Atlas Pipeline Partners, L.P. (NYSE:APL) (“APL” or the “Partnership”) today reported financial results for the second quarter 2009.
Highlights from the second quarter 2009 and recent events include the following:
- Net income was $133.4 million compared with a net loss of $275.6 million for the prior year second quarter. The increase between periods was due primarily to gain on sales of the NOARK system and a 51% ownership interest in the Appalachia system during the current period and losses incurred in the prior year period for the early termination of certain derivatives and mark-to-market derivative adjustments, partially offset by lower overall commodity prices;
- Adjusted earnings before interest, income taxes, depreciation and amortization (“adjusted EBITDA”), a non-GAAP measure, was $104.3 million in the second quarter 2009, including gains on sale of assets and realized hedge losses, compared to $74.8 million for the prior year comparable quarter. Adjusted EBITDA for the second quarter 2009 included realized cash gains on sale of approximately $81.3 million from the divesture of the NOARK system and from the formation of a joint venture, Laurel Mountain Midstream, LLC (“Laurel Mountain”), for APL’s Appalachia natural gas gathering system with Williams. These cash gains were partially offset by approximately $23.4 million of realized losses in the second quarter 2009 from legacy derivative positions. As previously announced, the Partnership has revised its hedge strategy to primarily focus on using options. This adaptation to the hedge strategy should greatly reduce the potential for future hedge loss experience. A reconciliation of non-GAAP measures, including adjusted EBITDA and distributable cash flow, is provided within the financial tables of this release;
- Excluding the gains on sale and realized hedge losses in the second quarter 2009 discussed above, adjusted EBITDA was $46.4 in the second quarter 2009 compared with $74.8 million for the prior year comparable quarter. The decrease between periods was principally due to lower overall commodity prices;
- Natural gas liquid (“NGL”) production in the second quarter 2009 increased by 5.0% compared to prior year second quarter despite lower processed natural gas volumes. The increase is due primarily to improved efficiencies on the Partnership’s processing systems;
- The Partnership closed the sales of the NOARK natural gas gathering and interstate transmission system (“NOARK”) and the Sweetwater II processing facility (“Sweetwater II”) and also completed the joint venture transaction with Williams for APL’s northern Appalachia gathering system. Total combined proceeds from the transactions of approximately $405 million were used to reduce indebtedness;
- APL successfully amended its senior secured credit facility with its lenders, creating greater financial flexibility and increased liquidity for the Partnership; and
- The Partnership reduced administrative and operating expenses due to cost reduction initiatives and operating efficiencies achieved on its systems.
Recent Events
Amendment to Credit Facility
On May 29, 2009, the Partnership entered into an amendment to its revolving credit and term loan agreement. This amendment created greater financial flexibility for the Partnership through relaxed financial covenants and improved its liquidity position by increasing the asset sale reinvestment basket allowing for the successful completion of certain growth capital projects. As a result of the amendment, lenders approved the recently announced joint venture with Williams to form Laurel Mountain, which will own and operates all of the Partnership’s northern Appalachian assets, including gathering and processing assets in the Marcellus Shale region in southwestern Pennsylvania. In conjunction with the amendment, the Partnership will not pay any further distributions for the remainder of 2009. Beginning with the first quarter 2010, Atlas Pipeline may pay distributions if, pro forma for such payment, its senior secured leverage ratio, as defined in the credit agreement, is less than or equal to 2.75x and minimum liquidity, as defined in the credit agreement, are satisfied.
Sale of NOARK Pipeline System
On April 7, 2009, the Partnership entered into a definitive agreement with Spectra Energy Partners OLP, LP to sell NOARK for approximately $294.5 million in cash, net of working capital adjustments. The transaction closed on May 4, 2009 and the proceeds were used to reduce borrowings under the Partnership’s senior secured term loan and revolving credit facility.
Sale of Sweetwater II Facility
On July 13, 2009, the Partnership announced the sale of a redundant natural gas processing facility, Sweetwater II, for approximately $22.6 million in cash to Penn Virginia Resource Partners, L.P. (“Penn Virginia”). Penn Virginia will provide volumes to the Sweetwater II facility and will reimburse the Partnership for its proportionate share of plant operating expenses. The property sold had been superseded by the Partnership’s new Nine Mile processing facility completed earlier this year and is likewise located in western Oklahoma. The proceeds from the transaction were used to reduce outstanding borrowings on the Partnership’s senior secured term loan.
Mid-Continent Segment Results
- The Velma system’s average natural gas processed volume was 77.3 Mmcfd for the second quarter 2009, an increase of approximately 24.4% compared with the prior year comparable quarter. This increase is primarily due to the expansion of the gathering system and connections made to new production through the recently installed Madill pipeline. Average NGL production also increased to 8,497 bpd, an increase of 21.5% compared to the prior year second quarter.
