounting that were settled resulted in a loss of $22 million for the nine months ended September 30, 2014 and a gain of $3 million for the nine months ended September 30, 2013. In general and without consideration of volatility or duration, as 2015 natural gas prices increase from September 30, 2014 levels, the Company will recognize losses in future periods and, likewise, as 2015 natural gas prices decline from September 30, 2014 levels, the Company will recognize gains in future periods on its derivative contracts not accounted for under hedge accounting prior to settlement.

Income Taxes

Our effective tax rate was 40% for the three and nine months ended September 30, 2014 and 2013. For the three months ended September 30, 2014, we recorded an income tax expense of $140 million compared to an income tax expense of $124 million for the same period in 2013. For the nine months ended September 30, 2014, we recorded an income tax expense of $409 million compared to an income tax expense of $373 million for the same period in 2013.

Stock-Based Compensation Expense

We recognized expense of $4 million and capitalized $4 million for stock-based compensation during the three months ended September 30, 2014 compared to $3 million expense and $3 million capitalized for the comparable period in 2013. We recognized expense of $13 million and capitalized $13 million for stock-based compensation costs recognized during the nine month period ended September 30, 2014 compared to $9 million expense and $9 million capitalized for the comparable period in 2013. We refer you to Note 13 in the unaudited condensed consolidated financial statements included in this Form 10-Q for additional discussion of our equity based compensation plans.

Reconciliation of Non-GAAP Measures

We report our financial results in accordance with GAAP. However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods. Such non-GAAP performance measures include adjusted EBITDA, adjusted net income, diluted adjusted earnings per share, and net cash flow (also referred to as net cash provided by operating activities before changes in net assets and liabilities).

Adjusted EBITDA is defined as net income plus interest, income tax expense, non-cash impairment of natural gas and oil properties, (gain) loss on derivatives excluding derivatives, settled, and depreciation, depletion and amortization. Management presents measures such as adjusted EBITDA because it is used by many investors and it is a financial measure commonly used in the energy industry. Adjusted EBITDA should not be considered in isolation or as a

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substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with GAAP, or as a measure of the company’s profitability or liquidity. Adjusted EBITDA as defined above may not be comparable to similarly titled measures of other companies. The table below reconciles Adjusted EBITDA, as defined, with net income.


		For the three months ended September 30,				For the nine months ended September 30,
		2014		2013		2014		2013
		(in millions)
Net Income	$	211	$	186	$	612	$	559
Net interest expense		13		11		39		29
Provision for income taxes		140		124		409		373
Depreciation, depletion and amortization expense		238		205		693		571
Add back:
(Gain) Loss on derivatives excluding derivatives, settled		(54)		(10)		7		(72)
Adjusted EBITDA	$	548	$	516	$	1,760	$	1,460

Adjusted net income and adjusted diluted earnings per share exclude certain charges or amounts and are measures Management presents because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP. The table below reconciles adjusted net income and diluted adjusted earnings per share with net income.


		For the three months ended September 30,
		2014				2013
		(in millions)		(per diluted share)		(in millions)		(per diluted share)
Net income	$	211	$	0.60	$	186	$	0.53
Add back:
(Gain) Loss on derivatives excluding derivatives, settled (net of taxes)		(33)		(0.10)		(6)		(0.02)
Adjusted net income	$	178	$	0.50	$	180	$	0.51



		For the nine months ended September 30,
		2014				2013
		(in millions)		(per diluted share)		(in millions)		(per diluted share)
Net income	$	612	$	1.74	$	559	$	1.59
Add back:
(Gain) Loss on derivatives excluding derivatives, settled (net of taxes)		4		0.01		(43)		(0.12)
Adjusted net income	$	616	$	1.75	$	516	$	1.47

Management presents the measure of net cash flow because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred. These adjusted amounts are not a measure of financial performance under GAAP. The table below reconciles net cash flow with the cash flow from operating activities.

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		For the nine months ended September 30,
		2014		2013
		(in millions)
Net cash provided by operating activities	$	1,774	$	1,378
Add back:
Change in operating assets and liabilities		(74)		68
Net cash flow	$	1,700	$	1,446

New Accounting Standards

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on internally-generated funds, our Credit Facility and funds accessed through debt and equity markets as our primary sources of liquidity.

For the remainder of 2014, assuming natural gas prices remain at current levels, we intend to draw on a portion of the funds available under our Credit Facility to fund our working capital needs and our planned capital investments (discussed below under “Capital Investments”). We refer you to Note 9 to the unaudited condensed consolidated financial statements included in this Form 10-Q and the section below under “Financing Requirements” for additional discussion of our Credit Facility.

