Attached files
Exhibit 99.3
UNAUDITED PRO FORMA FINANCIAL INFORMATION OF AHD
The following unaudited pro forma condensed consolidated financial data reflects AHD’s historical results as adjusted on a pro forma basis to give effect to (a) the acquisition of assets from Atlas Energy (the “asset acquisition”) and related transactions and (b) the sale of APL’s indirect 49% ownership interest in Laurel Mountain (the “Laurel Mountain acquisition”). The estimated adjustments to effect the asset acquisition and the Laurel Mountain acquisition are described in the notes to the unaudited pro forma financial data.
The unaudited pro forma condensed consolidated balance sheet information reflects the following transactions as if they occurred as of September 30, 2010, and the unaudited pro forma condensed consolidated statements of operations information for the nine months ended September 30, 2010 and the twelve months ended December 31, 2009 reflect the following transactions as if they occurred as of the beginning of the respective period:
| • | the asset acquisition for aggregate consideration consisting of 23,379,384 AHD common units and $30.0 million in cash and the repayment of AHD’s promissory note with an outstanding principal balance of $34.4 million at September 30, 2010 to Atlas Energy (the “AHD promissory note”). The cash payments are assumed to have been funded through borrowings under a new AHD senior secured credit facility entered into in connection with the consummation of these transactions; and |
| • | the Laurel Mountain acquisition for consideration of $403.0 million in cash, excluding $10.5 million for working capital adjustments. |
The unaudited pro forma condensed consolidated balance sheet and the pro forma condensed consolidated statements of operations were derived by adjusting AHD’s historical consolidated financial statements. However, AHD’s management believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma financial data presented is for informational purposes only and is based upon available information and assumptions that the management of AHD believes are reasonable under the circumstances. This unaudited pro forma financial information is not necessarily indicative of what the financial position or results of operations of AHD and its subsidiaries would have been had the transactions been consummated on the dates assumed, nor are they necessarily indicative of any future operating results or financial position. AHD and its subsidiaries may have performed differently had the transactions actually occurred on the dates assumed.
The unaudited pro forma condensed consolidated balance sheet and the unaudited pro forma condensed consolidated statements of operations include AHD’s historical consolidated financial statements, which have been adjusted to reflect APL’s sale of Elk City Oklahoma GP, LLC and Elk City Oklahoma Pipeline, L.P. (collectively, “Elk City”) in September 2010. As such, AHD has retrospectively adjusted its prior period consolidated financial statements to reflect the amounts related to the operations of Elk City as discontinued operations in accordance with prevailing accounting literature.
1
ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED)
SEPTEMBER 30, 2010
(in thousands)
| Historical | Asset Acquisition |
Asset Acquisition Adjustments |
Laurel Mountain Acquisition |
Laurel Mountain Acquisition Adjustments |
Pro Forma |
|||||||||||||||||||
| ASSETS |
||||||||||||||||||||||||
| CURRENT ASSETS: |
||||||||||||||||||||||||
| Cash and cash equivalents |
$ | 215 | $ | — | $ | 69,768 | (a) | $ | — | $ | 397,775 | (e) | $ | 510,674 | ||||||||||
| (34,383 | )(a) | (12,000 | )(f) | |||||||||||||||||||||
| (30,000 | )(b) | |||||||||||||||||||||||
| (5,385 | )(b) | |||||||||||||||||||||||
| 124,684 | (b) | |||||||||||||||||||||||
| 97,732 | (c) | |||||||||||||||||||||||
| (74,156 | )(d) | |||||||||||||||||||||||
| (23,576 | )(d) | |||||||||||||||||||||||
| Accounts receivable |
