UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A
(Amendment No. 2)
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of report (Date of earliest event reported): December 19, 2014
SOUTHWESTERN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation)
| 1-08246 | 71-0205415 | |
| (Commission File Number) | (IRS Employer Identification No.) |
| 10000 Energy Drive Spring, Texas | 77389 | |
| (Address of principal executive offices) | (Zip Code) |
(832) 796-4700
(Registrant's telephone number, including area code)
Not Applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
This Current Report on Form 8-K/A (this “Form 8-K/A) is being filed solely to correct an oversight made when the Registrant's Current Report on Form 8-K/A was filed with the Securities and Exchange Commission on January 7, 2015 (the “Original Filing”). The Company filed the report of PricewaterhouseCoopers LLP (the “Report”) and the audited statements of revenues and direct operating expenses of the West Virginia and Southwest Pennsylvania Properties (the “Financial Statements”), as Exhibit 99.1 to the Original Filing, although inadvertently omitted from the Report the conformed electronic signature of PricewaterhouseCoopers LLP. In order to correct this inadvertent oversight, a copy of the Report as originally filed, including the conformed electronic signature of PricewaterhouseCoopers LLP, and the Financial Statements are attached as Exhibit 99.1 to this Form 8-K/A and incorporated herein by reference. This Form 8-K/A makes no changes to the disclosures in, or exhibits to, the Original Filing other than to add the conformed signature of PricewaterhouseCoopers LLP and to provide an updated consent of Pricewaterhouse Coopers dated as of August 24, 2015.
Item 9.01 Financial Statements and Exhibits
(a) Financial Statements of Business Acquired
Statements of Revenues and Direct Operating Expenses of the West Virginia and Southwest Pennsylvania Properties for the three years ended December 31, 2013 (audited) and for the nine months ended September 30, 2014 and 2013 (unaudited), together with the related notes to the financial statements and the accompanying Independent Auditor’s Report, are set forth in Exhibit 99.1 and incorporated by reference herein.
(b) Pro Forma Financial Information
The Unaudited Pro Forma Condensed Combined Financial Information of the Company as of September 30, 2014 and for the year ended December 31, 2013 and the nine months ended September 30, 2014 together with the related notes to the financial information, each showing the pro forma effect of the Acquisition, are set forth in Exhibit 99.2 and incorporated by reference herein.
(d) Exhibits
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| SOUTHWESTERN ENERGY COMPANY | ||||
| Dated: August 25, 2015 | By: | /s/ R. CRAIG OWEN | ||
| Name: | R. Craig Owen | |||
| Title: | Senior Vice President and | |||
| Chief Financial Officer | ||||
EXHIBIT INDEX
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 ASR (No. 333-184882) and the Registration Statements on Form S-8 (Nos. 333-184885 and 333-188744) of Southwestern Energy Company ("Southwestern") of our report dated December 22, 2014 relating to the Statements of Revenues and Direct Operating Expenses of the Acquired West Virginia and Southwest Pennsylvania Properties, which appears in Southwestern's Current Report on Form 8-K/A dated December 19, 2014.
/s/ PricewaterhouseCoopers LLP
Houston, TX
August 24, 2015
Independent Auditor’s Report
To the Board of Directors of Southwestern Energy Company:
We have audited the accompanying financial statements of the Acquired West Virginia and Southwest Pennsylvania Properties (the “Properties”), which comprise the statements of revenues and direct operating expenses for each of the three years in the period ended December 31, 2013.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditor's Responsibility
Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Properties for each of the three years in the period ended December 31, 2013 in accordance with accounting principles generally accepted in the United States of America, using the basis of presentation described in Note 1.
Emphasis of Matter
The accompanying financial statements reflect the revenues and direct operating expenses of the Properties using the basis of presentation described in Note 1 and are not intended to be a complete presentation of the financial position, results of operations or cash flows of the Properties.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
December 22, 2014
1
ACQUIRED WEST VIRGINIA AND SOUTHWEST PENNSYLVANIA PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
|
Nine Months Ended |
|||||||||||||||
|
Years Ended |
September 30, |
||||||||||||||
|
December 31, |
(Unaudited) |
||||||||||||||
|
2013 |
2012 |
2011 |
2014 |
2013 |
|||||||||||
|
($ in millions) |
|||||||||||||||
|
Revenues |
$ |
342 |
$ |
147 |
$ |
181 |
$ |
340 |
$ |
235 | |||||
|
Direct operating expenses |
65 | 47 | 55 | 57 | 40 | ||||||||||
|
Revenues in excess of direct operating expenses |
$ |
277 |
$ |
100 |
$ |
126 |
$ |
283 |
$ |
195 | |||||
See accompanying notes to the Statements of Revenues and Direct Operating Expenses.
2
ACQUIRED WEST VIRGINIA AND SOUTHWEST PENNSYLVANIA PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(1) BASIS OF PRESENTATION
On December 23, 2014, Southwestern Energy Company (the “Company”) filed a Current Report on Form 8-K (the “Closing Report”) to report that a subsidiary of the Company completed the acquisition of certain oil and gas assets from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) 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 $4.975 billion, subject to customary closing adjustments. The accompanying Statements of Revenues and Direct Operating Expenses represent the direct undivided interests in the revenue and direct operating expenses associated with the Properties.
