SWN 2012 Q3 FORM 10-Q

 

 

 

 

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington,  D.C.  20549

 

 

 

 

 

 

 

Form 10-Q

 

 

 

 

(Mark One)

[X]   Quarterly Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the quarterly period ended September 30, 2012

 

 

 

 

Or

 

 

 

 

[  ] Transition Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the transition period from __________ to __________

 

 

 

 

Commission file number:  1-08246

 

 

Southwestern Energy Company

(Exact name of registrant as specified in its charter)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware 

71-0205415

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

 

 

 

 

2350 North Sam Houston Parkway East, Suite 125,  Houston,  Texas 

77032

(Address of principal executive offices)

(Zip Code)

 

 

 

 

(281) 618-4700

(Registrant’s telephone number, including area code)

 

 

 

 

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yesx     No o

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).  Yesx  No o

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 x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o     No x 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Class

Outstanding as of October 26, 2012

Common Stock, Par Value $0.01

350,353,301

 

 


 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY

 

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2012

 

 

 

PART I – FINANCIAL INFORMATION

 

 

 

 

Item 1. 

Financial Statements

Item 2. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

31 

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

40 

Item 4. 

Controls and Procedures

42 

 

 

 

PART II – OTHER INFORMATION

 

 

 

 

Item 1. 

Legal Proceedings

43 

Item 1A. 

Risk Factors

44 

Item 2. 

Unregistered Sales of Equity Securities and Use of Proceeds

45 

Item 3. 

Defaults Upon Senior Securities

45 

Item 4. 

Mine Safety Disclosures

45 

Item 5. 

Other Information

45 

Item 6. 

Exhibits

45 

 

 

 

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

 

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

 

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

 

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

 

·

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

·

our ability to fund our planned capital investments;

·

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

·

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

1


 

 

·

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

·

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

·

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

·

our ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and Marcellus Shale play;

·

our future property acquisition or divestiture activities;

·

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

·

the effects of weather;

·

increased competition and regulation;

·

the financial impact of accounting regulations and critical accounting policies;

·

the comparative cost of alternative fuels;

·

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

·

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

·

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

 

We caution you that forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, third-party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto, including this Form 10-Q (“Form 10-Qs”).

 

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

 

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

2


 

 

PART I – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS.

 

 

 

 

 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended

 

For the nine months ended

 

September 30,

 

September 30,

 

2012

 

2011

 

2012

 

2011

 

(in thousands, except share/per share amounts)

Operating Revenues:

 

 

 

 

 

 

 

 

 

 

 

Gas sales

$

491,340 

 

$

551,770 

 

$

1,384,152 

 

$

1,544,165 

Gas marketing

 

148,764 

 

 

176,787 

 

 

423,503 

 

 

549,243 

Oil sales

 

1,889 

 

 

2,157 

 

 

6,097 

 

 

7,387 

Gas gathering

 

43,855 

 

 

36,541 

 

 

128,293 

 

 

107,961 

 

 

685,848 

 

 

767,255 

 

 

1,942,045 

 

 

2,208,756 

Operating Costs and Expenses:

 

 

 

 

 

 

 

 

 

 

 

Gas purchases – midstream services

 

149,651 

 

 

175,236 

 

 

423,941 

 

 

545,518 

Operating expenses

 

61,906 

 

 

63,911 

 

 

179,478 

 

 

175,763 

General and administrative expenses

 

36,121 

 

 

35,600 

 

 

129,879 

 

 

112,955 

Depreciation, depletion and amortization

 

200,655 

 

 

179,113 

 

 

602,112 

 

 

514,180 

Impairment of natural gas and oil properties

 

441,465 

 

 

–  

 

 

1,377,364 

 

 

–  

Taxes, other than income taxes

 

16,252 

 

 

17,677 

 

 

51,154 

 

 

49,429 

 

 

906,050 

 

 

471,537 

 

 

2,763,928 

 

 

1,397,845 

Operating Income (Loss)

 

(220,202)

 

 

295,718 

 

 

(821,883)

 

 

810,911 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

Interest on debt

 

25,463 

 

 

16,696 

 

 

69,154 

 

 

48,380 

Other interest charges

 

1,058 

 

 

902 

 

 

3,096 

 

 

3,414 

Interest capitalized

 

(15,915)

 

 

(11,941)

 

 

(45,945)

 

 

(32,531)

 

 

10,606 

 

 

5,657 

 

 

26,305 

 

 

19,263 

 

 

 

 

 

 

 

 

 

 

 

 

Other Income (Loss), Net

 

238 

 

 

(122)

 

 

2,615 

 

 

321 

 

 

 

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 

(230,570)

 

 

289,939 

 

 

(845,573)

 

 

791,969 

Provision (Benefit) for Income Taxes:

 

 

 

 

 

 

 

 

 

 

 

Current

 

101 

 

 

3,491 

 

 

369 

 

 

3,691 

Deferred

 

(85,856)

 

 

111,275 

 

 

(320,731)

 

 

309,042 

 

 

(85,755)

 

 

114,766 

 

 

(320,362)

 

 

312,733 

Net Income (Loss)

$

(144,815)

 

$

175,173 

 

$

(525,211)

 

$

479,236 

 

 

 

 

 

 

 

 

   

 

 

   

Earnings (Loss) Per Share:

 

 

 

 

 

 

 

 

 

 

 

Basic

$

(0.42)

 

$

0.50 

 

$

(1.51)

 

$

1.38 

Diluted

$

(0.42)

 

$

0.50 

 

$

(1.51)

 

$

1.37 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

348,649,630 

 

 

347,239,793 

 

 

348,272,192 

 

 

347,070,330 

Diluted

 

348,649,630 

 

 

349,998,789 

 

 

348,272,192 

 

 

349,891,885 

See the accompanying notes which are an integral part of these

unaudited condensed consolidated financial statements.