59,421 | 26,812 | — | — | — | 86,233 | ||||||||||||||||||
| Current portion of derivative asset |
3,611 | 51,730 | (51,730 | )(c) | — | — | 3,611 | |||||||||||||||||
| Current portion of derivative receivable from investment partnerships |
— | 55 | (55 | )(d) | — | — | — | |||||||||||||||||
| Prepaid expenses and other |
14,883 | 8,477 | — | — | — | 23,360 | ||||||||||||||||||
| Total current assets |
78,130 | 87,074 | 72,899 | — | 385,775 | 623,878 | ||||||||||||||||||
| PROPERTY, PLANT AND EQUIPMENT, NET |
1,339,730 | 510,488 | — | (i) | — | — | 1,850,218 | |||||||||||||||||
| INTANGIBLE ASSETS, NET |
132,154 | 2,341 | — | — | — | 134,495 | ||||||||||||||||||
| GOODWILL, NET |
— | 31,784 | — | — | — | 31,784 | ||||||||||||||||||
| INVESTMENT IN JOINT VENTURE |
135,765 | — | — | (127,265 | ) | (8,500 | )(g) | — | ||||||||||||||||
| LONG-TERM PORTION OF DERIVATIVE ASSET |
— | 55,288 | (55,288 | )(c) | — | — | — | |||||||||||||||||
| LONG-TERM DERIVATIVE RECEIVABLE FROM INVESTMENT PARTNERSHIPS |
— | 5,481 | (5,481 | )(d) | — | — | — | |||||||||||||||||
| OTHER ASSETS, NET |
23,564 | 21,039 | — | — | 8,500 | (g) | 53,103 | |||||||||||||||||
| $ | 1,709,343 | $ | 713,495 | $ | 12,130 | $ | (127,265 | ) | $ | 385,775 | $ | 2,693,478 | ||||||||||||
| LIABILITIES AND EQUITY |
||||||||||||||||||||||||
| CURRENT LIABILITIES: |
||||||||||||||||||||||||
| Current portion of long-term debt |
$ | 34,589 | $ | — | $ | 69,768 | (a) | $ | — | $ | — | $ | 69,974 | |||||||||||
| (34,383 | )(a) | |||||||||||||||||||||||
| Accounts payable — affiliates |
10,708 | — | — | — | — | 10,708 | ||||||||||||||||||
| Accounts payable |
9,919 | 56,226 | — | — | — | 66,145 | ||||||||||||||||||
| Liabilities associated with drilling contracts |
— | 95,189 | — | — | — | 95,189 | ||||||||||||||||||
| Accrued producer liabilities |
58,143 | — | — | — | — | 58,143 | ||||||||||||||||||
| Current portion of derivative payable to investment partnerships |
— | 36,637 | (36,637 | )(d) | — | — | — | |||||||||||||||||
| Current portion of derivative liability |
1,511 | 245 | (245 | )(c) | — | — | 1,511 | |||||||||||||||||
| Accrued interest payable |
12,340 | — | — | — | — | 12,340 | ||||||||||||||||||
| Accrued well drilling and completion costs |
— | 49,494 | — | — | — | 49,494 | ||||||||||||||||||
| Accrued liabilities |
32,516 | 11,814 | — | — | — | 44,330 | ||||||||||||||||||
| Total current liabilities |
159,726 | 249,605 | (1,497 | ) | — | — | 407,834 | |||||||||||||||||
| LONG-TERM DEBT, LESS CURRENT PORTION |
507,676 | — | — | — | (12,000 | )(f) | 495,676 | |||||||||||||||||
| LONG-TERM PORTION OF DERIVATIVE PAYABLE TO INVESTMENT PARTNERSHIPS |
— | 43,055 | (43,055 | )(d) | — | — | — | |||||||||||||||||
| LONG-TERM PORTION OF DERIVATIVE LIABILITY |
5,770 | 9,041 | (9,041 | )(c) | — | — | 5,770 | |||||||||||||||||
| OTHER LONG-TERM LIABILITIES |
266 | 33,465 | — | — | — | 33,731 | ||||||||||||||||||
| EQUITY: |
||||||||||||||||||||||||
| Common limited partners’ interests |
22,840 | — | 372,200 | (b) | — | 34,580 | (e) | 501,472 | ||||||||||||||||
| (5,385 | )(b) | |||||||||||||||||||||||
| 100,813 | (b) | |||||||||||||||||||||||
| (23,576 | )(d) | |||||||||||||||||||||||
| Equity |
— | 378,329 | (378,329 | )(b) | (127,265 | ) | 127,265 | (e) | — | |||||||||||||||
| Accumulated other comprehensive loss |
(1,693 | ) | — | — | — | — | (1,693 | ) | ||||||||||||||||
| 21,147 | 378,329 | 65,723 | (127,265 | ) | 161,845 | 499,779 | ||||||||||||||||||
| Non-controlling interests |
(31,712 | ) | — | — | — | — | (31,712 | ) | ||||||||||||||||
| Non-controlling interest in Atlas Pipeline Partners, L.P. |
1,046,470 | — | — | — | 235,930 | (e) | 1,282,400 | |||||||||||||||||
| Total equity |
1,035,905 | 378,329 | 65,723 | (127,265 | ) | 397,775 | 1,750,467 | |||||||||||||||||
| $ | 1,709,343 | $ | 713,495 | $ | 12,130 | $ | (127,265 | ) | $ | 385,775 | $ | 2,693,478 | ||||||||||||
See accompanying notes to unaudited pro forma consolidated financial statements.