The Statements of Revenues and Direct Operating Expenses have been derived from the historical financial records of Chesapeake. For purposes of these statements, all properties identified in the purchase and sale agreement are included herein. During the periods presented, the Properties were not accounted for or operated as a separate subsidiary or division by Chesapeake. The accompanying Statements of Revenues and Direct Operating Expenses vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain expenses incurred in connection with the ownership and operation of the Properties, including but not limited to depreciation, depletion and amortization, impairments, accretion of asset retirement obligations, general and administrative expenses, interest expense and federal and state income taxes. These costs were not separately allocated to the working interests of the Properties in Chesapeake’s accounting records. In addition, these allocations, if made using historical general and administrative structures and tax burdens would not produce allocations indicative of the historical performance of the Properties had they been the Company’s properties due to the differing size, structure, specifications and accounting policies of Chesapeake as compared to the Company. Furthermore, no balance sheet has been presented for the Properties because the Properties were not accounted for as or operated as a separate subsidiary or division of Chesapeake and complete financial statements are not available, nor has information about the Properties’ operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statements of Revenues and Direct Operating Expenses of the Properties are presented in lieu of the full financial statements required under Item 3-05 of the Securities and Exchange Commission’s Regulation S-X. In addition, these Statements of Revenues and Direct Operating Expenses are not indicative of the results of operations for the Properties on a go forward basis.
The accompanying Statements of Revenues and Direct Operating Expenses for the nine months ended September 30, 2014 and 2013 are unaudited, and have been prepared on the same basis as the annual Statements of Revenues and Direct Operating Expenses and, in the opinion of management, reflect all adjustments necessary to fairly present the Properties’ excess of revenue over direct operating expenses for the nine months ended September 30, 2014 and 2013.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates – The Statements of Revenues and Direct Operating Expenses are derived from the historical operating statements of Chesapeake. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statements of Revenues and Direct Operating Expenses. Actual results could be different from those estimates. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Properties.
Revenue Recognition – Revenue from the sale of natural gas, oil and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges. Chesapeake uses the “sales method” of accounting for their natural gas, oil, and NGL revenue whereby sales revenue is recognized on all natural gas, oil, and NGL sold to purchasers, regardless of whether the sales are proportionate to their ownership in the property. There were no significant imbalances with other revenue interest owners during the three years ended December 31, 2013 and the nine months ended September 30, 2014 and 2013.
3
During the three years ended December 31, 2013 and the nine months ended September 30, 2014 and 2013, over 90% of gas and NGL sales were made to Chesapeake Energy Marketing, Inc (referred to herein as “CEMI”). During the nine months ended September 30, 2014 and 2013, sales to CEMI accounted for approximately 100% and 79%, respectively, of the Properties’ total oil revenues. During 2013, sales to CEMI accounted for approximately 85% of the Properties’ total oil revenues. During 2012, sales to CEMI, Clearfield Appalachian Holdings, Inc, Tyler Mountain Properties, LLC and Ergon Oil Purchasing, Inc. accounted for approximately 41%, 25%, 16%, and 11%, respectively, of the Properties’ total oil revenues. During 2011, sales to Clearfield Appalachian Holdings, Inc and Tyler Mountain Properties, LLC accounted for approximately 58% and 36%, respectively, of the Properties’ total oil revenues. During such periods, no other customers accounted for more than 10% of the Properties’ total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, it is not likely that the loss of any single significant customer or contract would materially affect the Properties in the long-term as such purchasers could be replaced by other purchasers under contracts with similar terms and conditions.
Direct Operating Expenses – Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Properties. Direct operating expenses include lease operating expenses, production taxes, and expense workover costs. Lease operating expenses include well repair expenses, saltwater disposal costs, facility maintenance expenses, and other field-related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil, natural gas, and NGL production activities.
(3) COMMITMENTS AND CONTINGENCIES
The activities of the Properties may become subject to potential claims and litigation in the normal course of operations. The Company does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Properties.
(4) SUBSEQUENT EVENTS
The Company has evaluated subsequent events through December 22, 2014, the date the Statements of Revenues and Direct Operating Expenses were available to be issued, and has concluded that no events need to be reported in relation to this period.
(5) SUPPLEMENTAL NATURAL GAS AND OIL RESERVE INFORMATION (UNAUDITED)
The following tables summarize the net ownership interest in the estimated proved reserves and the standardized measure of discounted future net cash flows (“standardized measure”) related to the proved reserves for the Properties. The components of the standardized measure were determined in accordance with the authoritative guidance of the Financial Accounting Standards Board (“FASB”).
Estimated Quantities of Proved Oil and Natural Gas Reserves
Proved reserves are estimated quantities of natural gas, NGLs and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate was made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.
The reserve estimates at December 31, 2013, 2012 and 2011 presented in the table below were prepared by Chesapeake’s reserve engineers, in accordance with the authoritative guidance of the FASB on natural gas and oil reserve estimation and disclosures. All of the natural gas, NGL and oil producing activities of the Properties were conducted within the United States.
Reserve estimates are inherently imprecise and are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, Chesapeake’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.
