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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, 2015 |
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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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10000 Energy Drive Spring, Texas |
77389 |
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(Address of principal executive offices) |
(Zip Code) |
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(832) 796-1000 |
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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. Yes☒ No ☐ |
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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). Yes☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. |
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Large accelerated filer ☒ |
Accelerated filer ☐ |
Non-accelerated filer ☐ |
Smaller reporting company ☐ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ |
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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 21, 2015 |
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Common Stock, Par Value $0.01 |
384,554,852 |
INDEX TO FORM 10-Q |
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FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2015 |
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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 |
28 |
Item 3. |
39 |
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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. |
42 |
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Item 2. |
42 |
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Item 3. |
42 |
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Item 4. |
42 |
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Item 5. |
42 |
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Item 6. |
42 |
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 (the “Exchange Act”). 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 Quarterly Report on 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:
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the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); |
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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; |
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the economic viability of, and our success in drilling, our large positions in the Fayetteville Shale, Northeast Appalachia and Southwest Appalachia overall as well as relative to other productive shale gas plays; |
1
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our ability to realize the expected benefits from recent acquisitions; |
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the impact of title and environmental defects and other matters on the value of the properties acquired in our recent acquisitions and any other future acquisitions; |
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difficulties in integrating our operations as a result of any significant acquisitions; |
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the impact of government regulation, including the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation relating to hydraulic fracturing, 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; |
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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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the different risks and uncertainties associated with proposed activities in Canada; |
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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”). |
Should one or more of the risks or uncertainties described above or elsewhere in this Quarterly Report 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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2015 |
2014 |
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(in millions, except share/per share amounts) |
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Operating Revenues: |
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Gas sales |
$ |
625 |
$ |
793 | |
Oil sales |
17 | 2 | |||
NGL sales |
18 |
– |
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Marketing |
225 | 272 | |||
Gas gathering |
48 | 46 | |||
933 | 1,113 | ||||
Operating Costs and Expenses: |
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Marketing purchases |
222 | 271 | |||
Operating expenses |
155 | 100 | |||
General and administrative expenses |
68 | 57 | |||
Depreciation, depletion and amortization |
293 | 225 | |||
Taxes, other than income taxes |
30 | 25 | |||
768 | 678 | ||||
Operating Income |
165 | 435 | |||
Interest Expense: |
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Interest on debt |
50 | 25 | |||
Other interest charges |
49 | 1 | |||
Interest capitalized |
(48) | (13) | |||
51 | 13 | ||||
Other Income (Loss), Net |
(1) | 1 | |||
Gain (Loss) on Derivatives |
14 | (100) | |||
Income Before Income Taxes |
127 | 323 | |||
Provision (Benefit) for Income Taxes: |
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Current |
– |
(1) | |||
Deferred |
49 | 130 | |||
49 | 129 | ||||
Net Income |
$ |
78 |
$ |
194 | |
Mandatory convertible preferred stock dividend |
25 |
– |
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Participating securities - mandatory convertible preferred stock |
7 |
– |
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Net Income Attributable to Common Stock |
$ |
46 |
$ |
194 | |
Earnings Per Common Share: |
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Basic |
$ |
0.12 |
$ |
0.55 | |
Diluted |
$ |
0.12 |
$ |
0.55 | |
Weighted Average Common Shares Outstanding: |
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Basic |
375,444,030 | 351,222,538 | |||
Diluted |
375,578,054 | 351,985,821 |
The accompanying notes 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 |
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(Unaudited) |
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For the three months ended |
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March 31, |
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2015 |
2014 |
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(in millions) |
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Net income |