2
ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010
(in thousands, except per unit data)
| Historical | Asset Acquisition |
Asset Acquisition Adjustments |
Laurel Mountain Acquisition |
Laurel Mountain Acquisition Adjustments |
Pro Forma |
|||||||||||||||||||
| REVENUE: |
||||||||||||||||||||||||
| Natural gas and liquids sales |
$ | 641,978 | $ | — | $ | — | $ | — | $ | — | $ | 641,978 | ||||||||||||
| Gas and oil production |
— | 82,017 | — | — | — | 82,017 | ||||||||||||||||||
| Well construction and completion |
— | 176,685 | — | — | — | 176,685 | ||||||||||||||||||
| Transportation, gathering, processing and other fees |
29,944 | 12,275 | — | — | — | 42,219 | ||||||||||||||||||
| Administration and oversight |
— | 7,489 | — | — | — | 7,489 | ||||||||||||||||||
| Well services |
— | 16,931 | — | — | — | 16,931 | ||||||||||||||||||
| Other, net |
10,551 | (3,266 | ) | — | — | — | 7,285 | |||||||||||||||||
| Total revenue and other, net |
682,473 | 292,131 | — | — | — | 974,604 | ||||||||||||||||||
| COSTS AND EXPENSES: |
||||||||||||||||||||||||
| Natural gas and liquids sales |
521,495 | — | — | — | — | 521,495 | ||||||||||||||||||
| Gas and oil production |
— | 19,154 | — | — | — | 19,154 | ||||||||||||||||||
| Well construction and completion |
— | 149,724 | — | — | — | 149,724 | ||||||||||||||||||
| Plant operating |
36,492 | — | — | — | — | 36,492 | ||||||||||||||||||
| Transportation, gathering and processing |
721 | 12,816 | — | — | — | 13,537 | ||||||||||||||||||
| Well services |
— | 7,691 | — | — | — | 7,691 | ||||||||||||||||||
| General and administrative |
25,350 | — | 5,385 | (h) | — | — | 30,735 | |||||||||||||||||
| Depreciation, depletion and amortization |
55,647 | 30,726 | — | (i) | — | — | 86,373 | |||||||||||||||||
| Total costs and expenses |
639,705 | 220,111 | 5,385 | — | — | 865,201 | ||||||||||||||||||
| OPERATING INCOME |
42,768 | 72,020 | (5,385 | ) | — | — | 109,403 | |||||||||||||||||
| Equity income in joint venture |
4,137 | — | — | (4,137 | ) | — | — | |||||||||||||||||
| Interest expense |
(80,588 | ) | — | (1,727 | )(j) | — | 621 | (l) | (79,714 | ) | ||||||||||||||
| 1,980 | (k) | |||||||||||||||||||||||
| Income (loss) from continuing operations |
(33,683 | ) | 72,020 | (5,132 | ) | (4,137 | ) | 621 | 29,689 | |||||||||||||||
| Discontinued operations |
320,684 | — | — | — | — | 320,684 | ||||||||||||||||||
| Net income (loss) |
287,001 | 72,020 | (5,132 | ) | (4,137 | ) | 621 | 350,373 | ||||||||||||||||
| Income attributable to non-controlling interests |
(3,338 | ) | — | — | — | — | (3,338 | ) | ||||||||||||||||
| Income (loss) attributable to non-controlling interest in Atlas Pipeline Partners, L.P. |
(251,721 | ) | — | — | — | 3,019 | (m) | (248,702 | ) | |||||||||||||||
| Net income (loss) attributable to common limited partners |
$ | 31,942 | $ | 72,020 | $ | (5,132 | ) | $ | (4,137 | ) | $ | 3,640 | $ | 98,333 | ||||||||||
| Income attributable to common limited partners: |
||||||||||||||||||||||||
| Income (loss) from continuing operations |
$ | (7,918 | ) | $ | 58,473 | |||||||||||||||||||