3


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended

 

 

For the nine months ended

 

 

September 30,

 

 

September 30,

 

 

2012

 

 

2011

 

 

2012

 

 

2011

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Net income  (loss)

$

(144,815)

 

$

175,173 

 

$

(525,211)

 

$

479,236 

 

 

 

 

 

 

 

 

 

 

 

 

Change in derivatives:

 

 

 

 

 

 

 

 

 

 

 

Reclassification to earnings (1) 

 

(94,996)

 

 

(49,436)

 

 

(310,882)

 

 

(113,850)

Ineffectiveness (2)

 

322 

 

 

1,574 

 

 

(1,215)

 

 

307 

Change in fair value of derivative instruments (3)

 

(36,468)

 

 

170,251 

 

 

93,985 

 

 

259,559 

Total change in derivatives

 

(131,142)

 

 

122,389 

 

 

(218,112)

 

 

146,016 

 

 

 

 

 

 

 

 

 

 

 

 

Change in value of pension and other postretirement liabilities:

 

 

 

 

 

 

 

 

 

 

 

Amortization of prior service cost included in net periodic pension cost (4)

 

254 

 

 

197 

 

 

762 

 

 

590 

 

 

 

 

 

 

 

 

 

 

 

 

Change in currency translation adjustment

 

997 

 

 

(1,219)

 

 

962 

 

 

(831)

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income  (loss)

$

(274,706)

 

$

296,540 

 

$

(741,599)

 

$

625,011 

 

 

(1)

Net of $(62.2),  $(31.6),  $(202.6) and $(72.8) million in taxes for the three months ended September 30, 2012 and 2011, and the nine months ended September 30, 2012 and 2011, respectively.

 

(2)

Net of $0.2,  $1.0, $(0.8) and $0.2 million in taxes for the three months ended September 30, 2012 and 2011, and the nine months ended September 30, 2012 and 2011, respectively.

 

(3)

Net of $ (22.1),  $108.8,  $62.7 and $165.9 million in taxes for the three months ended September 30, 2012 and 2011, and the nine months ended September 30, 2012 and 2011, respectively.

 

(4)

Net of $0.2,$0.2, $0.5 and $0.4 million in taxes for the three months ended September 30, 2012 and 2011, and the nine months ended September 30, 2012 and 2011, respectively.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See the accompanying notes which are an integral part of these

unaudited condensed consolidated financial statements.

4


 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

 

 

 

September 30,

 

 

December 31,

 

 

2012

 

 

2011

ASSETS

 

(in thousands)

Current assets:

 

 

 

 

 

Cash and cash equivalents

$

18,560 

 

$

15,627 

Restricted cash

 

127,074 

 

 

–  

Accounts receivable

 

297,773 

 

 

341,915 

Inventories

 

30,630 

 

 

46,234 

Hedging asset

 

300,861 

 

 

514,465 

Other

 

71,849 

 

 

60,037 

Total current assets

 

846,747 

 

 

978,278 

Natural gas and oil properties, using the full cost method, including $1,130.4 million in 2012 and $942.9 million in 2011 excluded from amortization

 

10,855,274 

 

 

9,544,708 

Gathering systems

 

1,087,139 

 

 

980,647 

Other

 

564,490 

 

 

535,464 

Less: Accumulated depreciation, depletion and amortization

 

(6,414,955)

 

 

(4,415,339)

Total property and equipment, net

 

6,091,948 

 

 

6,645,480 

Other assets

 

134,256 

 

 

279,139 

TOTAL ASSETS

$

7,072,951 

 

$

7,902,897 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

$

468,646 

 

$

514,071 

Taxes payable

 

36,902 

 

 

40,691 

Interest payable

 

14,232 

 

 

20,565 

Advances from partners

 

110,237 

 

 

84,082 

Current deferred income taxes

 

116,463 

 

 

194,163 

Other

 

14,685 

 

 

31,341 

Total current liabilities

 

761,165 

 

 

884,913 

Long-term debt

 

1,695,342 

 

 

1,342,100 

Deferred income taxes

 

1,203,703 

 

 

1,586,798 

Pension and other postretirement liabilities

 

18,141 

 

 

20,338 

Other long-term liabilities

 

141,321 

 

 

99,444 

Total long-term liabilities

 

3,058,507 

 

 

3,048,680 

Commitments and contingencies (Note 10)

 

 

 

 

 

Equity:

 

 

 

 

 

Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 350,415,917 shares in 2012 and 349,058,501 in 2011

 

3,504 

 

 

3,491 

Additional paid-in capital

 

928,322 

 

 

903,399 

Retained earnings

 

2,131,003 

 

 

2,656,214 

Accumulated other comprehensive income

 

192,040 

 

 

408,428 

Common stock in treasury, 66,791 shares in 2012 and 98,889 in 2011

 

(1,590)

 

 

(2,228)

Total equity

 

3,253,279 

 

 

3,969,304 

TOTAL LIABILITIES AND EQUITY

$

7,072,951 

 

$

7,902,897 

 

 

 

 

 

 

See the accompanying notes which are an integral part of these

unaudited condensed consolidated financial statements.

 

5


 

 

 

 

 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

 

 

 

 

For the nine months ended

 

 

September 30,

 

 

2012

 

 

2011

 

 

(in thousands)

Cash Flows From Operating Activities

 

 

 

 

 

Net income (loss)

$

(525,211)

 

$

479,236 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

604,887 

 

 

516,891 

Impairment of natural gas and oil properties

 

1,377,364 

 

 

–  

Deferred income taxes

 

(320,731)

 

 

309,042 

Unrealized gain on derivatives

 

(2,890)

 

 

905 

Stock-based compensation

 

8,226 

 

 

6,619 

Other

 

312 

 

 

(353)

Change in assets and liabilities:

 

 

 

 

 

Accounts receivable

 

44,148 

 

 

4,664 

Inventories

 

16,608 

 

 

(5,993)

Accounts payable

 

(11,050)

 

 

1,539 

Taxes payable

 

(3,789)

 

 

(21,165)

Interest payable

 

(2,306)

 

 

(9,365)

Advances from partners

 

26,155 

 

 

14,568 

Other assets and liabilities

 

(19,246)

 

 

3,623 

Net cash provided by operating activities

 

1,192,477 

 

 

1,300,211 

 

 

 

 

 

 

Cash Flows From Investing Activities

 

