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UNITED STATES |
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SECURITIES AND EXCHANGE COMMISSION |
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Washington, D.C. 20549 |
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Form 10-Q |
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(Mark One) |
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[X] Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended March 31, 2013 |
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Or |
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[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from __________ to __________ |
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Commission file number: 1-08246 |
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Southwestern Energy Company |
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(Exact name of registrant as specified in its charter) |
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Delaware |
71-0205415 |
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(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
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2350 North Sam Houston Parkway East, Suite 125, Houston, Texas |
77032 |
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(Address of principal executive offices) |
(Zip Code) |
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(281) 618-4700 |
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(Registrant’s telephone number, including area code) |
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Not Applicable |
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(Former name, former address and former fiscal year, if changed since last report) |
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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 |
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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. |
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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 |
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Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: |
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Class |
Outstanding as of April 30, 2013 |
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Common Stock, Par Value $0.01 |
351,522,140 |
SOUTHWESTERN ENERGY COMPANY |
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INDEX TO FORM 10-Q |
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FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013 |
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PART I – FINANCIAL INFORMATION |
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Item 1. |
3 |
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Item 2. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
31 |
Item 3. |
40 |
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Item 4. |
41 |
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PART II – OTHER INFORMATION |
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Item 1. |
42 |
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Item 1A. |
43 |
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Item 2. |
43 |
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Item 3. |
44 |
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Item 4. |
44 |
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Item 5. |
44 |
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Item 6. |
44 |
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.
Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
· |
the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); |
· |
our ability to fund our planned capital investments; |
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our ability to transport our production to the most favorable markets or at all; |
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the timing and extent of our success in discovering, developing, producing and estimating reserves; |
1
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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; |
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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; |
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the costs and availability of oilfield personnel, services and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews; |
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our ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and Marcellus Shale play; |
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our future property acquisition or divestiture activities; |
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the impact of the adverse outcome of any material litigation against us; |
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the effects of weather; |
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increased competition and regulation; |
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the financial impact of accounting regulations and critical accounting policies; |
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the comparative cost of alternative fuels; |
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conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed; |
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credit risk relating to the risk of loss as a result of non-performance by our counterparties; and |
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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, 2012 (the “2012 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
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS |
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(Unaudited) |
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For the three months ended |
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March 31, |
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2013 |
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2012 |
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(in thousands, except share/per share amounts) |
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Operating Revenues: |
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Gas sales |
$ |
504,496 |
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$ |
462,134 |
Gas marketing |
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179,841 |
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148,051 |
Oil sales |
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5,350 |
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2,528 |
Gas gathering |
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43,962 |
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42,122 |
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733,649 |
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654,835 |
Operating Costs and Expenses: |
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Gas purchases – midstream services |
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179,956 |
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146,676 |
Operating expenses |
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64,224 |
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60,958 |
General and administrative expenses |
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37,215 |
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48,826 |
Depreciation, depletion and amortization |
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179,467 |
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193,627 |
Taxes, other than income taxes |
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20,827 |
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20,422 |
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481,689 |
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470,509 |
Operating Income |
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251,960 |
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184,326 |
Interest Expense: |
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Interest on debt |
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24,097 |
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19,735 |
Other interest charges |
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1,110 |
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991 |
Interest capitalized |
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(16,186) |
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(13,388) |
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9,021 |
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7,338 |
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Other Loss, Net |
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(533) |
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(200) |
Commodity Derivative Income (Loss) |
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(29,794) |
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1,634 |
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Income Before Income Taxes |
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212,612 |
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178,422 |
Provision for Income Taxes: |
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Current |
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136 |
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168 |
Deferred |
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84,961 |
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70,550 |
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85,097 |
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70,718 |
Net Income |
$ |
127,515 |
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$ |
107,704 |
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Earnings Per Share: |
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Basic |
$ |
0.36 |
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$ |
0.31 |
Diluted |
$ |
0.36 |
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$ |
0.31 |
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Weighted Average Common Shares Outstanding: |
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Basic |
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350,032,430 |
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348,000,074 |
Diluted |
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350,738,309 |
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349,990,725 |
See the accompanying notes which are an integral part of these
unaudited condensed consolidated financial statements.
