10-K/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K/A (Amendment No. 1)
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2015
Commission file number 001-08246
Southwestern Energy Company
(Exact name of registrant as specified in its charter)
Delaware		71-0205415
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
1000 Energy Drive Spring, Texas		77389
(Address of principal executive offices)		(Zip Code)
(832) 796-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common Stock, Par Value $0.01		New York Stock Exchange
Depositary Shares, each representing a 1/20th ownership interest in a share of 6.25% Series B Mandatory Convertible Preferred Stock		New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☒     No☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐    No☒
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐
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 Act). Yes ☐     No ☒
The aggregate market value of the voting stock held by non-affiliates of the registrant was $8,964,538,969 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2015, of $22.73. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.
As of February 23, 2016, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 389,664,470.
Document Incorporated by Reference
Portions of the registrant’s definitive proxy statement to be filed with respect to the annual meeting of stockholders to be held on or about May 17, 2016 are incorporated by reference into Part III of this Form 10-K.

EXPLANATORY NOTE

The purpose of this Amendment No. 1 to Form 10-K for the year ended December 31, 2015 (“Form 10-K”), as filed with the Securities and Exchange Commission on February 25, 2016 is to furnish Exhibit 101 to the Form 10-K which provides certain items from Form 10-K formatted in eXtensible Business Reporting Language (“XBRL”).

Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

The contents of the Form 10-K have not otherwise been modified or changed.  This Form 10-K/A speaks as of the original filing date of the Form 10-K and has not been updated to reflect events occurring subsequent to the original filing date.

EXHIBIT INDEX

Exhibit Number	Description
2.1	Purchase Agreement dated as of October 14, 2014 between Southwestern Energy Production Company and Chesapeake Appalachia, L.L.C. (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on October 17, 2014)
3.1	Amended and Restated Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010)
3.2	Amended and Restated Bylaws of Southwestern Energy Company, as amended on November 9, 2015. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed November 13, 2015)
3.3	Certificate of Designations of 6.25% Series B Mandatory Convertible Preferred Stock (including form of stock certificate). (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
3.4	Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock, dated April 9, 2009. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 9, 2009)
4.1	Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.2	Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago, as trustee. (Incorporated by reference to Exhibit 4 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (File No. 33-63895) filed on November 17, 1995)
4.3	First Supplemental Indenture between Southwestern Energy Company and J.P. Morgan Trust Company, N.A. (as successor to the First National Bank of Chicago) dated June 30, 2006. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.4	Second Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee (as successor to J.P. Morgan Trust Company, N.A.), dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.5	Indenture dated June 1, 1998 by and among NOARK Pipeline Finance, L.L.C. and The Bank of New York. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)
4.6	First Supplemental Indenture dated May 2, 2006 by and among Southwestern Energy Company, NOARK Pipeline Finance, L.L.C., and UMB Bank, N.A., as trustee (as successor to the Bank of New York). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)

4.7	Second Supplemental Indenture between Southwestern Energy Company and UMB Bank, N.A., as trustee, dated June 30, 2006. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.8	Third Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and UMB Bank, N.A., as trustee, dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.9	Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of New York, as trustee, under the Indenture dated as of June 1, 1998 between NOARK Pipeline Finance L.L.C. and such trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2005)
4.10	Indenture dated January 16, 2008 among Southwestern Energy Company, the Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 16, 2008)
4.11	Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee, dated as of March 5, 2012. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012)
4.12	Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2006 Annual Meeting of Stockholders)
4.13	Credit Agreement dated December 16, 2013 among Southwestern Energy Company, JPMorgan Chase Bank, NA, Bank of America, N.A., Wells Fargo N.A., The Royal Bank of Scotland PLC, Citibank, N.A. and the other lenders named therein, JPMorgan Chase Bank, NA, as administrative agent. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed December 17, 2013)
4.14	Commitment Letter dated October 14, 2014 between Southwestern Energy Company, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Bank of America, N.A. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 17, 2014)
4.15	Bridge Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association and The Royal Bank of Scotland plc, as Co-Syndication Agents, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
4.16	Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
4.17	Form of certificate for the 6.25% Series B Mandatory Convertible Preferred Stock. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.18	Deposit Agreement, dated as of January 21, 2015, between Southwestern Energy Company and Computershare Trust Company, N.A., as depositary, on behalf of all holders from time to time of the receipts issued thereunder (including form of Depositary Receipt). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.19	Form of Depositary Receipt for the Depositary Shares. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)

4.20	Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.21	First Supplemental Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.22	Form of 3.300% Notes due 2018. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.23	Form of 4.050% Notes due 2020. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.24	Form of 4.095% Notes due 2025. (Incorporated by reference to Exhibit 4.5 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
10.1	Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
10.2	Form of Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company, effective February 17, 1999. (Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.3	Form of Amendment to Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company prior to 2011. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.4	Form of Executive Severance Agreement between Southwestern Energy Company and Executive Officers Post 2011.  (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No.1-08426) for the year ended December 31, 2012)
10.5	Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.2(b) to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.6	Amendment to Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.7	Second Amendment to Southwestern Energy Company Incentive Compensation Plan (Incorporated by reference to Exhibit 10.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2009)
10.8	Southwestern Energy Company Supplemental Retirement Plan as amended. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.9	Southwestern Energy Company Non-Qualified Retirement Plan as amended. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.10	Amendment One to the Southwestern Energy Company Non-Qualified Retirement Plan (Incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2009)
10.11	Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2000 Annual Meeting of Stockholders)
10.12	Southwestern Energy Company 2002 Employee Stock Incentive Plan, effective October 23, 2002.  (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)

10.13	Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December 8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2012)
10.14	Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
10.15	Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Annex A of the Registrant’s Proxy Statement filed April 8, 2013)
10.16	Southwestern Energy Company 2013 Incentive Plan Form of Performance Unit Award Agreement.(Incorporated by reference to Exhibit 10.16 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
10.17	Southwestern Energy Company 2013 Incentive Plan Guidelines for Annual Incentive Awards. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.18	Southwestern Energy Company 2013 Incentive Plan Form of Incentive Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.19	Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.20	Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option Award Agreement for Directors. (Incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.21	Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.22	Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award Agreement for Directors. (Incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.23	Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.24	Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award Agreement for Directors. (Incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.25	Form of Incentive Stock Option Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.26	Form of Non-Qualified Stock Option Agreement for non-employee directors for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.27	Form of Incentive Stock Option for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.28	Form of Restricted Stock Agreement for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.29	Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2005 and through December 8, 2011 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.30	Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2011.  (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08426) for the year ended December 31, 2012)

10.31	Master Lease Agreement by and between Southwestern Energy Company and SunTrust Leasing Corporation dated December 29, 2006. (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2006)
10.32	Guaranty by and between Southwestern Energy Company and Texas Gas Transmission, LLC, dated as of October 27, 2008. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2008)
10.33	Guaranty by and between Southwestern Energy Company and Fayetteville Express Pipeline, LLC dated September 30, 2008 (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.34	Retirement Letter Agreement dated February 24, 2012 between Southwestern Energy Company and Gene A. Hammons.  (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 27, 2012)
10.35	Retirement Agreement dated August 11, 2009 between Southwestern Energy Company and Harold M. Korell. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 14, 2009)
10.36	Settlement Agreement, dated December 22, 2014, between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
10.37	Term Loan Credit Agreement, dated November 17, 2015, among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Lead Arranger and Bookrunner, and the lenders from time to time party thereto. (Incorporated by reference to the Registrant’s Current Report on Form 8-K filed November 17, 2015)
10.38	Retirement Agreement dated January 11, 2016 between Southwestern Energy Company and Steven L. Mueller.(Incorporated by reference to Exhibit 10.38 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
21.1	List of Subsidiaries(Incorporated by reference to Exhibit 21.1 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
23.1	Consent of PricewaterhouseCoopers LLP(Incorporated by reference to Exhibit 23.1 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
23.2	Consent of Netherland, Sewell & Associates, Inc.(Incorporated by reference to Exhibit 23.2 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
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 furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002(Incorporated by reference to Exhibit 32.1 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
32.2	Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002(Incorporated by reference to Exhibit 32.2 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
95.1	Mine Safety Disclosure(Incorporated by reference to Exhibit 95.1 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)
99.1	Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated January 15, 2016(Incorporated by reference to Exhibit 99.1 to the Registrant’s Annual Report on Form 10-K (Commission File No. 001-08246) for the year ended December 31, 2015)

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

*Furnished herewith.

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:	February 26, 2016	/s/ R. CRAIG OWEN
		R. Craig Owen
		Senior Vice President and Chief Financial Officer

EX-31

Exhibit 31.1

CERTIFICATION

I, William J. Way, certify that:

1. I have reviewed this Form 10-K/A of Southwestern Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 26, 2016	/s/ WILLIAM J. WAY
			William J. Way
			Director, President and Chief Executive Officer

EX-31

Exhibit 31.2

CERTIFICATION

I, R. Craig Owen, certify that:

1. I have reviewed this Form 10-K/A of Southwestern Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 26, 2016	/s/ R. CRAIG OWEN
			R. Craig Owen
			Senior Vice President and Chief Financial Officer

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 23, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Entity Registrant Name	SOUTHWESTERN ENERGY CO
Entity Central Index Key	0000007332
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 8,694,538,969
Entity Common Stock, Shares Outstanding		389,664,470
Trading Symbol	SWN

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues:
Gas sales	$ 1,946	$ 2,827	$ 2,381
Oil sales	76	19	14
NGL sales	73	3	2
Marketing	863	996	792
Gas gathering	175	193	182
Total Operating Revenues	3,133	4,038	3,371
Operating Costs and Expenses:
Marketing purchases	852	980	782
Operating expenses	689	427	328
General and administrative expenses	246	221	191
Depreciation, depletion and amortization	1,091	942	787
Impairment of natural gas and oil properties	6,950
Gain on sale of assets, net	(283)
Taxes, other than income taxes	110	95	79
Total Operating Costs and Expenses	9,655	2,665	2,167
Operating Income (Loss)	(6,522)	1,373	1,204
Interest Expense:
Interest on debt	200	101	100
Other interest charges	60	13	4
Interest capitalized	(204)	(55)	(62)
Total Interest Expense	56	59	42
Other Income (Loss), Net	(30)	(4)	2
Gain on Derivatives	47	139	26
Income (Loss) Before Income Taxes	(6,561)	1,449	1,190
Provision (Benefit) for Income Taxes:
Current	(2)	21	(11)
Deferred	(2,003)	504	497
Provision (Benefit) for Income Taxes	(2,005)	525	486
Net Income (Loss)	(4,556)	924	704
Mandatory convertible preferred stock dividend	106
Net Income (Loss) Attributable to Common Stock	$ (4,662)	$ 924	$ 704
Earnings (Loss) Per Common Share:
Basic	$ (12.25)	$ 2.63	$ 2.01
Diluted	$ (12.25)	$ 2.62	$ 2.00
Weighted Average Common Shares Outstanding:
Basic	380,521,039	351,446,747	350,465,430
Diluted	380,521,039	352,410,683	351,101,452

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net income (loss)		$ (4,556)	$ 924	$ 704
Change in derivatives:
Settlements	[1]	(128)	16	(185)
Ineffectiveness	[2]	1		1
Change in fair value of derivative instruments	[3]	29	73	22
Total change in derivatives		(98)	89	(162)
Change in value of pension and other postretirement liabilities:
Current period net gain (loss)	[4]	(3)	(15)	11
Amortization of prior service cost and net loss included in net periodic pension cost	[5]	2		1
Total change in value of pension and other postretirement liabilities		(1)	(15)	12
Change in currency translation adjustment		(11)	(8)	(4)
Comprehensive income (loss)		$ (4,666)	$ 990	$ 550

[1] Net of ($81), $10, and ($124) million in taxes for the years ended December 31, 2015, 2014 and 2013, respectively.

[2] Net of $0, $0, and $1 million in taxes for the years ended December 31, 2015, 2014 and 2013, respectively.

[3] Net of $16, $49, and $16 million in taxes for the years ended December 31, 2015, 2014 and 2013, respectively.

[4] Net of $0, ($10), and $8 million in taxes for the years ended December 31, 2015, 2014 and 2013, respectively.

[5] Net of $0, $0, and $1 million in taxes for the years ended December 31, 2015, 2014, and 2013, respectively.

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Settlements tax	$ (81)	$ 10	$ (124)
Ineffectiveness tax	0	0	1
Change in fair value of derivative instruments tax	16	49	16
Current period net gain (loss) tax	0	(10)	8
Amortization of prior service cost and net loss included in net periodic pension cost tax	$ 0	$ 0	$ 1

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 15	$ 53
Accounts receivable, net	327	530
Inventories	3	37
Derivative assets	3	337
Other current assets	45	158
Total current assets	393	1,115
Natural gas and oil properties, using the full cost method, including $3,727 million in 2015 and $4,646 million in 2014 excluded from amortization	22,478	20,506
Gathering systems	1,280	1,439
Other	606	612
Less: Accumulated depreciation, depletion and amortization	(16,821)	(8,845)
Total property and equipment, net	7,543	13,712
Other long-term assets	174	98
TOTAL ASSETS	8,110	14,925
Current liabilities:
Short-term debt	1	4,501
Accounts payable	513	653
Taxes payable	64	92
Interest payable	75	34
Current deferred income taxes		$ 109
Dividends payable	27
Derivative liabilities	3	$ 9
Other current liabilities	24	30
Total current liabilities	707	5,428
Long-term debt	4,728	2,466
Deferred income taxes		1,951
Pension and other postretirement liabilities	50	44
Other long-term liabilities	343	374
Total long-term liabilities	$ 5,121	$ 4,835
Commitments and contingencies (see Note 9)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 390,138,549 shares in 2015 and 354,488,992 in 2014	$ 4	$ 4
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of December 31, 2015
Additional paid-in capital	$ 3,409	$ 1,019
Retained earnings (Accumulated deficit)	(1,082)	3,577
Accumulated other comprehensive income (loss)	(48)	$ 62
Common stock in treasury, 47,149 and 11,055 shares as of December 31, 2015 and 2014, respectively	(1)
Total equity	2,282	$ 4,662
TOTAL LIABILITIES AND EQUITY	$ 8,110	$ 14,925

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Natural gas and oil properties, using the full cost method, costs excluded from amortization	$ 3,727	$ 4,646
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,250,000,000	1,250,000,000
Common stock, shares issued	390,138,549	354,488,992
Treasury stock, shares	47,149	11,055
Series B Preferred Stock [Member]
Preferred stock, par value	$ 0.01
Preferred stock, shares authorized	10,000,000
Preferred stock, dividend rate	6.25%
Liquidation preference per share	$ 1,000
Preferred stock, shares issued	1,725,000
Preferred stock, shares outstanding	1,725,000

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows From Operating Activities
Net income (loss)	$ (4,556)	$ 924	$ 704
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,092	942	787
Impairment of natural gas and oil properties	6,950
Amortization of debt issuance cost	53	10	4
Deferred income taxes	(2,003)	504	497
(Gain) loss on derivatives, net of settlement	155	(130)	(21)
Stock-based compensation	26	18	13
Gain on sale of assets, net	(283)
Other	34	2	1
Change in assets and liabilities:
Accounts receivable	203	(66)	(86)
Inventories	4	1	(6)
Accounts payable	(78)	84	74
Taxes payable	(28)	24	5
Interest payable	9		(1)
Advances from partners			(69)
Other assets and liabilities	2	22	7
Net cash provided by operating activities	1,580	2,335	1,909
Cash Flows From Investing Activities
Capital investments	(1,798)	(2,043)	(2,157)
Acquisitions	(579)	(5,298)	(96)
Proceeds from sale of property and equipment	729	43	18
Transfers to restricted cash			9
Other	10	10	10
Net cash used in investing activities	(1,638)	(7,288)	(2,216)
Cash Flows From Financing Activities
Payments on current portion of long-term debt	(1)	(1)	(1)
Payments on long-term debt	(500)
Payments on short-term debt	(4,500)
Payments on revolving credit facility	(3,024)	(5,179)	(3,148)
Borrowings under revolving credit facility	2,840	5,196	3,430
Payments on commercial paper	(7,988)
Borrowings under commercial paper	7,988
Change in bank drafts outstanding	12	11	(7)
Proceeds from issuance of long-term debt	2,950	500
Proceeds from issuance of short-term debt		4,500
Debt issuance costs	(20)	(56)
Proceeds from exercise of common stock options		12	10
Proceeds from issuance of common stock	669
Proceeds from issuance of mandatory convertible preferred stock	1,673
Preferred stock dividend	(79)
Other			(7)
Net cash provided by financing activities	20	4,983	277
Effect of exchange rate changes on cash			(1)
Increase (decrease) in cash and cash equivalents	(38)	30	(31)
Cash and cash equivalents at beginning of year	53	23	54
Cash and cash equivalents at end of year	$ 15	$ 53	$ 23

XML

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Millions	Common Stock [Member]	Preferred Stock [Member] Series B Preferred Stock [Member]	Additional Paid-in Capital [Member] Series B Preferred Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Common Stock in Treasury [Member]	Series B Preferred Stock [Member]	Total
Balance, shares at Dec. 31, 2012	351,100,391
Balance at Dec. 31, 2012	$ 4			$ 934	$ 1,949	$ 150	$ (1)		$ 3,036
Comprehensive income (loss):
Net income (loss)					704				704
Other comprehensive income (loss)						(154)			(154)
Comprehensive income (loss)									550
Stock-based compensation				25					25
Exercise of stock options, shares	833,132
Exercise of stock options				10					10
Issuance of restricted stock, shares	1,102,926
Cancellation of restricted stock, shares	(74,083)
Tax withholding - stock compensation, shares	(25,131)
Tax withholding - stock compensation				(1)					(1)
Issuance of stock awards, shares	1,349
Treasury stock - non-qualified plan				1			1		2
Balance, shares at Dec. 31, 2013	352,938,584
Balance at Dec. 31, 2013	$ 4			969	2,653	(4)			3,622
Comprehensive income (loss):
Net income (loss)					924				924
Other comprehensive income (loss)						66			66
Comprehensive income (loss)									990
Stock-based compensation				38					38
Exercise of stock options, shares	402,190
Exercise of stock options				12					12
Issuance of restricted stock, shares	1,299,367
Cancellation of restricted stock, shares	(140,703)
Tax withholding - stock compensation, shares	(12,133)
Issuance of stock awards, shares	1,687
Balance, shares at Dec. 31, 2014	354,488,992
Balance at Dec. 31, 2014	$ 4			1,019	3,577	62			4,662
Comprehensive income (loss):
Net income (loss)					(4,556)				(4,556)
Other comprehensive income (loss)						(110)			(110)
Comprehensive income (loss)									(4,666)
Stock-based compensation				48					48
Preferred stock dividends					(106)				(106)
Issuance of restricted stock, shares	5,821,125
Cancellation of restricted stock, shares	(103,162)
Issuance of stock, shares	30,000,000	1,725,000
Issuance of stock			$ 1,673	669				$ 1,673	669
Tax withholding - stock compensation, shares	(73,869)
Issuance of stock awards, shares	5,463
Treasury stock - non-qualified plan							(1)		(1)
Balance, shares at Dec. 31, 2015	390,138,549	1,725,000
Balance at Dec. 31, 2015	$ 4			$ 3,409	(1,082)	$ (48)	$ (1)		2,282
Comprehensive income (loss):
Non-controlling interest					$ 3				$ 3

XML

Organization And Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Organization And Summary Of Significant Accounting Policies [Abstract]

Organization And Summary Of Significant Accounting Policies

(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production (“E&P”).  The Company’s current operations are principally focused within the United States on the development of unconventional reservoirs located in Pennsylvania, West Virginia and Arkansas.

The Company’s operations in northeast Pennsylvania are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”), its operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”) and its operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale.  Collectively, the Company’s properties located in Pennsylvania and West Virginia are herein referred to as the “Appalachian Basin.”  The Company also actively seeks to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which it refers to as “New Ventures,” and has exploration and production activities ongoing in Colorado and Louisiana, along with other areas in which it is currently exploring for new development opportunities.  The Company also has drilling rigs in Pennsylvania, West Virginia and Arkansas, as well as in other operating areas, and provides oilfield products and services, principally serving its exploration and production operations.  Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania, Louisiana and West Virginia.

Basis of Presentation

The consolidated financial statements included in this Annual Reportpresent the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.The Company evaluates subsequent events through the date the financial statements are issued.Certain reclassifications have been made to the prior year financial statements to conform to the 2015 presentation.The effects of the reclassifications were not material to the Company’s consolidated financial statements. 

Principles of Consolidation

The consolidated financial statements include the accounts of Southwestern and its wholly owned subsidiaries.  All significant intercompany accounts and transactions have been eliminated.

In 2015, the Company purchased an 86% ownership in a limited partnershipwhich owns and operates a gathering system in Northeast Appalachia as part of the WPX Property Acquisition (discussed in Note 2). Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the year ended December 31, 2015 was insignificant.

Revenue Recognition

Natural gas and liquid sales. Natural gas and liquid sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties.  Accordingly, natural gasand liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances.  The Company had no significant production imbalances at December 31, 2015 or 2014.

Marketing. The Company generally markets its natural gas and liquids, as well as some products produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts.  Marketing revenues are recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Gas gathering.In certain areas, the Company gathers its natural gas as well as some natural gas produced by third parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Cash and Cash Equivalents

Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash.  Management considers cash and cash equivalents to have minimal credit and market risk.

Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $29 million and $17 million as of December 31, 2015 and 2014, respectively.

Inventory

Inventory is comprised of tubulars and other equipment and natural gas in underground storage.  Tubulars and other equipment are carried at the lower of cost or market and are accounted for by a moving weighted average cost method that is applied within specific classes of inventory items.  In the fourth quarter of 2015, the Company wrote-down the carrying value of its inventory by $23 million as a result of reduced drilling activity.  Natural gas in underground storage is carried at the lower of cost or market and accounted for by a weighted average cost method.  During the fourth quarter of 2015, the Company completed the sale of its underground storage facility in Franklin County, Arkansas.

The components of inventory as of December 31, 2015 and December 31, 2014 consisted of the following:

	For years ended December 31,
	2015		2014
	(in millions)
Inventory:
Tubulars and other equipment	$	3	$	33
Natural gas in underground storage		–		4

Property, Depreciation, Depletion and Amortization

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, oil and NGLreserves. 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, oil and NGL reserves discounted at 10% 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, oil and NGL prices may subsequently increase the ceiling.  Companies using 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 $2.59 per MMBtu, West Texas Intermediate oil of $46.79 per barrel, and NGLs of $6.82 per barrel, adjusted for market differentials, theCompany’s net book valueof its United States natural gas and oil properties exceeded the ceiling by $1,586 million (net of tax) at December 31, 2015 and resulted in a non-cash ceiling test impairment.  No cash flow hedges were in place as of December 31, 2015.  In the second and third quarters of 2015, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015, respectively, and resulted in non-cash ceiling test impairments.  Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $60million and $40 million as of June 30, 2015 and September 30, 2015, respectively.  At December 31, 2014, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu, West Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 per barrel. At December 31, 2013, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.67 per MMBtu, for West Texas Intermediate oil of $93.42 and NGLs of $43.45 per barrel. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.

Gathering Systems.The Company’s investment in gathering systems is primarily related to its Fayetteville Shale assets in Arkansas.  These assets are being depreciated on a straight-line basis over 25 years.

Capitalized Interest.Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and actively being evaluated.

Asset Retirement Obligations.  The Company owns natural gas and oil properties, which require expenditures to plug and abandon the wells and reclaim the associated pads when reserves in the wells are depleted. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Impairment of long-lived assets. The carrying value of long-lived assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.

Intangible assets. The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their weighted average useful life.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.  The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations.  Additional information regarding uncertain tax positions can be found in Note 10 – Income Taxes.

Derivative Financial Instruments

The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity fixed price swaps and fixed price option contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivatives if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item.  In contrast, gains and losses from the ineffective portion of fixed price swaps designated for hedge accounting treatment are recognized currentlyand have an inconsequential impact in the consolidated statement of operations.Gains and losses from the unsettled portion of fixed price swaps not designated for hedge accounting treatment, interest rate swaps, fixed price call options and basis swaps that were not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations.  See Note 5– Derivatives and Risk Management and Note 7 – Fair Value Measurements for a discussion of the Company’s hedging activities.

Earnings Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock and performance units and the assumed conversion of mandatory convertible preferred stock.  An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.

In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares).  The common stock offering was priced at $23.00 per share.  Net proceeds, after underwriting discount and expenses, from the common stock offering were approximately $669 million.  Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1.7 billion.  Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share).  The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public offering of $2.2 billion in long-term senior notes.

The mandatory convertible preferred stock entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights.  Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (and, correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date.

The mandatory convertible preferred stock has the non-forfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security.  Accordingly, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method.  In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings.  The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

The following table presents the computation of earnings per share for the years ended December 31, 2015, 2014 and 2013.

	For the years ended
	December 31,
	2015		2014		2013
	(in millions, except share/per share amounts)
Net income (loss)	$	(4,556)	$	924	$	704
Mandatory convertible preferred stock dividend		106		–		–
Net income (loss) attributable to common stock	$	(4,662)	$	924	$	704
Number of common shares:
Weighted average outstanding		380,521,039		351,446,747		350,465,430
Issued upon assumed exercise of outstanding stock options (1)		–		241,603		377,626
Effect of issuance of non-vested restricted common stock (2)		–		448,415		258,396
Effect of issuance of non-vested performance units (3)		–		273,918		–
Effect of issuance of mandatory convertible preferred stock (4)		–		–		–
Weighted average and potential dilutive outstanding		380,521,039		352,410,683		351,101,452
Earnings (loss) per common share:
Basic	$	(12.25)	$	2.63	$	2.01
Diluted	$	(12.25)	$	2.62	$	2.00

(1) Due to the net loss for the year ended December 31, 2015, the unvested stock options were not recognized in diluted earnings per share calculations as they would be antidilutive.  Options for 3,835,234 shares, 1,446,004 shares and 1,634,695 shares were excluded from the calculation of diluted shares for the years ended December 31, 2015, 2014 and 2013, respectively, because they would have had an antidilutive effect.