| Income from discontinued operations |
39,860 | 39,860 | ||||||||||||||||||||||
| Net income attributable to common limited partners |
$ | 31,942 | $ | 98,333 | ||||||||||||||||||||
| Net income attributable to common limited partners per unit — basic: |
||||||||||||||||||||||||
| Income (loss) from continuing operations attributable to common limited partners |
$ | (0.29 | ) | $ | 1.14 | |||||||||||||||||||
| Income from discontinued operations attributable to common limited partners |
1.44 | 0.78 | ||||||||||||||||||||||
| Net income attributable to common limited partners |
$ | 1.15 | $ | 1.92 | ||||||||||||||||||||
| Net income attributable to common limited partners per unit — diluted: |
||||||||||||||||||||||||
| Income (loss) from continuing operations attributable to common limited partners |
$ | (0.29 | ) | $ | 1.14 | |||||||||||||||||||
| Income from discontinued operations attributable to common limited partners |
1.44 | 0.78 | ||||||||||||||||||||||
| Net income attributable to common limited partners |
$ | 1.15 | $ | 1.92 | ||||||||||||||||||||
| Weighted average common limited partner units outstanding: |
||||||||||||||||||||||||
| Basic |
27,704 | 51,083 | (n) | |||||||||||||||||||||
| Diluted |
27,704 | 51,083 | (n) | |||||||||||||||||||||
See accompanying notes to unaudited pro forma consolidated financial statements.
3
ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2009
(in thousands, except per unit data)
| Historical | Asset Acquisition |
Asset Acquisition Adjustments |
Laurel Mountain Acquisition |
Laurel Mountain Acquisition Adjustments |
Pro Forma |
|||||||||||||||||||
| REVENUE: |
||||||||||||||||||||||||
| Natural gas and liquids sales |
$ | 671,078 | $ | — | $ | — | $ | (587 | ) | $ | — | $ | 670,491 | |||||||||||
| Gas and oil production |
— | 108,821 | — | — | — | 108,821 | ||||||||||||||||||
| Well construction and completion |
— | 372,045 | — | — | — | 372,045 | ||||||||||||||||||
| Transportation, gathering, processing and other fees |
23,129 | 17,432 | — | (16,996 | ) | — | 23,565 | |||||||||||||||||
| Administration and oversight |
— | 15,554 | — | — | — | 15,554 | ||||||||||||||||||
| Well services |
— | 19,016 | — | — | — | 19,016 | ||||||||||||||||||
| Other, net |
(21,962 | ) | (1,502 | ) | — | — | — | (23,464 | ) | |||||||||||||||
| Total revenue and other, net |
672,245 | 531,366 | — | (17,583 | ) | — | 1,186,028 | |||||||||||||||||
| COSTS AND EXPENSES: |
||||||||||||||||||||||||
| Natural gas and liquids sales |
527,730 | — | — | (260 | ) | — | 527,470 | |||||||||||||||||
| Gas and oil production |
— | 22,107 | — | — | — | 22,107 | ||||||||||||||||||
| Well construction and completion |
— | 315,546 | — | — | — | 315,546 | ||||||||||||||||||
| Plant operating |
45,566 | — | — | — | — | 45,566 | ||||||||||||||||||
| Transportation, gathering and processing |
6,657 | 19,245 | — | (5,765 | ) | — | 20,137 | |||||||||||||||||
| Well services |
— | 8,745 | — | — | — | 8,745 | ||||||||||||||||||
| General and administrative |
38,932 | — | 5,385 | (h) | (8 | ) | — | 44,309 | ||||||||||||||||