$ |
78 |
$ |
194 | |
Change in derivatives: |
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Settlements (1) |
(25) | 25 | |||
Ineffectiveness (2) |
– |
1 | |||
Change in fair value of derivative instruments (3) |
17 | (54) | |||
Total change in derivatives |
(8) | (28) | |||
Change in currency translation adjustment |
(6) | (3) | |||
Comprehensive income |
$ |
64 |
$ |
163 |
(1) |
Net of $(17) and $17 million in taxes for the three months ended March 31, 2015 and 2014, respectively. |
(2) |
Net of $0 and $1 million in taxes for the three months ended March 31, 2015 and 2014, respectively. |
(3) |
Net of $7 and $(36) million in taxes for the three months ended March 31, 2015 and 2014, respectively. |
The accompanying notes 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, |
December 31, |
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2015 |
2014 |
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ASSETS |
(in millions) |
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Current assets: |
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Cash and cash equivalents |
$ |
17 |
$ |
53 | |
Accounts receivable |
491 | 530 | |||
Inventories |
39 | 37 | |||
Derivative assets |
295 | 337 | |||
Other current assets |
46 | 158 | |||
Total current assets |
888 | 1,115 | |||
Natural gas and oil properties, using the full cost method, including $4,997 million as of March 31, 2015 and $4,646 million as of December 31, 2014 excluded from amortization |
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21,516 |
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20,506 |
Gathering systems |
1,485 | 1,439 | |||
Other |
626 | 612 | |||
Less: Accumulated depreciation, depletion and amortization |
(9,144) | (8,845) | |||
Total property and equipment, net |
14,483 | 13,712 | |||
Other long-term assets |
216 | 98 | |||
TOTAL ASSETS |
$ |
15,587 |
$ |
14,925 | |
LIABILITIES AND EQUITY |
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Current liabilities: |
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Short-term debt |
$ |
1 |
$ |
4,501 | |
Accounts payable |
606 | 653 | |||
Taxes payable |
72 | 92 | |||
Interest payable |
31 | 34 | |||
Current deferred income taxes |
91 | 109 | |||
Dividends payable |
25 |
– |
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Derivative liabilities |
11 | 9 | |||
Other current liabilities |
108 | 30 | |||
Total current liabilities |
945 | 5,428 | |||
Long-term debt |
5,163 | 2,466 | |||
Deferred income taxes |
2,009 | 1,951 | |||
Pension and other postretirement liabilities |
45 | 44 | |||
Other long-term liabilities |
368 | 374 | |||
Total long-term liabilities |
7,585 | 4,835 | |||
Commitments and contingencies (Note 10) |
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Equity: |
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Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 384,572,080 shares as of March 31, 2015 and 354,488,992 as of December 31, 2014 |
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4 |
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4 |
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding |
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– |
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– |
Additional paid-in capital |
3,372 | 1,019 | |||
Retained earnings |
3,633 | 3,577 | |||
Accumulated other comprehensive income |
48 | 62 | |||
Common stock in treasury, 13,893 shares in 2015 and 11,055 in 2014 |
– |
– |
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Total equity |
7,057 | 4,662 | |||
TOTAL LIABILITIES AND EQUITY |
$ |
15,587 |
$ |
14,925 | |
The accompanying notes 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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2015 |
2014 |
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(in millions) |
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Cash Flows From Operating Activities |
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Net income |
$ |
78 |
$ |
194 | ||
Adjustments to reconcile net income to net cash provided by operating activities: |
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Depreciation, depletion and amortization |
293 | 225 | ||||
Amortization of debt issuance cost |
46 | 1 | ||||
Deferred income taxes |
49 | 130 | ||||
Loss on derivatives excluding derivatives, settled |
21 | 62 | ||||
Stock-based compensation |
6 | 4 | ||||
Other |
– |
1 | ||||
Change in assets and liabilities: |
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Accounts receivable |
38 | (78) | ||||
Inventories |
(3) | 1 | ||||
Accounts payable |
(35) | 94 | ||||
Taxes payable (receivable) |
(20) | (13) | ||||
Interest payable |
(1) | (10) | ||||
Other assets and liabilities |
69 | (2) | ||||
Net cash provided by operating activities |
541 | 609 | ||||
Cash Flows From Investing Activities |
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Capital investments |
(508) | (525) | ||||
Acquisitions |
(591) | (9) | ||||
Proceeds from sale of property and equipment |
1 | 17 | ||||
Other |
3 | 1 | ||||
Net cash used in investing activities |
(1,095) | (516) | ||||
Cash Flows From Financing Activities |
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Payments on revolving long-term debt |
(830) | (1,131) | ||||
Borrowings under revolving long-term debt |
1,330 | 1,009 | ||||
Change in bank drafts outstanding |
(7) | 19 | ||||
Payments on short-term debt |
(4,500) |
– |
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Proceeds from issuance of long-term debt |
2,200 |
– |
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Debt issuance costs |
(17) |
– |
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Proceeds from exercise of common stock options |
– |
6 | ||||
Proceeds from issuance of common stock |
669 |
– |
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Proceeds from issuance of mandatory convertible preferred stock |
1,673 |
– |
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Net cash provided by (used in) financing activities |
518 | (97) | ||||
Decrease in cash and cash equivalents |
(36) | (4) | ||||
Cash and cash equivalents at beginning of year |
53 | 23 | ||||
Cash and cash equivalents at end of period |
$ |
17 |
$ |
19 |
The accompanying notes are an integral part of these
unaudited condensed consolidated financial statements.