 

 

 

 

Capital investments

 

(1,623,751)

 

 

(1,543,549)

Proceeds from sale of property and equipment

 

201,161 

 

 

121,546 

Transfers to restricted cash

 

(167,774)

 

 

(85,040)

Transfers from restricted cash

 

40,700 

 

 

15,779 

Other

 

5,239 

 

 

4,940 

Net cash used in investing activities

 

(1,544,425)

 

 

(1,486,324)

 

 

 

 

 

 

Cash Flows From Financing Activities

 

 

 

 

 

Payments on current portion of long-term debt

 

(600)

 

 

(600)

Payments on revolving long-term debt

 

(1,774,000)

 

 

(2,575,000)

Borrowings under revolving long-term debt

 

1,129,000 

 

 

2,753,600 

Change in bank drafts outstanding

 

1,627 

 

 

10,621 

Proceeds from issuance of long-term debt

 

998,780 

 

 

–  

Debt issuance costs

 

(8,338)

 

 

–  

Revolving credit facility costs

 

–  

 

 

(10,211)

Proceeds from exercise of common stock options

 

8,422 

 

 

4,844 

Net cash provided by financing activities

 

354,891 

 

 

183,254 

 

 

 

 

 

 

Effect of exchange rate changes on cash

 

(10)

 

 

97 

Increase (decrease) in cash and cash equivalents

 

2,933 

 

 

(2,762)

Cash and cash equivalents at beginning of year

 

15,627 

 

 

16,055 

Cash and cash equivalents at end of period

$

18,560 

 

$

13,293 

 

See the accompanying notes which are an integral part of

these unaudited condensed consolidated financial statements.

6


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

Common Stock

 

Additional

 

 

 

 

Other

 

Common

 

 

 

 

Shares

 

 

 

 

Paid-In

 

Retained

 

Comprehensive

 

Stock in

 

 

 

 

Issued

 

Amount

 

Capital

 

Earnings

 

Income (Loss)

 

Treasury

 

Total

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2011

349,059 

 

$

3,491 

 

$

903,399 

 

$

2,656,214 

 

$

408,428 

 

$

(2,228)

 

$

3,969,304 

Comprehensive loss:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

–  

 

 

–  

 

 

–  

 

 

(525,211)

 

 

–  

 

 

–  

 

 

(525,211)

Other comprehensive loss

–  

 

 

–  

 

 

–  

 

 

–  

 

 

(216,388)

 

 

–  

 

 

(216,388)

Total comprehensive loss

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

(741,599)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

–  

 

 

–  

 

 

16,014 

 

 

–  

 

 

–  

 

 

–  

 

 

16,014 

Exercise of stock options

1,422 

 

 

14 

 

 

8,408 

 

 

–  

 

 

–  

 

 

–  

 

 

8,422 

Issuance of restricted stock

12 

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Cancellation of restricted stock

(77)

 

 

(1)

 

 

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Treasury stock – non-qualified plan

–  

 

 

–  

 

 

500 

 

 

–  

 

 

–  

 

 

638 

 

 

1,138 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at September 30, 2012

350,416 

 

$

3,504 

 

$

928,322 

 

$

2,131,003 

 

$

192,040 

 

$

(1,590)

 

$

3,253,279 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See the accompanying notes which are an integral part of these 

unaudited condensed consolidated financial statements.

 

7


 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

(1) BASIS OF PRESENTATION AND NEW ACCOUNTING STANDARDS

 

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

 

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

 

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report on Form 10-K”).

 

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s Board of Directors, are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s 2011 Annual Report on Form 10-K. 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 2012 presentation. The effects of the reclassifications were not material to the Company’s unaudited condensed consolidated financial statements.

 

In the third quarter of 2012, the Company recorded a correction to increase the asset retirement obligation by approximately $39 million.  Because the amounts involved were not material to the Company’s financial statements in any individual prior period and the cumulative amount is not material to the current period financial statements, the Company recorded the cumulative effect of correcting this error during the quarter ended September 30, 2012.

 

 

 

 

(2) DIVESTITURES

 

In May 2012, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $168.0 million, excluding typical purchase price adjustments.  The proceeds were deposited with a qualified intermediary to facilitate potential like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code and, unless utilized for one or more like-kind exchange transactions, were restricted in their use until October 2012. The assets included in the sale represented all of the Company’s interests and related assets in the Overton Field in Smith County. The net production from the sold assets was approximately 24.0 MMcfe per day as of the closing date and our net proved reserves were approximately 143.0 Bcfe at December 31, 2011. 

 

8


 

 

In May 2011, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $118.1 million.  The sale included only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 9,717 net acres. The net production from the Haynesville and Middle Bossier Shale intervals in this acreage was approximately 7.0 MMcf per day and proved net reserves were approximately 37.1 Bcf when the sale was closed in May 2011.

 

(3) PREPAID EXPENSES

 

The components of prepaid expenses included in other current assets as of September 30, 2012 and December 31, 2011 consisted of the following:

 

 

 

 

 

 

 

 

September 30,

 

December 31,

 

2012

 

2011

 

 

(in thousands)

 

 

 

 

 

 

Prepaid drilling costs

$

47,462 

 

$

42,775 

Prepaid insurance

 

11,944 

 

 

7,275 

Total

$

59,406 

 

$

50,050 

 

 

 

(4) INVENTORY

 

Inventory recorded in current assets includes $6.2 million at September 30, 2012 and $7.8 million at December 31, 2011 for natural gas in underground storage owned by the Company’s E&P segment, and $24.4 million at September 30, 2012 and $38.4 million at December 31, 2011 for tubular and other equipment used in the E&P segment.

 

Other Assets include $17.8 million at September 30, 2012 and $19.5 million December 31, 2011, respectively, for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems for the Fayetteville Shale play.