3
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) |
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(Unaudited) |
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For the three months ended |
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March 31, |
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2013 |
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2012 |
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(in thousands) |
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Net income |
$ |
127,515 |
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$ |
107,704 |
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Change in derivatives: |
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Settlements (1) |
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(47,173) |
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(97,942) |
Ineffectiveness (2) |
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(781) |
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(3,157) |
Change in fair value of derivative instruments (3) |
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(45,481) |
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166,934 |
Total change in derivatives |
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(93,435) |
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65,835 |
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Change in value of pension and other postretirement liabilities: |
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Amortization of prior service cost included in net periodic pension cost (4) |
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267 |
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254 |
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Change in currency translation adjustment |
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(1,029) |
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481 |
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Comprehensive income |
$ |
33,318 |
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$ |
174,274 |
(1) |
Net of $(31.4) and $(63.7) million in taxes for the three months ended March 31, 2013 and 2012. |
(2) |
Net of $(0.5) and $(2.1) million in taxes for the three months ended March 31, 2013 and 2012. |
(3) |
Net of $(30.3) and $108.5 million in taxes for the three months ended March 31, 2013 and 2012. |
(4) |
Net of $0.2 and $0.2 million in taxes for the three months ended March 31, 2013 and 2012. |
See the accompanying notes which are an integral part of these
unaudited condensed consolidated financial statements.
4
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED BALANCE SHEETS |
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(Unaudited) |
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March 31, |
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December 31, |
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2013 |
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2012 |
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ASSETS |
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(in thousands) |
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Current assets: |
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Cash and cash equivalents |
$ |
17,508 |
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$ |
53,583 |
Restricted cash |
|
7,108 |
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|
8,542 |
Accounts receivable |
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387,324 |
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|
377,638 |
Inventories |
|
30,408 |
|
|
28,141 |
Hedging asset |
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133,012 |
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282,693 |
Other |
|
41,447 |
|
|
58,315 |
Total current assets |
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616,807 |
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|
808,912 |
Natural gas and oil properties, using the full cost method, including $1,090.1 million in 2013 and $1,023.9 million in 2012 excluded from amortization |
|
11,766,978 |
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|
11,283,114 |
Gathering systems |
|
1,187,153 |
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|
1,148,261 |
Other |
|
607,607 |
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|
597,064 |
Less: Accumulated depreciation, depletion and amortization |
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(7,380,230) |
|
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(7,191,463) |
Total property and equipment, net |
|
6,181,508 |
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|
5,836,976 |
Other assets |
|
118,476 |
|
|
91,639 |
TOTAL ASSETS |
$ |
6,916,791 |
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$ |
6,737,527 |
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LIABILITIES AND EQUITY |