6
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
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(Unaudited) |
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Common Stock |
Preferred Stock |
Additional |
Accumulated Other |
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Shares |
Shares |
Paid-In |
Retained |
Comprehensive |
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Issued |
Amount |
Issued |
Capital |
Earnings |
Income |
Total |
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(in millions, except share amounts) |
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Balance at December 31, 2014 |
354,488,992 |
$ |
4 |
– |
$ |
1,019 |
$ |
3,577 |
$ |
62 |
$ |
4,662 | ||||||||||||
Comprehensive income: |
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Net income |
– |
– |
– |
– |
78 |
– |
78 | |||||||||||||||||
Other comprehensive loss |
– |
– |
– |
– |
– |
(14) | (14) | |||||||||||||||||
Total comprehensive income |
– |
– |
– |
– |
– |
– |
64 | |||||||||||||||||
Stock-based compensation |
– |
– |
– |
11 |
– |
– |
11 | |||||||||||||||||
Preferred stock dividends |
– |
– |
– |
– |
(25) |
– |
(25) | |||||||||||||||||
Issuance of restricted stock |
100,147 |
– |
– |
– |
– |
– |
– |
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Cancellation of restricted stock |
(17,023) |
– |
– |
– |
– |
– |
– |
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Issuance of common stock |
30,000,000 |
– |
– |
669 |
– |
– |
669 | |||||||||||||||||
Issuance of preferred stock |
– |
– |
1,725,000 | 1,673 |
– |
– |
1,673 | |||||||||||||||||
Tax withholding – stock compensation |
(36) |
– |
– |
– |
– |
– |
– |
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Non-controlling interest |
– |
– |
– |
– |
3 |
– |
3 | |||||||||||||||||
Balance at March 31, 2015 |
384,572,080 |
$ |
4 | 1,725,000 |
$ |
3,372 |
$ |
3,633 |
$ |
48 |
$ |
7,057 |
The accompanying notes 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 “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production (“E&P”). The Company’s current operations are principally focused within the United States on the development of unconventional reservoirs located in Arkansas, Pennsylvania and West Virginia. The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale, and its operations in northeast Pennsylvania are focused on an unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”). Recently, the Company acquired a significant stake in properties located in West Virginia and southwest Pennsylvania. These operations, primarily in West Virginia, are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”). Collectively, the Company’s properties located in West Virginia and Pennsylvania are herein referred to as the “Appalachian Basin.” To a lesser extent, the Company has exploration and production activities ongoing in Colorado, Louisiana, Texas and elsewhere in the United States. The Company also actively seeks to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which it refers to as “New Ventures,” and to obtain additional reserves through acquisitions. The Company also operates drilling rigs in Arkansas, Pennsylvania and West Virginia, and provides oilfield products and services, principally serving its exploration and production operations. Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Texas, Louisiana, Pennsylvania and West Virginia.
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. 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 for the year ended December 31, 2014 (“2014 Annual Report”).
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 2014 Annual Report.
Certain reclassifications have been made to the prior year financial statements to conform to the 2015 presentation. The effects of the reclassifications were not material to the Company’s unaudited condensed consolidated financial statements.
(2) ACQUISITIONS AND DIVESTITURES
In April 2015, the Company sold its gathering assets located in Bradford and Lycoming counties in northeastern Pennsylvania to Howard Midstream Energy Partners, LLC for an adjusted sales price of approximately $488 million. The net book value of these assets was $213 million and was held in the Midstream segment as of March 31, 2015. The assets include approximately 100 miles of natural gas gathering pipeline, with nearly 600 million cubic feet per day of capacity. The proceeds from the transaction were used to substantially repay borrowings under the Company’s $500 million term loan facility that would have matured in December 2016. The transaction is subject to customary post-closing adjustments.
In March 2015, the Company announced that it executed an agreement with a private buyer to sell the Company’s conventional oil and gas assets located in East Texas and the Arkoma Basin for approximately $218 million. The net book value of these assets is primarily in the full cost pool and is held in the E&P segment as of March 31, 2015. The proceeds from the transaction will be used to reduce Company debt. The transaction is expected to close in the second quarter of 2015 and is subject to customary closing conditions.