 

 

(5) NATURAL GAS AND OIL PROPERTIES

 

The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves, net of taxes, discounted at 10 percent plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies 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 $2.83 per MMBtu and $91.48 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $276.6 million (net of tax) at September 30, 2012 and resulted in a non-cash ceiling test impairment.  Cash flow hedges of natural gas production in place increased the ceiling by $330.6 million at September 30, 2012.  In the second quarter of 2012, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $578.9 million (net of tax) at June 30, 2012 and resulted in a non-cash ceiling test impairment.  Decreases in average quoted prices from September 30, 2012 levels as well as changes in production rates, levels of reserves, capitalized costs, the evaluation of costs excluded from amortization, future development costs, service costs and taxes could result in future ceiling test impairments. 

9


 

 

 

All of the Company’s costs directly associated with the acquisition and evaluation of properties in New Brunswick, Canada relating to its exploration program at September 30, 2012 were unproved and did not exceed the ceiling amount.  If the exploration program in Canada is unsuccessful on all or a portion of these properties, a ceiling test impairment may result in the future.

 

 

(6) EARNINGS PER SHARE

 

The following table presents the computation of earnings per share for the three- and nine-month periods ended September 30, 2012 and 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended

 

For the nine months ended

 

September 30,

 

September 30,

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) (in thousands)

$

(144,815)

 

$

175,173 

 

$

(525,211)

 

$

479,236 

 

 

 

 

 

 

 

 

 

 

 

 

Number of common shares:

 

 

 

 

 

 

 

 

 

 

 

Weighted average outstanding

 

348,649,630 

 

 

347,239,793 

 

 

348,272,192 

 

 

347,070,330 

Issued upon assumed exercise of outstanding stock options

 

–  

 

 

2,490,783 

 

 

–  

 

 

2,591,687 

Effect of issuance of nonvested restricted common stock

 

–  

 

 

268,213 

 

 

–  

 

 

229,868 

Weighted average and potential dilutive outstanding(1)

 

348,649,630 

 

 

349,998,789 

 

 

348,272,192 

 

 

349,891,885 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

Basic

$

(0.42)

 

$

0.50 

 

$

(1.51)

 

$

1.38 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

$

(0.42)

 

$

0.50 

 

$

(1.51)

 

$

1.37 

 

(1) As we recognized a net loss for the three- and nine-months ended September 30, 2012, the unvested share-based payments and stock options were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. Options for 1,664,232 shares and 560,848 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2012 because they would have had an antidilutive effect. Options for 783,823 shares and 5,645 shares of restricted stock were excluded from the calculation for the three months ended September 30, 2011 because they would have had an antidilutive effect. Options for 1,685,398 shares and 580,227 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2012 because they would have had an antidilutive effect. Options for 811,552 shares and 7,114 shares of restricted stock were excluded from the calculation for the nine months ended September 30, 2011 because they would have had an antidilutive effect.

 

10


 

 

 

(7) DERIVATIVES AND RISK MANAGEMENT

 

The Company is exposed to volatility in market prices and basis differentials for natural gas and crude oil which impacts the predictability of its cash flows related to the sale of natural gas and oil. These risks are managed by the Company’s use of certain derivative financial instruments.  At September 30, 2012 and December 31, 2011, the Company’s derivative financial instruments consisted of price swaps, costless-collars and basis 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.

 

Floating price swaps         The Company receives a floating market price from the counterparty and pays a fixed price.

 

Costless-collars               Arrangements that contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

 

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.  

 

GAAP requires that all derivatives be recognized in the balance sheet as either an asset or liability and be measured at fair value. Under GAAP, certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings or as a component of other comprehensive income. Gains and losses on derivatives that are not elected for hedge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings.

 

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.

 

 

11


 

 

The balance sheet classification of the assets related to derivative financial instruments are summarized below at September 30, 2012 and December 31, 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative Assets

 

 

September 30, 2012

 

December 31, 2011

 

 

Balance Sheet Classification

 

Fair Value

 

Balance Sheet Classification

 

Fair Value

 

 

(in thousands)

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Fixed and floating price swaps

 

Hedging asset

 

$

254,358 

 

Hedging asset

 

$

333,479 

Costless-collars

 

Hedging asset

 

 

43,984 

 

Hedging asset

 

 

179,080 

Fixed and floating price swaps

 

Other assets

 

 

48,252 

 

Other assets

 

 

201,081 

Total derivatives designated as hedging instruments

 

 

 

$

346,594 

 

 

 

$

713,640 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Basis swaps

 

Hedging asset

 

$

2,519 

 

Hedging asset

 

$

1,906 

Basis swaps

 

Other assets

 

 

696 

 

Other assets

 

 

1,797 

Total derivatives not designated as hedging instruments

 

 

 

$

3,215 

 

 

 

$

3,703 

 

 

 

 

 

 

 

 

 

 

 

Total derivative assets

 

 

 

$

349,809 

 

 

 

$

717,343 

 

 

 

 

 

Derivative Liabilities

 

 

September 30, 2012

 

December 31, 2011

 

 

Balance Sheet Classification

 

Fair Value

 

Balance Sheet Classification

 

Fair Value

 

 

(in thousands)

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Fixed and floating price swaps

 

Other current liabilities

 

$

1,818 

 

Other current liabilities

 

$

11,849 

Costless-collars

 

Other current liabilities

 

 

 –

 

Other current liabilities

 

 

209 

Total derivatives designated as hedging instruments

 

 

 

$

1,818 

 

 

 

$

12,058 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

 

 

Basis swaps

 

Other current liabilities

 

$

223 

 

Other current liabilities

 

$

400 

Basis swaps

 

Other long-term liabilities

 

 

15 

 

Other long-term liabilities

 

 

55 

Total derivatives not designated as hedging instruments

 

 

 

$

238 

 

 

 

$

455 

 

 

 

 

 

 

 

 

 

 

 

Total derivative liabilities

 

 

 

$

2,056 

 

 

 

$

12,513 

 

 

 

Cash Flow Hedges

 

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

 

12


 

 

As of September 30, 2012, the Company had cash flow hedges on the following volumes of natural gas production (in Bcf):

 

 

 

 

 

Year

Fixed price swaps

Costless-collars

2012

46.7

20.2

2013

185.6

 –

 

As of September 30, 2012, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $206.7 million. This amount is net of a deferred income tax liability recorded as of September 30, 2012 of $135.6 million. The amount recorded in accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the physical transactions being hedged occur. Assuming the market prices of natural gas futures as of September 30, 2012 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of $177.9 million from accumulated other comprehensive income to earnings during the next 12 months. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to gas sales in the unaudited condensed consolidated statements of operations. Volatility in earnings and other comprehensive income may occur in the future as a result of the Company’s derivative activities.