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Current liabilities: |
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|
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Accounts payable |
$ |
553,147 |
|
$ |
459,569 |
Taxes payable |
|
48,803 |
|
|
62,980 |
Interest payable |
|
14,185 |
|
|
34,431 |
Advances from partners |
|
24,511 |
|
|
68,919 |
Current deferred income taxes |
|
48,932 |
|
|
106,123 |
Other current liabilities |
|
41,896 |
|
|
35,749 |
Total current liabilities |
|
731,474 |
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|
767,771 |
Long-term debt |
|
1,703,403 |
|
|
1,668,273 |
Deferred income taxes |
|
1,131,312 |
|
|
1,049,138 |
Pension and other postretirement liabilities |
|
33,773 |
|
|
33,174 |
Other long-term liabilities |
|
235,021 |
|
|
183,299 |
Total long-term liabilities |
|
3,103,509 |
|
|
2,933,884 |
Commitments and contingencies (Note 10) |
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Equity: |
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|
|
|
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Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 351,530,606 shares in 2013 and 351,100,391 in 2012 |
|
3,516 |
|
|
3,511 |
Additional paid-in capital |
|
946,512 |
|
|
934,939 |
Retained earnings |
|
2,076,665 |
|
|
1,949,150 |
Accumulated other comprehensive income |
|
55,607 |
|
|
149,804 |
Common stock in treasury, 14,223 shares in 2013 and 64,715 in 2012 |
|
(492) |
|
|
(1,532) |
Total equity |
|
3,081,808 |
|
|
3,035,872 |
TOTAL LIABILITIES AND EQUITY |
$ |
6,916,791 |
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$ |
6,737,527 |
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|
|
|
|
|
See the accompanying notes which are an integral part of these |
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unaudited condensed consolidated financial statements. |
5
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |
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(Unaudited) |
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For the three months ended |
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March 31, |
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2013 |
|
2012 |
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(in thousands) |
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Cash Flows From Operating Activities |
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|
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Net income |
$ |
127,515 |
|
$ |
107,704 |
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
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Depreciation, depletion and amortization |
|
180,458 |
|
|
194,439 |
Deferred income taxes |
|
84,961 |
|
|
70,550 |
Commodity derivative loss (income) |
|
30,800 |
|
|
(2,114) |
Stock-based compensation |
|
2,994 |
|
|
2,844 |
Other |
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(476) |
|
|
(2,603) |
Change in assets and liabilities: |
|
|
|
|
|
Accounts receivable |
|
(9,689) |
|
|
42,604 |
Inventories |
|
(1,944) |
|
|
3,335 |
Accounts payable |
|
7,312 |
|
|
4,912 |
Taxes payable |
|
(14,177) |
|
|
8,285 |
Interest payable |
|
(7,245) |
|
|
(6,717) |
Advances from partners |
|
(44,408) |
|
|
34,235 |
Other assets and liabilities |
|
16,037 |
|
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(12,811) |
Net cash provided by operating activities |
|
372,138 |
|
|
444,663 |
|
|
|
|
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Cash Flows From Investing Activities |
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|
|
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Capital investments |
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(483,634) |
|
|
(557,631) |
Proceeds from sale of property and equipment |
|
– |
|
|
651 |
Transfers from restricted cash |
|
1,434 |
|
|
– |
Other |
|
1,038 |
|
|
1,770 |
Net cash used in investing activities |
|
(481,162) |
|
|
(555,210) |
|
|
|
|
|
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Cash Flows From Financing Activities |
|
|
|
|
|
Payments on revolving long-term debt |
|
(369,700) |
|
|
(1,271,300) |
Borrowings under revolving long-term debt |
|
404,800 |
|
|
599,800 |
Change in bank drafts outstanding |
|
33,046 |
|
|
(20,520) |
Proceeds from issuance of long-term debt |
|
– |
|
|
998,780 |
Debt issuance costs |
|
– |
|
|
(8,183) |
Proceeds from exercise of common stock options |
|
4,799 |
|
|
2,540 |
Net cash provided by financing activities |
|
72,945 |
|
|
301,117 |
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
4 |
|
|
(30) |
Increase (decrease) in cash and cash equivalents |
|
(36,075) |
|
|
190,540 |
Cash and cash equivalents at beginning of year |
|
53,583 |
|
|
15,627 |
Cash and cash equivalents at end of period |
$ |
17,508 |
|
$ |
206,167 |
See the accompanying notes which are an integral part of
these unaudited condensed consolidated financial statements.