| Depreciation, depletion and amortization |
75,684 | 37,509 | — | (i) | (3,006 | ) | — | 110,187 | ||||||||||||||||
| Goodwill and asset impairment loss |
10,325 | 156,359 | — | — | — | 166,684 | ||||||||||||||||||
| Total costs and expenses |
704,894 | 559,511 | 5,385 | (9,039 | ) | — | 1,260,751 | |||||||||||||||||
| OPERATING LOSS |
(32,649 | ) | (28,145 | ) | (5,385 | ) | (8,544 | ) | — | (74,723 | ) | |||||||||||||
| Equity income in joint venture |
4,043 | — | — | (4,043 | ) | — | — | |||||||||||||||||
| Gain on asset sales |
108,947 | — | — | (108,947 | ) | — | — | |||||||||||||||||
| Interest expense |
(106,531 | ) | — | (2,302 | )(j) | — | 600 | (l) | (106,970 | ) | ||||||||||||||
| 1,263 | (k) | |||||||||||||||||||||||
| Income (loss) from continuing operations |
(26,190 | ) | |
(28,145 |
) |
(6,424 | ) | (121,534 | ) | 600 | (181,693 | ) | ||||||||||||
| Discontinued operations |
84,148 | — | — | — | — | 84,148 | ||||||||||||||||||
| Net income (loss) |
57,958 | |
(28,145 |
) |
(6,424 | ) | (121,534 | ) | 600 | (97,545 | ) | |||||||||||||
| Income attributable to non-controlling interests |
(3,176 | ) | — | — | — | — | (3,176 | ) | ||||||||||||||||
| Income (loss) attributable to non-controlling interest in Atlas Pipeline Partners, L.P. |
(50,748 | ) | — | — | — | 104,859 | (m) | 54,111 | ||||||||||||||||
| Net income (loss) attributable to common limited partners |
$ | 4,034 | $ | (28,145 | ) | $ | (6,424 | ) | $ | (121,534 | ) | $ | 105,459 | $ | (46,610 | ) | ||||||||
| Income attributable to common limited partners: |
||||||||||||||||||||||||
| Loss from continuing operations |
$ | (7,839 | ) | $ | (58,483 | ) | ||||||||||||||||||
| Income from discontinued operations |
11,873 | 11,873 | ||||||||||||||||||||||
| Net income (loss) attributable to common limited partners |
$ | 4,034 | $ | (46,610 | ) | |||||||||||||||||||
| Net income attributable to common limited partners per unit — basic: |
||||||||||||||||||||||||
| Loss from continuing operations attributable to common limited partners |
$ | (0.28 | ) | $ | (1.14 | ) | ||||||||||||||||||
| Income from discontinued operations attributable to common limited partners |
0.43 | 0.23 | ||||||||||||||||||||||
| Net income (loss) attributable to common limited partners |
$ | 0.15 | $ | (0.91 | ) | |||||||||||||||||||
| Net income attributable to common limited partners per unit — diluted: |
||||||||||||||||||||||||
| Loss from continuing operations attributable to common limited partners |
$ | (0.28 | ) | $ | (1.14 | ) | ||||||||||||||||||
| Income from discontinued operations attributable to common limited partners |
0.43 | 0.23 | ||||||||||||||||||||||
| Net income (loss) attributable to common limited partners |
$ | 0.15 | $ | (0.91 | ) | |||||||||||||||||||
| Weighted average common limited partner units outstanding: |
||||||||||||||||||||||||
| Basic |
27,663 | 51,042 | (n) | |||||||||||||||||||||
| Diluted |
27,663 | 51,042 | (n) | |||||||||||||||||||||
See accompanying notes to unaudited pro forma consolidated financial statements.