8
In January 2015, the Company completed an acquisition of certain oil and gas assets including approximately 46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. for an adjusted purchase price of $288 million, subject to customary post-closing adjustments (the “WPX Property Acquisition”). This acreage was producing approximately 50 million net cubic feet of gas per day from 63 operated horizontal wells as of December 2014. As part of this transaction, the Company assumed firm transportation capacity of 260 million cubic feet of gas per day predominantly on the Millennium pipeline. This transaction was funded with the revolving credit facility and was accounted for as a business combination. The Company allocated approximately $169 million of the purchase price of the WPX Property Acquisition to natural gas and oil properties and approximately $119 million to intangible assets in other current assets and other long-term assets, based on the respective fair values of the assets acquired.
In January 2015, the Company and Statoil ASA completed an acquisition in which the Company’s subsidiary acquired certain oil and gas assets covering approximately 30,000 acres in West Virginia and southwest Pennsylvania comprising approximately 20% of Statoil’s interests in that acreage for $365 million, subject to customary post-closing adjustments (the “Statoil Property Acquisition”). All of these assets are also assets in which the Company has acquired interests under the Chesapeake Property Acquisition (as defined below). This transaction was funded with the revolving credit facility and was accounted for as a business combination. The Company allocated approximately $365 million of the purchase price to natural gas and oil properties, based on the respective fair values of the assets acquired.
In December 2014, the Company completed an acquisition of certain oil and gas assets from Chesapeake Energy Corporation covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, natural gas liquids (“NGLs”) and crude oil contained in the Upper Devonian, Marcellus and Utica Shales for approximately $5.0 billion, subject to customary post-closing adjustments (the “Chesapeake Property Acquisition”). The transaction was temporarily financed using a $4.5 billion 364-day senior unsecured bridge term loan credit facility and a $500 million two-year unsecured term loan. The Company repaid all principal and interest outstanding on the $4.5 billion bridge facility in January 2015 after permanent financing was finalized and, as a result, expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015 recognized in other interest charges on the unaudited condensed consolidated statement of operations. The term loan facility was repaid in full in April 2015 with proceeds from the divestiture of the Company’s northeastern Pennsylvania gathering assets and borrowings under the revolving credit facility.
The Chesapeake Property Acquisition qualified as a business combination, and as a result, the Company estimated the fair value of the assets acquired and liabilities assumed as of the December 22, 2014 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 8 – Fair Value Measurements. The following table summarizes the consideration paid for the Chesapeake Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date. The purchase price allocation is preliminary and subject to adjustment. These amounts will be finalized as soon as possible, but no later than December 2015.
Consideration (in millions): |
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Cash |
$ |
4,978 |
Recognized amounts of identifiable assets acquired and liabilities assumed: |
||
Assets acquired: |
||
Proved natural gas and oil properties |
1,424 | |
Unproved natural gas and oil properties |
3,605 | |
Other property and equipment |
19 | |
Inventory |
2 | |
Other receivables |
27 | |
Total assets acquired |
5,077 | |
Liabilities assumed: |
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Asset retirement obligations |
(42) | |
Other long-term liabilities |
(57) | |
Total liabilities assumed |
(99) | |
$ |
4,978 |
9
Summarized below are the consolidated results of operations for the three months ended March 31, 2014 on an unaudited pro forma basis, as if the acquisition and related permanent debt and equity financing, as finalized in January 2015, had occurred on January 1, 2013. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Chesapeake Property Acquisition properties. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related permanent financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations. The unaudited pro-forma financial information excludes the WPX and Statoil Property Acquisitions as the impacts are immaterial.
For the three months ended |
||
March 31, |
||
2014 |
||
(in millions, except per share amounts) (unaudited) |
||
Revenues |
$ |
1,251 |
Net income |
$ |
243 |
Earnings per common share: |
||
Basic |
$ |
0.48 |
Diluted |
$ |
0.48 |
In the second and third quarters of 2014, the Company completed several acquisitions to purchase approximately 380,000 net acres in northwest Colorado principally in the Niobrara formation for approximately $215 million. The Company utilized its revolving credit facility to finance these acquisitions and accounted for them as asset acquisitions.