The following table sets forth the Properties’ estimated net proved, proved developed and proved undeveloped oil, natural gas and NGLs reserves:
4
|
Natural |
||||||||
|
Natural |
Gas |
|||||||
|
Gas |
Oil |
Liquids |
Total |
|||||
|
(MMcf) |
(MBbls) |
(MBbls) |
(MMcfe) |
|||||
|
2011 |
||||||||
|
Proved reserves, beginning of year |
294,713 | 530 | 7,795 | 344,663 | ||||
|
Revisions of previous estimates |
64,917 | 738 | 3,641 | 91,191 | ||||
|
Extensions, discoveries and other additions |
93,495 | 1,301 | 3,333 | 121,300 | ||||
|
Production |
(33,908) | (166) | (1,122) | (41,636) | ||||
|
Acquisition of reserves in place |
5 |
– |
– |
5 | ||||
|
Disposition of reserves in place |
(2) |
– |
– |
(2) | ||||
|
Proved reserves, end of year |
419,220 | 2,403 | 13,647 | 515,521 | ||||
|
Proved developed reserves: |
||||||||
|
Beginning of year |
194,702 | 145 | 4,444 | 222,236 | ||||
|
End of year |
297,652 | 1,942 | 8,855 | 362,437 | ||||
|
Proved undeveloped reserves: |
||||||||
|
Beginning of year |
100,011 | 385 | 3,351 | 122,427 | ||||
|
End of year |
121,568 | 461 | 4,792 | 153,084 | ||||
|
2012 |
||||||||
|
Proved reserves, beginning of year |
419,220 | 2,403 | 13,647 | 515,521 | ||||
|
Revisions of previous estimates |
26,004 | (542) | 3,382 | 43,043 | ||||
|
Extensions, discoveries and other additions |
192,917 | 4,076 | 9,109 | 272,026 | ||||
|
Production |
(42,388) | (233) | (1,417) | (52,288) | ||||
|
Acquisition of reserves in place |
1 |
– |
– |
1 | ||||
|
Proved reserves, end of year |
595,754 | 5,704 | 24,721 | 778,303 | ||||
|
Proved developed reserves: |
||||||||
|
Beginning of year |
297,652 | 1,942 | 8,855 | 362,437 | ||||
|
End of year |
431,504 | 4,310 | 16,730 | 557,742 | ||||
|
Proved undeveloped reserves: |
||||||||
|
Beginning of year |
121,568 | 461 | 4,792 | 153,084 | ||||
|
End of year |
164,250 | 1,394 | 7,991 | 220,561 | ||||
5
|
Natural |
||||||||
|
Natural |
Gas |
|||||||
|
Gas |
Oil |
Liquids |
Total |
|||||
|
(MMcf) |
(MBbls) |
(MBbls) |
(MMcfe) |
|||||
|
2013 |
||||||||
|
Proved reserves, beginning of year |
595,754 | 5,704 | 24,721 | 778,303 | ||||
|
Revisions of previous estimates |
8,877 | 1,043 | 1,874 | 26,382 | ||||
|
Extensions, discoveries and other additions |
374,142 | 9,231 | 16,469 | 528,345 | ||||
|
Production |
(57,972) | (1,522) | (2,497) | (82,086) | ||||
|
Acquisition of reserves in place |
7 |
– |
– |
7 | ||||
|
Disposition of reserves in place |
(864) |
– |
– |
(864) | ||||
|
Proved reserves, end of year |
919,944 | 14,456 | 40,567 | 1,250,087 | ||||
|
Proved developed reserves: |
||||||||
|
Beginning of year |
431,504 | 4,310 | 16,730 | 557,742 | ||||
|
End of year |
551,123 | 10,612 | 21,599 | 744,391 | ||||
|
Proved undeveloped reserves: |
||||||||
|
Beginning of year |
164,250 | 1,394 | 7,991 | 220,561 | ||||
|
End of year |
368,821 | 3,844 | 18,968 | 505,696 |
Reserve additions from revisions of previous estimates, extensions, discoveries and other additions were primarily attributable to Chesapeake’s development drilling of proved acreage during the periods presented. There are numerous uncertainties in estimating quantities of proved reserves, which incorporate estimates of the future rates of production, the timing of development expenditures and other assumptions. The above reserve data represents estimates only, and is inherently imprecise and may be subject to substantial revisions as additional information becomes available, such as reservoir performance, additional drilling, technological advancements and other factors. Decreases in the prices of natural gas, NGLs or oil could have an adverse effect on reserve volumes and discounted future net cash flows related to the proved reserves. Similarly, the standardized measure incorporates various assumptions such as prices, costs, production rates and discount rates that are inherently imprecise. Actual results could be materially different and the results may not be comparable to estimates disclosed by other natural gas and oil companies.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted cash flows as of December 31, 2013, 2012 and 2011 and the changes between periods were derived from Chesapeake’s records. The standardized measure represents the present value of estimated future net cash flows from estimated net proved natural gas, NGLs and oil reserves, less future development, production, plugging and abandonment costs, and income tax expenses, discounted at 10% per annum, to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization or impairments of capitalized acquisition, exploration and development costs. As described in Note 1, the Statements of Revenue and Direct Operating Expenses do not include income tax expense, and therefore income tax expense was omitted from the standardized measure calculation below.
Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure below were $3.67 per Mcf for natural gas and $96.82 per barrel for oil before price differentials in 2013, $2.76 per Mcf for natural gas and $94.84 per barrel of oil before price differentials in 2012, and $4.12 per Mcf for natural gas and $95.97 per barrel for oil before price differentials in 2011. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine future cash inflows.
6
The standardized measure does not purport, nor should be interpreted, to present the fair market value of the Properties’ proved reserves. It is intended to present a standardized disclosure concerning possible future net cash flows from proved reserves that would result under the assumptions used and ignores future changes in prices and costs and the risks inherent in reserve estimates, among other things. Further, since prices and costs do not remain static, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other natural gas and oil producers. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results.