6
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY |
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(Unaudited) |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
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Accumulated |
|
|
|
|
|
|
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|
Common Stock |
|
Additional |
|
|
|
|
Other |
|
Common |
|
|
|
||||||||||||
|
Shares |
|
|
|
|
Paid-In |
|
Retained |
|
Comprehensive |
|
Stock in |
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|
|
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Issued |
|
Amount |
|
Capital |
|
Earnings |
|
Income (Loss) |
|
Treasury |
|
Total |
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|
(in thousands) |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Balance at December 31, 2012 |
351,100 |
|
$ |
3,511 |
|
$ |
934,939 |
|
$ |
1,949,150 |
|
$ |
149,804 |
|
$ |
(1,532) |
|
$ |
3,035,872 | ||||||
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net income |
– |
|
|
– |
|
|
– |
|
|
127,515 |
|
|
– |
|
|
– |
|
|
127,515 | ||||||
Other comprehensive loss |
– |
|
|
– |
|
|
– |
|
|
– |
|
|
(94,197) |
|
|
– |
|
|
(94,197) | ||||||
Total comprehensive income |
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
33,318 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Stock-based compensation |
– |
|
|
– |
|
|
5,856 |
|
|
– |
|
|
– |
|
|
– |
|
|
5,856 | ||||||
Exercise of stock options |
452 |
|
|
5 |
|
|
4,794 |
|
|
– |
|
|
– |
|
|
– |
|
|
4,799 | ||||||
Issuance of restricted stock |
3 |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
||||||
Cancellation of restricted stock |
(24) |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
||||||
Treasury stock – non-qualified plan |
– |
|
|
– |
|
|
923 |
|
|
– |
|
|
– |
|
|
1,040 |
|
|
1,963 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Balance at March 31, 2013 |
351,531 |
|
$ |
3,516 |
|
$ |
946,512 |
|
$ |
2,076,665 |
|
$ |
55,607 |
|
$ |
(492) |
|
$ |
3,081,808 |
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
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, 2012 (“2012 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 2012 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 2013 presentation. The effects of the reclassifications were not material to the Company’s unaudited condensed consolidated financial statements.
(2) DIVESTITURES
In May 2012, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $166.0 million. 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
(3) PREPAID EXPENSES
The components of prepaid expenses included in other current assets as of March 31, 2013 and December 31, 2012 consisted of the following:
|
March 31, |
|
December 31, |
||
|
2013 |
|
2012 |
||
|
|
(in thousands) |
|||
|
|
|
|
|
|
Prepaid drilling costs |
$ |
20,038 |
|
$ |
30,101 |
Prepaid insurance |
|
5,268 |
|
|
9,507 |
Total |
$ |
25,306 |
|
$ |
39,608 |
(4) INVENTORY
Inventory recorded in current assets includes $3.8 million at March 31, 2013 and $5.6 million at December 31, 2012 for natural gas in underground storage owned by the Company’s E&P segment, and $26.6 million at March 31, 2013 and $22.5 million at December 31, 2012 for tubular and other equipment used in the E&P segment.
Other Assets include $14.1 million at March 31, 2013 and $13.8 million at December 31, 2012, 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 $2.95 per MMBtu and $89.17 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at March 31, 2013. Cash flow hedges of natural gas production in place increased the ceiling value by $185.8 million, net of tax, at March 31, 2013.
All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program at March 31, 2013 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.
9
(6) EARNINGS PER SHARE
The following table presents the computation of earnings per share for the three months ended March 31, 2013 and 2012:
|
For the three months ended |
||||
|
March 31, |
||||
|
2013 |
|
2012 |
||
|
|
|
|
|
|
Net income (in thousands) |
$ |
127,515 |
|
$ |
107,704 |
|
|
|
|
|
|
Number of common shares: |
|
|
|
|
|
Weighted average outstanding |
|
350,032,430 |
|
|
348,000,074 |
Issued upon assumed exercise of outstanding stock options |
|
579,022 |
|
|
1,889,691 |
Effect of issuance of nonvested restricted common stock |
|
126,857 |
|
|
100,960 |
Weighted average and potential dilutive outstanding(1) |
|
350,738,309 |
|
|
349,990,725 |
|
|
|
|
|
|
Earnings (loss) per share: |
|
|
|
|
|
Basic |
$ |
0.36 |
|
$ |
0.31 |
|
|
|
|
|
|
Diluted |
$ |
0.36 |
|
$ |
0.31 |
(1) Options for 2,112,679 shares and 271,674 shares of restricted stock were excluded from the calculation for the three months ended March 31, 2013 because they would have had an antidilutive effect. Options for 1,702,166 shares and 657,763 shares of restricted stock were excluded from the calculation for the three months ended March 31, 2012 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 March 31, 2013 and December 31, 2012, the Company’s derivative financial instruments consisted of price swaps, basis swaps, and fixed price call options. 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.