(2) Due to the net loss for the year ended December 31, 2015, the unvested share-based payments were not recognized in diluted earnings per share calculations as they would be antidilutive.  The calculation excluded 1,990,383 shares,  29,879 shares and 114,433 shares of restricted stock  for the years ended December 31, 2015, 2014, and 2013, respectively, because they would have had an antidilutive effect.

(3) Due to the net loss for the year ended December 31, 2015, 140,414 shares of performance units were excluded in the calculation of diluted earnings per share as they would be antidilutive.   There were no performance units issued in 2013.

(4) Due to the net loss for the year ended December 31, 2015, the weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock were not recognized in diluted earnings per share calculations as they would be antidilutive.  The calculation excluded 70,890,312 weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock because they would have had an antidilutive effect.  There were no mandatory convertible preferred shares in 2014 or 2013.

Supplemental Disclosures of Cash Flow Information

The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2015, 2014, and 2013.

	For the years ended December 31,
	2015		2014		2013
	(in millions)
Cash paid during the year for interest, net of amounts capitalized	$	6	$	50	$	36
Cash paid (received) during the year for income taxes		(6)		28		19
Increase (decrease) in noncash property additions		(10)		174		(13)

Stock-Based Compensation

The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.

Treasury Stock

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liabilities of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2015, 47,149 shares were accounted for as treasury stock, compared to 11,055 shares at December 31, 2014.

Foreign Currency Translation

The Company has designated the Canadian dollar as the functional currency for our operations in Canada.  The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders' equity.

New Accounting Standards Implemented in this Report

In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (Topic 740) (“Update 2015-17”), which seeks to reduce the complexity in financial reporting.  The amendments in Update 2015-17 require that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as non-current on the balance sheet.  Although the amendments in Update 2015-17 are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, the Company has elected to early adopt the amendments of Update 2015-17 on a prospective basis for the current period.  The implementation did not have a material impact on the Company’s consolidated statement of operations, balance sheet or statement of cash flows.  The net deferred tax liability at December 31, 2014 was comprised of net long-term deferred income tax liabilities of $1,951 million, in addition to a net current deferred income tax liability of $109 million.  

New Accounting Standards Not Yet Implemented in this Report

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 requirement as 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 to those goods or services. Entities may apply the amendments in Update 2014-09 either (a) retrospectively to each 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.  In August 2015, the FASB issued Accounting Standards Update Accounting Standards Update (ASU) No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which finalizes Proposed ASU No. 2015-240 of the same name, and responds to stakeholders’ requests to defer the effective date of the guidance in ASU No. 2014-09. For public entities, Update 2014-09 and Update 2015-14 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-09 and 2015-14 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In November 2014, the FASB issued Accounting Standards Update No. 2014-16, Derivatives and Hedging – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (Subtopic 815-15) (“Update 2014-16”), addresses diversity in practice related to the determination of whether derivative features embedded in hybrid instruments issued in the form of a share should be bifurcated and accounted for separately. For public entities, Update 2014-16 is effective for annual reporting periods beginning after December 15, 2015 including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-16 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-03”), which seeks to simplify presentation of debt issuance costs. Update 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. Entities should apply the amendments in Update 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. For public entities, Update 2015-03 and Update 2015-15 are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company has evaluated the provisions of Update 2015-03 and Update 2015-15 and expects the impact to be immaterial on its consolidatedresults of operations, financial position and cash flows.

In May 2015, the FASB issued Accounting Standards Update No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent) (“Update 2015-07”), which amends ASC 820, Fair Value Measurement. The standard removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure requirements.  The amendments in Update 2015-07 are effective for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-07 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Inventory (Topic 330) (“Update 2015-11”), which seeks to simplify the measurement of inventory. Update 2015-11 requires that an entity should measure inventory at the lower of cost and net realizable value, where net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public entities, the amendments in Update 2015-11 are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-11 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In July 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-12 (“Update 2015-12”), which consists of three related parts: (1) Plan Accounting: Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Fully Benefit-Responsive Investment Contracts (“Part I”); (2) Plan Accounting: Defined Benefit Pension Plans (Topic 960); Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Plan Investment Disclosures (“Part II”); and (3) Plan Accounting: Defined Benefit Pension Plans (Topic 960); Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Measurement Date Practical Expedient (“Part III”). Part I requires (1) fully benefit-responsive investment contracts to be measured at contract value; and (2) an adjustment to reconcile contract value to fair value, when these measures differ, on the face of the plan financial statements. Part II eliminates the current requirement for both participant-directed investments and non-participant-directed investments to disclose individual investments representing 5% or more of net assets available for benefits, as well as the net appreciation or depreciation for investments by general type on a disaggregated basis.  Part III permits plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan’s fiscal year-end, when the fiscal period does not coincide with a month-end. The amendments in Update 2015-12 are effective for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-12 and assessing the impact, if any, it may have on its consolidated results of operations, financial position, or cash flows.

In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Business Combinations (Topic 805) (“Update 2015-16”), which seeks to reduce the complexity of amounts recognized in a business combination. The amendments in Update 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in Update 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in Update 2015-16 require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in Update 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Company is currently evaluating the provisions of Update 2015-16 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

XML

Acquisitions And Divestitures

12 Months Ended

Dec. 31, 2015

Acquisitions And Divestitures [Abstract]

Acquisitions And Divestitures

(2) ACQUISITIONS AND DIVESTITURES

In May 2015, the Company sold conventional oil and gas assets located in East Texas and the Arkoma Basin for approximately $211 million. These properties were previously referred to as the Ark-La-Tex division. The net book value of these assets was primarily in the full cost pool and was held in the E&P segment as of the closing date. The proceeds from the transaction were used to reduce the Company’s debt. Approximately $205 million of the proceeds received were recorded as a reduction of the capitalized costs of the Company’s natural gas and oil properties in the United States pursuant to the full cost method of accounting.

In April 2015, the Company sold its gathering assets located in Bradford and Lycoming counties in northeast Pennsylvania to Howard Midstream Energy Partners, LLC for an adjusted sales price of approximately $489 million. The net book value of these assets was $206 million and was held in the Midstream segment as of the closing date. A gain on sale of $283 million was recognized and is included in gain on sale of assets, net on the consolidated statement of operations. The assets include approximately 100 miles of natural gas gathering pipelines, with nearly 600 million cubic feet per day of capacity. The proceeds from the transaction were used to substantially repay borrowings under the Company’s $500 million term loan facility that would have matured in December 2016.

In January 2015, the Company completed an acquisition of certain natural gas and oil assets including approximately 46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. for an adjusted purchase price of $270 million (the “WPX Property Acquisition”). This acreage was producing approximately 50 million net cubic feet of gas per day from 63 operated horizontal wells as of December 2014. As part of this transaction, the Company assumed firm transportation capacity of 260 million cubic feet of gas per day predominantly on the Millennium pipeline. The firm transportation is being amortized over 19 years.  As of December 31, 2015 the Company has amortized $8.2 million.  This transaction was funded with the revolving credit facility and was accounted for as a business combination.  The following table summarizes the consideration paid for the WPX Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date:

Consideration:
Cash	$	270
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Proved natural gas and oil properties		31
Unproved natural gas and oil properties		114
Intangible asset		109
Gathering system		22
Other		1
Total assets acquired		277
Liabilities assumed:
Asset retirement obligations		(7)
Total liabilities assumed		(7)
	$	270

In January 2015, the Company completed an acquisition in which the Company’s subsidiary acquired certain natural gas and oil assets from Statoil ASA covering approximately 30,000 acres in West Virginia and southwest Pennsylvania comprising approximately 20% of Statoil’s interests in that acreage for $357 million, (the “Statoil Property Acquisition”). All of these assets are also assets in which the Company has acquired interests under the Chesapeake Property Acquisition. This transaction was funded with the revolving credit facility and was accounted for as a business combination. The Company allocated approximately $357 million of the purchase price to natural gas and oil properties, based on the respective fair values of the assets acquired.

In December 2014, the Company completed an acquisition of certain oil and gas assets from Chesapeake Energy Corporation covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, NGLs and crude oil contained in the Upper Devonian, Marcellus and Utica Shales for approximately $5.0 billion.  The Chesapeake Property Acquisition was temporarily financed using a $4.5 billion 364-day senior unsecured bridge term loan credit facility and a $500 million two-year unsecured term loan.  The Company repaid all principal and interest outstanding on the $4.5 billion bridge facility in January 2015 after permanent financing was finalized and as a result, expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015 recognized in other interest charges on the consolidated statement of operations. The term loan facility was repaid in full in April 2015 with proceeds from the divestiture of the Company’s northeast Pennsylvania gathering assets and borrowings under the revolving credit facility.

The following table summarizes the consideration paid for the Chesapeake Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date, updated for subsequent customary post-closing adjustments:

Consideration:
Cash	$	4,949
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Proved natural gas and oil properties		1,418
Unproved natural gas and oil properties		3,573
Other property and equipment		33
Inventory		3
Total assets acquired		5,027
Liabilities assumed:
Asset retirement obligations		(42)
Other liabilities		(36)
Total liabilities assumed		(78)
	$	4,949

The above acquisitions qualified as business combinations, and as a result, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 7 – Fair Value Measurements.

The Company recorded the assets acquired and liabilities assumed in the Chesapeake Property Acquisition at their estimated fair value of approximately $5.0 billion, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.  In addition, the Company included $1 million in general and administrative expenses and $5 million in interest expense for fees related to the Chesapeake Property Acquisition on its consolidated statement of operations for the year ended December 31, 2014. The Company included $47 million in other current assets and $1 million in other assets for unamortized fees related to the bridge facility and term loan facility, respectively, for the Chesapeake Property Acquisition on its consolidated balance sheet as of December 31, 2014. In January 2015, the Company repaid in full amounts outstanding on its bridge facility. Therefore, the Company expensed the $47 million of short-term unamortized debt issuance costs associated with the bridge facility in January 2015. The term loan facility was repaid in full in April 2015.

The results of operations of the Chesapeake Property Acquisition have been included in the Company’s consolidated financial statements since the December 22, 2014 closing date, including approximately $10 million of total revenue and $2 million of operating income for the year ended December 31, 2014. Summarized below are the consolidated results of operations for the years ended December 31, 2014 and 2013, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2013. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Chesapeake Property Acquisition properties. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations. The unaudited pro forma financial information excludes the WPX Property and Statoil Property Acquisitions as the impacts are immaterial.

	For the years ended
	December 31,
	2014		2013
	(in millions) (unaudited)
Revenues	$	4,439	$	3,713
Net income attributable to common stock		803		594
Earnings per share
Basic	$	2.11	$	1.56
Diluted		2.10		1.56

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 $215 million. The Company utilized its revolving credit facility to finance these acquisitions. The Company closed the acquisitions in the second and third quarters in 2014 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 $82 million, subject to closing conditions.  The Company utilized its revolving credit facility to finance the acquisition.  The Company closed the acquisition during the second quarter of 2013 and accounted for it as an asset acquisition.

XML

Prepaid Expenses

12 Months Ended

Dec. 31, 2015

Prepaid Expenses [Abstract]

Prepaid Expenses

(3)  PREPAID EXPENSES

The components of prepaid expenses included in other current assets as of December 31, 2015 and December 31, 2014 consisted of the following:

	2015		2014
		(in millions)
Prepaid taxes	$	26	$	30
Prepaid insurance		6		8
Other prepaid expenses		11		5
Deposits (1)		–		65
Total	$	43	$	108

(1) Deposits as of December 31, 2014 consisted of a $50 million and $15 million pre-payment related to the Statoil Property Acquisition and WPX Property Acquisition, respectively.

XML

Natural Gas And Oil Producing Activities

12 Months Ended

Dec. 31, 2015

Natural Gas And Oil Producing Activities [Abstract]

Natural Gas And Oil Producing Activities

(4) NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) 

The Company’s natural gas and oil properties are located in the United States and Canada.

Net Capitalized Costs

The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2015 and 2014:

	2015		2014
	(in millions)
Proved properties	$	18,751	$	15,860
Unproved properties(1)		3,727		4,646
Total capitalized costs		22,478		20,506
Less:  Accumulated depreciation, depletion and amortization		(16,248)		(8,327)
Net capitalized costs	$	6,230	$	12,179

(1) Includes $50 million and $76 million related to the Company’s exploration program in Canada as of December 31, 2015 and 2014, respectively.

Natural gas and oil properties not subject to amortization represent investments in unproved properties and major development projects in which the Company owns an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress.  The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2015.

	2015		2014		2013		Prior		Total
	(in millions)
Property acquisition costs(1)	$	274	$	2,870	$	42	$	105	$	3,291
Exploration and development costs(1)		128		56		29		36		249
Capitalized interest(1)		120		22		11		34		187
	$	522	$	2,948	$	82	$	175	$	3,727

(1) Property acquisition costs include $16 million, exploration costs include $26 million and capitalized interest includes $8 million related to the Company’s exploration program in Canada.

Of the total net unevaluated costs excluded from amortization as of December 31, 2015,  approximately $2.9 billion is related to the Chesapeake Property Acquisition, approximately $265 million is related to the acquisition of undeveloped properties in the Company’s New Ventures, excluding its exploration program in Canada, and approximately $121 million is related to the acquisition of the Company’s undeveloped properties in the Marcellus Shale. The Company has $50 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $157 million of unevaluated costs related to costs of wells in progress. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling, and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.

Costs Incurred in Natural Gas and Oil Exploration and Development

The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:

	2015		2014		2013
	(in millions, except per Mcfe amounts)
Proved property acquisition costs	$	81	$	1,455	$	1
Unproved property acquisition costs (1)		692		3,934		168
Exploration costs(2)		50		232		192
Development costs		1,417		1,600		1,662
Capitalized costs incurred		2,240		7,221		2,023
Full cost pool amortization per Mcfe	$	1.00	$	1.10	$	1.08

(1) Included  $1 million and $17 million in 2014 and 2013, respectively, related to the Company’s exploration program in Canada.

(2) Included  $3 million and $12 million in 2014 and 2013, respectively, related to the Company’s exploration program in Canada.

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $204million, $55 million and $62 million during 2015, 2014 and 2013, respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures.

In addition to capitalized interest, the Company capitalized internal costs totaling $307million, $320 million and $264 million during 2015, 2014 and 2013, respectively, which were directly related to the acquisition, exploration and development of the Company’s natural gas and oil properties.  Included in these amounts are internal costs from the Company’s subsidiaries involved with vertical integration of the Company’s exploration and development activities and totaled $118 million,  $123 million and $103 million during 2015, 2014 and 2013, respectively.  All internal costs are included in the Company’s cost of natural gas and oil properties.

Results of Operations from Natural Gas and Oil Producing Activities

The table below sets forth the results of operations from natural gas and oil producing activities:

	2015		2014		2013
	(in millions)
Sales	$	2,074	$	2,862	$	2,404
Production (lifting) costs		(989)		(776)		(629)
Depreciation, depletion and amortization		(1,028)		(884)		(735)
Impairment of natural gas and oil properties		(6,950)		–		–
		(6,893)		1,202		1,040
Provision (benefit) for income taxes		(2,619)		457		416
Results of operations (1)	$	(4,274)	$	745	$	624

(1) Results of operations exclude the gain (loss) on derivatives, unsettled, on commodity derivative instruments.  See Note 5-  Derivatives and Risk Management.

The results of operations shown above exclude general and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.

Natural Gas and Oil Reserve Quantities

The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties and accounted for approximately 100%,97% and 95% of the present worth of the Company’s total proved reserves as of December 31, 2015, 2014 and 2013, respectively. A reserve audit is not the same as a financial audit and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates are inherently imprecise and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, historical prices of natural gas and crude oil and analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business – Exploration and Production” in Item 1 of this Annual Report.

The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2015,  2014 and 2013 all of which were located in the United States:

	2015			2014			2013
	Natural			Natural			Natural
	Gas	Oil	NGL	Gas	Oil	NGL	Gas	Oil	NGL
	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)
Proved reserves, beginning of year	9,809	37,615	118,699	6,974	373	–	4,017	244	–
Revisions of previous estimates	(3,458)	(28,394)	(75,664)	542	(14)	66	325	38	50
Extensions, discoveries and other additions	546	1,367	6,274	1,692	250	48	3,284	229	–
Production	(899)	(2,265)	(10,702)	(766)	(235)	(231)	(656)	(138)	(50)
Acquisition of reserves in place	97	525	2,340	1,367	37,246	118,816	4	–	–
Disposition of reserves in place	(178)	(95)	–	–	(5)	–	–	–	–
Proved reserves, end of year	5,917	8,753	40,947	9,809	37,615	118,699	6,974	373	–
Proved developed reserves:
Beginning of year	5,675	7,445	38,632	4,237	372	–	3,196	243	–
End of year	5,474	8,753	40,947	5,675	7,445	38,632	4,237	372	–
Proved undeveloped reserves:
Beginning of year	4,134	30,170	80,067	2,737	1	–	821	1	–
End of year	443	–	–	4,134	30,170	80,067	2,737	1	–

The Company’s estimated proved natural gas and oil reserves were 6,215 Bcfe at year-end 2015, compared to 10,747 Bcfe at year-end 2014. The significant decrease in the Company’s reserves in 2015 was primarily due to the decrease in commodity prices.In 2015, the Company’s natural gas and liquids production was 976  Bcfe, up from 768 Bcfe in 2014. The increase in production in 2015 resulted primarily from a  140 Bcfe increase in net production from the Company’sSouthwest Appalachia properties, a 106 Bcf increase in net production from its Northeast Appalachia properties, partially offset by 29 Bcf and 9 Bcfe decreases in net production from its Fayetteville Shale and other properties, respectively. The Company hadnet downward revisions of 4,083 Bcfe and disposition of reserves in place of 179 Bcfe,  partially offset by 592 Bcfe of proved reserve additions and 114 Bcfe of proved reserve additions from acquisitions.  Of the reserve additions,  202 Bcf, 84 Bcfe, 129 Bcf and 1 Bcfe from the Company’s Northeast Appalachia, Southwest Appalachia, Fayetteville Shale and other divisions, respectively, were proved developed and 138 Bcf, 4 Bcfe and 34 Bcf from its Northeast Appalachia, Southwest Appalachia and Fayetteville Shale divisions, respectively, were proved undeveloped. In 2015,  downward reserve revisions resulting from lower prices totaled 2,315 Bcf, 1,875 Bcfe,1,496 Bcf and 32 Bcfe in the Company’s Northeast Appalachia,  Southwest Appalachia, Fayetteville Shale and other divisions, respectively.  The Company also had upward performance revisions in 2015 of 1,383 Bcf, 209 Bcfe,10 Bcf and 33 Bcfe in its Northeast Appalachia, Southwest Appalachia, Fayetteville Shale and other divisions, respectively. The Company’s December 31, 2015 proved reserves included217 Bcfe of proved undeveloped reserves from 75 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties had a negative present value of $34 million when discounted at 10%. The Company made a final investment decision and is committed to developing these reserves within the next five years.

The Company’s estimated proved natural gas and oil reserves were 10,747 Bcfe at year-end 2014, compared to 6,976 Bcfe at year-end 2013.The significant increase in the Company’s reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. In 2014, the Company’s natural gas and liquids production was 768 Bcfe, up from 657 Bcfe in 2013. The increase in production in 2014 resulted primarily from a 103 Bcf increase in net production from the Company’s Northeast Appalachia properties, an8 Bcf increase in net production from itsFayetteville properties, and a 3 Bcfe increase in net production from its Southwest Appalachia properties, which more than offset a combined 3 Bcfe decrease in net production from its East Texas and Arkoma Basin properties. The Company replaced 591% of its production volumes with 1,693 Bcfe of proved reserve additions, net upward revisions of 543 Bcfe, and 2,304 Bcfe of proved reserve additions as a result of acquisitions primarily associated with acreage in Southwest Appalachia.  Of the reserve additions, 283 Bcf, 246 Bcfe and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia and Brown Dense divisions, respectively, were proved developed and  573 Bcf and 589  Bcfe from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped.  In 2014, upward reserve revisions resulting from higher gas prices totaled 38 Bcf, 10 Bcf and 6 Bcf in the Fayetteville Shale, Northeast Appalachia, and Ark-La-Tex division, respectively.  The Company also had performance revisions in 2014 of (126) Bcf, 636 Bcf and (21) Bcf in its Fayetteville Shale, Northeast Appalachia, and Ark-La-Tex divisions, respectively.  The Company’s December 31, 2014 proved reserves include 181 Bcfe of proved undeveloped reserves from 60 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but did not have a positive present value when discounted at 10%. These properties had a negative present value of $28 million when discounted when at 10%.

The Company’s estimated proved natural gas and oil reserves were 6,976 Bcfe at year-end 2013, compared to 4,018 Bcfe at year-end 2012. The overall increase in total estimated proved reserves in 2013 was primarily due to its successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and the higher natural gas price environment compared to 2012.  In 2013, the Company’s natural gas and liquids production was 657 Bcfe, up from 565 Bcfe in 2012. The increase in production in 2013 resulted primarily from a 97 Bcf increase in production from the Company’s Northeast Appalachia properties, a 1 Bcfe increase in net production from its New Ventures properties, and a 1 Bcf increase in net production from its Fayetteville Shale properties, which more than offset a combined 7 Bcfe decrease in net production from its East Texas and Arkoma Basin properties. The Company replaced 550% of its production volumes with3,285 Bcfe of proved reserve additions, 557 Bcf, 386 Bcf and 2 Bcfe from the Company’s Fayetteville Shale, Northeast Appalachia and Brown Dense divisions, respectively, were proved developed and 1,530 Bcf and 810 Bcf from its Fayetteville Shale and Northeast Appalachia divisions, respectively, were proved undeveloped. In 2013, upward reserve revisions resulting from higher gas prices totaled 191 Bcf, 35 Bcf and 21 Bcf in the Fayetteville Shale, Northeast Appalachia, and the Company’s Ark-La-Tex division, respectively.  The Company also had upward performance revision in 2013 of 16 Bcf, 62 Bcf and 1 Bcfe in the Fayetteville Shale, Northeast Appalachia, and the Company’s New Ventures division, respectively. Additionally, the Company’s reserves increased by 4 Bcf in 2013 as a result of the acquisition of natural gas leases and wells in Northeast Appalachia.The Company’s December 31, 2013 proved reserves included 662 Bcfe of proved undeveloped reserves from 268 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but did not have a positive present value when discounted at 10%. These properties had a negative present value of $97 million when discounted when at 10%.

The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.

Standardized Measure of Discounted Future Net Cash Flows

The following standardized measures of discounted future net cash flows relating to proved natural gas and oil reserves as of December 31, 2015, 2014 and 2013 are calculated after income taxes and discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas and oil reserves:

	2015		2014		2013
	(in millions)
Future cash inflows	$	11,887	$	41,812	$	22,624
Future production costs		(7,376)		(16,477)		(8,896)
Future development costs		(792)		(5,750)		(3,626)
Future income tax expense (1)		–		(4,743)		(3,223)
Future net cash flows		3,719		14,842		6,879
10% annual discount for estimated timing of cash flows		(1,302)		(7,299)		(3,143)
Standardized measure of discounted future net cash flows	$	2,417	$	7,543	$	3,736

(1) The December 31, 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.

Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves.  Prices used for the standardized measure above were $2.59 per MMBtu for natural gas, $46.79 per barrel for oil and $6.82 per barrel for NGLs in 2015, $4.35 per MMBtu for natural gas,  $91.48 per barrel for oil and $23.79 per barrel for NGLs in 2014, and $3.67 per MMBtu for natural gas,  $93.42 per barrel for oil and $43.45 per barrel for NGLs in 2013. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.

Following is an analysis of changes in the standardized measure during 2015, 2014 and 2013:

	2015		2014		2013
	(in millions)
Standardized measure, beginning of year	$	7,543	$	3,736	$	2,051
Sales and transfers of natural gas and oil produced, net of production costs		(1,082)		(2,084)		(1,774)
Net changes in prices and production costs		(8,075)		1,192		1,853
Extensions, discoveries, and other additions, net of future production and development costs		162		1,049		1,454
Acquisition of reserves in place		28		1,897		5
Sales of reserves in place		(244)		–		–
Revisions of previous quantity estimates		(1,385)		622		349
Accretion of discount		946		513		232
Net change in income taxes		1,915		(522)		(1,120)
Changes in estimated future development costs		2,007		110		(196)
Previously estimated development costs incurred during the year		875		815		223
Changes in production rates (timing) and other		(273)		215		659
Standardized measure, end of year	$	2,417	$	7,543	$	3,736

XML

Derivatives And Risk Management

12 Months Ended

Dec. 31, 2015

Derivatives And Risk Management [Abstract]

Derivatives And Risk Management

(5) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of natural gas, oil and NGLs. These risks are managed by the Company’s use of certain derivative financial instruments.  As of December 31, 2015, the Company’s derivative financial instruments consisted of basis swaps, fixed price call options and interest rate swaps. As of December 31, 2014, 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.

All derivatives are recognized in the balance sheet as either an asset or liability and are 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. In the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in operating revenues. 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 credit-worthy 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.