The standardized measure of discounted future net cash flows relating to estimated proved reserves, excluding income tax expense, is as follows:
|
2013 |
2012 |
2011 |
|||||||
|
(in millions) |
|||||||||
|
Future cash inflows |
$ |
5,081 |
$ |
2,857 |
$ |
2,483 | |||
|
Future production costs |
(942) | (658) | (641) | ||||||
|
Future development costs |
(547) | (301) | (188) | ||||||
|
Future net cash flows |
3,592 | 1,898 | 1,654 | ||||||
|
10% annual discount for estimated timing of cash flows |
(2,106) | (1,108) | (956) | ||||||
|
Standardized measure of discounted future net cash flows |
$ |
1,486 |
$ |
790 |
$ |
698 | |||
Following is an analysis of changes in the standardized measure:
|
2013 |
2012 |
2011 |
|||||||
|
(in millions) |
|||||||||
|
Standardized measure, beginning of year |
$ |
790 |
$ |
698 |
$ |
402 | |||
|
Sales and transfers of natural gas and oil produced, net of production costs |
(277) | (100) | (126) | ||||||
|
Net changes in prices and production costs |
37 | (306) | (26) | ||||||
|
Extensions, discoveries, and other additions, net of future production and development costs |
688 | 344 | 192 | ||||||
|
Acquisition of reserves in place |
– |
– |
– |
||||||
|
Sales of reserves in place |
(1) |
– |
– |
||||||
|
Revisions of previous quantity estimates |
170 | 84 | 216 | ||||||
|
Accretion of discount |
79 | 70 | 40 | ||||||
|
Standardized measure, end of year |
$ |
1,486 |
$ |
790 |
$ |
698 | |||
7
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
Acquisition of Acquired West Virginia and Southwest Pennsylvania Properties
On December 23, 2014, Southwestern Energy Company (the “Company”) filed a Current Report on Form 8-K (the “Closing Report”) to report that a subsidiary of the Company completed the acquisition of certain oil and gas assets from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) 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 $4.975 billion, subject to customary closing adjustments (the “Acquisition”). The accompanying Statements of Revenues and Direct Operating Expenses represent the direct undivided interests in the revenue and direct operating expenses associated with the Properties.
In connection with the Acquisition, on December 19, 2014, the Company entered into a $4.5 billion unsecured 364-day bridge term loan facility (the “Bridge Facility”) and a $500 million unsecured two-year term loan facility (the “Term Loan Facility”), each with syndicate of lenders, including affiliates of the underwriters of this offering. On December 22, 2014, the Company incurred aggregate borrowings of $5 billion under the Bridge Facility and the Term Loan Facility to finance the Acquisition and to pay certain fees and expenses in connection with the Acquisition.
Unaudited Pro Forma Condensed Combined Financial Statements
The unaudited pro forma condensed combined financial statements and accompanying notes reflect the pro forma effects of the Acquisition and financing assuming the use of the Bridge Facility, Term Facility and existing revolving credit facility as of January 1, 2013. The unaudited pro forma condensed combined statements of operations for the nine months ended September 30, 2014 and the year ended December 31, 2013 have been prepared based on the Company’s historical consolidated statements of operations for such periods, and were prepared as if the Acquisition and related financing had occurred on January 1, 2013. The unaudited pro forma condensed combined balance sheet at September 30, 2014 was prepared based on the Company’s historical consolidated balance sheet at September 30, 2014, and was prepared as if the Acquisition and related financing had occurred on September 30, 2014.
Final working capital and other post-closing adjustments have not been reflected in these unaudited pro forma condensed combined financial statements. Further, the initial purchase accounting for the Acquisition is not complete and adjustments to estimated amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed reviews and valuations are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date. Additionally, the unaudited pro forma condensed combined financial statements do not reflect costs of integration activities or benefits that may result from other efficiencies.
The pro forma data is based on assumptions and include adjustments as explained in the notes herein. Management believes that the assumptions used to prepare the unaudited pro forma condensed combined financial statements and accompanying notes provide a reasonable and reliably determinable basis for presenting the significant effects directly attributable to the Acquisition and related financing. The pro forma data should not be viewed as indicative of what the actual financial position or results of operations would have been had we completed the transaction on the above dates, nor are they necessarily indicative of future results. The unaudited pro forma condensed combined financial statements should be read together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, and Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, the historical Statements of Revenues and Direct Operating Expenses for the acquired Properties and the notes thereto filed as Exhibit 99.1 to the Current Report on Form 8-K filed on December 19, 2014.
1
|
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
||||||||||||
|
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET |
||||||||||||
|
SEPTEMBER 30, 2014 |
||||||||||||
|
Pro Forma |
Pro Forma |
|||||||||||
|
Southwestern |
Acquisition |
Financing |
Southwestern |
|||||||||
|
Historical |
Adjustments (a) |
Adjustments (b) |
Pro Forma |
|||||||||
|
ASSETS |
(in millions) |
|||||||||||