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.
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 March 31, 2013 and December 31, 2012:
|
|
Derivative Assets |
||||||||
|
|
March 31, 2013 |
|
December 31, 2012 |
||||||
|
|
Balance Sheet Classification |
|
Fair Value |
|
Balance Sheet Classification |
|
Fair Value |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
||||||||
Derivatives designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
Fixed price swaps |
|
Hedging asset |
|
$ |
131,091 |
|
Hedging asset |
|
$ |
279,443 |
Fixed price swaps |
|
Other assets |
|
|
4,378 |
|
Other assets |
|
|
8,550 |
Total derivatives designated as hedging instruments |
|
|
|
$ |
135,469 |
|
|
|
$ |
287,993 |
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
Basis swaps |
|
Hedging asset |
|
$ |
936 |
|
Hedging asset |
|
$ |
3,250 |
Fixed price swaps |
|
Hedging asset |
|
|
985 |
|
Hedging asset |
|
|
– |
Basis swaps |
|
Other assets |
|
|
464 |
|
Other assets |
|
|
901 |
Fixed price swaps |
|
Other assets |
|
|
29,507 |
|
Other assets |
|
|
– |
Total derivatives not designated as hedging instruments |
|
|
|
$ |
31,892 |
|
|
|
$ |
4,151 |
|
|
|
|
|
|
|
|
|
|
|
Total derivative assets |
|
|
|
$ |
167,361 |
|
|
|
$ |
292,144 |
|
|
|
||||||||
|
|
Derivative Liabilities |
||||||||
|
|
March 31, 2013 |
|
December 31, 2012 |
||||||
|
|
Balance Sheet Classification |
|
Fair Value |
|
Balance Sheet Classification |
|
Fair Value |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
||||||||
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
Basis swaps |
|
Other current liabilities |
|
$ |
337 |
|
Other current liabilities |
|
$ |
138 |
Fixed price swaps |
|
Other current liabilities |
|
|
436 |
|
Other current liabilities |
|
|
– |
Basis swaps |
|
Other long-term liabilities |
|
|
– |
|
Other long-term liabilities |
|
|
– |
Fixed price call options |
|
Other long-term liabilities |
|
|
61,210 |
|
Other long-term liabilities |
|
|
4,128 |
Fixed price swaps |
|
Other long-term liabilities |
|
|
824 |
|
Other long-term liabilities |
|
|
– |
Total derivatives not designated as hedging instruments |
|
|
|
$ |
62,807 |
|
|
|
$ |
4,266 |
|
|
|
|
|
|
|
|
|
|
|
Total derivative liabilities |
|
|
|
$ |
62,807 |
|
|
|
$ |
4,266 |
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 March 31, 2013, the Company had cash flow hedges on the following volumes of natural gas production (in Bcf):
Year |
Fixed price swaps |
2013 |
139.6 |
2014 |
18.3 |
As of March 31, 2013, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $78.7 million. This amount is net of a deferred income tax liability recorded as of March 31, 2013 of $52.5 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 March 31, 2013 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of $76.3 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 month periods ended March 31, 2013 and 2012:
|
|
|
|
Gain (Loss) Recognized in |
||||
|
|
|
|
(Effective Portion) |
||||
|
|
|
|
For the three months ended |
||||
|
|
|
|
March 31, |
||||
Derivative Instrument |
|
|
|
2013 |
|
2012 |
||
|
|
|
|
(in thousands) |
||||
Fixed price swaps |
|
|
|
$ |
(73,902) |
|
$ |
218,957 |
Costless-collars |
|
|
|
$ |
– |
|
$ |
56,511 |
|
|
|
|
|
|
|
|
|
|
|
Classification of Gain |
|
Gain Reclassified from |