 

The following tables summarize the before tax effect of all cash flow hedges on the unaudited condensed consolidated financial statements for the three- and nine-month periods ended September 30, 2012 and 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain (Loss) Recognized in Other Comprehensive Income

 

 

 

 

(Effective Portion)

 

 

 

 

For the three months ended

 

For the nine months ended

 

 

 

 

September 30,

 

September 30,

Derivative Instrument

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

(in thousands)

Fixed price swaps

 

 

 

$

(55,039)

 

$

230,783 

 

$

116,089 

 

$

360,362 

Costless-collars

 

 

 

$

(3,497)

 

$

48,315 

 

$

40,644 

 

$

65,144 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Classification of Gain

 

Gain Reclassified from Accumulated Other Comprehensive

 

 

Reclassified from

 

Income into Earnings

 

 

Accumulated Other

 

(Effective Portion)

 

 

Comprehensive Income

 

For the three months ended

 

For the nine months ended

 

 

into Earnings

 

September 30,

 

September 30,

Derivative Instrument

 

(Effective Portion)

 

2012

 

2011

 

2012

 

2011

 

 

 

 

(in thousands)

Fixed price swaps

 

Gas Sales

 

$

102,789 

 

$

67,125 

 

$

337,994 

 

$

145,662 

Costless-collars

 

Gas Sales

 

$

54,489 

 

$

13,918 

 

$

175,531 

 

$

40,978 

 

 

 

 

 

 

 

 

 

 

Gain (Loss) Recognized in Earnings

 

 

 

 

(Ineffective Portion)

 

 

Classification of Gain (Loss)

 

 

For the three months ended

 

For the nine months ended

 

 

Recognized in Earnings

 

September 30,

 

September 30,

Derivative Instrument

 

(Ineffective Portion)

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

(in thousands)

Fixed price swaps

 

Gas Sales

 

$

(165)

 

$

(1,754)

 

$

1,831 

 

$

(755)

Costless-collars

 

Gas Sales

 

$

(373)

 

$

(826)

 

$

167 

 

$

252 

 

Fair Value Hedges

 

For fair value hedges, 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.  As of September 30, 2012 and December 31, 2011, the Company had no material fair value hedges.

13


 

 

Other Derivative Contracts

 

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 do not qualify as cash flow hedges are recorded on the balance sheet at their fair values under hedging assets, other assets and other current liabilities, as applicable, and all realized and unrealized gains and losses related to these contracts are recognized immediately in the unaudited condensed consolidated statements of operations as a component of gas sales.

 

As of September 30, 2012, the Company had basis swaps on natural gas production that did not qualify for hedge accounting treatment of 9.2 Bcf, 30.1 Bcf and 9.1 Bcf in 2012, 2013, and 2014, respectively.

 

The following table summarizes the before tax effect of basis swaps that did not qualify for hedge accounting on the unaudited condensed consolidated statements of operations for the three- and nine-month periods ended September 30, 2012 and 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized Loss

 

 

 

 

Recognized in Earnings

 

 

Income Statement

 

For the three months ended

 

For the nine months ended

 

 

Classification

 

September 30,

 

September 30,

Derivative Instrument

 

of Unrealized Loss

 

2012

 

2011

 

2012

 

2011

 

 

 

 

(in thousands)

Basis swaps

 

Gas Sales

 

$

(1,275)

 

$

(1,967)

 

$

(270)

 

$

(159)

 

 

 

 

 

 

 

 

 

 

Realized Gain (Loss)

 

 

 

 

Recognized in Earnings

 

 

Income Statement

 

For the three months ended

 

For the nine months ended

 

 

Classification

 

September 30,

 

September 30,

Derivative Instrument

 

of Realized Gain (Loss)

 

2012

 

2011

 

2012

 

2011

 

 

 

 

(in thousands)

Basis swaps

 

Gas Sales

 

$

624 

 

$

(22)

 

$

1,773 

 

$

(2,377)

 

14


 

 

 

 

(8) FAIR VALUE MEASUREMENTS

 

The carrying amounts and estimated fair values of the Company’s financial instruments as of September 30, 2012 and December 31, 2011 were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

 

2012

 

2011

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Amount

 

Value

 

Amount

 

Value

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

$

18,560 

 

$

18,560 

 

$

15,627 

 

$

15,627 

Restricted cash

$

127,074 

 

$

127,074 

 

$

–  

 

$

–  

Unsecured revolving credit facility

$

26,500 

 

$

26,500 

 

$

671,500 

 

$

671,500 

Senior notes

$

1,670,042 

 

$

1,878,983 

 

$

671,800 

 

$

773,578 

Derivative instruments

$

347,753 

 

$

347,753 

 

$

704,830 

 

$

704,830 

 

 

 

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

 

Debt: The fair values of the Company’s senior notes were based on the market for the Company’s publicly-traded debt as determined based on yield of the Company’s 7.5% Senior Notes due 2018, which was 3.1% at September 30, 2012 and 4.6% at December 31, 2011, and its 4.10% Senior Notes due 2022, which was 3.4% at September 30, 2012. The carrying value of the borrowings under the Company’s unsecured revolving credit facility at September 30, 2012 and December 31, 2011, approximate fair value because the interest rate is variable and reflective of market rates.   As such, the Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy. 

 

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

 

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

 

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

 

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

 

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

 

Pursuant to GAAP, the Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s Level 2 fair value measurements include fixed-price and floating-price swaps and are estimated using internal discounted cash flow calculations using the NYMEX futures index. The Company’s Level 3 fair value measurements include costless-collars and basis swaps. The Company’s costless-collars are valued using the Black-Scholes model, an industry standard option valuation model, and takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves. 