The balance sheet classification of the assets related to derivative financial instruments are summarized below as of December 31, 2015 and 2014:

	Derivative Assets
	December 31, 2015			December 31, 2014
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in millions)
Derivatives designated as hedging instruments:
Fixed price swaps	Derivative assets	$	–	Derivative assets	$	165
Total derivatives designated as hedging instruments		$	–		$	165
Derivatives not designated as hedging instruments:
Basis swaps	Derivative assets	$	3	Derivative assets	$	9
Fixed price swaps	Derivative assets		–	Derivative assets		163
Basis swaps	Other long-term assets		–	Other long-term assets		1
Interest rate swaps	Other long-term assets		–	Other long-term assets		1
Total derivatives not designated as hedging instruments		$	3		$	174
Total derivative assets		$	3		$	339
	Derivative Liabilities
	December 31, 2015			December 31, 2014
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in millions)
Derivatives not designated as hedging instruments:
Basis swaps	Derivative liabilities	$	–	Derivative liabilities	$	4
Fixed price call options	Derivative liabilities		–	Derivative liabilities		2
Interest rate swaps	Derivative liabilities		3	Derivative liabilities		3
Fixed price call options	Other long-term liabilities		–	Other long-term liabilities		10
Basis swaps	Other long-term liabilities		–	Other long-term liabilities		2
Interest rate swaps	Other long-term liabilities		2	Other long-term liabilities		2
Total derivatives not designated as hedging instruments		$	5		$	23
Total derivative liabilities		$	5		$	23

Cash Flow Hedges

The Company has certain fixed price swaps that are designated for hedge accounting. 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 are recognized in earnings immediately and had an inconsequential impact to the consolidated statement of operations as of December 31, 2015 and 2014.

The amount included in accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the physical transactions being hedged occur. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to revenues 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.As of December 31, 2015, the Company had nofixed price swap derivatives and no accumulated other comprehensive income related to its hedging activities.

The following tables summarize the before tax effect of all fixed price swaps designated for hedge accounting on the consolidated financial statements for the years ended December 31, 2015 and 2014.  

		Gain Recognized in Other Comprehensive Income
		(Effective Portion)
		For the years ended
		December 31,
Derivative Instrument		2015		2014
		(in millions)
Fixed price swaps		$	45	$	122
	Classification of Gain (Loss)	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Earnings
	Reclassified from Accumulated	(Effective Portion)
	Other Comprehensive Income	For the years ended
	into Earnings	December 31,
Derivative Instrument	(Effective Portion)	2015		2014
		(in millions)
Fixed price swaps	Gas Sales	$	209	$	(26)

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 through gain (loss) on derivatives. 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, 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 statements of operations as a component of gain (loss) on derivatives. As of December 31, 2015, the Company had5 Bcf of basis swaps on 2016 natural gas production that were not designated for hedge accounting.

As of December 31, 2015, the Company had fixed price call options on 120 Bcf of natural gas production in 2016 that do not qualify and are not designated for hedge accounting.

The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps have 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 tables summarize 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 consolidated statements of operations for the years ended December 31, 2015 and 2014.

		Gain (Loss) on Derivatives,
		Excluding Derivatives, Settled
		Recognized in Earnings
	Consolidated Statements of Operations	For the years ended
	Classification of Gain (Loss) on	December 31,
Derivative Instrument	Derivatives, Net of Settlement	2015		2014
		(in millions)
Basis swaps	Gain on Derivatives	$	(2)	$	(7)
Fixed price call options	Gain on Derivatives		13		18
Fixed price swaps	Gain on Derivatives		(164)		126
Interest rate swaps	Gain on Derivatives		(2)		(7)
		Gain (Loss)
		on Derivatives, Settled (1)
		Recognized in Earnings
	Consolidated Statements of Operations	For the years ended
	Classification of Gain (Loss)	December 31,
Derivative Instrument	on Derivatives, Settled (1)	2015		2014
		(in millions)
Basis swaps	Gain on Derivatives	$	(2)	$	12
Fixed price swaps	Gain on Derivatives		208		(2)
Interest rate swaps	Gain on Derivatives		(4)		(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.

XML

Reclassifications From Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2015

Reclassifications From Accumulated Other Comprehensive Income [Abstract]

Reclassifications From Accumulated Other Comprehensive Income

(6) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME

The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects for the year ended December 31, 2015:

	For the year ended
	December 31, 2015
	Gains (Losses) on Cash Flow Hedges		Pension and Other Postretirement		Foreign Currency		Total
	(in millions) (1)
Beginning balance, December 31, 2014	$	98	$	(24)	$	(12)	$	62
Other comprehensive income (loss) before reclassifications		29		–		(11)		18
Amounts reclassified from/to other comprehensive income (2)		(127)		(1)		–		(128)
Net current-period other comprehensive income (loss)		(98)		(1)		(11)		(110)
Ending balance, December 31, 2015	$	–	$	(25)	$	(23)	$	(48)

(1) All amounts are net of tax.

(2) See separate table below for details about these reclassifications.

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statements of Operations		Amount Reclassified from/to Accumulated Other Comprehensive Income
			For the year ended December 31, 2015
			(in millions)
Cash flow hedges
Settlements	Gas sales	$	(209)
Ineffectiveness	Gain on derivatives		1
	Provision (benefit) for income taxes		(81)
	Net income (loss)	$	(127)
Pension and other postretirement (1)
Net actuarial loss (2)		$	(3)
Amortization of prior service cost and net loss	General and administrative expenses	$	2
	Provision (benefit) for income taxes		–
	Net income (loss)	$	(1)
Total reclassifications for the period	Net income (loss)	$	(128)

(1) See Note 12 for additional details regarding the Company’s retirement and employee benefit plans.

(2) Net actuarial loss had no impact on the consolidated statement of operations.

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

(7) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2015 and 2014 were as follows:

	December 31, 2015				December 31, 2014
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in millions)
Cash and cash equivalents	$	15	$	15	$	53	$	53
Credit facility		116		116		300		300
Term loan facility		750		750		500		500
Bridge facility		–		–		4,500		4,500
Senior notes		3,863		2,672		1,667		1,751
Derivative instruments, net		(2)		(2)		316		316

The carrying values of cash and cash equivalents, accounts receivable, accounts payable, other current assets and current liabilities on the 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 value of the Company’s publiclytraded debt as determined based on the yield of the Company’s senior notes.  

The carrying values of the borrowings under the Company’s unsecured revolving credit facility, term loan facility and previously, bridge facility approximate 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.

The fair value hierarchy 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 fixed price swaps (Level 2) and are estimated using third-party discounted cash flow calculations using the NYMEX futures index. The Company utilized discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2015 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 fixed price call options (Level 3) 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 (Level 3) are estimated using third-party 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 the most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively. However, such changes would not have a significant impact.

Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):

	December 31, 2015
	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
Fixed price swap assets	$	–	$	–	$	–	$	–
Interest rate swap assets		–		–		–		–
Basis swap assets		–		–		3		3
Interest rate swap liabilities		–		(5)		–		(5)
Basis swap liabilities		–		–		–		–
Fixed price call option liabilities		–		–		–		–
Total	$	–	$	(5)	$	3	$	(2)
	December 31, 2014
	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
Fixed price swap assets	$	–	$	328	$	–	$	328
Interest rate swap assets		–		1		–		1
Basis swap assets		–		–		10		10
Interest rate swap liabilities		–		(5)		–		(5)
Basis swap liabilities		–		–		(6)		(6)
Fixed price call option liabilities		–		–		(12)		(12)
Total	$	–	$	324	$	(8)	$	316

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 years ended December 31, 2015 and 2014. 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 reasonable assumptions a marketplace participant would have used as of December 31, 2015 and December 31, 2014.

	For the years ended
	December 31,
	2015		2014
	(in millions)
Balance at beginning of year	$	(8)	$	(19)
Total gains (losses):
Included in earnings		9		23
Included in other comprehensive income		–		–
Purchases, issuances, and settlements:
Purchases		–		–
Issuances		–		–
Settlements		2		(12)
Transfers into/out of Level 3		–		–
Balance at end of year	$	3	$	(8)
Change in gains (losses) included in earnings relating to derivatives still held as of December 31	$	11	$	11

See Note 12 – Retirement and Employee Benefit Plans for a discussion of the fair value measurement of the Company’s pension plan assets.

XML

Debt

12 Months Ended

Dec. 31, 2015

Debt [Abstract]

Debt

(8) DEBT

The components of debt as of December 31, 2015 and 2014 consisted of the following:

	2015		2014
	(in millions)
Short-term debt:
7.15% Senior Notes due May 2018	$	1	$	1
Variable rate (1.515% at December 31, 2014) bridge facility, due December 2015		–		4,500
Total short-term debt		1		4,501
Long-term debt:
Variable rate (1.886%  and 1.515% at December 31, 2015 and December 31, 2014, respectively) credit facility, expires December 2018		116		300
Variable rate (1.545% at December 31, 2014) term loan facility, due December 2016		–		500
Variable rate (1.775% at December 31, 2015) term loan facility, due November 2018		750		–
7.35% Senior Notes due October 2017		15		15
7.125% Senior Notes due October 2017		25		25
3.3% Senior Notes due January 2018		350		–
7.5% Senior Notes due February 2018		600		600
7.15% Senior Notes due May 2018		26		27
4.05% Senior Notes due January 2020		850		–
Unamortized discount		(1)		–
4.10% Senior Notes due March 2022		1,000		1,000
Unamortized discount		(1)		(1)
4.95% Senior Notes due January 2025		1,000		–
Unamortized discount		(2)		–
Total long-term debt		4,728		2,466
Total debt	$	4,729	$	6,967

The following is a summary of scheduled long-term debt maturities by year as of December 31, 2015 (in millions):

2016		1
2017		41
2018		1,841
2019		–
2020		850
Thereafter		2,000
	$	4,733

Commercial Paper

In April 2015, the Company entered into a commercial paper program which allowed it to issue up to $2.0 billion in commercial paper, provided that outstanding borrowings from its commercial paper program, combined with outstanding borrowings under our revolving credit facility, not exceed $2.0 billion.  The commercial paper issuance had terms of up to 397 days and carried interest at rates agreed upon at the time of each issuance.  As of December 31, 2015, the Company had no outstanding issuances under its commercial paper program and had no plans of utilizing the commercial paper market after the first quarter of 2016.

Public Offering of Senior Notes

In January 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.30% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of its 4.05% senior notes due 2020 (the “2020 Notes”) and $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes” together with the 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses.  The proceeds from this offering were used to repay the remaining principal and interest outstanding under the Company’s $4.5 billion 364-day bridge term loan facility, which was first reduced with proceeds from the Company’s concurrent underwritten public offerings of common and preferred stock, and were also used to repay a portion of amounts outstanding under the Company’s revolving credit facility.  As a result of this repayment, the Company expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015 recognized in other interest charges on the consolidated statement of operations for the year ended December 31, 2015.  The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 Notes.  The interest rates on the Notes is determined based upon the Company’s public debt ratings from S&P and Moody’s.  Downgrades from either rating agency increase interest costs by 25.0 basis points per downgrade level on the following semi-annual bond interest payment.  In February 2016,  S&P and Moody’s downgraded the Company’s credit ratings,increasing the interest rates on these notes by 125.0 basis points effective July 2016.

Credit and Term Facilities 

In November 2015, the Company entered into a $750 million unsecured three-year term loan credit agreement with various lenders that was utilized to repay borrowings under the revolving credit facility. The interest rate on the term loan facility is determined based upon the Company’s public debt ratings from S&P and Moody’s and was 137.5 basis points over the London Interbank Offered Rate (“LIBOR”) as of December 31, 2015.  Based on the February 2016 downgrades from S&P and Moody’s the Company’s interest rate on the term loan increased to162.5 basis points over LIBOR.  The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business.

The Company’s revolving credit facility entered into in December 2013, provides a borrowing capacity of up to  $2.0 billion and matures in December 2018, with options for twoone-year extensions with participating lender approval. The amount available under the revolving credit facility may be increased by $500 million upon the Company’s agreement with its participating lenders. The interest rate on the revolving credit facility is calculated based upon the Company’s public debt ratings from S&P and Moody’s and was150.0and 137.5basis points over LIBOR as of December 31, 2015 and 2014, respectively.  Based on the February 2016 downgrades from S&P and Moody’s the Company’s interest rate on its revolving credit facility increased to 200.0 basis points over LIBOR. 

The revolving credit facility and term loan facility are unsecured and are not guaranteed by any subsidiaries of the Company.  The revolving credit facility and term loan facility contain covenants imposing certain restrictions on the Company, including a financial covenant under which Southwestern may not issue total debt in excess of 60% of its total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and the Company’s pension and other postretirement liabilities. As of December 31, 2015, the Company’s adjusted capital structure was 38% debt, 62% equity and was in compliance with the covenants of itsrevolving credit facility, term loan facility and other debt agreements.

In December 2014, the Company entered into a $500 million unsecured two-year term loan credit agreement with various lenders. The term loan facility, prior to its termination, required prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business. The term loan facility was repaid in full in April 2015 with proceeds from the divestiture of the Company’s northeast Pennsylvania gathering assets and borrowings under the Company’s revolving credit facility.

Chesapeake Property Acquisition Financing

On December 19, 2014, the Company entered into a $4.5 billion unsecured 364-day bridge term loan credit agreement with various lenders. The bridge facility requires prepayments under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business or for specified uses. The Company repaid the $4.5 billion outstanding and terminated the bridge facility in January 2015 with net proceeds of $669 million and $1.7 billion from common stock and depositary share offerings, respectively, and $2.2 billion from senior note offerings with the difference utilized to pay down amounts under the revolving credit facility.

XML

Commitments And Contingencies

12 Months Ended

Dec. 31, 2015

Commitments And Contingencies [Abstract]

Commitments And Contingencies

(9) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

The Company has contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems. As of December 31, 2015, future payments under non-cancelable firm transportation agreements are approximately $623 million in 2016, $691 million in 2017, $712 million in 2018, $751 million in 2019, $702 million in 2020 and $5,402 million thereafter.Of the total $8.9 billion, 38% related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. The Company also has guarantee obligations of up to $960 million of that amount.  Additionally, $100 million relates to demand charges under firm transportation agreements under which the Company has the option to reduce its commitment by 531 Bcf beginning in 2018.

The Company has 14 leases for pressure pumping equipment for its E&P operations under leases that expire between December 2017 and March 2018.  The Company’s current aggregate annual payment under the leases is approximately $8 million.  The Company has 7 leases for drilling rigs for its E&P operations that expire in 2020. The Company’s current aggregate annual payment under the leases is approximately $13million.The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners for their share of fracture stage charges.

The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through 2027.  As of December 31, 2015, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $71 million in 2016, $64 million in 2017, $44 million in 2018, $38 million in 2019, $30 million in 2020 and $28 million thereafter.

The Company also has commitments for compression services related to its Midstream Services and E&P segments. As of December 31, 2015, future minimum payments under these non-cancelable agreements are approximately $21 million in 2016, $14 million in 2017, $8 million in 2018, $5 million in 2019,  and $1 million in 2020.

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 the license periods. 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 December 31, 2015 has invested $45 million Canadian dollars, or $44 million US dollars, in New Brunswick towards the Company’s commitment, fully covering the promissory notes held by the Province of New Brunswick.No liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of December 31, 2015 and its future investment plans.In December 2014, New Brunswick’s provincial government announced its intent to impose a moratorium on hydraulic fracturing in the province, and, on March 27, 2015, the provincial legislature approved enabling legislation.  The Company has been granted an extension of its licenses.  The provincial government has announced a list of conditions that must be met before the moratorium can be lifted, but because these conditions are subjective and the government has discretion whether to grant an extension, the Company cannot predict the duration of the moratorium or whether it will continue beyond the expiration of the licenses, as their terms have been, or in the future may be, extended.  Unless and until the moratorium is lifted,the Company will not be able to continue with its program in New Brunswick. If the licenses expire before the moratorium is lifted or the Company can complete its program,the Company  may be required to write off its investment.

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 results of operations of the Company.

Litigation

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 the Company’s 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 are 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.

Tovah Energy

In February 2009, one of the Company’s subsidiaries 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 the Company’s subsidiary with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that the Company’s subsidiary 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 the Company’s subsidiary between February 2005 and February 2006.  She also sought disgorgement of the Company’s subsidiary’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 the Company’s subsidiary’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 Tyler Court of Appeals 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 is 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 secrets is affirmed, (4) the case be remanded to the trial court for a determination and award of attorney’s fees for the Company’s subsidiary 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 Tyler Court of Appeals denied rehearing in November 2013. 

The Company’s subsidiary filed a petition for review in the Supreme Court of Texas in February 2014.  The plaintiff and the intervenor filed a cross-petition for review in April 2014, but conditioned their filing on the court’s granting the Company’s subsidiary’s petition for review; i.e., if the court denies the Company’s subsidiary’s petition for review, then the plaintiff and the intervenor are not seeking further review of the court of appeals’ judgment.The Supreme Court granted the parties’ petitions and heard oral argument on the case in October 2015 but has not yet issued a decision.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 Companyhas not accrued any amounts with respect to this action.  If the Supreme Court affirms all aspects of the court of appeals’ judgment, then the Company’s subsidiary 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 depending on the Supreme Court’s decision, 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.

Arkansas Royalty Litigation

Certain of the Company’s subsidiaries are defendants in three cases, two filed in Arkansas state court in 2010 and 2013 and one in federal court in 2014, on behalf of putative classes of royalty owners on some of the Company’s leases located in Arkansas.  The chief complaint in all three cases is that one of the Company’s subsidiaries 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. 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’s subsidiaries are appealing those orders.  In one of those cases, the class representative has died, and the case has been remanded to the trial court for possible substitution of a new class representative.

On November 17, 2015, the court in the federal case denied the plaintiff’s motion to certify a class of royalty owners not included in either of the two state cases.  That court is still considering a motion by the Company’s subsidiaries to certify a broader class that would, among other things, encompass all cost-bearing royalty owners with leases for property in the Fayetteville Shale.  The federal court has not yet ruled on certification.  The plaintiff in the federal case presented two alternative damages theories.  Under one theory, plaintiffs have asserted that obligations to affiliates are not “incurred” and therefore the exploration subsidiary was not entitled to deduct any post-production costs; the federal court has granted partial summary judgment for the Company’s subsidiaries on this theory.  Under another theory, plaintiffs assert that the gathering and treating rates it deducted from royalty payments exceeded the affiliates’ actual costs or otherwise were not reasonable.  The plaintiffs have not disclosed a specific damage calculation for any putative class, but based on the putative class representative’s disclosure regarding the calculation of claimed damages, class-wide damages could exceed $100 million. Trial in the federal case is currently set to begin March 15, 2016.

In addition, in September 2015 three cases were filed in Arkansas state court on behalf of a total of 248 individually named plaintiffs. Each case asserts complaints that are in substance virtually identical to the above-described case. The Company and its subsidiaries have removed two of the cases to federal court, and those cases have been assigned to the court in which the above-described federal case is pending. All three cases have been stayed.

Management believes that, in all of the above cases, 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.

Indemnifications

The Company provides certain indemnifications in relation to dispositions of assets.  These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. No liability has been recognized in connection with these indemnifications.

XML

Income Taxes

12 Months Ended

Dec. 31, 2015

Income Taxes [Abstract]

Income Taxes

(10) INCOME TAXES

The provision (benefit) for income taxes included the following components:

		2015		2014		2013
	(in millions)
Current:
Federal	$	1	$	11	$	(12)
State		(3)		10		1
		(2)		21		(11)
Deferred:
Federal		(1,697)		501		408
State		(304)		2		88
Foreign		(2)		1		1
		(2,003)		504		497
Provision (benefit) for income taxes	$	(2,005)	$	525	$	486

The provision for income taxes was an effective rate of 31% in 2015,  36% in 2014 and 41% in 2013. The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income: 

		2015		2014		2013
		(in millions)
Expected provision (benefit) at federal statutory rate	$	(2,296)	$	507	$	417
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect		(194)		58		53
Nondeductible expenses		–		3		3
State rate redetermination		–		(48)		4
Change in valuation allowance		488		5		–
Other		(3)		–		9
Provision (benefit) for income taxes	$	(2,005)	$	525	$	486

Our effective tax rate decreased in 2015 as compared with 2014, primarily due to the change in valuation allowance.  

The components of the Company’s deferred tax balances as of December 31, 2015 and 2014 were as follows:

		2015		2014
	(in millions)
Deferred tax liabilities:
Differences between book and tax basis of property	$	216	$	2,504
Derivative activity		–		122
Other		9		21
		225		2,647
Deferred tax assets:
Accrued compensation		28		23
Alternative minimum tax credit carryforward		125		131
Accrued pension costs		19		17
Asset retirement obligations		77		79
Net operating loss carryforward		445		323
Other		24		19
		718		592
Valuation allowance		(493)		(5)
Net deferred tax liability	$	–	$	2,060

In 2015, the Company paid less than $1 million in state income taxes and did not pay federal income taxes.  In 2014, the Company paid $14 million in state income taxes and paid $14 million in federal income taxes.  The Company’s net operating loss carryforward as of December 31, 2015 was $1,278 million and $789 million for federal and state reporting purposes, respectively, the majority of which will expire between 2028 and 2035.  Additionally, the Company has an income tax net operating loss carryforward related to its Canadian operations of $51 million, with expiration dates of 2030 through 2035.  The Company also had an alternative minimum tax credit carryforward of $125 million and a statutory depletion carryforward of $13 million as of December 31, 2015.

A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.  Due to the material write-downs of the carrying value of our natural gas and oil properties, the Company ended the year in a net deferred tax asset position.  We believe it is more likely than not that these deferred tax assets will not be realized, and recorded a $488 million tax expense for the increase in our valuation allowance.  The net change in valuation allowance is reflected as a component of income tax expense.  Management assesses available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets.  The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present.

Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). Although these additional tax benefits or “windfalls” are reflected in net operating loss carryforwards, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable. Accordingly, since the tax benefit does not reduce the Company’s current taxes payable in 2015 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in its net operating losses in deferred tax assets for 2015. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2015 were $149 million.

A tax position must meet certain thresholds for any of the benefit of the uncertain tax position to be recognized in the financial statements. As of December 31, 2015, the amount of unrecognized tax benefits related to alternative minimum tax was $37 million.  The uncertain tax position identified would not have a material effect on the effective tax rate.  No material changes to the current uncertain tax position are expected within the next 12 months. As of December 31, 2015, the Company had accrued a liability of $2 million of interest related to this uncertain tax position. The Company recognizes penalties and interest related to uncertain tax positions in income tax expense.

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:

	2015		2014
	(in millions)
Unrecognized tax benefits at beginning of period	$	44	$	–
Additions based on tax positions related to the current year		7		15
Additions to tax positions of prior years		–		29
Reductions to tax positions of prior years		(14)		–
Unrecognized tax benefits at end of period	$	37	$	44

The income tax years 2012 to 2015 remain open to examination by the major taxing jurisdictions to which the Company is subject.

XML

Asset Retirement Obligation

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

(11) ASSET RETIREMENT OBLIGATIONS

The following table summarizes the Company’s 2015 and 2014 activity related to asset retirement obligations:

	2015		2014
	(in millions)
Asset retirement obligation at January 1	$	207	$	134
Accretion of discount		11		7
Obligations incurred (1)		17		64
Obligations settled/removed (2)		(30)		(4)
Revisions of estimates		(4)		6
Asset retirement obligation at December 31	$	201	$	207
Current liability		10		9
Long-term liability		191		198
Asset retirement obligation at December 31	$	201	$	207

(1) Obligations incurred in 2014 include $42 million related to the Chesapeake Property Acquisition.

(2) Obligations settled/removed in 2015 include $25 million related to asset divestitures.

XML

Retirement And Employee Benefit Plans

12 Months Ended

Dec. 31, 2015

Retirement And Employee Benefit Plans [Abstract]

Retirement And Employee Benefit Plans

(12) RETIREMENT AND EMPLOYEE BENEFIT PLANS

401(k) Defined Contribution Plan

The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $3 million, $3 million and $3 million of contribution expense in 2015, 2014 and 2013, respectively. Additionally, the Company capitalized $4 million, $3 million and $3 million of contributions in 2015, 2014 and 2013, respectively, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.

Defined Benefit Pension and Other Postretirement Plans

Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service.  Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.

The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.

Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.

The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, and funded status as of December 31, 2015 and 2014:

					Other Postretirement
	Pension Benefits				Benefits
	2015		2014		2015		2014
	(in millions)
Change in benefit obligations:
Benefit obligation at January 1	$	134	$	103	$	18	$	12
Service cost		16		13		3		2
Interest cost		6		5		1		1
Participant contributions		–		–		–		–
Actuarial loss		(7)		21		(2)		3
Benefits paid		(11)		(8)		–		–
Plan amendments		–		–		–		–
Settlements		–		–		–		–
Benefit obligation at December 31	$	138	$	134	$	20	$	18

					Other Postretirement
	Pension Benefits				Benefits
	2015		2014		2015		2014
	(in millions)
Change in plan assets:
Fair value of plan assets at January 1	$	108	$	99	$	–	$	–
Actual return on plan assets		(1)		5		–		–
Employer contributions		12		12		–		–
Participant contributions		–		–		–		–
Benefits paid		(11)		(8)		–		–
Settlements		–		–		–		–
Fair value of plan assets at December 31	$	108	$	108	$	–	$	–
Funded status of plans at December 31	$	(30)	$	(26)	$	(20)	$	(18)

The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above.

The change in accumulated other comprehensive income related to the pension plans was a loss of $2 million ($2 million after tax) for the year ended December 31, 2015 and a loss of $23 million ($14 million after tax) for the year ended December 31, 2014. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a  gainof  $1 million ($1 million after tax) for the year ended December 31, 2015 and was a loss of $2 million ($1 million after tax) for the year ended December 31, 2014. Included in accumulated other comprehensive income as of December 31, 2015 and 2014 was a $42 million loss ($25 million net of tax) and a $41 million loss ($24 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans.For the year ended December 31, 2015,  $3 million was classified to accumulated other comprehensive income primarily driven by actuarial loss adjustments. Amortization of prior period service cost reclassified from accumulated other comprehensive income to general and administrative expenses for the year was immaterial.

The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2016 is a $2 million net loss.