|
Current assets: |
||||||||||||
|
Cash and cash equivalents |
$ |
20 |
$ |
(4,975) |
$ |
4,975 |
$ |
20 | ||||
|
Accounts receivable |
457 |
– |
– |
457 | ||||||||
|
Inventories |
37 | 1 |
– |
38 | ||||||||
|
Derivative assets |
117 |
– |
– |
117 | ||||||||
|
Other current assets |
29 |
– |
53 | 82 | ||||||||
|
Total current assets |
660 | (4,974) | 5,028 | 714 | ||||||||
|
Natural gas and oil properties, using the full cost method, including $3,622 million in 2014 excluded from amortization |
14,945 | 5,025 |
– |
19,970 | ||||||||
|
Gathering systems |
1,415 |
– |
– |
1,415 | ||||||||
|
Other |
685 | 6 |
– |
691 | ||||||||
|
Less: Accumulated depreciation, depletion and amortization |
(8,652) |
– |
– |
(8,652) | ||||||||
|
Total property and equipment, net |
8,393 | 5,031 |
– |
13,424 | ||||||||
|
Other long-term assets |
124 |
– |
– |
124 | ||||||||
|
TOTAL ASSETS |
$ |
9,177 |
$ |
57 |
$ |
5,028 |
$ |
14,262 | ||||
|
LIABILITIES AND EQUITY |
||||||||||||
|
Current liabilities: |
||||||||||||
|
Accounts payable |
$ |
689 |
$ |
– |
$ |
– |
$ |
689 | ||||
|
Short-term debt |
1 |
– |
4,528 | 4,529 | ||||||||
|
Taxes payable |
69 |
– |
– |
69 | ||||||||
|
Interest payable |
14 |
– |
– |
14 | ||||||||
|
Current deferred income taxes |
32 |
– |
– |
32 | ||||||||
|
Derivative liabilities |
36 |
– |
– |
36 | ||||||||
|
Other current liabilities |
47 | 3 |
– |
50 | ||||||||
|
Total current liabilities |
888 | 3 | 4,528 | 5,419 | ||||||||
|
Long-term debt |
1,806 |
– |
500 | 2,306 | ||||||||
|
Deferred income taxes |
1,913 |
– |
– |
1,913 | ||||||||
|
Pension and other postretirement liabilities |
17 |
– |
– |
17 | ||||||||
|
Other long-term liabilities |
260 | 54 |
– |
314 | ||||||||
|
Total long-term liabilities |
3,996 | 54 | 500 | 4,550 | ||||||||
|
Commitments and contingencies |
||||||||||||
|
Equity: |
||||||||||||
|
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 353,125,665 shares in 2014 |
4 |
– |
– |
4 | ||||||||
|
Additional paid-in capital |
1,005 |
– |
– |
1,005 | ||||||||
|
Retained earnings |
3,265 |
– |
– |
3,265 | ||||||||
|
Accumulated other comprehensive income |
19 |
– |
– |
19 | ||||||||
|
Total equity |
4,293 |
– |
– |
4,293 | ||||||||
|
TOTAL LIABILITIES AND EQUITY |
$ |
9,177 |
$ |
57 |
$ |
5,028 |
$ |
14,262 | ||||
|
The accompanying notes are an integral part of these |
||||||||||||
|
unaudited pro forma condensed combined financial statements. |
||||||||||||
2
|
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
||||||||||||
|
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS |
||||||||||||
|
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014 |
||||||||||||
|
Pro Forma |
Pro Forma |
|||||||||||
|
Southwestern |
Acquisition |
Financing |
Southwestern |
|||||||||
|
Historical |
Adjustments |
Adjustments |
Pro Forma |
|||||||||
|
(in millions, except share/per share amounts) |
||||||||||||
|
Operating Revenues: |
||||||||||||
|
Gas sales |
$ |
2,155 |
$ |
113 |
(c) |
$ |
– |
$ |
2,268 | |||
|
Gas marketing |
765 |
– |
– |
765 | ||||||||
|
Oil sales |
12 | 123 |
(c) |
– |
135 | |||||||
|
NGL sales |
1 | 104 |
(c) |
105 | ||||||||
|
Gas gathering |
143 |
– |
– |
143 | ||||||||
| 3,076 | 340 |
– |
3,416 | |||||||||
|
Operating Costs and Expenses: |
||||||||||||
|
Gas purchases – midstream services |
752 |
– |
– |
752 | ||||||||
|
Operating expenses |
309 | 29 |
(c) |
– |
338 | |||||||
|
General and administrative expenses |
162 |
– |
– |
162 | ||||||||
|
Depreciation, depletion and amortization |
693 | 200 |
(d) |
– |
893 | |||||||
|
Taxes, other than income taxes |
72 | 28 |
(c) |
– |
100 | |||||||
| 1,988 | 257 |
– |
2,245 | |||||||||
|
Operating Income |
1,088 | 83 |
– |
1,171 | ||||||||
|
Interest Expense: |
||||||||||||
|
Interest on debt |
75 |
– |
68 |
(e) |
143 | |||||||
|
Other interest charges |
4 |
– |
70 |
(e) |
74 | |||||||
|
Interest capitalized |
(40) |
– |
(45) |
(e) |
(85) | |||||||
| 39 |
– |
93 | 132 | |||||||||
|
Other Gain, Net |
1 |
– |
– |
1 | ||||||||
|
Loss on Derivatives |
(29) |
– |
– |
(29) | ||||||||
|
Income (Loss) Before Income Taxes |
1,021 | 83 | (93) | 1,011 | ||||||||
|
Provision for Income Taxes: |
||||||||||||
|
Current |
34 |
– |
– |
34 | ||||||||
|
Deferred |
375 | 33 |
(f) |
(37) |
(f) |
371 | ||||||
| 409 | 33 | (37) | 405 | |||||||||
|
Net Income (Loss) |
$ |
612 |
$ |
50 |
$ |
(56) |
$ |
606 | ||||
|
Earnings Per Share: |
||||||||||||
|
Basic |
$ |
1.74 |
$ |
1.72 | ||||||||
|
Diluted |
$ |
1.74 |
$ |
1.72 | ||||||||
|
Weighted Average Common Shares Outstanding: |
||||||||||||
|
Basic |
351,357,913 | 351,357,913 | ||||||||||
|
Diluted |
352,334,546 | 352,334,546 | ||||||||||
|
The accompanying notes are an integral part of these |
||||||||||||
|
unaudited pro forma condensed combined financial statements. |
||||||||||||
3
|
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES |
||||||||||||
|
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS |
||||||||||||
|
FOR THE YEAR ENDED DECEMBER 31, 2013 |
||||||||||||
|
Pro Forma |
Pro Forma |
|||||||||||
|
Southwestern |
Acquisition |
Financing |
Southwestern |
|||||||||
|
Historical |
Adjustments |
Adjustments |
Pro Forma |
|||||||||
|
(in millions, except share/per share amounts) |
||||||||||||
|
Operating Revenues: |
||||||||||||
|
Gas sales |
$ |
2,382 |
$ |
121 |
(c) |
$ |
– |
$ |
2,503 | |||
|
Gas marketing |
792 |
– |
– |
792 | ||||||||
|
Oil sales |
14 | 131 |
(c) |
– |
145 | |||||||
|
NGL sales |
2 | 90 |
(c) |
92 | ||||||||
|
Gas gathering |
181 |
– |
– |
181 | ||||||||
| 3,371 | 342 |
– |
3,713 | |||||||||
|
Operating Costs and Expenses: |
||||||||||||
|
Gas purchases – midstream services |
782 |
– |
– |
782 | ||||||||
|
Operating expenses |
328 | 35 |
(c) |
– |
363 | |||||||
|