 

The accounting group, reporting to the Vice President and Controller, is responsible for determining the Company’s Level 3 fair value measurements.  Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of most significant inputs on a monthly basis. An increase (decrease) in volatility would result

15


 

 

in an increase (decrease) in fair value measurement, respectively.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2012

 

 

 

 

 

 

Fair Value Measurements Using:

 

 

 

 

 

Quoted Prices

 

Significant

 

 

 

 

 

 

 

 

in Active

 

Other

 

Significant

 

 

 

 

 

Markets

 

Observable Inputs

 

Unobservable Inputs

 

Assets (Liabilities)

 

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

at Fair Value

Derivative assets

 

$

–  

 

$

302,610 

 

$

47,199 

 

$

349,809 

Derivative liabilities

 

 

–  

 

 

(1,818)

 

 

(238)

 

 

(2,056)

Total

 

$

–  

 

$

300,792 

 

$

46,961 

 

$

347,753 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

Fair Value Measurements Using:

 

 

 

 

 

Quoted Prices

 

Significant

 

 

 

 

 

 

 

 

in Active

 

Other

 

Significant

 

 

 

 

 

Markets

 

Observable Inputs

 

Unobservable Inputs

 

Assets (Liabilities)

 

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

at Fair Value

Derivative assets

 

$

–  

 

$

534,560 

 

$

182,783 

 

$

717,343 

Derivative liabilities

 

 

–  

 

 

(11,849)

 

 

(664)

 

 

(12,513)

Total

 

$

–  

 

$

522,711 

 

$

182,119 

 

$

704,830 

 

 

The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three- and nine-month periods ended September 30, 2012 and September 30, 2011. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect the assumptions a reasonable marketplace participant would have used at September 30, 2012 and September 30, 2011.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended

 

For the nine months ended

 

 

September 30,

 

September 30,

 

 

2012

 

2011

 

2012

 

2011

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at beginning of period

 

$

106,222 

 

$

89,395 

 

$

182,119 

 

$

97,677 

Total gains or losses (realized/unrealized):

 

 

   

 

 

 

 

 

 

 

 

 

Included in earnings

 

 

53,465 

 

 

11,102 

 

 

177,201 

 

 

38,694 

Included in other comprehensive income

 

 

(57,614)

 

 

35,223 

 

 

(135,055)

 

 

23,913 

Purchases, issuances, and settlements:

 

 

   

 

 

   

 

 

   

 

 

   

Purchases

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Issuances

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Settlements

 

 

(55,112)

 

 

(13,895)

 

 

(177,304)

 

 

(38,601)

Transfers into/out of Level 3

 

 

–  

 

 

–  

 

 

–  

 

 

142 

Balance at end of period

 

$

46,961 

 

$

121,825 

 

$

46,961 

 

$

121,825 

Change in unrealized gains included in earnings relating to derivatives still held as of September 30

 

$

(1,647)

 

$

(2,793)

 

$

(103)

 

$

93 

 

16


 

 

 

 

(9) DEBT

 

The components of debt as of September 30, 2012 and December 31, 2011 consisted of the following:

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

 

 

2012

 

2011

 

 

(in thousands)

Short-term debt:

 

 

 

 

 

 

7.15% Senior Notes due 2018

 

$

1,200 

 

$

1,200 

Total short-term debt

 

 

1,200 

 

 

1,200 

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

 

Variable rate (2.200%  and 2.276% at September 30, 2012 and December 31, 2011, respectively) unsecured revolving credit facility, expires February 2016

 

 

26,500 

 

 

671,500 

7.5% Senior Notes due 2018

 

 

600,000 

 

 

600,000 

7.35% Senior Notes due 2017

 

 

15,000 

 

 

15,000 

7.125% Senior Notes due 2017

 

 

25,000 

 

 

25,000 

7.15% Senior Notes due 2018

 

 

30,000 

 

 

30,600 

4.10% Senior Notes due 2022

 

 

1,000,000 

 

 

–  

Unamortized discount

 

 

(1,158)

 

 

–  

Total long-term debt

 

 

1,695,342 

 

 

1,342,100 

 

 

 

 

 

 

 

Total debt

 

$

1,696,542 

 

$

1,343,300 

 

 

Issuance of Senior Notes and Subsidiary Guarantees 

 

The indentures governing the Company’s senior notes contain covenants that, among other things, restrict the ability of the Company and/or its subsidiaries’ ability to incur liens, to engage in sale and leaseback transactions and to merge, consolidate, or sell assets.  All of the Company’s senior notes are currently guaranteed by its subsidiaries, SEECO, Inc. (“SEECO”), Southwestern Energy Production Company (“SEPCO”) and Southwestern Energy Services Company (“SES”).  If no default or event of default has occurred and is continuing, these guarantees will be released (i) automatically upon any sale, exchange, or transfer of all of the Company’s equity interests in the guarantor; (ii) automatically upon the liquidation and dissolution of a guarantor; (iii) following delivery of notice to the trustee of the release of the guarantor of its obligations under the Company’s credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes.

 

Please refer to Note 16, “Condensed Consolidating Financial Information” in this Form 10-Q for additional information.

 

In March 2012, the Company issued $1.0 billion of 4.10% Senior Notes due 2022 in a private placement. The 4.10% Senior Notes are redeemable at the Company’s election, in whole or in part, at any time prior to December 15, 2021, at a redemption price equal to the greater of: (1) 100% of the principal amount of the notes to be redeemed then outstanding; and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed (not including any portion of such payments of interest accrued to the date of redemption) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) as determined in accordance with the Indenture, plus 35 basis points, plus, in either of such cases, accrued and unpaid interest to the date of redemption on the notes to be redeemed. In addition, if the Company undergoes a “change of control,” as defined in the indenture, holders of the 4.10% Senior Notes will have the option to require the Company to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the change of control date. Payment obligations with respect to the 4.10% Senior Notes are currently guaranteed by the Company’s subsidiaries, SEECO, SEPCO and SES, which guarantees may be unconditionally released in certain circumstances. The Company has agreed to cause to become effective a registration statement with respect to an offer to exchange the 4.10% Senior Notes and related guarantees for freely tradeable notes with identical terms and related guarantees on or prior to the 270th calendar day after issuance and to cause a shelf registration statement to become effective for resales if requested by the initial purchasers of the Notes.  The Company will be obligated to pay additional interest if the exchange offer is not

17


 

 

completed or the shelf registration statement, if required, is not effective, on or before the 330th day after issuance.  The indentures governing the 4.10% Senior Notes and the Company’s other senior notes contain covenants that, among other things, restrict the ability of the Company and/or its subsidiaries to incur liens, to engage in sale and leaseback transactions and to merge, consolidate or sell assets.