The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2015 and 2014 are as follows:

		2015		2014
	(in millions)
Projected benefit obligation	$	138	$	134
Accumulated benefit obligation		135		129
Fair value of plan assets		108		108

Pension and other postretirement benefit costs include the following components for 2015, 2014 and 2013:

								Other Postretirement
		Pension Benefits						Benefits
		2015		2014		2013		2015		2014		2013
	(in millions)
Service cost	$	16	$	13	$	14	$	3	$	2	$	2
Interest cost		6		5		4		1		1		1
Expected return on plan assets		(9)		(7)		(6)		–		–		–
Amortization of transition obligation		–		–		–		–		–		–
Amortization of prior service cost		–		–		–		–		–		–
Amortization of net loss		2		1		2		–		–		–
Net periodic benefit cost		15		12		14		4		3		3
Settlements and curtailments		–		–		–		–		–		–
Total benefit cost	$	15	$	12	$	14	$	4	$	3	$	3

Amounts recognized in other comprehensive income for the year ended December 31, 2015 were as follows:

	Pension Benefits		Other Postretirement Benefits
	(in millions)
Net actuarial (loss) gain arising during the year	$	(4)	$	1
Amortization of prior service cost		–		–
Amortization of net loss		2		–
Settlements		–		–
Tax effect		–		–
	$	(2)	$	1

The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2015 and 2014 are as follows:

	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015		2014
Discount rate	4.60	%	4.25	%	4.60	%	4.25	%
Rate of compensation increase	3.50	%	4.50	%	n/a		n/a

The assumptions used in the measurement of the Company’s net periodic benefit cost for 2015, 2014 and 2013 are as follows:

	Pension Benefits						Other Postretirement Benefits
	2015		2014		2013		2015		2014		2013
Discount rate	4.25	%	5.00	%	4.00	%	4.25	%	5.00	%	4.00	%
Expected return on plan assets	7.00	%	7.00	%	7.00	%	n/a		n/a		n/a
Rate of compensation increase	4.50	%	4.50	%	4.50	%	n/a		n/a		n/a

The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification.

For measurement purposes, the following trend rates were assumed for 2015 and 2014:

	2015	2014
Health care cost trend assumed for next year	8%	8%
Rate to which the cost trend is assumed to decline	5%	5%
Year that the rate reaches the ultimate trend rate	2034	2033

Assumed health care cost trend rates have a significant effect on the amounts for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:

		1% Increase		1% Decrease
	(in millions)
Effect on the total service and interest cost components	$	1	$	(1)
Effect on postretirement benefit obligations	$	3	$	(2)

Pension Payments and Asset Management

In 2015, the Company contributed $12 million to its pension plans and $0.2 million to its other postretirement benefit plan.  As of February 23, 2016 the Company is uncertain of its required 2016 contributions to its pension and other postretirement benefit plans as a result of the recent reduction in workforce, which was announced in January of 2016 and is expected to be completed by the end of the first quarter of 2016.  As a result of the workforce reduction, the Company continues to evaluate its pension and other postretirement benefit funding requirements and will disclose its funding plans once reasonably determined.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Pension Benefits			Other Postretirement Benefits
(in millions)
2016	$	8	2016	$	1
2017		9	2017		1
2018		10	2018		1
2019		11	2019		1
2020		10	2020		2
Years 2021-2025		67	Years 2021-2025		11

The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term benefit payment of obligations to participants, retirees and beneficiaries. The Benefits Administration Committee of the Company administers the Company’s pension plan assets. The Benefits Administration Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets.

The table below presents the allocations targeted by the Benefits Administration Committee and the actual weighted-average asset allocation of the Company’s pension plan as of December 31, 2015, by asset category. The asset allocation targets are subject to change and the Benefits Administration Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions.  Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range.

	Pension Plan Asset Allocations
Asset category:
Equity securities:	Target		Actual
U.S. Equity(1)	35	%	36	%
Non-U.S. Developed Equity(2)	30	%	29	%
Emerging Markets Equity(3)	5	%	5	%
Opportunistic(4)	–	%	–	%
Fixed income(5)	28	%	28	%
Cash(6)	2	%	2	%
Total	100	%	100	%

(1) Asset category above includes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity.

(2) Asset category above includes Non-U.S. equity securities in the table below.

(3) Asset category above includes Emerging markets equity securities below.

(4) Asset category above includes none of the securities in the table below.

(5) Asset category above includes Fixed income pension plan assets in the table below.

(6) Asset category above includes Cash and cash equivalents pension plan assets in the table below.

Utilizing the fair value hierarchy described in Note 7 – Fair Value Measurements, the Company’s fair value measurement of pension plan assets as of December 31, 2015 are as follows:

Asset category:	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Equity securities:
U.S. large cap growth equity(1)	$	9	$	9	$	–	$	–
U.S. large cap value equity(2)		9		9		–		–
U.S. large cap core equity(3)		18		–		18		–
U.S. small cap equity(4)		3		3		–		–
Non-U.S. equity(5)		31		31		–		–
Emerging markets equity(6)		5		5		–		–
Fixed income (7)		31		–		31		–
Cash and cash equivalents		2		2		–		–
Total	$	108	$	59	$	49	$	–

(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.

(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.

(3) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.

(4) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.

(5) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.

(6) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.

(7) Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.

Utilizing the fair value hierarchy described in Note 7 – Fair Value Measurements, the Company’s fair value measurement of pension plan assets at December 31, 2014 are as follows:

Asset category:	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Equity securities:
U.S. large cap growth equity(1)	$	8	$	8	$	–	$	–
U.S. large cap value equity(2)		9		9		–		–
U.S. large cap core equity(3)		19		–		19		–
U.S. small cap equity(4)		3		3		–		–
Non-U.S. equity(5)		29		29		–		–
Emerging markets equity(6)		5		5		–		–
Fixed income (7)		31		–		31		–
Cash and cash equivalents		4		4		–		–
Total	$	108	$	58	$	50	$	–

(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.

(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.

(3) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.

(4) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.

(5) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.

(6) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.

(7) An institutional fund that seeks an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S.  Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.

The Company’s pension plan assets that are classified as Level 1 are due to the pension plan’s investments comprising either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair value measurement as Level 1. The Company’s Level 2 pension plan assets represent investments in institutional funds.  These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.  No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund.

XML

Stock-Based Compensation

12 Months Ended

Dec. 31, 2015

Stock-Based Compensation [Abstract]

Stock-Based Compensation

(13) STOCK-BASED COMPENSATION

The Southwestern Energy Company 2013 Incentive Plan (“2013 Plan”) was adopted in February 2013 and approved by stockholders in May 2013. The 2013 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2013 Plan replaced the Southwestern Energy Company 2004 Stock Incentive Plan, the Southwestern Energy Company 2000 Stock Incentive Plan (“2000 Plan”), and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (“2002 Plan”) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for stock splits as permitted under such plans.

The 2013 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers, and directors that in the aggregate do not exceed 20,500,000 shares. The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s board of directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2013 Plan.

As initially adopted, the 2004 Plan, the 2000 Plan,and the 2002 Plan provided for grants of options, stock appreciation rights, shares of phantom stock, and shares of restricted stock that in the aggregate did not exceed 16,800,000,  1,250,000, and 300,000 shares, respectively, to employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934, as amended.The Company may utilize treasury shares, if available, or authorized but unissued shares when a stock option is exercised or when restricted stock is granted.

The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under both the 2013 Plan and the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach retirement age during the vesting period. Restricted stock and stock options granted to participants on or after December 6, 2013 immediately vest upon death, disability, or retirement (subject to a minimum of three years of service).

Stock Options

The Company recorded the following compensation costs related to stock options for the years ended December 31, 2015, 2014 and 2013:

	2015		2014		2013
	(in millions)
Stock-based compensation cost related to stock options – general and administrative expense	$	5	$	5	$	5
Stock-based compensation cost related to stock options – capitalized	$	3	$	4	$	5

The Company also recorded a deferred tax asset of $2, $3 and$4 million related to stock options in 2015, 2014 and 2013, respectively. A total of $13 million of unrecognized compensation cost related to the Company’s unvested stock options. This cost is expected to be recognized over a weighted-average period of 2 years.

The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table.  Expected volatility is based on historical volatility of the Company’s common stock and other factors.  The Company uses historical data on exercise of stock options, post vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant.

Assumptions	2015	2014	2013
Risk-free interest rate	1.7%	1.6%	1.5%
Expected dividend yield	–	–	–
Expected volatility	36.0%	32.5%	38.6%
Expected term	5 years	5 years	5 years

The following tables summarize stock option activity for the years 2015, 2014 and 2013 and provide information for options outstanding at December 31 of each year:

	2015			2014			2013
		Weighted			Weighted			Weighted
		Average			Average			Average
	Number	Exercise		Number	Exercise		Number	Exercise
	of Shares	Price		of Shares	Price		of Shares	Price
	(in thousands)			(in thousands)			(in thousands)
Options outstanding at January 1	3,622	$	35.41	3,313	$	35.70	3,650	$	29.84
Granted	2,401		9.47	835		32.31	571		38.95
Exercised	–		–	(402)		30.60	(833)		12.12
Forfeited or expired	(400)		32.20	(124)		37.80	(75)		37.31
Options outstanding at December 31	5,623	$	24.57	3,622	$	35.41	3,313	$	35.70

	Options Outstanding				Options Exercisable
				Weighted				Weighted
				Average				Average
	Options	Weighted		Remaining	Options	Weighted		Remaining
	Outstanding at	Average		Contractual	Exercisable at	Average		Contractual
Range of	December 31,	Exercise		Life	December 31,	Exercise		Life
Exercise Prices	2015	Price		(Years)	2015	Price		(Years)
	(in thousands)				(in thousands)
$7.74-$29.69	2,421		9.63	6.8	20		28.46	1.8
$30.59-$35.91	1,397		32.32	4.9	900		33.27	4.3
$36.22-$39.68	1,412		37.50	3.4	1,249		37.31	3.2
$40.15-$51.47	393		42.58	2.0	333		41.86	1.4
	5,623	$	24.57	5.1	2,502	$	36.39	3.4

The weighted-average grant-date fair value of options granted during the years 2015, 2014 and 2013 was $3.16,$10.16, and $13.39, respectively. There were no options exercised in 2015.  The total intrinsic value of options exercised during 2014 and 2013was $4 million and $22 million, respectively.

Restricted Stock

The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2015, 2014 and 2013:

		2015		2014		2013
		(in millions)
Stock-based compensation cost related to restricted stock grants – general and administrative expense	$	14	$	10	$	7
Stock-based compensation cost related to restricted stock grants – capitalized	$	16	$	12	$	7

The Company also recorded a deferred tax assetof $11 million related to restricted stock for the year ended December 31, 2015, compared to deferred tax liabilities of $10 million for 2014 and $15 million for 2013. As of December 31, 2015, there was $88 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of 3 years.

The following table summarizes the restricted stock activity for the years 2015, 2014 and 2013 and provides information for restricted stock outstanding at December 31 of each year:

	2015			2014			2013
	Number of Shares		Weighted Average Grant Date Fair Value	Number of Shares		Weighted Average Grant Date Fair Value	Number of Shares		Weighted Average Grant Date Fair Value
	(in thousands)			(in thousands)			(in thousands)
Unvested shares at January 1	2,376	$	34.00	1,771	$	37.55	1,118	$	35.64
Granted	5,822		8.07	1,295		30.89	1,109		38.92
Vested	(873)		33.33	(548)		37.12	(382)		36.29
Forfeited	(103)		29.14	(142)		37.91	(74)		35.81
Unvested shares at December 31	7,222	$	13.24	2,376	$	34.00	1,771	$	37.55

The fair values of the grants were $47 million for 2015, $40 million for 2014 and $43 million for 2013. The total fair value of shares vested were $29 million for 2015, $20 million for 2014 and $14 million for 2013.

Equity-Classified Performance Units

The Company recorded the following compensation costs related to equity-classified performance units for the years ended December 31, 2015.  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”), collectively the “Performance Measures.”  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 economic analysis for each investment opportunity based upon the expected present value added for each dollar to be invested and amortized to compensation expense on a straight line basis over the vesting period of the award. The grant date fair value is calculated using the Performance Measures and the closing price of the Company’s common stock at the grant date. 

		a
	2015		2014
	(in millions)
Stock-based compensation cost related to performance units - general and administrative expense	$	6	$	3
Stock-based compensation cost related to performance units - capitalized	$	4	$	2

The Company also recorded a deferred tax asset of $4million related to equity-based performance units for the year ended December 31, 2015, compared to a deferred tax asset of $2 million in 2014 and no deferred tax recorded in 2013. As of December 31, 2015, there was $14 million of total unrecognized compensation cost related to unvested equity-based performance units that is expected to be recognized over a weighted-average period of 2 years.

The following table summarizes performance unit activity to be paid out in Company stock for the twelve months ended December 31, 2015 and provides information for unvested units as of December 31, 2015: 

	2015			2014
	Number of Units (1)	Weighted Average Grant Date Fair Value		Number of Units (1)	Weighted Average Grant Date Fair Value
Unvested shares at January 1	223	$	40.44	–	$	–
Granted	443		35.22	359		40.44
Vested	(259)		37.46	(111)		40.44
Forfeited	–		–	(25)		40.44
Unvested shares at December 31	407	$	36.65	223	$	40.44

(1) These amounts reflect the number of performance units granted in thousands. The actual payout of shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures.

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 goals. At the end of each performance period, the value of the vested performance units, if any, is paid in cash.  The Company paid $31million related to the vested performance units in 2015,  $25million in 2014, and $3 million in 2013.  As of December 31, 2015 and 2014, the Company’s liability under the performance unit agreements was $8million and $51 million, respectively.

XML

Segment Information

12 Months Ended

Dec. 31, 2015

Segment Information [Abstract]

Segment Information

(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 liquids. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids 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 – Organization and Summary of Significant Accounting Policies. 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,gain (loss) on derivatives 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)
2015
Revenues from external customers	$	2,095		$	1,038	$	–	$	3,133
Intersegment revenues		(21)			2,081		–		2,060
Operating income (loss)		(7,104)	(2)		583		(1)		(6,522)
Other loss, net		(21)			(9)		–		(30)
Gain (loss) on derivatives		51			–		(4)		47
Depreciation, depletion and amortization expense		1,028			62		1		1,091
Impairment of natural gas and oil properties		6,950			–		–		6,950
Interest expense(1)		47			9		–		56
Provision (benefit) for income taxes(1)		(2,273)			268		–		(2,005)
Assets		6,588	(3)		1,290		232		8,110
Capital investments(4)		2,258			167		12		2,437
2014
Revenues from external customers	$	2,850		$	1,188	$	–	$	4,038
Intersegment revenues		12			3,170		–		3,182
Operating income (loss)		1,013			361		(1)		1,373
Other loss, net		(3)			(1)		–		(4)
Gain (loss) on derivatives		142			(1)		(2)		139
Depreciation, depletion and amortization expense		884			58		–		942
Interest expense(1)		47			12		–		59
Provision for income taxes(1)		402			123		–		525
Assets		13,018	(3)		1,554		353		14,925
Capital investments(4)		7,254			144		49		7,447
2013
Revenues from external customers	$	2,398		$	973	$	–	$	3,371
Intersegment revenues		6			2,374		–		2,380
Operating income		879			325		–		1,204
Other income (loss), net		3			–		(1)		2
Gain on derivatives		26			–		–		26
Depreciation, depletion and amortization expense		735			51		1		787
Interest expense(1)		30			11		1		42
Provision (benefit) for income taxes(1)		368			119		(1)		486
Assets		6,357	(3)		1,427		264		8,048
Capital investments(4)		2,052			158		25		2,235

(1) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

(2) Includes $6,950 million from non-cash impairments of natural gas and oil properties.

(3) Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.

(4) Capital investments include a decrease of  $33 million for 2015, an increase of $155 million for 2014 and a decrease of $25 million for 2013 related to the change in accrued expenditures between years.

Included in intersegment revenues of the Midstream Services segment are approximately$1.8 billion, $2.8 billion and $2.0 billion for 2015, 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. For 2015, 2014,  and 2013, capital investments within the E&P segment include $4 million,  $11 million, and $35respectively, related to the Company’s activities in Canada. As of December 31, 2015,  2014, and 2013, E&P assets include $50 million,  $77 million, $79 million related to the Company’s activities in Canada.

XML

Quarterly Results

12 Months Ended

Dec. 31, 2015

Quarterly Results [Abstract]

Quarterly Results

(15) QUARTERLY RESULTS (UNAUDITED)

The following is a summary of the quarterly results of operations for the years ended December 31, 2015 and 2014:

	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
	(in millions, except per share amounts)
	2015
Operating revenues	$	933	$	764	$	749	$	687
Operating income (loss) (1)		165		(1,284)		(2,842)		(2,561)
Net income (loss) attributable to common stock (2)		46		(815)		(1,766)		(2,134)
Earnings per share - Basic		0.12		(2.13)		(4.62)		(5.58)
Earnings per share - Diluted		0.12		(2.13)		(4.62)		(5.58)
	2014
Operating revenues	$	1,113	$	1,035	$	928	$	962
Operating income		435		367		286		285
Net income		194		207		211		312
Earnings per share - Basic		0.55		0.59		0.60		0.89
Earnings per share - Diluted		0.55		0.59		0.60		0.88

(1) The operating losses for the second, third and fourth quarters of 2015 included full cost non-cash impairments of natural gas and oil properties of $1.5 billion, $2.8 billion and $2.6 billion, respectively.

(2) Net income attributable to common stock was reduced by $7 million in the first quarter of 2015 to recognize the portion of the Company’s net income that would be distributed to the holders of preferred securities (mandatory convertible preferred stock) at year-end. However, as a result of the Company’s net loss in the second quarter that persisted for the year ended December 31, 2015, participating securities were ultimately not entitled to receive a distribution.

XML

Subsequent Events

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Subsequent Events

(16) SUBSEQUENT EVENTS

As of January 6, 2016, the Company accepted the resignation of Steven L. Mueller as Chief Executive Officer (“CEO”) of the Company and appointed William J. Way as CEO.  Mr. Way will continue as President and was elected as a director of the Company as of January 6, 2016.  Mr. Mueller will continue as a non-officer employee of the Company and as a director and non-executive Chairman of the Board of Directors of the Company through May 17, 2016, the date scheduled for the next annual meeting of stockholders and will not stand for re-election.

On January 21, 2016, the Company notified employees of a workforce reduction plan. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, amendments to outstanding equity awards that modified forfeiture provisions on separation from the Company.  Some affected employees were offered the opportunity to accept reduced roles with the Company.  The Company expects the plan to be substantially implemented by the end of the first quarter of 2016.

The Company expects to record a pre-tax charge to earnings in the first quarter of 2016 ranging from approximately $60 to $70 million, including the following:

· one-time cash severance payments and payment of taxes totaling approximately $45 to $50 million, and

· costs associated with the elimination of service requirements for equity awards to certain terminated employees of approximately $15 to $20 million. 

Each range of charges is an estimate. The actual charge may vary based on various factors, including the number of affected employees who accept different jobs with the Company.

XML

Organization And Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2015

Organization And Summary Of Significant Accounting Policies [Abstract]

Nature Of Operations

Nature of Operations

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production (“E&P”).  The Company’s current operations are principally focused within the United States on the development of unconventional reservoirs located in Pennsylvania, West Virginia and Arkansas.

The Company’s operations in northeast Pennsylvania are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”), its operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”) and its operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale.  Collectively, the Company’s properties located in Pennsylvania and West Virginia are herein referred to as the “Appalachian Basin.”  The Company also actively seeks to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which it refers to as “New Ventures,” and has exploration and production activities ongoing in Colorado and Louisiana, along with other areas in which it is currently exploring for new development opportunities.  The Company also has drilling rigs in Pennsylvania, West Virginia and Arkansas, as well as in other operating areas, and provides oilfield products and services, principally serving its exploration and production operations.  Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania, Louisiana and West Virginia.

Basis Of Presentation

Basis of Presentation

The consolidated financial statements included in this Annual Reportpresent the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.The Company evaluates subsequent events through the date the financial statements are issued.Certain reclassifications have been made to the prior year financial statements to conform to the 2015 presentation.The effects of the reclassifications were not material to the Company’s consolidated financial statements. 

Principles Of Consolidation

Principles of Consolidation

The consolidated financial statements include the accounts of Southwestern and its wholly owned subsidiaries.  All significant intercompany accounts and transactions have been eliminated.

In 2015, the Company purchased an 86% ownership in a limited partnershipwhich owns and operates a gathering system in Northeast Appalachia as part of the WPX Property Acquisition (discussed in Note 2). Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the year ended December 31, 2015 was insignificant.

Revenue Recognition

Revenue Recognition

Natural gas and liquid sales. Natural gas and liquid sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties.  Accordingly, natural gasand liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances.  The Company had no significant production imbalances at December 31, 2015 or 2014.

Marketing. The Company generally markets its natural gas and liquids, as well as some products produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts.  Marketing revenues are recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Gas gathering.In certain areas, the Company gathers its natural gas as well as some natural gas produced by third parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Cash And Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash.  Management considers cash and cash equivalents to have minimal credit and market risk.

Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $29 million and $17 million as of December 31, 2015 and 2014, respectively.

Inventory

Inventory

Inventory is comprised of tubulars and other equipment and natural gas in underground storage.  Tubulars and other equipment are carried at the lower of cost or market and are accounted for by a moving weighted average cost method that is applied within specific classes of inventory items.  In the fourth quarter of 2015, the Company wrote-down the carrying value of its inventory by $23 million as a result of reduced drilling activity.  Natural gas in underground storage is carried at the lower of cost or market and accounted for by a weighted average cost method.  During the fourth quarter of 2015, the Company completed the sale of its underground storage facility in Franklin County, Arkansas.

The components of inventory as of December 31, 2015 and December 31, 2014 consisted of the following:

	For years ended December 31,
	2015		2014
	(in millions)
Inventory:
Tubulars and other equipment	$	3	$	33
Natural gas in underground storage		–		4

Property, Depreciation, Depletion And Amortization

Property, Depreciation, Depletion and Amortization

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, oil and NGLreserves. 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, oil and NGL reserves discounted at 10% 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, oil and NGL prices may subsequently increase the ceiling.  Companies using 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 $2.59 per MMBtu, West Texas Intermediate oil of $46.79 per barrel, and NGLs of $6.82 per barrel, adjusted for market differentials, theCompany’s net book valueof its United States natural gas and oil properties exceeded the ceiling by $1,586 million (net of tax) at December 31, 2015 and resulted in a non-cash ceiling test impairment.  No cash flow hedges were in place as of December 31, 2015.  In the second and third quarters of 2015, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015, respectively, and resulted in non-cash ceiling test impairments.  Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $60million and $40 million as of June 30, 2015 and September 30, 2015, respectively.  At December 31, 2014, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu, West Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 per barrel. At December 31, 2013, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.67 per MMBtu, for West Texas Intermediate oil of $93.42 and NGLs of $43.45 per barrel. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.

Gathering Systems.The Company’s investment in gathering systems is primarily related to its Fayetteville Shale assets in Arkansas.  These assets are being depreciated on a straight-line basis over 25 years.

Capitalized Interest.Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and actively being evaluated.

Asset Retirement Obligations.  The Company owns natural gas and oil properties, which require expenditures to plug and abandon the wells and reclaim the associated pads when reserves in the wells are depleted. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Impairment of long-lived assets. The carrying value of long-lived assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.

Intangible assets. The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their weighted average useful life.

Income Taxes

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.  The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations.  Additional information regarding uncertain tax positions can be found in Note 10 – Income Taxes.

Derivative Financial Instruments

Derivative Financial Instruments

The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity fixed price swaps and fixed price option contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivatives if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item.  In contrast, gains and losses from the ineffective portion of fixed price swaps designated for hedge accounting treatment are recognized currentlyand have an inconsequential impact in the consolidated statement of operations.Gains and losses from the unsettled portion of fixed price swaps not designated for hedge accounting treatment, interest rate swaps, fixed price call options and basis swaps that were not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations.  See Note 5– Derivatives and Risk Management and Note 7 – Fair Value Measurements for a discussion of the Company’s hedging activities.

Earnings Per Share

Earnings Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock and performance units and the assumed conversion of mandatory convertible preferred stock.  An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.

In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares).  The common stock offering was priced at $23.00 per share.  Net proceeds, after underwriting discount and expenses, from the common stock offering were approximately $669 million.  Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1.7 billion.  Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share).  The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public offering of $2.2 billion in long-term senior notes.

The mandatory convertible preferred stock entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights.  Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (and, correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date.

The mandatory convertible preferred stock has the non-forfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security.  Accordingly, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method.  In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings.  The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

The following table presents the computation of earnings per share for the years ended December 31, 2015, 2014 and 2013.

	For the years ended
	December 31,
	2015		2014		2013
	(in millions, except share/per share amounts)
Net income (loss)	$	(4,556)	$	924	$	704
Mandatory convertible preferred stock dividend		106		–		–
Net income (loss) attributable to common stock	$	(4,662)	$	924	$	704
Number of common shares:
Weighted average outstanding		380,521,039		351,446,747		350,465,430
Issued upon assumed exercise of outstanding stock options (1)		–		241,603		377,626
Effect of issuance of non-vested restricted common stock (2)		–		448,415		258,396
Effect of issuance of non-vested performance units (3)		–		273,918		–
Effect of issuance of mandatory convertible preferred stock (4)		–		–		–
Weighted average and potential dilutive outstanding		380,521,039		352,410,683		351,101,452
Earnings (loss) per common share:
Basic	$	(12.25)	$	2.63	$	2.01
Diluted	$	(12.25)	$	2.62	$	2.00

(1) Due to the net loss for the year ended December 31, 2015, the unvested stock options were not recognized in diluted earnings per share calculations as they would be antidilutive.  Options for 3,835,234 shares, 1,446,004 shares and 1,634,695 shares were excluded from the calculation of diluted shares for the years ended December 31, 2015, 2014 and 2013, respectively, because they would have had an antidilutive effect.

(2) Due to the net loss for the year ended December 31, 2015, the unvested share-based payments were not recognized in diluted earnings per share calculations as they would be antidilutive.  The calculation excluded 1,990,383 shares,  29,879 shares and 114,433 shares of restricted stock  for the years ended December 31, 2015, 2014, and 2013, respectively, because they would have had an antidilutive effect.