General and administrative expenses |
191 |
– |
– |
191 | ||||||||
|
Depreciation, depletion and amortization |
787 | 246 |
(d) |
– |
1,033 | |||||||
|
Taxes, other than income taxes |
79 | 30 |
(c) |
– |
109 | |||||||
| 2,167 | 311 |
– |
2,478 | |||||||||
|
Operating Income |
1,204 | 31 |
– |
1,235 | ||||||||
|
Interest Expense: |
||||||||||||
|
Interest on debt |
100 |
– |
96 |
(e) |
196 | |||||||
|
Other interest charges |
4 |
– |
154 |
(e) |
158 | |||||||
|
Interest capitalized |
(63) |
– |
(71) |
(e) |
(134) | |||||||
| 41 |
– |
179 | 220 | |||||||||
|
Other Gain, Net |
2 |
– |
– |
2 | ||||||||
|
Gain on Derivatives |
26 |
– |
– |
26 | ||||||||
|
Income (Loss) Before Income Taxes |
1,191 | 31 | (179) | 1,043 | ||||||||
|
Provision for Income Taxes: |
||||||||||||
|
Current |
(11) |
– |
– |
(11) | ||||||||
|
Deferred |
498 | 13 |
(f) |
(73) |
(f) |
438 | ||||||
| 487 | 13 | (73) | 427 | |||||||||
|
Net Income (Loss) |
$ |
704 |
$ |
18 |
$ |
(106) |
$ |
616 | ||||
|
Earnings Per Share: |
||||||||||||
|
Basic |
$ |
2.01 |
$ |
1.76 | ||||||||
|
Diluted |
$ |
2.00 |
$ |
1.75 | ||||||||
|
Weighted Average Common Shares Outstanding: |
||||||||||||
|
Basic |
350,465,430 | 350,465,430 | ||||||||||
|
Diluted |
351,101,452 | 351,101,452 | ||||||||||
|
The accompanying notes are an integral part of these |
||||||||||||
|
unaudited pro forma condensed combined financial statements. |
||||||||||||
4
Notes to Unaudited Pro Forma Condensed Combined Financial Information
(1) BASIS OF PRESENTATION
On December 23, 2014, Southwestern Energy Company (the “Company”) filed a Current Report on Form 8-K (the “Closing Report”) to report that a subsidiary of the Company completed the acquisition of certain oil and gas assets from a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) 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 $4.975 billion, subject to customary closing adjustments (the “Acquisition”). The accompanying Statements of Revenues and Direct Operating Expenses represent the direct undivided interests in the revenue and direct operating expenses associated with the Properties.
The historical financial information is derived from the historical, consolidated financial statements of the Company and the historical statements of revenues and direct operating expenses for the Chesapeake Properties (which are based on information provided by Chesapeake). The unaudited pro forma condensed combined statements of operations were prepared assuming the Acquisition and related financing transactions occurred on January 1, 2013. The unaudited pro forma condensed combined balance sheet at September 30, 2014 was prepared based on the Company’s historical consolidated balance sheet at September 30, 2014, and was prepared as if the Acquisition and related financing had occurred September 30, 2014.
The unaudited pro forma condensed combined financial statements and underlying pro forma adjustments are based upon currently available information and certain estimates and assumptions made by the Company’s management; therefore, actual results could differ materially from the pro forma information. However, management believes the assumptions provide a reasonable basis for presenting the significant effects of the Acquisition and related financing transactions. These unaudited pro forma condensed combined financial statements are provided for illustrative purposes only and may or may not provide an indication of results in the future. As part of the Acquisition, the Company has obligations for demand charges under firm transportation agreements and gathering agreements that vary in length over approximately the next 40 years, with a peak capacity of approximately 517 MMcf/day in 2017.
(2) PRO FORMA ADJUSTMENTS AND OTHER INFORMATION
Balance Sheet. The unaudited pro forma condensed combined balance sheet at September 30, 2014 reflects the following adjustments:
|
|
(a) |
Adjustments to reflect the consideration paid and the preliminary fair value measurements of assets acquired and liabilities assumed by the Company for the Acquisition. |
The Acquisition qualifies as a business combination, and as such, the Company estimated the fair value of these properties assuming a September 30, 2014 acquisition close date, in accordance with the Financial Accounting Standards Board’s authoritative guidance on business combinations. 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 (exit price). Fair value measurements also utilize market assumptions of market participants.
The Company used a discounted cash flow model to calculate the fair value of oil and natural gas properties and asset retirement obligations (“ARO”). The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of oil and natural gas properties include the Company’s estimates of i) quantities of oil and natural gas reserves, ii) future commodity prices, iii) future operating and development costs, iv) projections of future timing and rates of production, v) expected recovery rates and vi) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates.
Estimating the future ARO requires management to make estimates and judgments regarding the existence of a liability and settlement timing, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
5
The Company estimates the fair value of the Acquisition to be approximately $4,975 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase price being recognized. The acquisition costs were insignificant and were expensed as incurred. The Acquisition is considered a taxable transaction; therefore, no deferred tax amounts were recognized at the acquisition date as the tax basis of the assets acquired and liabilities assumed were recorded at fair value.