Net cash provided by operating activities increased 29% to $1,774 million for the nine months ended September 30, 2014, up from $1,378 million for the same period in 2013, due to an increase in net income adjusted for non-cash expenses primarily resulting from increased revenues due to higher natural gas production and gathering volumes, higher realized gas prices, and changes in working capital. During the nine months ended September 30, 2014, requirements for our capital investments were funded primarily from our cash generated by operating activities, cash and cash equivalents, and net proceeds from borrowings under our Credit Facility. For the nine months ended September 30, 2014, cash generated from our operating activities funded 97% of our cash requirements for capital investments compared to 79% for the nine months ended September 30, 2013.

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We believe that our operating cash flow, cash equivalents, and available funds under our Credit Facility will be adequate to meet our capital and operating requirements for 2014. The credit status of the financial institutions participating in our Credit Facility could adversely impact our ability to borrow funds under the Credit Facility. Although we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet its obligation.

Our cash flow from operating activities is highly dependent upon the market prices that we receive for our natural gas and oil production, including regional basis differentials. Natural gas and oil prices are subject to wide fluctuations and are driven by market supply and demand factors that are impacted by the overall state of the economy. The price received for our production is also influenced by our commodity hedging activities, as more fully discussed in Item 3, “Quantitative and Qualitative Disclosures about Market Risks” and Note 6 in the unaudited condensed consolidated financial statements included in this Form 10-Q. Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to complete the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.

Additionally, our short-term cash flows are dependent on the timely collection of receivables from our customers and partners. We actively manage this risk through credit management activities and through the date of this filing have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and partners could adversely impact our cash flows.

Due to the above factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we will adjust our discretionary uses of cash dependent upon available cash flow.

Capital Investments

Our capital investments were $1.8 billion for the nine months ended September 30, 2014, and 2013. Our E&P segment investments were $1.7 billion and $1.6 billion for the nine months ended September 30, 2014 and 2013 respectively. Our E&P segment capitalized internal costs of $238 million for the nine months ended September 30, 2014 compared to $190 million for the comparable period in 2013. These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties.

Our capital investments for 2014 are planned to be approximately $2.4 billion, consisting of $2.1 billion for E&P, $0.1 billion for Midstream Services and $0.2 billion for corporate and other purposes. Of the approximate $2.1 billion for E&P, we expect to allocate approximately $900 million to our Fayetteville Shale assets and approximately $700 million to our Marcellus Shale assets. Our planned level of capital investments in 2014 is expected to allow us to continue our progress in our shale properties and explore and develop other areas. Our remaining 2014 capital investment program is expected to be funded through cash flow from operations and borrowings under our revolving credit facility. The planned capital program for 2014 is flexible and can be modified. We will reevaluate our proposed investments as needed to take into account prevailing market conditions and we could change our planned investments.

Financing Requirements

Our total debt outstanding was $1.8 billion at September 30, 2014 compared to $2.0 billion at December 31, 2013. On December 16, 2013, the Company entered into a new Credit Agreement (“Credit Facility”), which exchanged our previous revolving credit facility. Under the Credit Facility, we have a borrowing capacity of $2 billion. The Credit Facility has a maturity date in December 2018 and options for two one-year extensions with participating lender approval. The amount available under the Credit Facility may be increased by $500 million upon the Company’s agreement with its participating lenders.

The interest rate on our Credit Facility is calculated based upon our public debt rating and is currently 137.5 basis points over LIBOR. Our publicly traded notes are rated BBB by Standard and Poor’s, our senior unsecured debt rating by Fitch Ratings is BBB-, and we have a long-term debt rating of Baa3 by Moody’s. Any downgrades in our public debt ratings could increase our cost of funds under the Credit Facility.

Our Credit Facility contains covenants that impose certain restrictions on us. Under the Credit Facility, we must keep our total debt at or below 60% of our total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments (after December 31, 2011), certain non-cash hedging activities and our pension and other postretirement liabilities. Therefore, under our Credit Facility

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provision, our total debt as of September 30, 2014, was 25% of total adjusted book capital. We were in compliance with all of the covenants of our Credit Facility as of September 30, 2014. Although we do not anticipate any violations of our financial covenants, our ability to comply with those covenants is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and oil. If we are unable to borrow under our Credit Facility, we may have to decrease our capital investment plans.

At September 30, 2014, on a GAAP basis, our capital structure consisted of 30% debt and 70% equity (exclusive of cash and cash equivalents) and $20 million in cash and cash equivalents, compared to 35% debt and 65% equity and $23 million in cash and cash equivalents at December 31, 2013. Equity at September 30, 2014 included an accumulated other comprehensive income gain of $36 million related to our hedging activities offset by a $9 million loss in pension and other postretirement liabilities. The amount recorded in equity for our hedging activities is based on current market values for our hedges at September 30, 2014 and does not necessarily reflect the value that we will receive or pay when the hedges are ultimately settled, nor does it take into account revenues to be received associated with the physical delivery of sales volumes hedged.