(3) Due to the net loss for the year ended December 31, 2015, 140,414 shares of performance units were excluded in the calculation of diluted earnings per share as they would be antidilutive.   There were no performance units issued in 2013.

(4) Due to the net loss for the year ended December 31, 2015, the weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock were not recognized in diluted earnings per share calculations as they would be antidilutive.  The calculation excluded 70,890,312 weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock because they would have had an antidilutive effect.  There were no mandatory convertible preferred shares in 2014 or 2013.

Supplemental Disclosures Of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2015, 2014, and 2013.

	For the years ended December 31,
	2015		2014		2013
	(in millions)
Cash paid during the year for interest, net of amounts capitalized	$	6	$	50	$	36
Cash paid (received) during the year for income taxes		(6)		28		19
Increase (decrease) in noncash property additions		(10)		174		(13)

Stock-Based Compensation

Stock-Based Compensation

The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.

Treasury Stock

Treasury Stock

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liabilities of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2015, 47,149 shares were accounted for as treasury stock, compared to 11,055 shares at December 31, 2014.

Foreign Currency Translation

Foreign Currency Translation

The Company has designated the Canadian dollar as the functional currency for our operations in Canada.  The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders' equity.

New Accounting Standards Implemented In This Report

New Accounting Standards Implemented in this Report

In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (Topic 740) (“Update 2015-17”), which seeks to reduce the complexity in financial reporting.  The amendments in Update 2015-17 require that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as non-current on the balance sheet.  Although the amendments in Update 2015-17 are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, the Company has elected to early adopt the amendments of Update 2015-17 on a prospective basis for the current period.  The implementation did not have a material impact on the Company’s consolidated statement of operations, balance sheet or statement of cash flows.  The net deferred tax liability at December 31, 2014 was comprised of net long-term deferred income tax liabilities of $1,951 million, in addition to a net current deferred income tax liability of $109 million.  

New Accounting Standards Not Yet Implemented In This Report

New Accounting Standards Not Yet Implemented in this Report

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 requirement as 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 to those goods or services. Entities may apply the amendments in Update 2014-09 either (a) retrospectively to each 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.  In August 2015, the FASB issued Accounting Standards Update Accounting Standards Update (ASU) No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which finalizes Proposed ASU No. 2015-240 of the same name, and responds to stakeholders’ requests to defer the effective date of the guidance in ASU No. 2014-09. For public entities, Update 2014-09 and Update 2015-14 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-09 and 2015-14 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In November 2014, the FASB issued Accounting Standards Update No. 2014-16, Derivatives and Hedging – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (Subtopic 815-15) (“Update 2014-16”), addresses diversity in practice related to the determination of whether derivative features embedded in hybrid instruments issued in the form of a share should be bifurcated and accounted for separately. For public entities, Update 2014-16 is effective for annual reporting periods beginning after December 15, 2015 including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-16 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-03”), which seeks to simplify presentation of debt issuance costs. Update 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. Entities should apply the amendments in Update 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. For public entities, Update 2015-03 and Update 2015-15 are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company has evaluated the provisions of Update 2015-03 and Update 2015-15 and expects the impact to be immaterial on its consolidatedresults of operations, financial position and cash flows.

In May 2015, the FASB issued Accounting Standards Update No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent) (“Update 2015-07”), which amends ASC 820, Fair Value Measurement. The standard removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure requirements.  The amendments in Update 2015-07 are effective for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-07 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Inventory (Topic 330) (“Update 2015-11”), which seeks to simplify the measurement of inventory. Update 2015-11 requires that an entity should measure inventory at the lower of cost and net realizable value, where net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public entities, the amendments in Update 2015-11 are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-11 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In July 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-12 (“Update 2015-12”), which consists of three related parts: (1) Plan Accounting: Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Fully Benefit-Responsive Investment Contracts (“Part I”); (2) Plan Accounting: Defined Benefit Pension Plans (Topic 960); Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Plan Investment Disclosures (“Part II”); and (3) Plan Accounting: Defined Benefit Pension Plans (Topic 960); Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Measurement Date Practical Expedient (“Part III”). Part I requires (1) fully benefit-responsive investment contracts to be measured at contract value; and (2) an adjustment to reconcile contract value to fair value, when these measures differ, on the face of the plan financial statements. Part II eliminates the current requirement for both participant-directed investments and non-participant-directed investments to disclose individual investments representing 5% or more of net assets available for benefits, as well as the net appreciation or depreciation for investments by general type on a disaggregated basis.  Part III permits plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan’s fiscal year-end, when the fiscal period does not coincide with a month-end. The amendments in Update 2015-12 are effective for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-12 and assessing the impact, if any, it may have on its consolidated results of operations, financial position, or cash flows.

In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Business Combinations (Topic 805) (“Update 2015-16”), which seeks to reduce the complexity of amounts recognized in a business combination. The amendments in Update 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in Update 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in Update 2015-16 require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in Update 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Company is currently evaluating the provisions of Update 2015-16 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

XML

Organization And Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Organization And Summary Of Significant Accounting Policies [Abstract]

Components Of Inventory

	For years ended December 31,
	2015		2014
	(in millions)
Inventory:
Tubulars and other equipment	$	3	$	33
Natural gas in underground storage		–		4

Schedule Of Earnings Per Share

	For the years ended
	December 31,
	2015		2014		2013
	(in millions, except share/per share amounts)
Net income (loss)	$	(4,556)	$	924	$	704
Mandatory convertible preferred stock dividend		106		–		–
Net income (loss) attributable to common stock	$	(4,662)	$	924	$	704
Number of common shares:
Weighted average outstanding		380,521,039		351,446,747		350,465,430
Issued upon assumed exercise of outstanding stock options (1)		–		241,603		377,626
Effect of issuance of non-vested restricted common stock (2)		–		448,415		258,396
Effect of issuance of non-vested performance units (3)		–		273,918		–
Effect of issuance of mandatory convertible preferred stock (4)		–		–		–
Weighted average and potential dilutive outstanding		380,521,039		352,410,683		351,101,452
Earnings (loss) per common share:
Basic	$	(12.25)	$	2.63	$	2.01
Diluted	$	(12.25)	$	2.62	$	2.00

(1) Due to the net loss for the year ended December 31, 2015, the unvested stock options were not recognized in diluted earnings per share calculations as they would be antidilutive.  Options for 3,835,234 shares, 1,446,004 shares and 1,634,695 shares were excluded from the calculation of diluted shares for the years ended December 31, 2015, 2014 and 2013, respectively, because they would have had an antidilutive effect.

(2) Due to the net loss for the year ended December 31, 2015, the unvested share-based payments were not recognized in diluted earnings per share calculations as they would be antidilutive.  The calculation excluded 1,990,383 shares,  29,879 shares and 114,433 shares of restricted stock  for the years ended December 31, 2015, 2014, and 2013, respectively, because they would have had an antidilutive effect.

(3) Due to the net loss for the year ended December 31, 2015, 140,414 shares of performance units were excluded in the calculation of diluted earnings per share as they would be antidilutive.   There were no performance units issued in 2013.

(4) Due to the net loss for the year ended December 31, 2015, the weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock were not recognized in diluted earnings per share calculations as they would be antidilutive.  The calculation excluded 70,890,312 weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock because they would have had an antidilutive effect.  There were no mandatory convertible preferred shares in 2014 or 2013.

Schedule Of Supplemental Disclosures Of Cash Flow Information

	For the years ended December 31,
	2015		2014		2013
	(in millions)
Cash paid during the year for interest, net of amounts capitalized	$	6	$	50	$	36
Cash paid (received) during the year for income taxes		(6)		28		19
Increase (decrease) in noncash property additions		(10)		174		(13)

XML

Acquisitions And Divestitures (Tables)

12 Months Ended

Dec. 31, 2015

WPX Property Acquisition [Member]

Business Acquisition [Line Items]

Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed

Consideration:
Cash	$	270
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Proved natural gas and oil properties		31
Unproved natural gas and oil properties		114
Intangible asset		109
Gathering system		22
Other		1
Total assets acquired		277
Liabilities assumed:
Asset retirement obligations		(7)
Total liabilities assumed		(7)
	$	270

Chesapeake Property Acquisition [Member]

Business Acquisition [Line Items]

Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed

Consideration:
Cash	$	4,949
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Proved natural gas and oil properties		1,418
Unproved natural gas and oil properties		3,573
Other property and equipment		33
Inventory		3
Total assets acquired		5,027
Liabilities assumed:
Asset retirement obligations		(42)
Other liabilities		(36)
Total liabilities assumed		(78)
	$	4,949

Summary Of Consolidated Results Of Operations On Pro Forma Basis

	For the years ended
	December 31,
	2014		2013
	(in millions) (unaudited)
Revenues	$	4,439	$	3,713
Net income attributable to common stock		803		594
Earnings per share
Basic	$	2.11	$	1.56
Diluted		2.10		1.56

XML

Prepaid Expenses (Tables)

12 Months Ended

Dec. 31, 2015

Prepaid Expenses [Abstract]

Components Of Prepaid Expenses

	2015		2014
		(in millions)
Prepaid taxes	$	26	$	30
Prepaid insurance		6		8
Other prepaid expenses		11		5
Deposits (1)		–		65
Total	$	43	$	108

(1) Deposits as of December 31, 2014 consisted of a $50 million and $15 million pre-payment related to the Statoil Property Acquisition and WPX Property Acquisition, respectively.

XML

Natural Gas And Oil Producing Acitivities (Tables)

12 Months Ended

Dec. 31, 2015

Natural Gas And Oil Producing Activities [Abstract]

Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure

	2015		2014
	(in millions)
Proved properties	$	18,751	$	15,860
Unproved properties(1)		3,727		4,646
Total capitalized costs		22,478		20,506
Less:  Accumulated depreciation, depletion and amortization		(16,248)		(8,327)
Net capitalized costs	$	6,230	$	12,179

(1) Includes $50 million and $76 million related to the Company’s exploration program in Canada as of December 31, 2015 and 2014, respectively.

Composition Of Net Unevaluated Costs Excluded From Amortization

	2015		2014		2013		Prior		Total
	(in millions)
Property acquisition costs(1)	$	274	$	2,870	$	42	$	105	$	3,291
Exploration and development costs(1)		128		56		29		36		249
Capitalized interest(1)		120		22		11		34		187
	$	522	$	2,948	$	82	$	175	$	3,727

(1) Property acquisition costs include $16 million, exploration costs include $26 million and capitalized interest includes $8 million related to the Company’s exploration program in Canada.

Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities Disclosure

	2015		2014		2013
	(in millions, except per Mcfe amounts)
Proved property acquisition costs	$	81	$	1,455	$	1
Unproved property acquisition costs (1)		692		3,934		168
Exploration costs(2)		50		232		192
Development costs		1,417		1,600		1,662
Capitalized costs incurred		2,240		7,221		2,023
Full cost pool amortization per Mcfe	$	1.00	$	1.10	$	1.08

(1) Included  $1 million and $17 million in 2014 and 2013, respectively, related to the Company’s exploration program in Canada.

(2) Included  $3 million and $12 million in 2014 and 2013, respectively, related to the Company’s exploration program in Canada.

Results Of Operations For Oil And Gas Producing Activities Disclosure

	2015		2014		2013
	(in millions)
Sales	$	2,074	$	2,862	$	2,404
Production (lifting) costs		(989)		(776)		(629)
Depreciation, depletion and amortization		(1,028)		(884)		(735)
Impairment of natural gas and oil properties		(6,950)		–		–
		(6,893)		1,202		1,040
Provision (benefit) for income taxes		(2,619)		457		416
Results of operations (1)	$	(4,274)	$	745	$	624

(1) Results of operations exclude the gain (loss) on derivatives, unsettled, on commodity derivative instruments.  See Note 5-  Derivatives and Risk Management.

Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities

	2015			2014			2013
	Natural			Natural			Natural
	Gas	Oil	NGL	Gas	Oil	NGL	Gas	Oil	NGL
	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)	(Bcf)	(MBbls)	(MBbls)
Proved reserves, beginning of year	9,809	37,615	118,699	6,974	373	–	4,017	244	–
Revisions of previous estimates	(3,458)	(28,394)	(75,664)	542	(14)	66	325	38	50
Extensions, discoveries and other additions	546	1,367	6,274	1,692	250	48	3,284	229	–
Production	(899)	(2,265)	(10,702)	(766)	(235)	(231)	(656)	(138)	(50)
Acquisition of reserves in place	97	525	2,340	1,367	37,246	118,816	4	–	–
Disposition of reserves in place	(178)	(95)	–	–	(5)	–	–	–	–
Proved reserves, end of year	5,917	8,753	40,947	9,809	37,615	118,699	6,974	373	–
Proved developed reserves:
Beginning of year	5,675	7,445	38,632	4,237	372	–	3,196	243	–
End of year	5,474	8,753	40,947	5,675	7,445	38,632	4,237	372	–
Proved undeveloped reserves:
Beginning of year	4,134	30,170	80,067	2,737	1	–	821	1	–
End of year	443	–	–	4,134	30,170	80,067	2,737	1	–

Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure

	2015		2014		2013
	(in millions)
Future cash inflows	$	11,887	$	41,812	$	22,624
Future production costs		(7,376)		(16,477)		(8,896)
Future development costs		(792)		(5,750)		(3,626)
Future income tax expense (1)		–		(4,743)		(3,223)
Future net cash flows		3,719		14,842		6,879
10% annual discount for estimated timing of cash flows		(1,302)		(7,299)		(3,143)
Standardized measure of discounted future net cash flows	$	2,417	$	7,543	$	3,736

(1) The December 31, 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.

Schedule Of Analysis Of Changes In Standardized Measure

	2015		2014		2013
	(in millions)
Standardized measure, beginning of year	$	7,543	$	3,736	$	2,051
Sales and transfers of natural gas and oil produced, net of production costs		(1,082)		(2,084)		(1,774)
Net changes in prices and production costs		(8,075)		1,192		1,853
Extensions, discoveries, and other additions, net of future production and development costs		162		1,049		1,454
Acquisition of reserves in place		28		1,897		5
Sales of reserves in place		(244)		–		–
Revisions of previous quantity estimates		(1,385)		622		349
Accretion of discount		946		513		232
Net change in income taxes		1,915		(522)		(1,120)
Changes in estimated future development costs		2,007		110		(196)
Previously estimated development costs incurred during the year		875		815		223
Changes in production rates (timing) and other		(273)		215		659
Standardized measure, end of year	$	2,417	$	7,543	$	3,736

XML

Derivatives And Risk Management (Tables)

12 Months Ended

Dec. 31, 2015

Derivatives And Risk Management [Abstract]

Balance Sheet Classification Of Derivative Financial Instruments

	Derivative Assets
	December 31, 2015			December 31, 2014
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in millions)
Derivatives designated as hedging instruments:
Fixed price swaps	Derivative assets	$	–	Derivative assets	$	165
Total derivatives designated as hedging instruments		$	–		$	165
Derivatives not designated as hedging instruments:
Basis swaps	Derivative assets	$	3	Derivative assets	$	9
Fixed price swaps	Derivative assets		–	Derivative assets		163
Basis swaps	Other long-term assets		–	Other long-term assets		1
Interest rate swaps	Other long-term assets		–	Other long-term assets		1
Total derivatives not designated as hedging instruments		$	3		$	174
Total derivative assets		$	3		$	339
	Derivative Liabilities
	December 31, 2015			December 31, 2014
	Balance Sheet Classification	Fair Value		Balance Sheet Classification	Fair Value
	(in millions)
Derivatives not designated as hedging instruments:
Basis swaps	Derivative liabilities	$	–	Derivative liabilities	$	4
Fixed price call options	Derivative liabilities		–	Derivative liabilities		2
Interest rate swaps	Derivative liabilities		3	Derivative liabilities		3
Fixed price call options	Other long-term liabilities		–	Other long-term liabilities		10
Basis swaps	Other long-term liabilities		–	Other long-term liabilities		2
Interest rate swaps	Other long-term liabilities		2	Other long-term liabilities		2
Total derivatives not designated as hedging instruments		$	5		$	23
Total derivative liabilities		$	5		$	23

Summary Of Before Tax Effect Of Cash Flow Hedges On Consolidated Financial Statements

		Gain Recognized in Other Comprehensive Income
		(Effective Portion)
		For the years ended
		December 31,
Derivative Instrument		2015		2014
		(in millions)
Fixed price swaps		$	45	$	122
	Classification of Gain (Loss)	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Earnings
	Reclassified from Accumulated	(Effective Portion)
	Other Comprehensive Income	For the years ended
	into Earnings	December 31,
Derivative Instrument	(Effective Portion)	2015		2014
		(in millions)
Fixed price swaps	Gas Sales	$	209	$	(26)

Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting

		Gain (Loss) on Derivatives,
		Excluding Derivatives, Settled
		Recognized in Earnings
	Consolidated Statements of Operations	For the years ended
	Classification of Gain (Loss) on	December 31,
Derivative Instrument	Derivatives, Net of Settlement	2015		2014
		(in millions)
Basis swaps	Gain on Derivatives	$	(2)	$	(7)
Fixed price call options	Gain on Derivatives		13		18
Fixed price swaps	Gain on Derivatives		(164)		126
Interest rate swaps	Gain on Derivatives		(2)		(7)
		Gain (Loss)
		on Derivatives, Settled (1)
		Recognized in Earnings
	Consolidated Statements of Operations	For the years ended
	Classification of Gain (Loss)	December 31,
Derivative Instrument	on Derivatives, Settled (1)	2015		2014
		(in millions)
Basis swaps	Gain on Derivatives	$	(2)	$	12
Fixed price swaps	Gain on Derivatives		208		(2)
Interest rate swaps	Gain on Derivatives		(4)		(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.

XML

Reclassifications From Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2015

Reclassifications From Accumulated Other Comprehensive Income [Abstract]

Components Of Accumulated Other Comprehensive Income (Loss)

	For the year ended
	December 31, 2015
	Gains (Losses) on Cash Flow Hedges		Pension and Other Postretirement		Foreign Currency		Total
	(in millions) (1)
Beginning balance, December 31, 2014	$	98	$	(24)	$	(12)	$	62
Other comprehensive income (loss) before reclassifications		29		–		(11)		18
Amounts reclassified from/to other comprehensive income (2)		(127)		(1)		–		(128)
Net current-period other comprehensive income (loss)		(98)		(1)		(11)		(110)
Ending balance, December 31, 2015	$	–	$	(25)	$	(23)	$	(48)

(1) All amounts are net of tax.

(2) See separate table below for details about these reclassifications.

Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)

Details about Accumulated Other Comprehensive Income	Affected Line Item in the Consolidated Statements of Operations		Amount Reclassified from/to Accumulated Other Comprehensive Income
			For the year ended December 31, 2015
			(in millions)
Cash flow hedges
Settlements	Gas sales	$	(209)
Ineffectiveness	Gain on derivatives		1
	Provision (benefit) for income taxes		(81)
	Net income (loss)	$	(127)
Pension and other postretirement (1)
Net actuarial loss (2)		$	(3)
Amortization of prior service cost and net loss	General and administrative expenses	$	2
	Provision (benefit) for income taxes		–
	Net income (loss)	$	(1)
Total reclassifications for the period	Net income (loss)	$	(128)

(1) See Note 12 for additional details regarding the Company’s retirement and employee benefit plans.

(2) Net actuarial loss had no impact on the consolidated statement of operations.

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Measurements [Abstract]

Carrying Amount And Estimated Fair Values Of Financial Instruments

	December 31, 2015				December 31, 2014
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(in millions)
Cash and cash equivalents	$	15	$	15	$	53	$	53
Credit facility		116		116		300		300
Term loan facility		750		750		500		500
Bridge facility		–		–		4,500		4,500
Senior notes		3,863		2,672		1,667		1,751
Derivative instruments, net		(2)		(2)		316		316

Summary Assets And Liabilities Measured At Fair Value On Recurring Basis

	December 31, 2015
	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
Fixed price swap assets	$	–	$	–	$	–	$	–
Interest rate swap assets		–		–		–		–
Basis swap assets		–		–		3		3
Interest rate swap liabilities		–		(5)		–		(5)
Basis swap liabilities		–		–		–		–
Fixed price call option liabilities		–		–		–		–
Total	$	–	$	(5)	$	3	$	(2)
	December 31, 2014
	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
Fixed price swap assets	$	–	$	328	$	–	$	328
Interest rate swap assets		–		1		–		1
Basis swap assets		–		–		10		10
Interest rate swap liabilities		–		(5)		–		(5)
Basis swap liabilities		–		–		(6)		(6)
Fixed price call option liabilities		–		–		(12)		(12)
Total	$	–	$	324	$	(8)	$	316

Reconciliations For 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 years ended
	December 31,
	2015		2014
	(in millions)
Balance at beginning of year	$	(8)	$	(19)
Total gains (losses):
Included in earnings		9		23
Included in other comprehensive income		–		–
Purchases, issuances, and settlements:
Purchases		–		–
Issuances		–		–
Settlements		2		(12)
Transfers into/out of Level 3		–		–
Balance at end of year	$	3	$	(8)
Change in gains (losses) included in earnings relating to derivatives still held as of December 31	$	11	$	11

XML

Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt [Abstract]

Components Of Debt

	2015		2014
	(in millions)
Short-term debt:
7.15% Senior Notes due May 2018	$	1	$	1
Variable rate (1.515% at December 31, 2014) bridge facility, due December 2015		–		4,500
Total short-term debt		1		4,501
Long-term debt:
Variable rate (1.886%  and 1.515% at December 31, 2015 and December 31, 2014, respectively) credit facility, expires December 2018		116		300
Variable rate (1.545% at December 31, 2014) term loan facility, due December 2016		–		500
Variable rate (1.775% at December 31, 2015) term loan facility, due November 2018		750		–
7.35% Senior Notes due October 2017		15		15
7.125% Senior Notes due October 2017		25		25
3.3% Senior Notes due January 2018		350		–
7.5% Senior Notes due February 2018		600		600
7.15% Senior Notes due May 2018		26		27
4.05% Senior Notes due January 2020		850		–
Unamortized discount		(1)		–
4.10% Senior Notes due March 2022		1,000		1,000
Unamortized discount		(1)		(1)
4.95% Senior Notes due January 2025		1,000		–
Unamortized discount		(2)		–
Total long-term debt		4,728		2,466
Total debt	$	4,729	$	6,967

Schedule Of Long Term Debt Maturities

2016		1
2017		41
2018		1,841
2019		–
2020		850
Thereafter		2,000
	$	4,733

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Taxes [Abstract]

Provision (Benefit) For Income Taxes

		2015		2014		2013
	(in millions)
Current:
Federal	$	1	$	11	$	(12)
State		(3)		10		1
		(2)		21		(11)
Deferred:
Federal		(1,697)		501		408
State		(304)		2		88
Foreign		(2)		1		1
		(2,003)		504		497
Provision (benefit) for income taxes	$	(2,005)	$	525	$	486

Reconciliation Of Provision For Income Taxes

		2015		2014		2013
		(in millions)
Expected provision (benefit) at federal statutory rate	$	(2,296)	$	507	$	417
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect		(194)		58		53
Nondeductible expenses		–		3		3
State rate redetermination		–		(48)		4
Change in valuation allowance		488		5		–
Other		(3)		–		9
Provision (benefit) for income taxes	$	(2,005)	$	525	$	486

Components Of Deferred Tax Balances

		2015		2014
	(in millions)
Deferred tax liabilities:
Differences between book and tax basis of property	$	216	$	2,504
Derivative activity		–		122
Other		9		21
		225		2,647
Deferred tax assets:
Accrued compensation		28		23
Alternative minimum tax credit carryforward		125		131
Accrued pension costs		19		17
Asset retirement obligations		77		79
Net operating loss carryforward		445		323
Other		24		19
		718		592
Valuation allowance		(493)		(5)
Net deferred tax liability	$	–	$	2,060

Reconciliation Of Beginning And Ending Balances Of Unrecognized Tax Benefits

	2015		2014
	(in millions)
Unrecognized tax benefits at beginning of period	$	44	$	–
Additions based on tax positions related to the current year		7		15
Additions to tax positions of prior years		–		29
Reductions to tax positions of prior years		(14)		–
Unrecognized tax benefits at end of period	$	37	$	44

XML

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation [Abstract]

Schedule Of Asset Retirement Obligations

	2015		2014
	(in millions)
Asset retirement obligation at January 1	$	207	$	134
Accretion of discount		11		7
Obligations incurred (1)		17		64
Obligations settled/removed (2)		(30)		(4)
Revisions of estimates		(4)		6
Asset retirement obligation at December 31	$	201	$	207
Current liability		10		9
Long-term liability		191		198
Asset retirement obligation at December 31	$	201	$	207

(1) Obligations incurred in 2014 include $42 million related to the Chesapeake Property Acquisition.

(2) Obligations settled/removed in 2015 include $25 million related to asset divestitures.