The following table summarizes the consideration paid for the Acquisition and the fair value of the assets acquired and liabilities assumed as of September 30, 2014. The purchase price allocation is preliminary and subject to adjustments (including adjustments based upon title and environmental due diligence currently being completed).
|
Consideration given to Acquisition (in millions): |
|||
|
Cash |
$ |
4,975 | |
|
Recognized amounts of identifiable assets acquired and liabilities assumed: |
|||
|
Proved natural gas and oil properties |
$ |
2,440 | |
|
Unproved natural gas and oil properties |
2,585 | ||
|
Other property and equipment |
6 | ||
|
Inventory |
1 | ||
|
Asset retirement obligations |
(57) | ||
|
$ |
4,975 |
|
(b) |
Adjustments to reflect the financing transactions related to the Acquisition. |
The Company obtained a commitment from Bank of America, N.A. for a $4.5 billion 364-day senior unsecured bridge term loan credit facility and a $500 million two-year senior unsecured term loan credit facility. These pro forma financial statements assumed the use of the Bridge Facility and Term Facility to finance the Acquisition resulting in assumed aggregate proceeds to the Company of $5.0 billion. Additional assumed offering expenses payable by the Company would total approximately $52.6 million, which were assumed to be funded by the Term Facility and the Company’s revolving credit facility, and are included in other current assets on the unaudited pro forma condensed combined balance sheet at September 30, 2014. The Company’s historical unevaluated balance was $1,037 million and assumed $2,585 million unevaluated balance attributable to the Acquisition properties, resulting in a pro forma unevaluated balance of $3,622 million in the natural gas and oil properties line of the balance sheet as of September 30, 2014.
Statements of Operations. The unaudited pro forma condensed combined statements of operations for the nine month period ended September 30, 2014 and the year ended December 31, 2013 reflect the following adjustments:
|
(c) |
Revenues, direct operating expenses, and taxes, other than income taxes, of the oil and natural gas properties acquired in the Acquisition. The pro forma adjustments represent the reclassification of the acquired Properties’ gas, oil and NGL sales, and direct operating expenses, to conform to the presentation of the Company. |
|
(d) |
Depreciation, depletion and amortization (“DD&A”) and accretion expense for ARO related to the Properties. DD&A was calculated using the unit-of-production method under the full-cost method of accounting, and includes adjustments for (1) the increase in DD&A reflecting the fair values and production volumes attributable to the Properties and (2) the revision to the Company’s DD&A rate reflecting the proved reserve volumes acquired and future development costs associated with the Acquisition. The pro forma DD&A rate is $1.25 per Mcfe and $1.28 per Mcfe for the nine months ended September 30, 2014 and the year ended December 31, 2013, respectively. This adjustment also includes the straight-line depreciation on other property and equipment of $0.3 million and $0.4 million and the additional accretion expense on ARO of $2.3 million and $2.9 million attributable to the Properties for the nine months ended September 30, 2014 and the year ended December 31, 2013, respectively. |
|
6
|
(e) |
Interest expense, net of capitalized interest, and amortization of deferred financing costs and fees associated with the assumed borrowings under the Bridge Facility, Term Facility and revolving credit facility for the periods presented. The Company assumed that it would utilize the Bridge Facility for the year ended December 31, 2013 and enter into a new Bridge Facility agreement on January 1, 2014, with the same financing terms as the Bridge Facility utilized for the year ended December 31, 2013. The Company assumed $153.8 million for deferred financing costs and fees associated with borrowings under the Bridge facility for both the nine months ended September 30, 2014 and year ended December 31, 2013. The Company assumed other interest charge expense of $70.4 million and $153.8 million associated with the amortization of deferred financing costs and fees, for the nine months ended September 30, 2014 and year ended December 31, 2013, respectively. The other interest charge expense for the nine months ended September 30, 2014 was significantly lower as compared to the year ended December 31, 2013, due to the timing of recognition and amortization of the deferred financing costs and fees. Interest expense of $68.2 million and $96.5 million was computed using an effective interest rate of 1.5% and 1.8% for borrowings under its revolving credit facility, an estimated interest rate of 1.8% and 1.9% for assumed borrowings of $4.5 billion under our Bridge Facility, and an estimated interest rate of 1.5% and 1.6% for assumed borrowings of $500 million under our Term Facility, for the nine months ended September 30, 2014 and year ended December 31, 2013, respectively. A 1/8% change in the interest rate associated with the Bridge Facility, Term Facility and revolving credit facility would result in a change in interest expense of approximately $4.9 million and $6.3 million for the nine months ended September 30, 2014 and year ended December 31, 2013, respectively. Interest capitalized for the nine months ended September 30, 2014 and year ended December 31, 2013, was assumed to be $44.6 million and $71.2 million, respectively. The assumptions above are for pro forma purposes only, as the Company intends to replace the Bridge Facility with permanent financing which includes a mix of long-term debt and equity. |
|
(f) |
Income tax expense for the nine months ended September 30, 2014 and the year ended December 31, 2013 was recorded at 40.0% and 40.9% of pre-tax net income, respectively. The Company’s effective tax rates for the periods presented were consistent with the statutory tax rate applicable to the U.S. and the blended state rate for the states in which the Company conducts business. |
(3) PROVED RESERVES AND OPERATING DATA
Proved Reserves
The following table sets forth information about the Company’s historical estimated net proved reserves as of December 31, 2013. This reserve data represents the estimates of our reservoir engineers made under the supervision of our management. A significant portion of these reserves were audited by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, as of December 31, 2013.
In addition, the following table also sets forth information as of December 31, 2013 about the estimated net proved reserves attributable to the properties acquired in our previously-announced transaction with Chesapeake, and our pro forma estimated net proved reserves as if the Acquisition had occurred on December 31, 2013. The acquired reserve estimates at December 31, 2013 presented in the table below were prepared by Chesapeake’s reserve engineers, in accordance with the authoritative guidance of the FASB on natural gas and oil reserve estimation and disclosures.