Our hedges allow us to ensure a certain level of cash flow to fund our operations. At October 21, 2014, we had NYMEX commodity price hedges in place on 117 Bcf of our remaining targeted 2014 natural gas production and 240 Bcf of our expected 2015 natural gas production. The amount of long-term debt we incur will be largely dependent upon commodity prices and our capital investment plans.

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our 2013 Annual Report on Form 10-K.

Contingent Liabilities and Commitments

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47 million Canadian dollars in the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of $45 million Canadian dollars. The promissory notes secure the Company's capital expenditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration program in 2010 and, as of September 30, 2014 has invested $44 million Canadian dollars, or $44 million US dollars, in New Brunswick towards the Company’s commitment. In December 2012, the Company received two one-year extensions to our exploration license agreements, the second of which will expire on March 16, 2015. No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of September 30, 2014 and its future investment plans.

Substantially all of our employees are covered by defined pension and postretirement benefit plans. As of September 30, 2014, the Company has contributed $9 million to the pension plan, and expects to contribute an additional $3 million to the pension plan in 2014. At September 30, 2014, we recognized a liability of $17 million as a result of the underfunded status of our pension and other postretirement benefit plans compared to a liability of $16 million at December 31, 2013.

We are subject to litigation, claims and proceedings (including with respect to environmental matters) that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and proceedings will not have a material adverse impact on our financial position, results of operations, or cash flows, but these matters are subject to inherent uncertainties and management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. For further information regarding

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commitments and contingencies, we refer you to Note 10 in the unaudited condensed consolidated financial statements included in this Form 10-Q.

Working Capital

We had negative working capital of $228 million at September 30, 2014 and negative working capital of $44 million at December 31, 2013. Current assets increased by $16 million during the nine months ended September 30, 2014 primarily due to a $46 million increase in current hedging assets, partially offset by a decrease of $19 million in other current assets, a decrease of $7 million in accounts receivable, a decrease of $3 million in cash and cash equivalents, and a decrease of $1 million in inventory. Current liabilities increased by $200 million during the nine months ended September 30, 2014 primarily as a result of a $183 million increase in accounts payable, a $29 million increase in derivative liabilities, an $8 million increase in current deferred income taxes, and a $1 million increase in taxes payable. These increases were partially offset by a $19 million decrease in interest payable and a $2 million decrease in other current liabilities. We maintain access to funds that may be needed to meet capital requirements through our Credit Facility described in “Financing Requirements” above.

Natural Gas in Underground Storage

We record our natural gas stored in inventory at the lower of weighted average cost or market. The natural gas in inventory is used primarily to supplement production in meeting contractual commitments, especially during periods of colder weather. In determining the lower of cost or market for storage gas, we utilize the natural gas futures market in assessing the price we expect to be able to realize for our natural gas in inventory. A decline in the future market price of natural gas could result in write-downs of our natural gas in underground storage carrying cost.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. We use natural gas agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. The Board of Directors has approved our use of financial products for the reduction of interest rate risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our customers and their dispersion across geographic areas. No single customer accounted for greater than 10% of revenues for the nine months ended September 30, 2014. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

Interest Rate Risk

At September 30, 2014, we had approximately $1.8 billion of total debt with a weighted average interest rate of 5.15%. Our revolving credit facility has a floating interest rate (1.50% at September 30, 2014). At September 30, 2014, we had borrowings outstanding of $139 million under our Credit Facility.

Interest rate swaps may be used to adjust interest rate exposures when deemed appropriate. At September 30, 2014, the Company had a net derivative liability position of $1 million related to interest rate swaps. A 10% increase or decrease in interest rates would not result in a material increase or decrease in the aggregate fair value of outstanding interest rate swap agreements. For a summary of the Company’s open interest rate derivative positions, see Note 6-Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Commodities Risk

We use over-the-counter natural gas agreements and options to hedge sales of our production against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index

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(referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps) and (3) the purchase and sale of index-related puts and calls (collars) that provide a “floor” price, below which the counterparty pays funds equal to the amount by which the price of the commodity is below the contracted floor, and a “ceiling” price above which we pay to the counterparty the amount by which the price of the commodity is above the contracted ceiling.

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major commercial banks, investment banks and integrated energy companies which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, given the recent volatility in the financial markets, we cannot be certain that we will not experience such losses in the future.

Exploration and Production

The following table provides information about our financial instruments that are sensitive to changes in commodity prices and that are used to hedge prices for natural gas production. The table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates. At September 30, 2014, the net fair value of our financial instruments related to natural gas production was a $79 million liability.