XML

Retirement And Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2015

Retirement And Employee Benefit Plans [Abstract]

Changes In Plans Benefit Obligations, Fair Value Of Assets, And Funded Status

					Other Postretirement
	Pension Benefits				Benefits
	2015		2014		2015		2014
	(in millions)
Change in benefit obligations:
Benefit obligation at January 1	$	134	$	103	$	18	$	12
Service cost		16		13		3		2
Interest cost		6		5		1		1
Participant contributions		–		–		–		–
Actuarial loss		(7)		21		(2)		3
Benefits paid		(11)		(8)		–		–
Plan amendments		–		–		–		–
Settlements		–		–		–		–
Benefit obligation at December 31	$	138	$	134	$	20	$	18

					Other Postretirement
	Pension Benefits				Benefits
	2015		2014		2015		2014
	(in millions)
Change in plan assets:
Fair value of plan assets at January 1	$	108	$	99	$	–	$	–
Actual return on plan assets		(1)		5		–		–
Employer contributions		12		12		–		–
Participant contributions		–		–		–		–
Benefits paid		(11)		(8)		–		–
Settlements		–		–		–		–
Fair value of plan assets at December 31	$	108	$	108	$	–	$	–
Funded status of plans at December 31	$	(30)	$	(26)	$	(20)	$	(18)

Projected Benefit Obligation, Accumulated Benefit Obligation, And Fair Value Of Plan Assets

		2015		2014
	(in millions)
Projected benefit obligation	$	138	$	134
Accumulated benefit obligation		135		129
Fair value of plan assets		108		108

Pension And Other Postretirement Benefit Costs

								Other Postretirement
		Pension Benefits						Benefits
		2015		2014		2013		2015		2014		2013
	(in millions)
Service cost	$	16	$	13	$	14	$	3	$	2	$	2
Interest cost		6		5		4		1		1		1
Expected return on plan assets		(9)		(7)		(6)		–		–		–
Amortization of transition obligation		–		–		–		–		–		–
Amortization of prior service cost		–		–		–		–		–		–
Amortization of net loss		2		1		2		–		–		–
Net periodic benefit cost		15		12		14		4		3		3
Settlements and curtailments		–		–		–		–		–		–
Total benefit cost	$	15	$	12	$	14	$	4	$	3	$	3

Amounts Recognized In Other Comprehensive Income

	Pension Benefits		Other Postretirement Benefits
	(in millions)
Net actuarial (loss) gain arising during the year	$	(4)	$	1
Amortization of prior service cost		–		–
Amortization of net loss		2		–
Settlements		–		–
Tax effect		–		–
	$	(2)	$	1

Schedule Of Assumptions Used

The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2015 and 2014 are as follows:

	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015		2014
Discount rate	4.60	%	4.25	%	4.60	%	4.25	%
Rate of compensation increase	3.50	%	4.50	%	n/a		n/a

The assumptions used in the measurement of the Company’s net periodic benefit cost for 2015, 2014 and 2013 are as follows:

	Pension Benefits						Other Postretirement Benefits
	2015		2014		2013		2015		2014		2013
Discount rate	4.25	%	5.00	%	4.00	%	4.25	%	5.00	%	4.00	%
Expected return on plan assets	7.00	%	7.00	%	7.00	%	n/a		n/a		n/a
Rate of compensation increase	4.50	%	4.50	%	4.50	%	n/a		n/a		n/a

Schedule Of Health Care Cost Trend Rates

	2015	2014
Health care cost trend assumed for next year	8%	8%
Rate to which the cost trend is assumed to decline	5%	5%
Year that the rate reaches the ultimate trend rate	2034	2033

One Percentage Point Change In Assumed Health Care Cost Trend Rates

		1% Increase		1% Decrease
	(in millions)
Effect on the total service and interest cost components	$	1	$	(1)
Effect on postretirement benefit obligations	$	3	$	(2)

Schedule Of Expected Benefit Payments

Pension Benefits			Other Postretirement Benefits
(in millions)
2016	$	8	2016	$	1
2017		9	2017		1
2018		10	2018		1
2019		11	2019		1
2020		10	2020		2
Years 2021-2025		67	Years 2021-2025		11

Schedule Of Allocation Of Plan Assets

	Pension Plan Asset Allocations
Asset category:
Equity securities:	Target		Actual
U.S. Equity(1)	35	%	36	%
Non-U.S. Developed Equity(2)	30	%	29	%
Emerging Markets Equity(3)	5	%	5	%
Opportunistic(4)	–	%	–	%
Fixed income(5)	28	%	28	%
Cash(6)	2	%	2	%
Total	100	%	100	%

(1) Asset category above includes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity.

(2) Asset category above includes Non-U.S. equity securities in the table below.

(3) Asset category above includes Emerging markets equity securities below.

(4) Asset category above includes none of the securities in the table below.

(5) Asset category above includes Fixed income pension plan assets in the table below.

(6) Asset category above includes Cash and cash equivalents pension plan assets in the table below.

Fair Value Measurement Of Pension Plan Assets

Asset category:	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Equity securities:
U.S. large cap growth equity(1)	$	9	$	9	$	–	$	–
U.S. large cap value equity(2)		9		9		–		–
U.S. large cap core equity(3)		18		–		18		–
U.S. small cap equity(4)		3		3		–		–
Non-U.S. equity(5)		31		31		–		–
Emerging markets equity(6)		5		5		–		–
Fixed income (7)		31		–		31		–
Cash and cash equivalents		2		2		–		–
Total	$	108	$	59	$	49	$	–

(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.

(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.

(3) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.

(4) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.

(5) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.

(6) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.

(7) Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.

Utilizing the fair value hierarchy described in Note 7 – Fair Value Measurements, the Company’s fair value measurement of pension plan assets at December 31, 2014 are as follows:

Asset category:	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in millions)
Equity securities:
U.S. large cap growth equity(1)	$	8	$	8	$	–	$	–
U.S. large cap value equity(2)		9		9		–		–
U.S. large cap core equity(3)		19		–		19		–
U.S. small cap equity(4)		3		3		–		–
Non-U.S. equity(5)		29		29		–		–
Emerging markets equity(6)		5		5		–		–
Fixed income (7)		31		–		31		–
Cash and cash equivalents		4		4		–		–
Total	$	108	$	58	$	50	$	–

(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.

(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.

(3) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.

(4) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.

(5) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.

(6) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.

(7) An institutional fund that seeks an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S.  Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.

XML

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Schedule Of Valuation Assumptions

Assumptions	2015	2014	2013
Risk-free interest rate	1.7%	1.6%	1.5%
Expected dividend yield	–	–	–
Expected volatility	36.0%	32.5%	38.6%
Expected term	5 years	5 years	5 years

Summary Of Stock Option Activity

	2015			2014			2013
		Weighted			Weighted			Weighted
		Average			Average			Average
	Number	Exercise		Number	Exercise		Number	Exercise
	of Shares	Price		of Shares	Price		of Shares	Price
	(in thousands)			(in thousands)			(in thousands)
Options outstanding at January 1	3,622	$	35.41	3,313	$	35.70	3,650	$	29.84
Granted	2,401		9.47	835		32.31	571		38.95
Exercised	–		–	(402)		30.60	(833)		12.12
Forfeited or expired	(400)		32.20	(124)		37.80	(75)		37.31
Options outstanding at December 31	5,623	$	24.57	3,622	$	35.41	3,313	$	35.70

Summary Of Stock Options Outstanding And Options Exercisable

	Options Outstanding				Options Exercisable
				Weighted				Weighted
				Average				Average
	Options	Weighted		Remaining	Options	Weighted		Remaining
	Outstanding at	Average		Contractual	Exercisable at	Average		Contractual
Range of	December 31,	Exercise		Life	December 31,	Exercise		Life
Exercise Prices	2015	Price		(Years)	2015	Price		(Years)
	(in thousands)				(in thousands)
$7.74-$29.69	2,421		9.63	6.8	20		28.46	1.8
$30.59-$35.91	1,397		32.32	4.9	900		33.27	4.3
$36.22-$39.68	1,412		37.50	3.4	1,249		37.31	3.2
$40.15-$51.47	393		42.58	2.0	333		41.86	1.4
	5,623	$	24.57	5.1	2,502	$	36.39	3.4

Summary Of Restricted Stock Activity

	2015			2014			2013
	Number of Shares		Weighted Average Grant Date Fair Value	Number of Shares		Weighted Average Grant Date Fair Value	Number of Shares		Weighted Average Grant Date Fair Value
	(in thousands)			(in thousands)			(in thousands)
Unvested shares at January 1	2,376	$	34.00	1,771	$	37.55	1,118	$	35.64
Granted	5,822		8.07	1,295		30.89	1,109		38.92
Vested	(873)		33.33	(548)		37.12	(382)		36.29
Forfeited	(103)		29.14	(142)		37.91	(74)		35.81
Unvested shares at December 31	7,222	$	13.24	2,376	$	34.00	1,771	$	37.55

Summary Of Equity-Classified Performance Units Activity

	2015			2014
	Number of Units (1)	Weighted Average Grant Date Fair Value		Number of Units (1)	Weighted Average Grant Date Fair Value
Unvested shares at January 1	223	$	40.44	–	$	–
Granted	443		35.22	359		40.44
Vested	(259)		37.46	(111)		40.44
Forfeited	–		–	(25)		40.44
Unvested shares at December 31	407	$	36.65	223	$	40.44

(1) These amounts reflect the number of performance units granted in thousands. The actual payout of shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures.

Stock Options [Member]

Schedule Of Stock-Based Compensation Costs

	2015		2014		2013
	(in millions)
Stock-based compensation cost related to stock options – general and administrative expense	$	5	$	5	$	5
Stock-based compensation cost related to stock options – capitalized	$	3	$	4	$	5

Restricted Stock [Member]

Schedule Of Stock-Based Compensation Costs

		2015		2014		2013
		(in millions)
Stock-based compensation cost related to restricted stock grants – general and administrative expense	$	14	$	10	$	7
Stock-based compensation cost related to restricted stock grants – capitalized	$	16	$	12	$	7

Equity-Classified Performance Units [Member]

Schedule Of Stock-Based Compensation Costs

		a
	2015		2014
	(in millions)
Stock-based compensation cost related to performance units - general and administrative expense	$	6	$	3
Stock-based compensation cost related to performance units - capitalized	$	4	$	2

XML

Segment Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Information [Abstract]

Summary Financial Information For Company's Reportable Segments

	Exploration
	and			Midstream
	Production			Services		Other		Total
	(in millions)
2015
Revenues from external customers	$	2,095		$	1,038	$	–	$	3,133
Intersegment revenues		(21)			2,081		–		2,060
Operating income (loss)		(7,104)	(2)		583		(1)		(6,522)
Other loss, net		(21)			(9)		–		(30)
Gain (loss) on derivatives		51			–		(4)		47
Depreciation, depletion and amortization expense		1,028			62		1		1,091
Impairment of natural gas and oil properties		6,950			–		–		6,950
Interest expense(1)		47			9		–		56
Provision (benefit) for income taxes(1)		(2,273)			268		–		(2,005)
Assets		6,588	(3)		1,290		232		8,110
Capital investments(4)		2,258			167		12		2,437
2014
Revenues from external customers	$	2,850		$	1,188	$	–	$	4,038
Intersegment revenues		12			3,170		–		3,182
Operating income (loss)		1,013			361		(1)		1,373
Other loss, net		(3)			(1)		–		(4)
Gain (loss) on derivatives		142			(1)		(2)		139
Depreciation, depletion and amortization expense		884			58		–		942
Interest expense(1)		47			12		–		59
Provision for income taxes(1)		402			123		–		525
Assets		13,018	(3)		1,554		353		14,925
Capital investments(4)		7,254			144		49		7,447
2013
Revenues from external customers	$	2,398		$	973	$	–	$	3,371
Intersegment revenues		6			2,374		–		2,380
Operating income		879			325		–		1,204
Other income (loss), net		3			–		(1)		2
Gain on derivatives		26			–		–		26
Depreciation, depletion and amortization expense		735			51		1		787
Interest expense(1)		30			11		1		42
Provision (benefit) for income taxes(1)		368			119		(1)		486
Assets		6,357	(3)		1,427		264		8,048
Capital investments(4)		2,052			158		25		2,235

(1) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

(2) Includes $6,950 million from non-cash impairments of natural gas and oil properties.

(3) Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.

(4) Capital investments include a decrease of  $33 million for 2015, an increase of $155 million for 2014 and a decrease of $25 million for 2013 related to the change in accrued expenditures between years.

XML

Quarterly Results (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Results [Abstract]

Schedule Of Quarterly Financial Information

	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
	(in millions, except per share amounts)
	2015
Operating revenues	$	933	$	764	$	749	$	687
Operating income (loss) (1)		165		(1,284)		(2,842)		(2,561)
Net income (loss) attributable to common stock (2)		46		(815)		(1,766)		(2,134)
Earnings per share - Basic		0.12		(2.13)		(4.62)		(5.58)
Earnings per share - Diluted		0.12		(2.13)		(4.62)		(5.58)
	2014
Operating revenues	$	1,113	$	1,035	$	928	$	962
Operating income		435		367		286		285
Net income		194		207		211		312
Earnings per share - Basic		0.55		0.59		0.60		0.89
Earnings per share - Diluted		0.55		0.59		0.60		0.88

(1) The operating losses for the second, third and fourth quarters of 2015 included full cost non-cash impairments of natural gas and oil properties of $1.5 billion, $2.8 billion and $2.6 billion, respectively.

(2) Net income attributable to common stock was reduced by $7 million in the first quarter of 2015 to recognize the portion of the Company’s net income that would be distributed to the holders of preferred securities (mandatory convertible preferred stock) at year-end. However, as a result of the Company’s net loss in the second quarter that persisted for the year ended December 31, 2015, participating securities were ultimately not entitled to receive a distribution.

XML

Organization And Summary Of Significant Accounting Policies (Narrative) (Details) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended			12 Months Ended
	Dec. 19, 2014 USD ($)	Jan. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2015 USD ($) $ / shares shares	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($) $ / shares $ / bbl $ / MMBTU shares	Dec. 31, 2014 USD ($) $ / bbl $ / MMBTU shares	Dec. 31, 2013 $ / bbl $ / MMBTU	Feb. 28, 2015 $ / shares
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Outstanding checks included in accounts payable			$ 29			$ 29	$ 17
Inventory write-down of carrying value			23			$ 23
Natural gas, oil and NGL reserves discount						10.00%	10.00%	10.00%
Period of time needed to calculate ceiling value of reserves						12 months	12 months	12 months
Net capitalized costs exceeding ceiling			$ 1,586	$ 1,746	$ 944
Cash flow hedges impact on ceiling value, net of tax				$ 40	$ 60
Amount recognized is the largest amount of tax benefit, threshold						50.00%
Number of common shares: Effect of issuance of non-vested performance units | shares							273,918
Treasury stock, shares | shares			47,149			47,149	11,055
Net long term deferred income tax liability							$ 1,951
Net current deferred income tax liability							109
Senior Notes [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Proceeds from issuance of debt		$ 2,200				$ 2,200
Bridge Loan [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Bridge loan	$ 4,500						$ 4,500
Debt instrument, term	364 days						364 days
NGL [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price | $ / bbl						6.82	23.79	43.45
Henry Hub Natural Gas [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price | $ / MMBTU						2.59	4.35	3.67
West Texas Intermediate Oil [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Full cost ceiling test, price | $ / bbl						46.79	91.48	93.42
Gathering Systems [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Straight-line depreciation period						25 years
Common Stock [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued | shares		30,000,000
Share price | $ / shares		$ 23.00
Proceeds from issuance of shares		$ 669
Depositary Shares [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued | shares		34,500,000
Proceeds from issuance of shares		$ 1,700
Depositary shares conversion rate		0.05
Liquidation preference per share | $ / shares		$ 50
Series B Preferred Stock [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Liquidation preference per share | $ / shares			$ 1,000			$ 1,000			$ 1,000
Trading day period						20 days
Minimum [Member] | Depositary Shares [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued upon conversion | shares			1.85014			1.85014
Minimum [Member] | Series B Preferred Stock [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued upon conversion | shares			37.0028			37.0028
Maximum [Member] | Depositary Shares [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued upon conversion | shares			2.17391			2.17391
Maximum [Member] | Series B Preferred Stock [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares issued upon conversion | shares			43.4782			43.4782
WPX Property Acquisition [Member]
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Percentage of interest acquired			86.00%			86.00%

XML

Organization And Summary Of Significant Accounting Policies (Components Of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Organization And Summary Of Significant Accounting Policies [Abstract]
Tubulars and other equipment	$ 3	$ 33
Natural gas in underground storage		$ 4

XML

Organization And Summary Of Significant Accounting Policies (Schedule Of Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Line Items]
Net income (loss)									$ (4,556)	$ 924	$ 704
Mandatory convertible preferred stock dividend									106
Net Income (Loss) Attributable to Common Stock	$ (2,134)	$ (1,766)	$ (815)	$ 46	$ 312	$ 211	$ 207	$ 194	$ (4,662)	$ 924	$ 704
Number of common shares, Weighted average outstanding									380,521,039	351,446,747	350,465,430
Number of common shares: Issued upon assumed exercise of outstanding stock options										241,603	377,626
Number of common shares: Effect of issuance of non-vested restricted common stock										448,415	258,396
Number of common shares: Effect of issuance of non-vested performance units										273,918
Number of common shares, Weighted average and potential dilutive outstanding									380,521,039	352,410,683	351,101,452
Basic	$ (5.58)	$ (4.62)	$ (2.13)	$ 0.12	$ 0.89	$ 0.60	$ 0.59	$ 0.55	$ (12.25)	$ 2.63	$ 2.01
Diluted	$ (5.58)	$ (4.62)	$ (2.13)	$ 0.12	$ 0.88	$ 0.60	$ 0.59	$ 0.55	$ (12.25)	$ 2.62	$ 2.00
Stock Options [Member]
Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares									3,835,234	1,446,004	1,634,695
Restricted Stock [Member]
Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares									1,990,383	29,879	114,433
Performance Units [Member]
Earnings Per Share [Line Items]
Number of common shares: Effect of issuance of non-vested performance units											0
Antidilutive securities excluded from computation of earnings per share, shares									140,414
Mandatory Convertible Preferred Stock [Member]
Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, shares									70,890,312	0	0

XML

Organization And Summary Of Significant Accounting Policies (Schedule Of Supplemental Disclosures Of Cash Flow Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization And Summary Of Significant Accounting Policies [Abstract]
Cash paid during the year for interest, net of amounts capitalized	$ 6	$ 50	$ 36
Cash paid (received) during the year for income taxes	(6)	28	19
Increase (decrease) in noncash property additions	$ (10)	$ 174	$ (13)

XML

Acquisitions And Divestitures (Narrative) (Details) $ in Millions		1 Months Ended					3 Months Ended								5 Months Ended	12 Months Ended
	Dec. 19, 2014 USD ($)	May. 31, 2015 USD ($)	Apr. 30, 2015 USD ($) mi MMcf	Jan. 31, 2015 USD ($) a MMcf	Dec. 31, 2014 USD ($) a MMcf	Apr. 30, 2013 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) a MMcf	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Jul. 31, 2014 USD ($) a	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) a item MMcf	Dec. 31, 2013 USD ($)
Business Acquisition [Line Items]
Debt issuance costs				$ 47.0
General and administrative expenses																$ 246.0	$ 221.0	$ 191.0
Interest expense																56.0	59.0	42.0
Other current assets					$ 158.0		$ 45.0				$ 158.0					45.0	158.0
Revenues							687.0	$ 749.0	$ 764.0	$ 933.0	962.0	$ 928.0	$ 1,035.0	$ 1,113.0		3,133.0	4,038.0	3,371.0
Operating income (loss)							$ (2,561.0)	$ (2,842.0)	$ (1,284.0)	$ 165.0	285.0	$ 286.0	$ 367.0	$ 435.0		(6,522.0)	$ 1,373.0	$ 1,204.0
Bridge Loan [Member]
Business Acquisition [Line Items]
Maturity date, month and year																	2015-12
Bridge loan	$ 4,500.0				4,500.0						4,500.0						$ 4,500.0
Debt instrument, term	364 days																364 days
Repayment of debt				4,500.0
Debt issuance costs				$ 47.0
Unsecured Debt [Member] | 1.545% Term Loan due December 2016 [Member]
Business Acquisition [Line Items]
Loans payable					$ 500.0						$ 500.0						$ 500.0
Maturity date, month and year																	2016-12
Debt instrument, term																	2 years
WPX Property Acquisition [Member]
Business Acquisition [Line Items]
Area of land purchased | a				46,700
Cash consideration				$ 270.0
Net production per day of acreage sold in MMcf | MMcf					50						50						50
Number of horizontal wells operated | item																	63
Firm transportation capacity assumed, per day | MMcf				260
Firm transportation, useful life				19 years
Amortization																$ 8.2
Percentage of interest acquired							86.00%									86.00%
Statoil Property Acquisition [Member]
Business Acquisition [Line Items]
Area of land purchased | a				30,000
Allocated to natural gas and oil properties				$ 357.0
Percentage of interest acquired				20.00%
Cost to acquire property				$ 357.0
Chesapeake Property Acquisition [Member]
Business Acquisition [Line Items]
Area of land purchased | a					413,000						413,000						413,000
Cash consideration					$ 4,949.0
General and administrative expenses																	$ 1.0
Interest expense																	5.0
Revenues																	10.0
Operating income (loss)																	2.0
Chesapeake Property Acquisition [Member] | Bridge Loan [Member]
Business Acquisition [Line Items]
Other current assets					47.0						$ 47.0						47.0
Chesapeake Property Acquisition [Member] | Unsecured Debt [Member] | 1.545% Term Loan due December 2016 [Member]
Business Acquisition [Line Items]
Unamortized fees					$ 1.0						$ 1.0						$ 1.0
East Texas and Arkoma Basin [Member]
Business Acquisition [Line Items]
Proceeds from sale of oil and gas property and equipment		$ 211.0
Reduction in capitalized costs relating to proceeds		$ (205.0)
Bradford And Lycoming Counties, Pennsylvania [Member]
Business Acquisition [Line Items]
Proceeds from sale of oil and gas property and equipment			$ 489.0
Net book value			206.0
Gain on sale of property			$ 283.0
Number of miles of natural gas gathering pipeline | mi			100
Pipeline capacity per day | MMcf			600
Niobrara Formation In Colorado [Member]
Business Acquisition [Line Items]
Area of land purchased | a															380,000
Cost to acquire natural gas properties through definitive purchase agreement															$ 215.0
Marcellus Shale In Pennsylvania [Member]
Business Acquisition [Line Items]
Cost to acquire natural gas properties through definitive purchase agreement						$ 82.0

XML

Acquisitions And Divestitures (Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed) (Details) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2015	Dec. 31, 2014
WPX Property Acquisition [Member]
Business Acquisition [Line Items]
Cash	$ 270
Proved natural gas and oil properties	31
Unproved natural gas and oil properties	114
Intangible asset	109
Gathering system	22
Other	1
Total assets acquired	277
Asset retirement obligations	(7)
Total liabilities assumed	(7)
Total assets acquired and liabilities assumed	$ 270
Chesapeake Property Acquisition [Member]
Business Acquisition [Line Items]
Cash		$ 4,949
Proved natural gas and oil properties		1,418
Unproved natural gas and oil properties		3,573
Other property and equipment		33
Inventory		3
Total assets acquired		5,027
Asset retirement obligations		(42)
Other liabilities		(36)
Total liabilities assumed		(78)
Total assets acquired and liabilities assumed		$ 4,949

XML

Acquisitions And Divestitures (Summary Of Consolidated Results Of Operations On Pro Forma Basis) (Details) - Chesapeake Property Acquisition [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$ 4,439	$ 3,713
Net income attributable to common stock	$ 803	$ 594
Basic	$ 2.11	$ 1.56
Diluted	$ 2.10	$ 1.56

XML

Prepaid Expenses (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Prepaid Expenses [Line Items]
Prepaid taxes	$ 26	$ 30
Prepaid insurance	6	8
Other prepaid expenses	11	5
Deposits		65
Total	$ 43	108
Statoil Property Acquisition [Member]
Prepaid Expenses [Line Items]
Deposits		50
WPX Property Acquisition [Member]
Prepaid Expenses [Line Items]
Deposits		$ 15