Reserve estimates are inherently imprecise and are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, reserve estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.
7
|
December 31, 2013 |
|||||||||||||||||
|
Pro Forma |
Acquired Reserves |
Southwestern Historical |
|||||||||||||||
|
Proved Reserves |
|||||||||||||||||
|
Developed: |
|||||||||||||||||
|
Natural gas (MMcf) |
4,788,618 | 551,123 | 4,237,495 | ||||||||||||||
|
Oil (MBbl) |
10,984 | 10,612 | 372 | ||||||||||||||
|
Natural gas liquids (MBbl) |
21,599 | 21,599 |
- |
||||||||||||||
|
Undeveloped: |
|||||||||||||||||
|
Natural gas (MMcf) |
3,105,403 | 368,821 | 2,736,582 | ||||||||||||||
|
Oil (MBbl) |
3,845 | 3,844 | 1 | ||||||||||||||
|
Natural gas liquids (MBbl) |
18,968 | 18,968 |
- |
||||||||||||||
|
Total Proved Reserves |
|||||||||||||||||
|
(MMcfe)1 |
8,226,402 | 1,250,087 | 6,976,315 | ||||||||||||||
|
Calculated average price used in estimates2: |
|||||||||||||||||
|
Gas ($/Mcf) |
$ |
3.67 |
$ |
3.67 |
$ |
3.67 | |||||||||||
|
Oil ($/Bbl) |
$ |
96.74 |
$ |
96.82 |
$ |
93.42 | |||||||||||
|
1 |
Oil, condensate, and natural gas liquids are converted to natural gas at the ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of natural gas. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil, condensate, or natural gas liquids to an Mcf of natural gas. The sales price of one barrel of oil, condensate, or natural gas liquids has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to one barrel of oil, condensate, or natural gas liquids. |
|
2 |
Reflects natural gas and oil spot prices based on the average price during the 12-month period before the date of the estimate determined as an unweighted, arithmetic average of the first day of the month price for each month in the period. |
Sustained lower commodities prices, especially natural gas, can reduce the quantity of our reserves by causing the economic limit of our developed and proposed undeveloped wells (the point at which the costs to operate exceed the value of estimated future production, assuming constant prices and costs under Securities Exchange Commission rules) to occur earlier in their productive lives than would be the case with higher prices. Our undeveloped reserves may also be reduced by the elimination of wells we planned to drill because they would not be economically producible at such prices and costs. Our proved undeveloped reserves may also be eliminated, or reduced to probable reserves, by the deferral of drilling of otherwise economic wells beyond the five year proved reserve development horizon as a result of revisions to our development plan adopted in response to lower prices or otherwise.
Pro forma Standardized Measure of Discounted Future Net Cash Flows
The following table presents the Standardized Measure of Discounted Future Net Cash Flows relating to the proved crude oil and natural gas reserves of the Company and of the properties acquired in the Acquisition on a pro forma combined basis as of December 31, 2013. The Standardized Measure shown below represents estimates only and should not be construed as the current market value of our estimated oil and natural gas reserves or those estimated oil and natural gas reserves attributable to the Properties acquired.
8
|
December 31, 2013 |
|||||||||||
|
Southwestern |
Acquired |
||||||||||
|
Historical |
Reserves |
Adjustment |
Pro Forma |
||||||||
|
(In millions) |
|||||||||||
|
Future Cash Inflows |
$ |
22,625 |
$ |
5,081 |
$ |
- |
$ |
27,706 | |||
|
Future Production Costs |
(8,896) | (942) |
- |
(9,838) | |||||||
|
Future Development Costs |
(3,627) | (547) |
- |
(4,174) | |||||||
|
Future Income Tax |
(3,223) |
- |
(1,478) | (4,701) | |||||||
|
Future Net Cash Flows |
$ |
6,879 |
$ |
3,592 |
$ |
(1,478) |
$ |
8,993 | |||
|
Discount to present value at 10% annual rate |
(3,143) | (2,106) | 867 | (4,382) | |||||||
|
Standardized Measure |
$ |
3,736 |
$ |
1,486 |
$ |
(611) |
$ |
4,611 | |||
Pro forma income tax expense reflects expense on the combined future net cash flows based on the Company’s estimated effective tax rate, after giving effect to the pro forma transactions. Variances in the Company’s effective tax rate from the 35% federal statutory rate primarily result from the effect of state income taxes.
Operating Data
The following table sets forth certain information regarding production volumes associated with our sale of natural gas, oil and natural gas liquids for the year ended December 31, 2013. Pro forma information for the year ended December 31, 2013 gives effect to the Acquisition as if it occurred on January 1, 2013.
|
Year Ended December 31, 2013 |
||||||
|
Pro |
Acquired |
Southwestern |
||||
|
Forma |
Properties |
Historical |
||||
|
Net production: |
||||||
|
Natural gas (MMcf) |
713,676 | 57,972 | 655,704 | |||
|
Oil (MBbl) |
1,660 | 1,522 | 138 | |||
|
NGL (MBbl) |
2,547 | 2,497 | 50 | |||
|
Total (MMcfe) |
738,918 | 82,086 | 656,832 | |||
9
Southwestern Energy Company
10000 Energy Drive Spring, Texas 77389
August 25, 2015
Securities and Exchange Commission
ATTN: Filing Desk, Stop 1-4
450 Fifth Street, N. W.
Washington, DC 20549-1004
Ladies and Gentlemen:
Pursuant to regulations of the Securities and Exchange Commission, submitted herewith for filing on behalf of Southwestern Energy Company is Form 8-K/A dated December 19, 2014.
This filing is being effected by direct transmission to the Commission's EDGAR System.
Kind Regards,
/s/JOSH C. ANDERS
Vice President and Controller