4
ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
| (a) | To reflect $69.8 million of borrowings under a new $70.0 million senior secured revolving credit facility of AHD, of which $34.4 million is assumed to have been used to repay the remaining balance outstanding on a promissory note held by Atlas Energy at September 30, 2010 and $30.0 million is assumed to have been used to pay the cash portion of the asset acquisition consideration as described in note (b). |
| (b) | To reflect the consummation of the asset acquisition, including adjustments for (1) the payment of the asset acquisition consideration to the seller, including (i) the issuance of 23,379,384 AHD common units to the seller at an estimated fair value of $372.2 million as of February 17, 2011 (the estimated fair value on November 8, 2010, the date of the transaction agreement, was approximately $220.0 million) and (ii) $30.0 million in cash, (2) a $124.7 million cash adjustment amount from the seller to AHD and (3) the payment of estimated transaction expenses of approximately $5.4 million. In addition, the entry reflects an adjustment of $100.8 million to common limited partners’ interests for the remaining difference between the value of the asset acquisition consideration and the book value of the assets acquired and liabilities assumed due to the related-party relationship between the parties. |
| (c) | To reflect the monetization of derivative contracts associated with the transferred business, pursuant to the transaction agreement. |
| (d) | To reflect the payment of the $74.2 million of net proceeds attributable to third-party limited partners in the investment partnerships from the monetization of the derivative contracts associated with the transferred business, noted in (c) above, to the third-party limited partners of the investment partnerships, and the payment of $23.6 million of net proceeds to Atlas Energy pursuant to the AHD transaction agreement. |
| (e) | To reflect the consummation of the Laurel Mountain acquisition for $403.0 million in cash, excluding $10.5 million for working capital adjustments, less estimated transaction costs of approximately $5.2 million. AHD adjusted common limited partners’ interests within equity on the pro forma condensed consolidated balance sheet to reflect its equity ownership interest in APL’s estimated $270.5 million gain upon its disposition of its indirect 49% ownership interest in Laurel Mountain, which was based upon its historical cost basis in the asset at September 30, 2010, with the remaining balance of the gain reflected within non-controlling interest in Atlas Pipeline Partners, L.P. within equity. |
| (f) | To reflect the $12.0 million repayment of outstanding borrowings at September 30, 2010 under APL’s senior secured credit facility with a portion of the net proceeds received from APL’s disposition of its indirect 49% ownership interest in Laurel Mountain. |
| (g) | To reflect the reclassification of APL’s $8.5 million note receivable from Laurel Mountain, which was retained by APL and is due in installments through June 2012, from investment in joint venture to other assets, net. |
| (h) | To reflect the payment of AHD’s estimated transaction costs for the acquisition of assets in the asset acquisition of approximately $5.4 million, which are included within general and administrative expense on the pro forma condensed consolidated statement of operations. |
| (i) | Depreciation, depletion and amortization expense for the assets acquired in the asset acquisition has not been adjusted as the difference between the value of the asset acquisition consideration and the book value of the assets acquired and liabilities assumed was recorded as an adjustment to common limited partners’ interests due to the related-party relationship between the parties. The pro forma condensed consolidated statements of operations information for the nine months ended September 30, 2010 and the twelve months ended December 31, 2009 and the pro forma condensed consolidated balance sheet information as of September 30, 2010 do not include the impact of a $50.0 million impairment of oil and gas properties recognized during the three months ended December 31, 2010. |
5
Prior to AHD’s consummation of the asset acquisition, it did not own oil and gas properties. The following information is required supplementary oil and gas disclosure information for the asset acquisition for the historical periods presented.
Oil and Gas Reserve Information. The preparation of the transferred business’ natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures by ATLS’s reserve engineers. The accompanying reserve information included below is attributable only to the reserves of the assets acquired by AHD, and were derived from the reserve reports prepared for ATLS’s annual Form 10-K for the years ended December 31, 2009, 2008 and 2007. For these periods, independent third-party reserve engineers were retained to prepare a report of proved reserves related to ATLS. The reserve information for the transferred business includes natural gas and oil reserves which are all located in the United States, primarily in Colorado, Indiana, New York, Ohio, Pennsylvania and Tennessee. The independent reserves engineer’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. The independent reserves engineer’s report was prepared in accordance with generally accepted petroleum engineering and evaluation principles. The transferred business’ internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. In accordance with the modernization of oil and gas accounting, the transferred business changed its calculation of proved reserves. Under the current accounting literature, the proved reserves quantities and future net cash flows were estimated using a 12-month average pricing at December 31, 2009 based on the prices on the first day of each month. Using this calculation resulted in the use of lower prices at December 31, 2009 than would have resulted using year-end prices as required by the previous rules.
The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil, condensate and natural gas liquids owned at year end and changes in proved reserves during the last three years. Proved oil and gas reserves are those quantities of oil and gas which can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated unless such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.
There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within the transferred business or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.
Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the transferred business is as follows (unaudited):
| Gas (Mcf) | Oil (Bbls) | |||||||
| Balance, January 1, 2007 |
168,541,574 | 2,067,646 | ||||||
| Extensions, discoveries and other additions(1) |
48,268,222 | 28,947 | ||||||
| Sales of reserves in-place |
(62,699 | ) | (625 | ) | ||||
| Purchase of reserves in-place(2) |
3,509,605 | 32,887 | ||||||
| Transfers to limited partnerships |
(4,695,641 | ) | (62 | ) | ||||
| Revisions |
(9,594,082 | ) | (142,074 | ) | ||||
| Production |
(15,092,337 | ) | (14,360 | ) | ||||
| Balance, December 31, 2007 |
190,874,642 | 1,972,359 | ||||||
| Extensions, discoveries and other additions(1) |
57,953,670 | 111,972 | ||||||
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| Sales of reserves in-place |
(34,924 | ) | (161 | ) | ||||
| Purchase of reserves in-place |
3,461,987 | 794 | ||||||
| Transfers to limited partnerships |
(6,026,785 | ) | 8 | |||||
| Revisions(3) |
(30,589,331 | ) | (204,457 | ) | ||||
| Production |
(12,002,314 | ) | (154,681 | ) | ||||
| Balance, December 31, 2008 |
203,636,945 | 1,725,834 | ||||||
| Extensions, discoveries and other additions(1) |
58,349,703 | 25,737 | ||||||
| Sales of reserves in-place |
(101,295 | ) | (1,944 | ) | ||||
| Purchase of reserves in-place |
110,953 | 302 | ||||||
| Transfers to limited partnerships |
(22,125,866 | ) | — | |||||
| Revisions(4) |
(42,117,044 | ) | 265,371 | |||||
| Production |
(14,098,432 | ) | (192,578 | ) | ||||
| Balance, December 31, 2009 |
183,654,964 | 1,822,722 | ||||||
| Proved developed reserves at: |
||||||||
| January 1, 2007 |
107,683,343 | 2,064,276 | ||||||
| December 31, 2007 |
131,100,466 | 1,966,774 | ||||||
| December 31, 2008 |
137,014,900 | 1,677,664 | ||||||
| December 31, 2009 |
43,262,907 | 37,010 | ||||||
| Proved undeveloped reserves at: |
||||||||
| January 1, 2007 |
60,858,231 | 3,370 | ||||||
| December 31, 2007 |
59,774,179 | 5,585 | ||||||
| December 31, 2008 |
66,622,045 | 48,170 | ||||||
| December 31, 2009 |
140,392,057 | 1,785,712 |
| (1) | Includes a significant increase in proved undeveloped reserves both due to the addition of proved undeveloped reserves for Marcellus wells. |
| (2) | Represents the reserves purchased from the acquisition of AGO in June 2007. |
| (3) | Represents a decrease in the price of natural gas and oil compared from the year ended December 31, 2007 to the year ended December 31, 2008. |
| (4) | Represents a decrease in the price of natural gas and oil compared from the year ended December 31, 2008 to the year ended December 31, 2009, based on the change in pricing methodology to a 12-month unweighted average based on the first-day-of-the-month prices for the year ended December 31, 2009. |
Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the transferred business during the periods indicated were as follows (in thousands):
| Years Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
| Natural gas and oil properties: |
||||||||
| Proved properties |
$ | 707,218 | $ | 593,618 | ||||
| Unproved properties |
40,189 | 42,362 | ||||||
| Support equipment |
4,839 | 5,248 | ||||||
| 752,246 | 641,228 | |||||||
| Accumulated depreciation, depletion and amortization(1) |
(301,995 | ) | (113,851 | ) | ||||
| $ | 450,251 | $ | 527,376 | |||||
| (1) | During the year ended December 31, 2009, the transferred business recognized a $156.4 million impairment related to its shallow natural gas wells in the Upper Devonian Shale. Costs related to unproved properties are excluded from amortization as they are assessed for impairment. |
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Results of Operations from Oil and Gas Producing Activities. The results of operations related to the transferred business’ oil and gas producing activities during the periods indicated were as follows (in thousands):
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| Revenues(1) |
$ | 108,821 | $ | 117,396 | $ | 88,402 | ||||||
| Production costs |
(22,107 | ) | (24,366 | ) | (16,779 | ) | ||||||
| Depreciation, depletion and amortization |
(35,291 | ) | (28,340 | ) | (22,402 | ) | ||||||
| Goodwill and other asset impairment(2) |
(156,359 | ) | — | — | ||||||||
| $ | (104,936 | ) | $ | 64,690 | $ | 49,221 | ||||||