||||
|
|
Reclassified from |
|
Comprehensive Income into Earnings |
||||
|
|
Accumulated Other |
|
(Effective Portion) |
||||
|
|
Comprehensive Income |
|
For the three months ended |
||||
|
|
into Earnings |
|
March 31, |
||||
Derivative Instrument |
|
(Effective Portion) |
|
2013 |
|
2012 |
||
|
|
|
|
(in thousands) |
||||
Fixed price swaps |
|
Gas Sales |
|
$ |
78,621 |
|
$ |
106,311 |
Costless-collars |
|
Gas Sales |
|
$ |
– |
|
$ |
55,310 |
|
|
|
|
|
|
|||
|
|
|
|
Gain Recognized in |
||||
|
|
|
|
(Ineffective Portion) |
||||
|
|
Classification of Gain |
|
For the three months ended |
||||
|
|
Recognized in Earnings |
|
March 31, |
||||
Derivative Instrument |
|
(Ineffective Portion) |
|
2013 |
|
2012 |
||
|
|
|
|
(in thousands) |
||||
Fixed price swaps |
|
Gas Sales |
|
$ |
1,301 |
|
$ |
4,299 |
Costless-collars |
|
Gas Sales |
|
$ |
– |
|
$ |
911 |
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 March 31, 2013 and December 31, 2012, 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 March 31, 2013, the Company had basis swaps on natural gas production that did not qualify for hedge accounting treatment of 22.3 Bcf and 10.9 Bcf in 2013 and 2014, respectively.
As of March 31, 2013, the Company had fixed price call options on natural gas production that did not qualify for hedge accounting treatment of 199.8 Bcf for 2015. As of March 31, 2013, the Company had fixed price swaps not designated for hedge accounting on natural gas production of 181.5 Bcf for 2014.
The following table summarizes the before tax effect of basis swaps, fixed price call options that did not qualify for hedge accounting, and fixed price swaps not designated for hedge accounting, within the commodity derivative income (loss) line on the unaudited condensed consolidated statements of operations for the three month period ended March 31, 2013 and 2012:
|
|
|
|
Unrealized Gain (Loss) |
||||
|
|
|
|
Recognized in Earnings |
||||
|
|
Income Statement |
|
For the three months ended |
||||
|
|
Classification |
|
March 31, |
||||
Derivative Instrument |
|
of Unrealized Gain (Loss) |
|
2013 |
|
2012 |
||
|
|
|
|
(in thousands) |
||||
Basis swaps |
|
Commodity Derivative Income (Loss) |
|
$ |
(2,950) |
|
$ |
1,223 |
Fixed price call options |
|
Commodity Derivative Income (Loss) |
|
$ |
(57,082) |
|
$ |
– |
Fixed price swaps |
|
Commodity Derivative Income (Loss) |
|
$ |
29,232 |
|
$ |
– |
|
|
|
|
|
|
|||
|
|
|
|
Realized Gain |
||||
|
|
|
|
Recognized in Earnings |
||||
|
|
Income Statement |
|
For the three months ended |
||||
|
|
Classification |
|
March 31, |
||||
Derivative Instrument |
|
of Realized Gain |
|
2013 |
|
2012 |
||
|
|
|
|
(in thousands) |
||||
Basis swaps |
|
Commodity Derivative Income (Loss) |
|
$ |
1,007 |
|
$ |
1,018 |
As of March 31, 2013, the Company had fixed price swaps not designated for hedge accounting on the following volumes of natural gas production (in Bcf):
Year |
Fixed price swaps not designated |
2014 |
181.5 |
(8) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME
In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“Update 2013-02”), which finalizes proposed ASU No. 2012-240, and seeks to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Update 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income.