	Volume (Bcf)	Weighted Average Fixed Price Swaps ($/MMBtu)		Weighted Average Floor Price ($/MMBtu)		Weighted Average Ceiling Price ($/MMBtu)		Weighted Average Basis Differential ($/MMBtu)		Fair value at September 30, 2014 ($ in millions)
Natural Gas (Bcf):

Fixed Price Swaps:
2014	117	$	4.35	$	–	$	–	$	–	$	29
2015	240	$	4.40	$	–	$	–	$	–	$	96

Basis Swaps:
2014	10	$	–	$	–	$	–	$	0.50	$	10
2015	15	$	–	$	–	$	–	$	0.61	$	(13)
2016	4	$	–	$	–	$	–	$	0.72	$	(2)

Fixed Price Call Options:
2015	200	$	–	$	–	$	5.09	$	–	$	(20)
2016	120	$	–	$	–	$	5.00	$	–	$	(21)

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At September 30, 2014, our basis swaps, certain fixed price swaps, call options and interest rate swaps were not designated for hedge accounting. Changes in the fair value of derivatives that are not designated as cash flow hedges are recorded in gain (loss) on derivatives. For the nine months ended September 30, 2014, we recorded a loss on derivatives excluding derivatives, settled of $11 million related to fixed price call options not designated for hedge accounting, a gain on derivatives excluding derivatives, settled of $24 million related to fixed price swaps not designated for hedge accounting, a loss on derivatives excluding derivatives, settled of $16 million related to the basis swaps not designated for hedge accounting, a loss on derivatives excluding derivatives, settled of $4 million related to interest rate swaps not designated for hedge accounting and a gain of $1 million related to the change in estimated ineffectiveness of our cash flow hedges. Typically, our hedge ineffectiveness results from changes at the end of a reporting period in the price differentials between the index price of the derivative contract, which is primarily a NYMEX price, and the index price for the point of sale for the cash flow that is being hedged.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d 15(e) under the Securities Exchange Act of 1934, as amended. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, summarize and report information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of September 30, 2014 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are subject to laws and regulations relating to the protection of the environment. Our policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, results of operations, and cash flows.

Tovah Energy

In February 2009, SEPCO was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al., pending in the 273rd District Court in Shelby County, Texas. By the time of trial in December 2010, Ms. Berry-Helfand (the only remaining plaintiff) alleged that, in 2005, she provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, she alleged various statutory and common law claims, including, but not limited to, claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 2005 and February 2006. She also sought disgorgement of SEPCO’s profits. A former associate of the plaintiff intervened in the matter claiming to have helped develop the prospect years earlier.

SEPCO filed a petition for review in the Supreme Court of Texas in February 2014. The plaintiff and the intervenor filed cross-petition for review in April 2014, but conditioned their filing on the court’s granting SEPCO’s petition for review; i.e., if the court denies SEPCO’s petition for review, then the plaintiff and the intervenor are not seeking further review of the court of appeals’ judgment. Based on the Company’s understanding and judgment of the facts and merits of this case, including appellate matters, and after considering the advice of counsel, the Company has determined that, although reasonably possible, a materially adverse final outcome to this action is not probable. As such, the Company has not accrued any amounts with respect to this action. If the Supreme Court declines to hear the case or affirms all aspects of the court of appeals’ judgment, then SEPCO would owe the $11 million in damages, plus interest and attorneys’ fees, offset by any award of attorneys’ fees for its prevailing on the theft count. The Company’s assessment may change in the future due to occurrence of certain events, such as the result of the petition or petitions for review at the Supreme Court of Texas, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.

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Arkansas Royalty Litigation

Other

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ITEM 1A. RISK FACTORS.

There were no additions or material changes to the Company’s risk factors as disclosed in Item 1A of Part I in the Company’s 2013 Annual Report on Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES.

Our sand mining operations, in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Form 10-Q.

ITEM 5. OTHER INFORMATION.

Not applicable.

ITEM 6. EXHIBITS.


(31.1)	Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2)	Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1)	Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(95.1)	Mine Safety Disclosure.
(101.INS)	Interactive Data File Instance Document.
(101.SCH)	Interactive Data File Schema Document.
(101.CAL)	Interactive Data File Calculation Linkbase Document.
(101.LAB)	Interactive Data File Label Linkbase Document.
(101.PRE)	Interactive Data File Presentation Linkbase Document.
(101.DEF)	Interactive Data File Definition Linkbase Document.

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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.

			SOUTHWESTERN ENERGY COMPANY
			Registrant


Dated:	October 23, 2014	/s/ R. CRAIG OWEN
		R. Craig Owen
		Senior Vice President
		and Chief Financial Officer