XML

Natural Gas And Oil Producing Activities (Narrative) (Details) ft³ in Thousands, $ in Millions	12 Months Ended				108 Months Ended	144 Months Ended
	Dec. 31, 2015 USD ($) $ / bbl $ / MMBTU site MBbls ft³	Dec. 31, 2014 USD ($) a $ / bbl $ / MMBTU site MBbls ft³	Dec. 31, 2013 USD ($) $ / bbl $ / MMBTU site MBbls ft³	Dec. 31, 2012 MBbls ft³	Dec. 31, 2012 USD ($) MBbls ft³	Dec. 31, 2015 USD ($) site MBbls ft³	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)
Natural Gas and Oil Properties [Line Items]
Natural gas, oil and NGL reserves discount	10.00%	10.00%	10.00%
Period of time needed to calculate ceiling value of reserves	12 months	12 months	12 months
Cash flow hedges impact on ceiling value, net of tax | $							$ 40	$ 60
Net unevaluated costs excluded from amortization | $	$ 522	$ 2,948	$ 82		$ 175	$ 3,727
Percentage of present worth of proved reserves evaluated in audit	100.00%	97.00%	95.00%
Capitalized interest based on weighted average cost of borrowings | $	$ 204	$ 55	$ 62
Capitalized internal costs related to acquisition, exploration and development | $	307	320	264
Capitalized internal costs related to acquisition, exploration and development activities - subsidiaries | $	$ 118	$ 123	$ 103
Production		768,000,000	657,000,000	565,000,000
Production volumes replaced with proved reserve additions, net upward revisions and acquisitions, percentage		591.00%	550.00%
Extensions, discoveries and other additions	592,000,000	1,693,000,000	3,285,000,000
Revisions	(4,083,000,000)	543,000,000
Proved reserves, dispositions	179,000,000					179,000,000
Undeveloped Properties Fayetteville Shale [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	34,000,000	573,000,000	1,530,000,000
Undeveloped Properties Marcellus Shale [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization | $	$ 121
Undeveloped Properties New Ventures - Excluding Canada [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization | $	265
Exploration Program in Canada [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization | $	50
Wells In Progress [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization | $	$ 157
Southwest Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Net increase (decrease) in production	140,000,000	3,000,000				140,000,000
Northeast Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Net increase (decrease) in production	106,000,000	103,000,000	97,000,000			106,000,000
Northeast Appalachia [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions		636,000,000	62,000,000
Northeast Appalachia [Member] | Higher Gas Prices [Member]
Natural Gas and Oil Properties [Line Items]
Revisions		10,000,000	35,000,000
Fayetteville Shale [Member]
Natural Gas and Oil Properties [Line Items]
Net increase (decrease) in production	(29,000,000)	8,000,000	1,000,000			(29,000,000)
Fayetteville Shale [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions		(126,000,000)	16,000,000
Fayetteville Shale [Member] | Higher Gas Prices [Member]
Natural Gas and Oil Properties [Line Items]
Revisions		38,000,000	191,000,000
Other Properties [Member]
Natural Gas and Oil Properties [Line Items]
Net increase (decrease) in production	(9,000,000)					(9,000,000)
Acquisitions [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	114,000,000	2,304,000,000	4,000,000
Developed Properties Northeast Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	202,000,000	246,000,000	386,000,000
Developed Properties Northeast Appalachia [Member] | Lower Gas Prices [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	(2,315,000,000)
Developed Properties Northeast Appalachia [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	1,383,000,000
Developed Properties Southwest Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	84,000,000
Developed Properties Southwest Appalachia [Member] | Lower Gas Prices [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	(1,875,000,000)
Developed Properties Southwest Appalachia [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	209,000,000
Developed Properties Fayetteville Shale [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	129,000,000	283,000,000	557,000,000
Developed Properties Fayetteville Shale [Member] | Lower Gas Prices [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	(1,496,000,000)
Developed Properties Fayetteville Shale [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	10,000,000
Developed Properties Other Divisions [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	1,000,000
Developed Properties Other Divisions [Member] | Lower Gas Prices [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	(32,000,000)
Developed Properties Other Divisions [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions	33,000,000
Undeveloped Properties Northeast Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	138,000,000	589,000,000	810,000,000
Undeveloped Properties Southwest Appalachia [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions	4,000,000
East Texas and Arkoma Basin [Member]
Natural Gas and Oil Properties [Line Items]
Net increase (decrease) in production		(3,000,000)	(7,000,000)
Developed Properties Brown Dense [Member]
Natural Gas and Oil Properties [Line Items]
Extensions, discoveries and other additions		2,000,000	2,000,000
Ark-La-Tex [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions		(21,000,000)
Ark-La-Tex [Member] | Higher Gas Prices [Member]
Natural Gas and Oil Properties [Line Items]
Revisions		6,000,000	21,000,000
Undeveloped Properties, Various Locations [Member]
Natural Gas and Oil Properties [Line Items]
Natural gas, oil and NGL reserves discount	10.00%	10.00%	10.00%
Proved undeveloped reserves	217,000,000	181,000,000	662,000,000			217,000,000
Number of locations | site	75	60	268			75
Present value of proved reserves, discounted basis | $	$ (34)	$ (28)	$ (97)			$ (34)
Proved reserves, committed development period	5 years
New Ventures [Member]
Natural Gas and Oil Properties [Line Items]
Net increase (decrease) in production			1,000,000
New Ventures [Member] | Performance [Member]
Natural Gas and Oil Properties [Line Items]
Revisions			1,000,000
Chesapeake Property Acquisition [Member]
Natural Gas and Oil Properties [Line Items]
Net unevaluated costs excluded from amortization | $	$ 2,900
Area of land purchased | a		413,000
Natural Gas [Member]
Natural Gas and Oil Properties [Line Items]
Proved developed and undeveloped reserves	5,917,000,000	9,809,000,000	6,974,000,000	4,017,000,000	4,017,000,000	5,917,000,000
Production	899,000,000	766,000,000	656,000,000
Extensions, discoveries and other additions	546,000,000	1,692,000,000	3,284,000,000
Revisions	(3,458,000,000)	542,000,000	325,000,000
Proved undeveloped reserves	443,000,000	4,134,000,000	2,737,000,000	821,000,000	821,000,000	443,000,000
Average market prices used in reserves | $ / MMBTU	2.59	4.35	3.67
Oil [Member]
Natural Gas and Oil Properties [Line Items]
Proved developed and undeveloped reserves | MBbls	8,753	37,615	373	244	244	8,753
Production | MBbls	2,265	235	138
Extensions, discoveries and other additions | MBbls	1,367	250	229
Revisions | MBbls	(28,394)	(14)	38
Proved undeveloped reserves | MBbls		30,170	1	1	1
Average market prices used in reserves | $ / bbl	46.79	91.48	93.42
NGL [Member]
Natural Gas and Oil Properties [Line Items]
Full cost ceiling test, price | $ / bbl	6.82	23.79	43.45
Proved developed and undeveloped reserves | MBbls	40,947	118,699				40,947
Production | MBbls	10,702	231	50
Extensions, discoveries and other additions | MBbls	6,274	48
Revisions | MBbls	(75,664)	66	50
Proved undeveloped reserves | MBbls		80,067
Average market prices used in reserves | $ / MMBTU	6.82	23.79	43.45
Natural Gas and Oil [Member]
Natural Gas and Oil Properties [Line Items]
Production	976,000,000	768,000,000
Natural Gas and Oil [Member] | Estimated [Member]
Natural Gas and Oil Properties [Line Items]
Proved developed and undeveloped reserves	6,215,000,000	10,747,000,000	6,976,000,000	4,018,000,000	4,018,000,000	6,215,000,000
Synthetic Gas, Synthetic Oil or Nonrenewable Natural Resources [Member]
Natural Gas and Oil Properties [Line Items]
Proved developed and undeveloped reserves	0					0

XML

Natural Gas And Oil Producing Activities (Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Capitalized Costs Relating to Oil and Gas Producing Activities [Line Items]
Proved properties	$ 18,751	$ 15,860
Unproved properties	3,727	4,646
Total capitalized costs	22,478	20,506
Less: Accumulated depreciation, depletion and amortization	(16,248)	(8,327)
Net capitalized costs	6,230	12,179
Unproved property acquisition costs	692	3,934	$ 168
Capitalized Costs [Member] | Exploration Program in Canada [Member]
Net Capitalized Costs Relating to Oil and Gas Producing Activities [Line Items]
Unproved property acquisition costs	$ 50	$ 76

XML

Natural Gas And Oil Producing Activities (Composition Of Net Unevaluated Costs Excluded From Amortization) (Details) - USD ($) $ in Millions	12 Months Ended			108 Months Ended	144 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	$ 274	$ 2,870	$ 42	$ 105	$ 3,291
Exploration and development costs	128	56	29	36	249
Capitalized interest	120	22	11	34	187
Net unevaluated costs excluded from amortization	522	$ 2,948	$ 82	$ 175	3,727
Exploration Program in Canada [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Net unevaluated costs excluded from amortization	$ 50
Composition of Net Unevaluated Costs [Member] | Exploration Program in Canada [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs					16
Exploration and development costs					26
Capitalized interest					$ 8

XML

Natural Gas And Oil Producing Activities (Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities Disclosure) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) $ / ft³	Dec. 31, 2014 USD ($) $ / ft³	Dec. 31, 2013 USD ($) $ / ft³
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition costs	$ 81	$ 1,455	$ 1
Unproved property acquisition costs	692	3,934	168
Exploration costs	50	232	192
Development costs	1,417	1,600	1,662
Capitalized costs incurred	$ 2,240	$ 7,221	$ 2,023
Full cost pool amortization per Mcfe | $ / ft³	1.00	1.10	1.08
Costs Incurred in Natural Gas and Oil Exploration and Development [Member] | Exploration Program in Canada [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved property acquisition costs		$ 1	$ 17
Exploration costs		$ 3	$ 12

XML

Natural Gas And Oil Producing Activities (Results Of Operations For Oil And Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Natural Gas And Oil Producing Activities [Abstract]
Sales	$ 2,074	$ 2,862	$ 2,404
Production (lifting) costs	(989)	(776)	(629)
Depreciation, depletion and amortization	(1,028)	(884)	(735)
Impairment of natural gas and oil properties	(6,950)
Results of operations - income before income taxes	(6,893)	1,202	1,040
Provision (benefit) for income taxes	(2,619)	457	416
Results of operations	$ (4,274)	$ 745	$ 624

XML

Natural Gas And Oil Producing Activities (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details) ft³ in Billions	12 Months Ended
	Dec. 31, 2015 MBbls ft³	Dec. 31, 2014 MBbls ft³	Dec. 31, 2013 MBbls ft³	Dec. 31, 2012 MBbls ft³
Reserve Quantities [Line Items]
Revisions of previous estimates | ft³	(4,083)	543
Extensions, discoveries and other additions | ft³	592	1,693	3,285
Production | ft³		(768)	(657)	(565)
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year | ft³	9,809	6,974	4,017
Revisions of previous estimates | ft³	(3,458)	542	325
Extensions, discoveries and other additions | ft³	546	1,692	3,284
Production | ft³	(899)	(766)	(656)
Acquisition of reserves in place | ft³	97	1,367	4
Disposition of reserves in place | ft³	(178)
Proved reserves, end of year | ft³	5,917	9,809	6,974	4,017
Proved Developed Reserves [Abstract]
Beginning of year | ft³	5,675	4,237	3,196
End of year | ft³	5,474	5,675	4,237	3,196
Proved Undeveloped Reserves [Abstract]
Beginning of year | ft³	4,134	2,737	821
End of year | ft³	443	4,134	2,737	821
Oil [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	37,615	373	244
Revisions of previous estimates	(28,394)	(14)	38
Extensions, discoveries and other additions	1,367	250	229
Production	(2,265)	(235)	(138)
Acquisition of reserves in place	525	37,246
Disposition of reserves in place	(95)	(5)
Proved reserves, end of year	8,753	37,615	373	244
Proved Developed Reserves [Abstract]
Beginning of year	7,445	372	243
End of year	8,753	7,445	372	243
Proved Undeveloped Reserves [Abstract]
Beginning of year	30,170	1	1
End of year		30,170	1	1
NGL [Member]
Reserve Quantities [Line Items]
Proved reserves, beginning of year	118,699
Revisions of previous estimates	(75,664)	66	50
Extensions, discoveries and other additions	6,274	48
Production	(10,702)	(231)	(50)
Acquisition of reserves in place	2,340	118,816
Disposition of reserves in place
Proved reserves, end of year	40,947	118,699
Proved Developed Reserves [Abstract]
Beginning of year	38,632
End of year	40,947	38,632
Proved Undeveloped Reserves [Abstract]
Beginning of year	80,067
End of year		80,067

XML

Natural Gas And Oil Producing Activities (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Natural Gas And Oil Producing Activities [Abstract]
Future cash inflows	$ 11,887	$ 41,812	$ 22,624
Future production costs	(7,376)	(16,477)	(8,896)
Future development costs	(792)	(5,750)	(3,626)
Future income tax expense		(4,743)	(3,223)
Future net cash flows	3,719	14,842	6,879
10% annual discount for estimated timing of cash flows	(1,302)	(7,299)	(3,143)
Standardized measure of discounted future net cash flows	$ 2,417	$ 7,543	$ 3,736	$ 2,051
Annual discount for estimated timing of cash flows percent	10.00%	10.00%	10.00%

XML

Natural Gas And Oil Producing Activities (Schedule Of Analysis Of Changes In Standardized Measure) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Natural Gas And Oil Producing Activities [Abstract]
Standardized measure, beginning of year	$ 7,543	$ 3,736	$ 2,051
Sales and transfers of natural gas and oil produced, net of production costs	(1,082)	(2,084)	(1,774)
Net changes in prices and production costs	(8,075)	1,192	1,853
Extensions, discoveries, and other additions, net of future production and development costs	162	1,049	1,454
Acquisition of reserves in place	28	1,897	5
Sales of reserves in place	(244)
Revisions of previous quantity estimates	(1,385)	622	349
Accretion of discount	946	513	232
Net change in income taxes	1,915	(522)	(1,120)
Changes in estimated future development costs	2,007	110	(196)
Previously estimated development costs incurred during the year	875	815	223
Changes in production rates (timing) and other	(273)	215	659
Standardized measure, end of year	$ 2,417	$ 7,543	$ 3,736

XML

Derivatives And Risk Management (Narrative) (Details) ft³ in Billions	12 Months Ended
	Dec. 31, 2015 USD ($) ft³
2015 Fixed Price Swaps [Member]
Derivative [Line Items]
Volume of natural gas production	0
Accumulated other comprehensive income | $	$ 0
Interest Rate Swaps [Member]
Derivative [Line Items]
Notional amount | $	$ 170,000,000
Derivative, expiration	Jun. 30, 2020
Not Designated as Hedging Instrument [Member] | 2016 Basis Swaps [Member]
Derivative [Line Items]
Volume of natural gas production	5
Not Designated as Hedging Instrument [Member] | 2016 Fixed Price Call Options [Member]
Derivative [Line Items]
Volume of Natural Gas Production (in Bcf), Fixed Price Swaps Not Qualifying for Hedge Accounting Treatment	120

XML

Derivatives And Risk Management (Balance Sheet Classification Of Derivative Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets	$ 3	$ 339
Derivative liabilities	5	23
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		165
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		165
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	3	174
Derivative liabilities	5	23
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	3	9
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		1
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		4
Not Designated as Hedging Instrument [Member] | Basis Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		2
Not Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		163
Not Designated as Hedging Instrument [Member] | Fixed Price Call Options [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		2
Not Designated as Hedging Instrument [Member] | Fixed Price Call Options [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities		10
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Other Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets		1
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	3	3
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | Other Long-Term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 2	$ 2

XML

Derivatives And Risk Management (Summary Of Before Tax Effect Of Cash Flow Hedges On Consolidated Financial Statements) (Details) - Fixed Price Swaps [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain Recognized in Other Comprehensive Income (Effective Portion)	$ 45	$ 122
Gas Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Earnings (Effective Portion)	$ 209	$ (26)

XML

Derivatives And Risk Management (Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Basis Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Net of Settlement	$ (2)	$ (7)
Derivative Instrument, Gain (Loss) on Derivatives, Settled	(2)	12
Fixed Price Call Options [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Net of Settlement	13	18
Fixed Price Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Net of Settlement	(164)	126
Derivative Instrument, Gain (Loss) on Derivatives, Settled	208	(2)
Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instrument, Gain (Loss) on Derivatives, Net of Settlement	(2)	(7)
Derivative Instrument, Gain (Loss) on Derivatives, Settled	$ (4)	$ (1)

XML

Reclassifications From Accumulated Other Comprehensive Income (Components Of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2014	$ 62
Other comprehensive income (loss) before reclassifications	18
Amounts reclassified from/to other comprehensive income	(128)
Net current-period other comprehensive income (loss)	(110)	$ 66	$ (154)
Ending balance, December 31, 2015	(48)	62
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2014	98
Other comprehensive income (loss) before reclassifications	29
Amounts reclassified from/to other comprehensive income	(127)
Net current-period other comprehensive income (loss)	$ (98)
Ending balance, December 31, 2015		98
Pension And Other Postretirement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2014	$ (24)
Amounts reclassified from/to other comprehensive income	(1)
Net current-period other comprehensive income (loss)	(1)
Ending balance, December 31, 2015	(25)	(24)
Foreign Currency [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, December 31, 2014	(12)
Other comprehensive income (loss) before reclassifications	(11)
Net current-period other comprehensive income (loss)	(11)
Ending balance, December 31, 2015	$ (23)	$ (12)

XML

Reclassifications From Accumulated Other Comprehensive Income (Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Gas sales		$ 1,946	$ 2,827	$ 2,381
Gain (loss) on derivatives		47	139	26
Net actuarial loss	[1]	(3)	(15)	11
General and administrative expenses		246	221	191
Provision (benefit) for income taxes		(2,005)	525	486
Net Income (Loss)		(4,556)	$ 924	$ 704
Reclassification from/to Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss)		(128)
Cash Flow Hedges [Member] | Reclassification from/to Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Provision (benefit) for income taxes		(81)
Net Income (Loss)		(127)
Cash Flow Hedges [Member] | Reclassification from/to Accumulated Other Comprehensive Income [Member] | Settlements [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Gas sales		(209)
Cash Flow Hedges [Member] | Reclassification from/to Accumulated Other Comprehensive Income [Member] | Ineffectiveness [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Gain (loss) on derivatives		1
Pension And Other Postretirement [Member] | Reclassification from/to Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net actuarial loss		(3)
General and administrative expenses		2
Net Income (Loss)		$ (1)

[1] Net of $0, ($10), and $8 million in taxes for the years ended December 31, 2015, 2014 and 2013, respectively.

XML

Fair Value Measurements (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, net	$ (2)	$ 316
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	15	53
Credit facility	116	300
Derivative instruments, net	(2)	316
Carrying Amount [Member] | Bridge Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans		4,500
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	15	53
Credit facility	116	300
Derivative instruments, net	(2)	316
Fair Value [Member] | Bridge Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans		4,500
Unsecured Debt [Member] | Carrying Amount [Member] | Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	750	500
Unsecured Debt [Member] | Fair Value [Member] | Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loans	750	500
Senior Notes [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	3,863	1,667
Senior Notes [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	$ 2,672	$ 1,751

XML

Fair Value Measurements (Summary Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	$ (2)	$ 316
Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	(5)	324
Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	3	(8)
Fixed Price Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		328
Fixed Price Swaps [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		328
Interest Rate Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		1
Derivative liabilities	(5)	(5)
Interest Rate Swaps [Member] | Significant Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		1
Derivative liabilities	(5)	(5)
Basis Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	10
Derivative liabilities		(6)
Basis Swaps [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 3	10
Derivative liabilities		(6)
Fixed Price Call Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		(12)
Fixed Price Call Options [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities		$ (12)

XML

Fair Value Measurements (Reconciliations For Change In Net Fair Value Of Derivative Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value Measurements [Abstract]
Balance at beginning of year	$ (8)	$ (19)
Included in earnings	$ 9	$ 23
Purchases, issuances, and settlements:
Purchases
Issuances
Settlements	$ 2	$ (12)
Transfers into/out of Level 3
Balance at end of year	$ 3	$ (8)
Change in gains (losses) included in earnings relating to derivatives still held as of December 31	$ 11	$ 11

XML

Debt (Narrative) (Details)		1 Months Ended				12 Months Ended
	Dec. 19, 2014 USD ($)	Feb. 29, 2016	Nov. 30, 2015 USD ($)	Apr. 30, 2015 USD ($)	Jan. 31, 2015 USD ($)	Dec. 31, 2015 USD ($) item	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Debt issuance costs					$ 47,000,000
Adjusted debt capital structure, percentage						38.00%
Adjusted equity capital structure, percentage						62.00%
Unsecured Debt [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 2,000,000,000
Commercial paper						$ 0
Unsecured Debt [Member] | Commercial Paper [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, term				397 days
Unsecured Debt [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Unsecured revolving credit facility, borrowing capacity						$ 2,000,000,000
Credit facility, maturity date						Dec. 01, 2018
Number of extension options | item						2
Extension term						1 year
Unsecured revolving credit facility, increase in current borrowing capacity potential						$ 500,000,000
Unsecured Debt [Member] | Credit Facility [Member] | Over LIBOR [Member]
Debt Instrument [Line Items]
Basis points						1.50%	1.375%
Unsecured Debt [Member] | Credit Facility [Member] | Over LIBOR [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Basis points		2.00%
Senior Notes [Member]
Debt Instrument [Line Items]
Proceeds from issuance of debt					2,200,000,000	$ 2,200,000,000
Senior Notes [Member] | Over LIBOR [Member]
Debt Instrument [Line Items]
Incremental increase on basis points						0.25%
Senior Notes [Member] | Over LIBOR [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Increase in basis spread		1.25%
Bridge Loan [Member]
Debt Instrument [Line Items]
Debt instrument, term	364 days						364 days
Maturity date, month and year							2015-12
Bridge loan	$ 4,500,000,000						$ 4,500,000,000
Debt issuance costs					47,000,000
Repayment of debt					4,500,000,000
Commercial Paper And Revolving Credit Facility [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 2,000,000,000
3.3% Senior Notes due January 2018 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes					$ 350,000,000	$ 350,000,000
Stated interest rate					3.30%	3.30%
Maturity date, month and year					2018-01	2018-01
Percentage of face amount, sold to public					99.949%
4.05% Senior Notes due January 2020 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes					$ 850,000,000	$ 850,000,000
Stated interest rate					4.05%	4.05%
Maturity date, month and year					2020-01	2020-01
Percentage of face amount, sold to public					99.897%
4.95% Senior Notes due January 2025 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes					$ 1,000,000,000	$ 1,000,000,000
Stated interest rate					4.95%	4.95%
Maturity date, month and year					2025-01	2025-01
Percentage of face amount, sold to public					99.782%
1.775% Term Loan due November 2018 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt instrument, term			3 years
Maturity date, month and year						2018-11
Loans payable			$ 750,000,000			$ 750,000,000
1.775% Term Loan due November 2018 [Member] | Unsecured Debt [Member] | Over LIBOR [Member]
Debt Instrument [Line Items]
Basis points						1.375%
1.775% Term Loan due November 2018 [Member] | Unsecured Debt [Member] | Over LIBOR [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Basis points		1.625%
Revolving Credit Facility And Term Loan Facility [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt percentage of adjusted book capital structure covenant						60.00%
1.545% Term Loan due December 2016 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt instrument, term							2 years
Maturity date, month and year							2016-12
Loans payable							$ 500,000,000
Common Stock [Member]
Debt Instrument [Line Items]
Proceeds from issuance of shares					$ 669,000,000
Depositary Shares [Member]
Debt Instrument [Line Items]
Proceeds from issuance of shares					$ 1,700,000,000

XML

Debt (Components Of Debt) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Nov. 30, 2015	Dec. 19, 2014
Debt Instrument [Line Items]
Total short-term debt		$ 1	$ 4,501
Long-term debt		4,728	2,466
Total debt		4,729	6,967
Senior Notes [Member] | 7.15% Senior Notes due May 2018 [Member]
Debt Instrument [Line Items]
Senior notes		$ 1	1
Stated interest rate		7.15%
Maturity date, month and year		2018-05
Bridge Loan [Member]
Debt Instrument [Line Items]
Variable rate (1.515% at December 31, 2014) bridge facility, due December 2015			$ 4,500		$ 4,500
Maturity date, month and year			2015-12
Variable interest rate			1.515%
Senior Notes [Member] | 7.35% Senior Notes due October 2017 [Member]
Debt Instrument [Line Items]
Senior notes		$ 15	$ 15
Stated interest rate		7.35%
Maturity date, month and year		2017-10
Senior Notes [Member] | 7.125% Senior Notes due October 2017 [Member]
Debt Instrument [Line Items]
Senior notes		$ 25	25
Stated interest rate		7.125%
Maturity date, month and year		2017-10
Senior Notes [Member] | 3.3% Senior Notes due January 2018 [Member]
Debt Instrument [Line Items]
Senior notes	$ 350	$ 350
Stated interest rate	3.30%	3.30%
Maturity date, month and year	2018-01	2018-01
Senior Notes [Member] | 7.5% Senior Notes due February 2018 [Member]
Debt Instrument [Line Items]
Senior notes		$ 600	600
Stated interest rate		7.50%
Maturity date, month and year		2018-02
Senior Notes [Member] | 7.15% Senior Notes due May 2018 [Member]
Debt Instrument [Line Items]
Senior notes		$ 26	27
Stated interest rate		7.15%
Maturity date, month and year		2018-05
Senior Notes [Member] | 4.05% Senior Notes due January 2020 [Member]
Debt Instrument [Line Items]
Senior notes	$ 850	$ 850
Unamortized discount		$ (1)
Stated interest rate	4.05%	4.05%
Maturity date, month and year	2020-01	2020-01
Senior Notes [Member] | 4.10% Senior Notes due March 2022 [Member]
Debt Instrument [Line Items]
Senior notes		$ 1,000	1,000
Unamortized discount		$ (1)	(1)
Stated interest rate		4.10%
Maturity date, month and year		2022-03
Senior Notes [Member] | 4.95% Senior Notes due January 2025 [Member]
Debt Instrument [Line Items]
Senior notes	$ 1,000	$ 1,000
Unamortized discount		$ (2)
Stated interest rate	4.95%	4.95%
Maturity date, month and year	2025-01	2025-01
Unsecured Debt [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Variable rate (1.886% and 1.515% at December 31, 2015 and December 31, 2014, respectively) credit facility, expires December 2018		$ 116	$ 300
Credit facility, variable interest rate		1.886%	1.515%
Credit facility, maturity date		Dec. 01, 2018
Unsecured Debt [Member] | 1.545% Term Loan due December 2016 [Member]
Debt Instrument [Line Items]
Variable rate term loan facility			$ 500
Maturity date, month and year			2016-12
Variable interest rate			1.545%
Unsecured Debt [Member] | 1.775% Term Loan due November 2018 [Member]
Debt Instrument [Line Items]
Variable rate term loan facility		$ 750		$ 750
Maturity date, month and year		2018-11
Variable interest rate		1.775%

XML

Debt (Schedule Of Long Term Debt Maturities) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Debt [Abstract]
2016	$ 1
2017	41
2018	1,841
2020	850
Thereafter	2,000
Total long-term debt maturities	$ 4,733