(3) INVENTORY
Inventory is comprised of natural gas in underground storage and tubular and other equipment. Natural gas in underground storage is carried at the lower of cost or market and accounted for by a weighted average cost method. Tubulars and other equipment are carried at the lower of cost or market and are accounted for by a moving weighted average cost method that is applied within specific classes of inventory items.
The components of inventory recorded in current assets as of March 31, 2015 and December 31, 2014 consisted of the following:
March 31, |
December 31, |
|||||
2015 |
2014 |
|||||
(in millions) |
||||||
Tubulars and other equipment |
$ |
37 |
$ |
33 | ||
Natural gas in underground storage |
$ |
2 |
$ |
4 |
(4) NATURAL GAS AND OIL PROPERTIES
The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10% plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Companies using the full cost method must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.
10
Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.88 per MMBtu, West Texas Intermediate oil of $79.21 per barrel, and NGLs of $16.38 per barrel, 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, 2015. Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $45 million as of March 31, 2015. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.
Using the first-day-of-the-month prices of natural gas for the first four months of 2015 and NYMEX strip prices for the remainder of 2015, as applicable, the prices required to be used to determine the ceiling amount in the Company’s full cost ceiling test are likely to require write-downs in each of the remaining quarters in 2015.
Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.99 per MMBtu, West Texas Intermediate oil of $94.92 per barrel, and NGLs of $43.64 per barrel, adjusted for market differentials, the 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, 2014. Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $40 million as of March 31, 2014.
All of the Company’s costs directly associated with the acquisition and evaluation of properties in Canada relating to its exploration program as of March 31, 2015 were unproved and did not exceed the ceiling amount. If the Company’s exploration program in Canada is terminated or otherwise unsuccessful on all or a portion of the Company’s Canadian assets, including the effects of changes in laws or regulations due to the new government in New Brunswick or otherwise, a ceiling test impairment may result in the future.
(5) EARNINGS PER SHARE
Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock and performance units and the assumed conversion of mandatory convertible preferred stock. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.
In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). The common stock offering was priced at $23.00 per share. Net proceeds, after underwriting discount and expenses, from the common stock offering were approximately $669 million. Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1.7 billion. Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public offering of $2.2 billion in long-term senior notes.
The mandatory convertible preferred stock entitles the holders to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (and, correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date.
The mandatory convertible preferred stock has the non-forfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. As such, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings.
11
The following table presents the computation of earnings per share for the three month periods ended March 31, 2015 and 2014:
For the three months ended |
|||||
March 31, |
|||||
2015 |
2014 |
||||
(in millions, except share/per share amounts) |
|||||
Net income |
$ |
78 |
$ |
194 | |
Mandatory convertible preferred stock dividend |
25 |
– |
|||
Net income attributable to shareholders |
53 | 194 | |||
Participating securities - mandatory convertible preferred stock |
7 |
– |
|||
Net income attributable to common stock |
46 | 194 | |||
Number of common shares: |
|||||
Weighted average outstanding |
375,444,030 | 351,222,538 | |||
Issued upon assumed exercise of outstanding stock options (1) |
– |
348,798 | |||
Effect of issuance of non-vested restricted common stock (1) |
133,634 | 349,608 | |||
Effect of issuance of non-vested performance units |
390 | 64,877 | |||
Effect of mandatory convertible preferred stock (2) |
– |
– |
|||
Weighted average and potential dilutive outstanding |
375,578,054 | 351,985,821 | |||
Earnings per common share: |
|||||
Basic |
$ |
0.12 |
$ |
0.55 | |
Diluted |
$ |
0.12 |
$ |
0.55 |
(1) |
Options for 3,704,089 shares and 1,916,645 shares of restricted stock were excluded from the calculation for the three months ended March 31, 2015 because they would have had an antidilutive effect. Options for 1,179,914 shares and 29,688 shares of restricted stock were excluded from the calculation for the three months ended March 31, 2014 because they would have had an antidilutive effect. |
(2) |
Weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock totaling 58,333,252 shares were excluded from the computation of diluted earnings per share as such conversion would have been antidilutive. |
12
(6) DERIVATIVES AND RISK MANAGEMENT
The Company is exposed to volatility in market prices and basis differentials for natural gas and oil which impacts the predictability of its cash flows related to the sale of natural gas, NGLs and oil. These risks are managed by the Company’s use of certain derivative financial instruments. As of March 31, 2015 and December 31, 2014, the Company’s derivative financial instruments consisted of fixed price swaps, basis swaps, fixed price call options, and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:
Fixed price swaps |
The Company receives a fixed price for the contract and pays a floating market price to the counterparty. |
Basis swaps |
Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. |
Fixed price call options |
The Company sells fixed price call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess on sold fixed price call options. If the market price settles below the fixed price of the call option, no payment is due from either party. |
Interest rate swaps |
Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes. |
All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value other than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings or as a component of other comprehensive income. Gains and losses on derivatives that are not designated for hedge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings as a component of gain (loss) on derivatives. Within the gain (loss) on derivatives component of the statement of operations are gains (losses) on derivatives excluding derivatives, settled and gains (losses) on derivatives, settled. The Company calculates gains (losses) on derivatives, settled, as the summation of gains and losses on positions which have settled within the period.