14
The following table details the components of AOCI and the related tax effects for the three months ended March 31, 2013:
|
|
Gains and Losses on Cash Flow Hedges |
|
|
Pension and Other Postretirement |
|
|
Foreign Currency |
|
|
Total |
||||
|
|
(in thousands) (1) |
|||||||||||||
Beginning balance |
|
$ |
172,166 |
|
|
$ |
(22,311) |
|
|
$ |
(51) |
|
|
$ |
149,804 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income before reclassifications |
|
|
(45,481) |
|
|
|
– |
|
|
|
(1,029) |
|
|
|
(46,510) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts reclassified from accumulated other comprehensive income (2) |
|
|
(47,954) |
|
|
|
267 |
|
|
|
– |
|
|
|
(47,687) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net current-period other comprehensive Income |
|
|
(93,435) |
|
|
|
267 |
|
|
|
(1,029) |
|
|
|
(94,197) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
78,731 |
|
|
$ |
(22,044) |
|
|
$ |
(1,080) |
|
|
$ |
55,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) All amounts are net-of-tax.
(2) See separate table below for details about these reclassifications.
The following table details the amounts reclassified from AOCI into earnings for the three months ended March 31, 2013:
Details about Accumulated Other Comprehensive Income |
|
|
Amount Reclassified from Accumulated Other Comprehensive Income |
|
Affected Line Item in the Consolidated Statement of Operations |
Gains and losses on cash flow hedges |
|
|
|
|
|
Settlements |
|
$ |
(78,621) |
|
Gas Sales |
Ineffectiveness |
|
|
(1,302) |
|
Gas Sales |
|
|
|
(79,923) |
|
Income before income taxes |
|
|
|
(31,969) |
|
Provision for income taxes |
|
|
$ |
(47,954) |
|
Net income |
|
|
|
|
|
|
Pension and other postretirement |
|
|
|
|
|
Amortization of prior service cost included in net periodic pension cost (1) |
|
$ |
445 |
|
General and administrative expenses |
|
|
|
445 |
|
Income before income taxes |
|
|
|
178 |
|
Provision for income taxes |
|
|
$ |
267 |
|
Net income |
|
|
|
|
|
|
Total reclassifications for the period |
|
$ |
(47,687) |
|
Net income |
(1) This accumulated other comprehensive income component is included in the computation of net periodic pension cost (see pension footnote for additional details.)
15
(9) FAIR VALUE MEASUREMENTS
The carrying amounts and estimated fair values of the Company’s financial instruments as of March 31, 2013 and December 31, 2012 were as follows:
|
March 31, |
|
December 31, |
||||||||
|
2013 |
|
2012 |
||||||||
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
||||
|
Amount |
|
Value |
|
Amount |
|
Value |
||||
|
(in thousands) |
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
$ |
17,508 |
|
$ |
17,508 |
|
$ |
53,583 |
|
$ |
53,583 |
Restricted cash |
$ |
7,108 |
|
$ |
7,108 |
|
$ |
8,542 |
|
$ |
8,542 |
Unsecured revolving credit facility |
$ |
35,100 |
|
$ |
35,100 |
|
$ |
– |
|
$ |
– |
Senior notes |
$ |
1,669,503 |
|
$ |
1,885,523 |
|
$ |
1,669,473 |
|
$ |
1,917,005 |
Derivative instruments |
$ |
104,554 |
|
$ |
104,554 |
|
$ |
287,878 |
|
$ |
287,878 |
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 2.5% at March 31, 2013 and 2.6% at December 31, 2012, and its 4.10% Senior Notes due 2022, which was 3.4% at March 31, 2013. The carrying value of the borrowings under the Company’s unsecured revolving credit facility at March 31, 2013, 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 fixed price call options and basis swaps. The Company’s fixed price call options are valued using the Black-Scholes model, an industry standard option valuation model, 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
16
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):
|
|
March 31, 2013 |
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|
Fair Value Measurements Using: |
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|
|
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|
|
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 |
|
$ |
– |
|
$ |
165,961 |
|
$ |
1,400 |
|
$ |
167,361 |
Derivative liabilities |
|