 

Credit Facility 

 

In February 2011, the Company amended and restated its unsecured revolving credit facility, increasing the borrowing capacity to $1.5 billion and extending the maturity date to February 2016 (“Credit Facility”).  The amount available under the Credit Facility may be increased to $2.0 billion at any time upon the Company’s agreement with its existing or additional lenders. The interest rate on the Credit Facility is calculated based upon our debt rating and is currently 200 basis points over the current London Interbank Offered Rate (LIBOR) and was 200 basis points over LIBOR at September 30, 2012. The Credit Facility is guaranteed by the Company’s subsidiary, SEECO and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied.  The facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 60% of its total adjusted capital and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. The terms of the Credit Facility also include covenants that restrict the ability of the Company and its material subsidiaries to merge, consolidate or sell all or substantially all of their assets, restrict the ability of the Company and its subsidiaries to incur liens and restrict the ability of the Company’s subsidiaries to incur indebtedness.  As of September 30, 2012, the Company was in compliance with the covenants of its debt agreements.  While the Company believes all of the lenders under the Credit Facility have the ability to provide funds, it cannot predict whether each will be able to meet its obligation under the facility.

 

(10) COMMITMENTS AND CONTINGENCIES

 

Commitments

 

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brunswick of approximately $47.0 million Canadian dollars (“CAD”) in the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate principal amount of CAD $44.5 million. 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 no liability has been recognized in connection with the promissory notes due to the Company’s investments in New Brunswick as of September 30, 2012 and its future investment plans.

 

On March 23, 2012, SES entered into a precedent agreement with Constitution Pipeline Co. LLC for a proposed 121-mile pipeline connecting to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in Schoharie County, New York. Subject to the receipt of regulatory approvals and satisfaction of other conditions, SES has agreed to enter a fifteen year firm transportation agreement with a total capacity of 150 MMcf per day.  The project is expected to be in service by the second quarter of 2015.  

 

SES and SEPCO have entered into a number of short and long term firm transportation service and gathering agreements in support of our growing Marcellus Shale operations in Pennsylvania. As of September 30, 2012, the aggregate obligations under such gathering and firm transportation agreements (including precedent agreements assuming completion of the pipeline projects) for the Marcellus Shale operations totaled approximately $1.3 billion and the Company has guarantee obligations of up to $100.0 million of that amount.  

 

Environmental Risk

 

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

18


 

 

 

Litigation

 

In February 2009, SEPCO was added as a defendant in a Third Amended Petition in the matter of Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al.  In the Sixth Amended Petition, filed in July 2010, in the 273rd District Court in Shelby County, Texas (collectively, the “Sixth Petition”), plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiff’s allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 15, 2005 and February 15, 2006.  In the Sixth Petition, plaintiff sought actual damages of over $55.0 million as well as other remedies, including special damages and punitive damages of four times the amount of actual damages established at trial.

 

Immediately before the commencement of the trial in November 2010, plaintiff was permitted, over SEPCO’s objections, to file a Seventh Amended Petition claiming actual damages of $46.0 million and also seeking the equitable remedy of disgorgement of all profits for the misappropriation of trade secrets and the breach of fiduciary duty claims. In December 2010, the jury found in favor of the plaintiff with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages. The jury did not, however, award the plaintiff any special, punitive or other damages. In addition, the jury separately determined that SEPCO’s profits for purposes of disgorgement were $381.5 million. This profit determination does not constitute a judgment or an award. The plaintiff’s entitlement to disgorgement of profits as an equitable remedy will be determined by the judge and it is within the judge’s discretion to award none, some or all the amount of profit to the plaintiff.  On December 31, 2010, the plaintiff filed a motion to enter the judgment based on the jury’s verdict.  On February 11, 2011, SEPCO filed a motion for a judgment notwithstanding the verdict and a motion to disregard certain findings.  On March 11, 2011, the plaintiff filed an amended motion for judgment and intervenor filed its motion for judgment seeking not only the monetary damages and the profits determined by the jury but also seeking, as a new remedy, a constructive trust for profits from 143 wells as well as future drilling and sales of properties in the prospect areas.  A hearing on the post-verdict motions was held on March 14, 2011.  At the suggestion of the judge, all parties voluntarily agreed to participate in non-binding mediation efforts.  The mediation occurred on April 6, 2011 and was unsuccessful. On June 6, 2011, SEPCO received by mail a letter dated June 2, 2011 from the judge, in which he made certain rulings with respect to the post-verdict motions and responses filed by the parties. In his rulings, the judge denied SEPCO’s motion for judgment, judgment notwithstanding the verdict and to disregard certain findings. Plaintiff’s and intervenor’s claim for a constructive trust was denied but the judge ruled that plaintiff and intervenor shall recover from SEPCO $11.4 million and a reasonable attorney’s fee of 40% of the total damages awarded and are entitled to recover on their claim for disgorgement.  The judge instructed that SEPCO calculate the profit on the designated wells for each respective period.  SEPCO performed the calculation and provided it to the judge in June 2011.  On July 5, 2011, plaintiff and intervenor filed a letter with the court raising objections to the accounting provided by SEPCO, to which SEPCO filed a response on July 11, 2011.  On July 12, 2011, the judge sent a letter to the parties in which he ruled that after reviewing the parties’ respective position letters, he was awarding $23.9 million in disgorgement damages in favor of the plaintiff and intervenor.  In the July 12, 2011 letter, the judge instructed the plaintiff and intervenor to prepare a judgment for his approval prior to July 21, 2011 consistent with his findings in his June 2, 2011 letter and the disgorgement award.  On August 24, 2011, a judgment was entered pursuant to which plaintiff and intervenor are entitled to recover approximately $11.4 million in actual damages and approximately $23.9 million in disgorgement as well as prejudgment interest and attorneys' fees which currently are estimated to be up to $8.9 million and all costs of court of the plaintiff and intervenor.  On September 23, 2011, SEPCO filed a motion for a new trial and on November 18, 2011 filed a notice of appeal.  On November 30, 2011, the court approved SEPCO’s supersedeas bond in the amount of $14.1 million, which stays execution on the judgment pending appeal.  The bond covers the $11.4 million judgment for actual damages, plus $1.3 million in pre-judgment interest, $1.3 million in post-judgment interest (estimating two years for the duration of appeal), and court costs.  On April 17, 2012, SEPCO filed an unopposed motion for the appellate court’s permission to extend the deadline for filing its appeal to May 23, 2012. 