The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy at the time the transactions are entered into and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.
13
The balance sheet classification of the assets related to derivative financial instruments are summarized below as of March 31, 2015 and December 31, 2014:
Derivative Assets |
||||||||||
March 31, 2015 |
December 31, 2014 |
|||||||||
Balance Sheet Classification |
Fair Value |
Balance Sheet Classification |
Fair Value |
|||||||
(in millions) |
||||||||||
Derivatives designated as hedging instruments: |
||||||||||
Fixed price swaps |
Derivative assets |
$ |
146 |
Derivative assets |
$ |
165 | ||||
Total derivatives designated as hedging instruments |
$ |
146 |
$ |
165 | ||||||
Derivatives not designated as hedging instruments: |
||||||||||
Basis swaps |
Derivative assets |
$ |
3 |
Derivative assets |
$ |
9 | ||||
Fixed price swaps |
Derivative assets |
146 |
Derivative assets |
163 | ||||||
Basis swaps |
Other long-term assets |
– |
Other long-term assets |
1 | ||||||
Interest rate swaps |
Other long-term assets |
– |
Other long-term assets |
1 | ||||||
Total derivatives not designated as hedging instruments |
|
|
|
$ |
149 |
|
|
|
$ |
174 |
Total derivative assets |
$ |
295 |
$ |
339 | ||||||
Derivative Liabilities |
||||||||||
March 31, 2015 |
December 31, 2014 |
|||||||||
Balance Sheet Classification |
Fair Value |
Balance Sheet Classification |
Fair Value |
|||||||
(in millions) |
||||||||||
Derivatives not designated as hedging instruments: |
||||||||||
Basis swaps |
Derivative liabilities |
$ |
6 |
Derivative liabilities |
$ |
4 | ||||
Fixed price call options |
Derivative liabilities |
2 |
Derivative liabilities |
2 | ||||||
Interest rate swaps |
Derivative liabilities |
3 |
Derivative liabilities |
3 | ||||||
Basis swaps |
Other long-term liabilities |
– |
Other long-term liabilities |
2 | ||||||
Fixed price call options |
Other long-term liabilities |
3 |
Other long-term liabilities |
10 | ||||||
Interest rate swaps |
Other long-term liabilities |
3 |
Other long-term liabilities |
2 | ||||||
Total derivatives not designated as hedging instruments |
|
|
|
$ |
17 |
|
|
|
$ |
23 |
Total derivative liabilities |
$ |
17 |
$ |
23 |
As of March 31, 2015, the Company had fixed price swap derivatives designated for hedge accounting and not designated for hedge accounting on the following volumes of natural gas production (in Bcf):
Year |
Fixed price swaps designated for hedge accounting |
Fixed price swaps not designated for hedge accounting |
Total |
Weighted Average Price to be Swapped ($/MMBtu) (1) |
||||
2015 |
91 |
90 |
181 |
$4.40 |
(1) |
The weighted average swap price is $4.40 for each category and in total. |
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 are recognized in earnings immediately and had an inconsequential impact to the unaudited condensed consolidated statement of operations for the three month periods ended March 31, 2015 and 2014.
As of March 31, 2015, accumulated other comprehensive income includes a gain related to its hedging activities of $90 million net of a deferred income tax liability of $56 million. The amount included in accumulated other
14
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, 2015 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of approximately $90 million from accumulated other comprehensive income to earnings during the next 12 months. Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to natural gas sales in the consolidated statements of operations. Volatility in net income, comprehensive income and accumulated other comprehensive income may occur in the future as a result of the Company’s derivative activities.