| (1) | Includes unrealized gains from mark-to-market derivatives of $26.3 million during the year ended December 31, 2007. |
| (2) | During the year ended December 31, 2009, the transferred business recognized a $156.4 million impairment related to its shallow natural gas wells in the Upper Devonian Shale. |
The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the transferred business’ proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the year ended December 31, 2009, and at year-end prices for the years ended December 31, 2008 and 2007, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual agreements. The resulting estimated future cash inflows was reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| Future cash inflows |
$ | 993,206 | $ | 1,464,734 | $ | 1,714,008 | ||||||
| Future production costs |
(429,630 | ) | (550,179 | ) | (495,156 | ) | ||||||
| Future development costs |
(75,011 | ) | (155,055 | ) | (162,281 | ) | ||||||
| Future net cash flows |
$ | 488,565 | $ | 759,499 | $ | 1,056,571 | ||||||
| Less 10% annual discount for estimated timing of cash flows |
$ | (309,748 | ) | $ | (487,884 | ) | $ | (656,367 | ) | |||
| Standardized measure of discounted future net cash flows |
$ | 178,818 | $ | 271,616 | $ | 400,204 | ||||||
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The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves, net of income taxes (in thousands):
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| Balance, beginning of year |
$ | 271,616 | $ | 400,204 | $ | 280,249 | ||||||
| Increase (decrease) in discounted future net cash flows: |
||||||||||||
| Sales and transfers of oil and gas, net of related costs |
(38,288 | ) | (58,281 | ) | (70,779 | ) | ||||||
| Net changes in prices and production costs |
(95,712 | ) | (120,320 | ) | 109,094 | |||||||
| Revisions of previous quantity estimates |
22,098 | (1,208 | ) | (4,348 | ) | |||||||
| Development costs incurred |
9,936 | 14,406 | 8,290 | |||||||||
| Changes in future development costs |
(43,615 | ) | (41,136 | ) | 6,971 | |||||||
| Transfers to limited partnerships |
(9,834 | ) | (615 | ) | (159 | ) | ||||||
| Extensions, discoveries, and improved recovery less related costs |
24,882 | 32,037 | 64,226 | |||||||||
| Purchases of reserves in-place |
141 | 5,170 | 9,664 | |||||||||
| Sales of reserves in-place, net of tax effect |
(303 | ) | (97 | ) | (105 | ) | ||||||
| Accretion of discount |
25,298 | 39,639 | 27,709 | |||||||||
| Estimated settlement of asset retirement obligations |
(2,252 | ) | (3,745 | ) | (3,499 | ) | ||||||
| Estimated proceeds on disposals of well equipment |
2,285 | 4,440 | 4,124 | |||||||||
| Changes in production rates (timing) and other |
12,566 | 1,122 | (31,233 | ) | ||||||||
| Outstanding, end of year |
$ | 178,818 | $ | 271,616 | $ | 400,204 | ||||||
| (j) | To reflect the adjustments to interest expense resulting from AHD’s borrowings of $69.8 million under a new senior secured credit facility, which are assumed to have been used to partially finance the acquisition of the transferred business and the related transaction costs, at a current interest rate of 3.3%. |
| (k) | To reflect the elimination of the historical interest expense associated with the repayment of the AHD promissory note owed to Atlas Energy in the amount of $34.4 million with a portion of the borrowings under AHD’s new senior secured credit facility. |
| (l) | To reflect the adjustment of interest expense for APL’s repayment of the $12.0 million outstanding balance under its senior secured credit facility at September 30, 2010 with a portion of the net proceeds received from its disposition of its indirect 49% ownership interest in Laurel Mountain, at an interest rate of 6.9% for the nine months ended September 30, 2010 and 5.0% for the twelve months ended December 31, 2009. |
| (m) | To reflect the adjustment of income allocated to APL’s non-controlling minority interests resulting from APL’s disposition of its indirect 49% ownership interest in Laurel Mountain. |
| (n) | To reflect the adjustment of AHD’s weighted average common limited partner units outstanding for the issuance of 23,379,384 AHD common units as part of the asset acquisition consideration. |
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