XML

Commitments And Contingencies (Details) a in Millions, CAD in Millions, ft³ in Billions		1 Months Ended				12 Months Ended
	Nov. 17, 2015 item	Sep. 30, 2015 plaintiff item	Jul. 31, 2013 USD ($)	Aug. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2015 USD ($) ft³	Dec. 31, 2015 CAD item	Dec. 31, 2015 USD ($) item	Mar. 31, 2010 CAD a
Commitments And Contingencies [Line Items]
Future demand transportation charges, 2016								$ 623,000,000
Future demand transportation charges, 2017								691,000,000
Future demand transportation charges, 2018								712,000,000
Future demand transportation charges, 2019								751,000,000
Future demand transportation charges, 2020								702,000,000
Future demand transportation charges, thereafter								5,402,000,000
Total future demand transportation charges due								8,900,000,000
Guarantee obligations relative to the firms transportation agreements and gathering project and services								960,000,000
Option to reduce obligation under transportation agreement						$ 100,000,000
Option to reduce volume obligation under transportation agreement | ft³						531
Lease expiration date						Dec. 31, 2027
Operating leases, future minimum payments, 2016								71,000,000
Operating leases, future minimum payments, 2017								64,000,000
Operating leases, future minimum payments, 2018								44,000,000
Operating leases, future minimum payments, 2019								38,000,000
Operating leases, future minimum payments, 2020								30,000,000
Operating leases, future minimum payments, thereafter								28,000,000
Litigation settlement, gross					$ 11,000,000
Litigation, portion of profits considered for disgorgement					$ 382,000,000
Actual damages recoverable by plaintiff per August 2011 judgement				$ 11,000,000
Disgorgement recoverable by plaintiff per August 2011 judgement				24,000,000
Prejudgement interest and attorney's fees recoverable by plaintiff per August 2011 judgement				$ 9,000,000
Disgorgement recoverable by plaintiff to be reversed			$ 24,000,000
Actual damages recoverable by plaintiff to be reversed			11,000,000
Litigation settlement upheld			$ 11,000,000
Indemnification liability								$ 0
Purchase Commitment [Member] | Access Capacity on Future Projects Concentration Risk [Member]
Commitments And Contingencies [Line Items]
Concentration percentage						38.00%
Arkansas Royalty Litigation [Member]
Commitments And Contingencies [Line Items]
Number of cases | item							3	3
Arkansas Royalty Litigation [Member] | Arkansas State Court 2010 and 2013 [Member]
Commitments And Contingencies [Line Items]
Number of cases | item							2	2
Arkansas Royalty Litigation [Member] | Federal Court 2014 [Member]
Commitments And Contingencies [Line Items]
Number of cases | item							1	1
Number of alternative damages theories presented | item	2
Loss contingency, range of possible loss, minimum								$ 100,000,000
Arkansas Royalty Litigation [Member] | Arkansas State Court 2015 [Member]
Commitments And Contingencies [Line Items]
Number of cases | item		3
Number of plaintiffs | plaintiff		248
Exploration and Production [Member] | Pressure Pumping Equipment [Member]
Commitments And Contingencies [Line Items]
Number of leases | item							14	14
Aggregate annual lease payment								$ 8,000,000
Exploration and Production [Member] | Drilling Rigs [Member]
Commitments And Contingencies [Line Items]
Number of leases | item							7	7
Lease expiration date						Dec. 31, 2020
Aggregate annual lease payment								$ 13,000,000
Exploration and Production [Member] | Maximum [Member] | Pressure Pumping Equipment [Member]
Commitments And Contingencies [Line Items]
Lease expiration date						Mar. 01, 2018
Exploration and Production [Member] | Minimum [Member] | Pressure Pumping Equipment [Member]
Commitments And Contingencies [Line Items]
Lease expiration date						Dec. 01, 2017
Midstream Services and E&P [Member]
Commitments And Contingencies [Line Items]
Operating leases, future minimum payments, 2016								21,000,000
Operating leases, future minimum payments, 2017								14,000,000
Operating leases, future minimum payments, 2018								8,000,000
Operating leases, future minimum payments, 2019								5,000,000
Operating leases, future minimum payments, 2020								1,000,000
Exploration Program in Canada [Member]
Commitments And Contingencies [Line Items]
Investment in New Brunswick towards Company's commitment							CAD 45	$ 44,000,000
Unrecorded capital investments obligation, Exploration program acres coverage (acres) | a									2.5
Unrecorded capital investments obligation | CAD									CAD 47
Unrecorded promissory note payable | CAD									CAD 45

XML

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Effective tax rate of provision for income taxes	31.00%	36.00%	41.00%
Cash paid for income taxes	$ (6,000,000)	$ 28,000,000	$ 19,000,000
Net operating loss carryforward	445,000,000	323,000,000
Alternative minimum tax credit carryforward	125,000,000	131,000,000
Statutory depletion carryforward	13,000,000
Increase in valuation allowance	488,000,000
Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets	149,000,000
Unrecognized tax benefits related to alternative minimum tax	37,000,000	44,000,000
Accrued liability of interest related to uncertain tax position	2,000,000
Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforward	51,000,000
State [Member]
Income Taxes [Line Items]
Cash paid for income taxes		14,000,000
Net operating loss carryforward	789,000,000
Federal [Member]
Income Taxes [Line Items]
Cash paid for income taxes	0	$ 14,000,000
Net operating loss carryforward	$ 1,278,000,000
Minimum [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	Jan. 01, 2028
Minimum [Member] | Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	Jan. 01, 2030
Maximum [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	Dec. 31, 2035
Maximum [Member] | Exploration Program in Canada [Member]
Income Taxes [Line Items]
Net operating loss carryforwards expiration date	Dec. 31, 2035
Maximum [Member] | State [Member]
Income Taxes [Line Items]
Cash paid for income taxes	$ 1,000,000

XML

Income Taxes (Provision (Benefit) For Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	$ 1	$ 11	$ (12)
State	(3)	10	1
Total	(2)	21	(11)
Deferred:
Federal	(1,697)	501	408
State	(304)	2	88
Foreign	(2)	1	1
Total	(2,003)	504	497
Provision (Benefit) for Income Taxes	$ (2,005)	$ 525	$ 486

XML

Income Taxes (Reconciliation Of Provision (Benefit) For Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Abstract]
Expected provision (benefit) at federal statutory rate	$ (2,296)	$ 507	$ 417
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect	(194)	58	53
Nondeductible expenses		3	3
State rate redetermination		(48)	4
Change in valuation allowance	488	5
Other	(3)		9
Provision (Benefit) for Income Taxes	$ (2,005)	$ 525	$ 486

XML

Income Taxes (Components Of Deferred Tax Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred tax liabilities:
Differences between book and tax basis of property	$ 216	$ 2,504
Derivative activity		122
Other	9	21
Total deferred tax liabilities	225	2,647
Deferred tax assets
Accrued compensation	28	23
Alternative minimum tax credit carryforward	125	131
Accrued pension costs	19	17
Asset retirement obligations	77	79
Net operating loss carryforward	445	323
Other	24	19
Total deferred tax assets	718	592
Valuation allowance	$ (493)	(5)
Net deferred tax liability		$ 2,060

XML

Income Taxes (Reconciliation Of Beginning And Ending Balances Of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Abstract]
Unrecognized tax benefits at beginning of period	$ 44
Additions based on tax positions related to the current year	7	$ 15
Additions to tax positions of prior years		$ 29
Reductions to tax positions of prior years	(14)
Unrecognized tax benefits at end of period	$ 37	$ 44

XML

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Line Items]
Asset retirement obligation at January 1	$ 207	$ 134
Accretion of discount	11	7
Obligations incurred	17	64
Obligations settled/removed	(30)	(4)
Revisions of estimates	(4)	6
Asset retirement obligation at December 31	201	207
Current liability	10	9
Long-term liability	191	198
Chesapeake Property Acquisition [Member]
Asset Retirement Obligations [Line Items]
Obligations incurred		$ 42
Asset Divestitures [Member]
Asset Retirement Obligations [Line Items]
Obligations settled/removed	$ (25)

XML

Retirement And Employee Benefit Plans (Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Contribution expense		$ 3.0	$ 3.0	$ 3.0
Contributions capitalized		4.0	3.0	3.0
Change in accumulated other comprehensive income (loss) after tax		1.0	15.0	(12.0)
Current period net gain (loss)	[1]	(3.0)	(15.0)	$ 11.0
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Change in accumulated other comprehensive income (loss)		2.0	23.0
Change in accumulated other comprehensive income (loss) after tax		2.0	14.0
Current period net gain (loss)		(4.0)
Net loss		(2.0)
Employer contributions		12.0
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Change in accumulated other comprehensive income (loss)		(1.0)	2.0
Change in accumulated other comprehensive income (loss) after tax		(1.0)	1.0
Current period net gain (loss)		1.0
Employer contributions		0.2
United States Postretirement Benefit Plan of US Entity, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan included in accumulated other comprehensive income (loss)		(42.0)	(41.0)
Defined benefit plan included in accumulated other comprehensive income (loss) after tax		$ (25.0)	$ (24.0)

[1] Net of $0, ($10), and $8 million in taxes for the years ended December 31, 2015, 2014 and 2013, respectively.

XML

Retirement And Employee Benefit Plans (Changes In The Plans Benefit Obligations, Fair Value Of Assets, And Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 16.0	$ 13.0	$ 14.0
Interest cost	6.0	5.0	4.0
Employer contributions	12.0
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	3.0	2.0	2.0
Interest cost	1.0	1.0	1.0
Employer contributions	0.2
Change In Benefit Obligation [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at January 1	134.0	103.0
Service cost	16.0	13.0
Interest cost	6.0	5.0
Actuarial loss	(7.0)	21.0
Benefits paid	(11.0)	(8.0)
Benefit obligation at December 31	138.0	134.0	103.0
Change In Benefit Obligation [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at January 1	18.0	12.0
Service cost	3.0	2.0
Interest cost	1.0	1.0
Actuarial loss	(2.0)	3.0
Benefit obligation at December 31	20.0	18.0	12.0
Change In Plan Assets [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	108.0	99.0
Employer contributions	12.0	12.0
Benefits paid	(11.0)	(8.0)
Actual return on plan assets	(1.0)	5.0
Fair value of plan assets at December 31	108.0	108.0	$ 99.0
Funded status of plans at December 31	(30.0)	(26.0)
Change In Plan Assets [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Funded status of plans at December 31	$ (20.0)	$ (18.0)

XML

Retirement And Employee Benefit Plans (Projected Benefit Obligation, Accumulated Benefit Obligation And Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Retirement And Employee Benefit Plans [Abstract]
Projected benefit obligation	$ 138	$ 134
Accumulated benefit obligation	135	129
Fair value of plan assets	$ 108	$ 108

XML

Retirement And Employee Benefit Plans (Pension And Other Postretirement Benefit Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 16	$ 13	$ 14
Interest cost	6	5	4
Expected return on plan assets	$ (9)	$ (7)	$ (6)
Amortization of transition obligation
Amortization of prior service cost
Amortization of net loss	$ 2	$ 1	$ 2
Net periodic benefit cost	15	12	14
Total benefit cost	15	12	14
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	3	2	2
Interest cost	$ 1	$ 1	$ 1
Amortization of transition obligation
Amortization of prior service cost
Net periodic benefit cost	$ 4	$ 3	$ 3
Total benefit cost	$ 4	$ 3	$ 3

XML

Retirement And Employee Benefit Plans (Amounts Recognized In Other Comprehensive Income) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Current period net gain (loss)	[1]	$ (3)	$ (15)	$ 11
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Current period net gain (loss)		$ (4)
Amortization of prior service cost
Amortization of net loss		$ 2
Settlements
Total		$ (2)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Current period net gain (loss)		$ 1
Amortization of prior service cost
Amortization of net loss
Settlements
Total		$ 1

[1] Net of $0, ($10), and $8 million in taxes for the years ended December 31, 2015, 2014 and 2013, respectively.

XML

Retirement And Employee Benefit Plans (Schedule Of Assumptions Used - Benefit Obligations) (Details)	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.60%	4.25%
Rate of compensation increase	3.50%	4.50%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.60%	4.25%

XML

Retirement And Employee Benefit Plans (Schedule Of Assumptions Used - Benefit Obligations - Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	5.00%	4.00%
Expected return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	4.50%	4.50%	4.50%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	5.00%	4.00%

XML

Retirement And Employee Benefit Plans (Schedule Of Health Care Cost Trend Rates) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Retirement And Employee Benefit Plans [Abstract]
Health care cost trend assumed for next year	8.00%	8.00%
Rate to which the cost trend is assumed to decline	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2034	2033

XML

Retirement And Employee Benefit Plans (One Percentage Point Change In Assumed Health Care Cost Trend Rates) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Retirement And Employee Benefit Plans [Abstract]
Effect on total service and interest cost components increase	$ 1
Effect on total service and interest cost components decrease	(1)
Effect on postretirement benefit obligations increase	3
Effect on postretirement benefit obligation decrease	$ (2)

XML

Retirement And Employee Benefit Plans (Schedule Of Expected Benefit Payments) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	$ 8
2017	9
2018	10
2019	11
2020	10
Years 2021-2025	67
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	1
2017	1
2018	1
2019	1
2020	2
Years 2021-2025	$ 11

XML

Retirement And Employee Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) - Pension Benefits [Member]	12 Months Ended
	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	100.00%
Actual asset allocations	100.00%
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	28.00%
Actual asset allocations	28.00%
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	2.00%
Actual asset allocations	2.00%
U.S. Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	35.00%
Actual asset allocations	36.00%
Non-U.S. Developed Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	30.00%
Actual asset allocations	29.00%
Emerging Market Equity [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocations	5.00%
Actual asset allocations	5.00%

XML

Retirement And Employee Benefit Plans (Fair Value Measurement Of Pension Plan Assets) (Details) - Pension Benefits [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 108	$ 108
Equity Securities [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	59	58
Equity Securities [Member] | Significant Observable Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	49	50
Equity Securities [Member] | Large Cap Growth Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	8
Equity Securities [Member] | Large Cap Growth Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	8
Equity Securities [Member] | Large Cap Value Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	9
Equity Securities [Member] | Large Cap Value Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	9
Equity Securities [Member] | Large Cap Core Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18	19
Equity Securities [Member] | Large Cap Core Equity [Member] | Significant Observable Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18	19
Equity Securities [Member] | Small Cap Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	3
Equity Securities [Member] | Small Cap Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	3
Equity Securities [Member] | Non-U.S. Developed Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31	29
Equity Securities [Member] | Non-U.S. Developed Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31	29
Equity Securities [Member] | Emerging Market Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	5
Equity Securities [Member] | Emerging Market Equity [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	5
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31	31
Fixed Income [Member] | Significant Observable Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31	31
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2	4
Cash and Cash Equivalents [Member] | Quoted Prices in Active Markets for Identical Assets, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 2	$ 4

XML

Stock-Based Compensation (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period of service for immediate vesting upon death, disability or retirement	3 years
2004 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	16,800,000
Expiration period from date of grant	7 years
2013 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period from date of grant	7 years
2002 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	300,000
Expiration period from date of grant	10 years
2000 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	1,250,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years
Deferred tax asset (liability) recorded	$ 2,000,000	$ 3,000,000	$ 4,000,000
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units	$ 13,000,000
Weighted average period over which cost is recognized, years	2 years
Weighted-average grant-date fair value of options granted	$ 3.16	$ 10.16	$ 13.39
Stock options, exercised, number of options	0	402,000	833,000
Intrinsic value		$ 4,000,000	$ 22,000,000
Stock-based compensation costs - expensed	$ 5,000,000	5,000,000	5,000,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	4 years
Deferred tax asset (liability) recorded	$ 11,000,000	(10,000,000)	(15,000,000)
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units	$ 88,000,000
Weighted average period over which cost is recognized, restricted stock (years)	3 years
Total fair value of restricted stock grants	$ 47,000,000	40,000,000	43,000,000
Total fair value of shares vested	29,000,000	20,000,000	14,000,000
Stock-based compensation costs - expensed	$ 14,000,000	10,000,000	7,000,000
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for stock awards from grant date	3 years
Stock-based compensation costs - expensed	$ 31,000,000	25,000,000	3,000,000
Performance unit liability recorded	8,000,000	51,000,000
Equity-Classified Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred tax asset (liability) recorded	4,000,000	2,000,000	$ 0
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units	$ 14,000,000
Weighted average period over which cost is recognized, years	2 years
Stock-based compensation costs - expensed	$ 6,000,000	$ 3,000,000
Maximum [Member] | 2013 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares	20,500,000

XML

Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Stock Options) (Details) - Stock Options [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-based compensation costs - expensed	$ 5	$ 5	$ 5
Stock-based compensation costs - capitalized	$ 3	$ 4	$ 5

XML

Stock-Based Compensation (Schedule Of Valuation Assumptions) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-Based Compensation [Abstract]
Risk-free interest rate	1.70%	1.60%	1.50%
Expected volatility	36.00%	32.50%	38.60%
Expected term	5 years	5 years	5 years

XML

Stock-Based Compensation (Summary Of Stock Option Activity) (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options, Outstanding at January 1, Number of Shares	3,622,000	3,313,000	3,650,000
Stock options, Granted, Number of Shares	2,401,000	835,000	571,000
Stock options, Exercised, Number of Shares	0	(402,000)	(833,000)
Stock options, Forfeited or expired, Number of Shares	(400,000)	(124,000)	(75,000)
Stock options, Outstanding at December 31, Number of Shares	5,623,000	3,622,000	3,313,000
Stock options, Outstanding at January 1, Weighted Average Exercise Price	$ 35.41	$ 35.70	$ 29.84
Stock options, Granted, Weighted Average Exercise Price	9.47	32.31	38.95
Stock options, Exercised, Weighted Average Exercise Price		30.60	12.12
Stock options, Forfeited or expired, Weighted Average Exercise Price	32.20	37.80	37.31
Stock options, Outstanding at December 31, Weighted Average Exercise Price	$ 24.57	$ 35.41	$ 35.70

XML

Stock-Based Compensation (Summary Of Stock Options Outstanding And Options Exercisable) (Details) - Stock Options [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Outstanding - Options Outstanding at December 31, 2015	5,623	3,622	3,313	3,650
Options Outstanding - Weighted Average Exercise Price	$ 24.57	$ 35.41	$ 35.70	$ 29.84
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	5 years 1 month 6 days
Options Exercisable - Options Exercisable at December 31, 2015	2,502
Options Exercisable - Weighted average exercise price	$ 36.39
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	3 years 4 months 24 days
Range of Exercise Prices $7.74-$29.69 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 7.74
Range of Exercise Prices, Upper Range Limit	$ 29.69
Options Outstanding - Options Outstanding at December 31, 2015	2,421
Options Outstanding - Weighted Average Exercise Price	$ 9.63
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	6 years 9 months 18 days
Options Exercisable - Options Exercisable at December 31, 2015	20
Options Exercisable - Weighted average exercise price	$ 28.46
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 9 months 18 days
Range of Exercise Prices $30.59-$35.91 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 30.59
Range of Exercise Prices, Upper Range Limit	$ 35.91
Options Outstanding - Options Outstanding at December 31, 2015	1,397
Options Outstanding - Weighted Average Exercise Price	$ 32.32
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	4 years 10 months 24 days
Options Exercisable - Options Exercisable at December 31, 2015	900
Options Exercisable - Weighted average exercise price	$ 33.27
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	4 years 3 months 18 days
Range of Exercise Prices $36.22-$39.68 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 36.22
Range of Exercise Prices, Upper Range Limit	$ 39.68
Options Outstanding - Options Outstanding at December 31, 2015	1,412
Options Outstanding - Weighted Average Exercise Price	$ 37.50
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	3 years 4 months 24 days
Options Exercisable - Options Exercisable at December 31, 2015	1,249
Options Exercisable - Weighted average exercise price	$ 37.31
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	3 years 2 months 12 days
Range of Exercise Prices $40.15-$51.47 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Lower Range Limit	$ 40.15
Range of Exercise Prices, Upper Range Limit	$ 51.47
Options Outstanding - Options Outstanding at December 31, 2015	393
Options Outstanding - Weighted Average Exercise Price	$ 42.58
Options Outstanding - Weighted Average Remaining Contractual Life (Years)	2 years
Options Exercisable - Options Exercisable at December 31, 2015	333
Options Exercisable - Weighted average exercise price	$ 41.86
Options Exercisable - Weighted Average Remaining Contractual Life (Years)	1 year 4 months 24 days

XML

Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Restricted Stock) (Details) - Restricted Stock [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-based compensation costs - expensed	$ 14	$ 10	$ 7
Stock-based compensation costs - capitalized	$ 16	$ 12	$ 7

XML

Stock-Based Compensation (Summary Of Restricted Stock Activity) (Details) - Restricted Stock [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares/units at January 1, Number of Shares	2,376	1,771	1,118
Granted, Number of Shares/Units	5,822	1,295	1,109
Vested, Number of Shares/Units	(873)	(548)	(382)
Forfeited, Number of Shares/Units	(103)	(142)	(74)
Unvested shares/units at December 31, Number of Shares	7,222	2,376	1,771
Unvested shares/units at January 1, Weighted Average Grant Date Fair Value	$ 34.00	$ 37.55	$ 35.64
Granted, Weighted Average Grant Date Fair Value	8.07	30.89	38.92
Vested, Weighted Average Grant Date Fair Value	33.33	37.12	36.29
Forfeited, Weighted Average Grant Date Fair Value	29.14	37.91	35.81
Unvested shares at December 31, Weighted Average Grant Date Fair Value	$ 13.24	$ 34.00	$ 37.55

XML

Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Equity-Classified Performance Units) (Details) - Equity-Classified Performance Units [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Stock-based compensation costs - expensed	$ 6	$ 3
Stock-based compensation costs - capitalized	$ 4	$ 2

XML

Stock-Based Compensation (Summary Of Equity-Classified Performance Units) (Details) - Equity-Classified Performance Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares/units at January 1, Number of Shares	223,000
Granted, Number of Shares/Units	443,000	359,000
Vested, Number of Shares/Units	(259,000)	(111,000)
Forfeited, Number of Shares/Units		(25,000)
Unvested shares/units at December 31, Number of Shares	407,000	223,000
Unvested shares/units at January 1, Weighted Average Grant Date Fair Value	$ 40.44
Granted, Weighted Average Grant Date Fair Value	35.22	$ 40.44
Vested, Weighted Average Grant Date Fair Value	37.46	40.44
Forfeited, Weighted Average Grant Date Fair Value		40.44
Unvested shares at December 31, Weighted Average Grant Date Fair Value	$ 36.65	$ 40.44
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Number of Shares/Units	0
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Number of Shares/Units	2

XML

Segment Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 687	$ 749	$ 764	$ 933	$ 962	$ 928	$ 1,035	$ 1,113	$ 3,133	$ 4,038	$ 3,371
Operating income (loss)	(2,561)	(2,842)	(1,284)	$ 165	285	$ 286	$ 367	$ 435	(6,522)	1,373	1,204
Other income (loss), net									(30)	(4)	2
Gain (loss) on derivatives									47	139	26
Depreciation, depletion and amortization expense									1,091	942	787
Impairment of natural gas and oil properties	2,600	$ 2,800	$ 1,500						6,950
Interest expense									56	59	42
Provision (benefit) for income taxes									(2,005)	525	486
Assets	8,110				14,925				8,110	14,925	8,048
Capital investments									2,437	7,447	2,235
Impairment of natural gas and oil properties									6,950
Change in accrued expenditures									(33)	155	(25)
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									(2,060)	(3,182)	(2,380)
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenues									2,095	2,850	2,398
Operating income (loss)									(7,104)	1,013	879
Other income (loss), net									(21)	(3)	3
Gain (loss) on derivatives									51	142	26
Depreciation, depletion and amortization expense									1,028	884	735
Impairment of natural gas and oil properties									6,950
Interest expense									47	47	30
Provision (benefit) for income taxes									(2,273)	402	368
Assets	6,588				13,018				6,588	13,018	6,357
Capital investments									2,258	7,254	2,052
Exploration and Production [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									21	(12)	(6)
Exploration and Production [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Assets	50				77				50	77	79
Capital investments									4	11	35
Midstream Services [Member]
Segment Reporting Information [Line Items]
Revenues									1,038	1,188	973
Operating income (loss)									583	361	325
Other income (loss), net									(9)	(1)
Gain (loss) on derivatives										(1)
Depreciation, depletion and amortization expense									62	58	51
Interest expense									9	12	11
Provision (benefit) for income taxes									268	123	119
Assets	1,290				1,554				1,290	1,554	1,427
Capital investments									167	144	158
Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									(2,081)	(3,170)	(2,374)
Other [Member]
Segment Reporting Information [Line Items]
Operating income (loss)									(1)	(1)
Other income (loss), net											(1)
Gain (loss) on derivatives									(4)	(2)
Depreciation, depletion and amortization expense									1		1
Interest expense											1
Provision (benefit) for income taxes											(1)
Assets	$ 232				$ 353				232	353	264
Capital investments									12	49	25
Marketing [Member] | Midstream Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues									$ (1,800)	$ (2,800)	$ (2,000)

XML

Quarterly Results (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Line Items]
Operating revenues	$ 687	$ 749	$ 764	$ 933	$ 962	$ 928	$ 1,035	$ 1,113	$ 3,133	$ 4,038	$ 3,371
Operating income (loss)	(2,561)	(2,842)	(1,284)	165	285	286	367	435	(6,522)	1,373	1,204
Net income (loss) attributable to common stock	$ (2,134)	$ (1,766)	$ (815)	$ 46	$ 312	$ 211	$ 207	$ 194	$ (4,662)	$ 924	$ 704
Earnings per share - Basic	$ (5.58)	$ (4.62)	$ (2.13)	$ 0.12	$ 0.89	$ 0.60	$ 0.59	$ 0.55	$ (12.25)	$ 2.63	$ 2.01
Earnings per share - Diluted	$ (5.58)	$ (4.62)	$ (2.13)	$ 0.12	$ 0.88	$ 0.60	$ 0.59	$ 0.55	$ (12.25)	$ 2.62	$ 2.00
Impairment of natural gas and oil properties	$ 2,600	$ 2,800	$ 1,500						$ 6,950
Series B Preferred Stock [Member]
Quarterly Financial Data [Line Items]
Mandatory convertible preferred participating securities				$ 7

XML

Subsequent Events (Details) - Subsequent Event [Member] - Scenario, Forecast [Member] $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Minimum [Member]
Subsequent Event [Line Items]
Severance costs	$ 60
Minimum [Member] | One-time Termination Benefits [Member]
Subsequent Event [Line Items]
Severance costs	45
Minimum [Member] | Elimination of Service Requirements for Equity Awards [Member]
Subsequent Event [Line Items]
Severance costs	15
Maximum [Member]
Subsequent Event [Line Items]
Severance costs	70
Maximum [Member] | One-time Termination Benefits [Member]
Subsequent Event [Line Items]
Severance costs	50
Maximum [Member] | Elimination of Service Requirements for Equity Awards [Member]
Subsequent Event [Line Items]
Severance costs	$ 20