The following tables summarize the before tax effect of all cash flow hedges on the unaudited condensed consolidated financial statements for the three month periods ended March 31, 2015 and 2014:
Gain (Loss) Recognized in |
||||||||
(Effective Portion) |
||||||||
For the three months ended |
||||||||
March 31, |
||||||||
Derivative Instrument |
2015 |
2014 |
||||||
(in millions) |
||||||||
Fixed price swaps |
$ |
24 |
$ |
(90) | ||||
Classification of Gain (Loss) |
Gain (Loss) Reclassified from Accumulated |
|||||||
Reclassified from |
Other Comprehensive Income |
|||||||
Accumulated Other |
into Earnings (Effective Portion) |
|||||||
Comprehensive Income |
For the three months ended |
|||||||
into Earnings |
March 31, |
|||||||
Derivative Instrument |
(Effective Portion) |
2015 |
2014 |
|||||
(in millions) |
||||||||
Fixed price swaps |
Gas sales |
$ |
42 |
$ |
(42) |
Other Derivative Contracts
For other derivative contracts, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately through gain (loss) on derivatives. Although the Company’s basis swaps meet the objective of managing commodity price exposure, these trades are typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and therefore do not generally qualify for hedge accounting. Basis swap derivative instruments that are not designated for hedge accounting are recorded on the balance sheet at their fair values under derivative assets, other long-term assets, other current liabilities, and other long-term liabilities, as applicable and all gains and losses related to these contracts are recognized immediately in the unaudited condensed consolidated statement of operations as a component of gain (loss) on derivatives. As of March 31, 2015, the Company had basis swaps on natural gas production that were not designated for hedge accounting of 11 Bcf and 4 Bcf in 2015 and 2016, respectively.
As of March 31, 2015, the Company had fixed price call options on 151 Bcf and 120 Bcf of natural gas production in 2015 and 2016, respectively, not designated for hedge accounting and fixed price swaps of 90 Bcf of natural gas production in 2015 not designated for hedge accounting.
The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps build to a notional amount of $170 million and expire in June 2020. The Company did not designate the interest rate swaps for hedge accounting. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives in the consolidated statements of operations.
15
The following tables summarize the before tax effect of fixed price swaps, basis swaps, fixed price call options and interest rate swaps not designated for hedge accounting on the condensed consolidated statements of operations for the three month periods ended March 31, 2015 and 2014:
Gain (Loss) on Derivatives |
||||||||
Excluding Derivatives, Settled |
||||||||
Recognized in Earnings |
||||||||
Consolidated Statement of Operations |
For the three months ended |
|||||||
Classification of Gain (Loss) on |
March 31, |
|||||||
Derivative Instrument |
Derivatives, Net of Settlement |
2015 |
2014 |
|||||
(in millions) |
||||||||
Basis swaps |
Gain (Loss) on Derivatives |
$ |
(8) |
$ |
(10) | |||
Fixed price call options |
Gain (Loss) on Derivatives |
$ |
8 |
$ |
(27) | |||
Fixed price swaps |
Gain (Loss) on Derivatives |
$ |
(18) |
$ |
(23) | |||
Interest rate swaps |
Gain (Loss) on Derivatives |
$ |
(3) |
$ |
(2) | |||
Gain (Loss) |
||||||||
on Derivatives, Settled (1) |
||||||||
Recognized in Earnings |
||||||||
Consolidated Statement of Operations |
For the three months ended |
|||||||
Classification of Gain (Loss) |
March 31, |
|||||||
Derivative Instrument |
on Derivatives, Settled (1) |
2015 |
2014 |
|||||
(in millions) |
||||||||
Basis swaps |
Gain (Loss) on Derivatives |
$ |
(6) |
$ |
(14) | |||
Fixed price swaps |
Gain (Loss) on Derivatives |
$ |
42 |
$ |
(24) | |||
Interest rate swaps |
Gain (Loss) on Derivatives |
$ |
(1) |
$ |
– |
(1) |
The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period reported. |
16
(7) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME
The following tables detail the components of accumulated other comprehensive income and the related tax effects for the three months ended March 31, 2015:
For the three months ended |
|||||||||||||||
March 31, 2015 |
|||||||||||||||
(in millions) (1) |
|||||||||||||||
Cash Flow Hedges |
Pension and Other Postretirement |
Foreign Currency |