19


 

 

On June 22, 2012, SEPCO filed its appellate brief and, on June 25, 2012, plaintiff and intervenor filed a cross-appellate brief seeking limited remand to reassess the disgorgement determination. The parties are seeking a final extension of their deadlines to respond to the opposing party’s brief.  Thus, we expect that plaintiff and intervenor will file their response to SEPCO’s appellate brief on November 7, 2012, and SEPCO will file its response to plaintiff and intervenor’s cross-appellate brief on the same day.  Oral arguments are expected to occur in spring 2013.  Based on the Company's understanding and judgment of the facts and merits of this case, including appellate defenses, and after considering the advice of counsel, the Company has determined that, although reasonably possible after exhaustion of all appeals, an adverse final outcome to this lawsuit is not probable.  As such, the Company has not accrued any amounts with respect to this lawsuit.  If the plaintiff and intervenor were to ultimately prevail in the appellate process, the Company currently estimates, based on the judgments to date, that SEPCO’s potential liability would be up to $44.2 million, including interest and attorney’s fees. The Company’s assessment may change in the future due to occurrence of certain events, such as denied appeals, and such 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.

 

On February 20, 2012, the Company became aware that SEPCO was named as a defendant in the matter of Gery Muncey v. Southwestern Energy Production Company, et al filed in the District Court of San Augustine County in Texas on January 31, 2012.  The plaintiff in this case is also the intervenor in the Tovah Energy matter described above and alleges various claims including fraud, misappropriation and breach of fiduciary duty that are purported as independent of the claims alleged in the Tovah Energy matter but arise from the substantially same circumstances involved in the Tovah Energy matter.  The plaintiff is seeking value for various royalty and override ownership interests in wells drilled, disgorgement of profits and punitive damages.  SEPCO’s motion for summary judgment was granted on July 9, 2012. On August 22, 2012, the court signed a final take-nothing judgment in SEPCO’s favor.  Muncey has not filed any post-judgment motions or a notice of appeal, and the deadlines for filing same have now passed.  This matter has been resolved in SEPCO’s favor and is now over.

 

In March 2010, the Company’s subsidiary, SEECO, Inc., was served with a subpoena from a federal grand jury in Little Rock, Arkansas.  Based on the documents requested under the subpoena and subsequent discussions described below, the Company believes the grand jury is investigating matters involving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefore and whether royalties and other production attributable to federal lands have been properly accounted for and paid.  The Company believes it has fully complied with all requests related to the federal subpoena and delivered its affidavit to that effect. The Company and representatives of the Bureau of Land Management and the U.S. Attorney have had discussions since the production of the documents pursuant to the subpoena.  In January 2011, the Company voluntarily produced additional materials informally requested by the government arising from these discussions.  Although, to the Company’s knowledge, no proceeding in this matter has been initiated against SEECO, the Company cannot predict whether or when one might be initiated. The Company intends to fully comply with any further requests and to cooperate with any related investigation. No assurance can be made as to the time or resources that will need to be devoted to this inquiry or the impact of the final outcome of the discussions or any related proceeding.

 

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

20


 

 

(11) SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

 

Supplemental disclosures of cash flow information:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the three months ended

 

For the nine months ended

 

 

September 30,

 

September 30,

 

 

2012

 

2011

 

2012

 

2011

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash paid during the year for interest

 

$

45,667 

 

$

25,897 

 

$

75,487 

 

$

57,745 

Cash paid during the year for income taxes

 

 

400 

 

 

3,391 

 

 

468 

 

 

20,391 

Noncash property changes

 

 

(55,729)

 

 

(46,792)

 

 

(34,940)

 

 

16,078 

 

(12) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

 

The Company has defined pension and postretirement benefit plans which cover substantially all of the Company’s employees. Net periodic pension and other postretirement benefit costs include the following components for the three- and nine-month periods ended September 30, 2012 and 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension Benefits

 

 

For the three months ended

 

For the nine months ended

 

 

September 30,

 

September 30,

 

 

2012

 

2011

 

2012

 

2011

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

2,736 

 

$

2,330 

 

$

8,207 

 

$

6,992 

Interest cost

 

 

1,013 

 

 

918 

 

 

3,038 

 

 

2,753 

Expected return on plan assets

 

 

(1,356)

 

 

(1,099)

 

 

(4,069)

 

 

(3,298)

Amortization of prior service cost

 

 

71 

 

 

86 

 

 

214 

 

 

258 

Amortization of net loss

 

 

305 

 

 

214 

 

 

915 

 

 

642 

Net periodic benefit cost

 

$

2,769 

 

$

2,449 

 

$

8,305 

 

$

7,347 

 

 

 

 

 

 

Postretirement Benefits

 

 

For the three months ended

 

For the nine months ended

 

 

September 30,

 

September 30,

 

 

2012

 

2011

 

2012

 

2011

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

458 

 

$

338 

 

$

1,374 

 

$

1,015 

Interest cost

 

 

100 

 

 

63 

 

 

299 

 

 

189 

Amortization of transition obligation

 

 

16 

 

 

16 

 

 

48 

 

 

48 

Amortization of prior service cost

 

 

 

 

 

 

11 

 

 

11 

Amortization of net loss

 

 

23