- The western Oklahoma systems, comprised of the Elk City/Sweetwater and Chaney Dell complexes, had average NGL production of 25,244 bpd, an increase of 6.0% compared to the prior year second quarter and flat with the first quarter 2009, due primarily to improved plant efficiencies. Average natural gas processed volume was 435.9 Mmcfd for the second quarter 2009, a decrease of 10.4% from the prior year comparable quarter.
- The Midkiff/Benedum system’s average natural gas processed volume was 150.1 Mmcfd for the second quarter 2009, an increase of approximately 6.3% compared with the prior year comparable quarter. Average NGL production volumes decreased to 20,473 bpd, or 2% when compared to the prior year comparable quarter. NGL production at the Midkiff/Benedum complex is expected to be enhanced with the efficiencies provided by the new consolidator plant scheduled for completion by the end of the year.
- Mid-Continent segment total revenue for the second quarter 2009 decreased to $167.0 million, or approximately 45% compared with the prior year comparable quarter, excluding the effect of derivative early termination cash and non-cash expenses. This decrease principally related to lower average realized commodity prices.
Appalachia Segment Results
- Gross throughput volume on the system increased to a record 107.4 MMcfd for the second quarter 2009, an increase of over 27% compared with the prior year second quarter, resulting from the connection of new wells to the Appalachia gathering system from drilling activity by APL’s affiliate, Atlas Energy Resources, LLC (NYSE: ATN).
- Total revenue for the Appalachia segment, excluding the gain on sale from the Laurel Mountain joint venture, decreased to $7.9 million for the second quarter 2009, or approximately 39%, compared with $13.0 million the prior year comparable quarter. The decrease is due primarily to APL’s contribution of the majority of the system to the Laurel Mountain joint venture, in which APL has a 49% ownership interest, as of May 31, 2009.
Corporate and Other
- General and administrative expense, including amounts reimbursed to affiliates, was $6.5 million for the second quarter 2009 compared with $9.6 million for the prior year second quarter. The decrease was primarily related to a $1.3 million decrease due to expense reduction initiatives in the Mid-Continent segment, a $1.0 million decrease in corporate allocated expenses and a $0.8 million decrease in non-cash compensation expense.
- Depreciation and amortization increased to $23.0 million for the second quarter 2009 compared with $20.4 million for the prior year second quarter due primarily to expansion capital expenditures incurred subsequent to second quarter 2008.
- Net of deferred financing costs, interest expense increased to $22.8 million for the second quarter 2009 as compared with $18.1 million for the comparable prior year period. This increase was primarily due to an increase in interest expense related to our additional senior notes issued during June 2008, partially offset by a decrease in interest expense associated with our senior secured term loan primarily due to the repayment of $370.1 million of indebtedness since June 2008 and lower unhedged interest rates.
- At June 30, 2009, the Partnership had $1.276 billion of total debt, a decrease of $249 million from the first quarter 2009 due to the repayment of debt using proceeds received from the recent sale of the NOARK pipeline and the from the Appalachia joint venture with Williams. The June 30, 2009 debt balance includes $459.9 million outstanding on its term loan that matures in 2014, $494.4 million of 8 1/8% and 8 7/8% senior unsecured notes that mature in 2015 and 2018, respectively, and $322.0 million of outstanding borrowings under its revolving credit facility that matures in 2013. The Partnership also has interest rate swap contracts for a notional principal amount totaling $450.0 million which expire during the first half of 2010.
Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s second quarter 2009 results on Friday, August 7, 2009 at 9:00 am ET by going to the Investor Relations section of the Partnership’s website at www.atlaspipelinepartners.com. An audio replay of the conference call will also be available beginning at 11:00 am ET on Friday, August 7, 2009. To access the replay, dial 1-888-286-8010 and enter conference code 74481414.
Atlas Pipeline Partners, L.P. is active in the transmission, gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, southern Kansas, northern and western Texas and the Texas panhandle, APL owns and operates eight active gas processing plants and a treating facility, as well as approximately 8,750 miles of active intrastate gas gathering pipeline. In Appalachia, APL is a 49% joint venture partner with Williams in Laurel Mountain Midstream, LLC, which manages the natural gas gathering system in that region, namely from the Marcellus Shale in southwestern Pennsylvania. For more information, visit the Partnership’s website at www.atlaspipelinepartners.com or contact investorrelations@atlaspipelinepartners.com.
Atlas Pipeline Holdings, L.P. is a limited partnership which owns and operates the general partner of Atlas Pipeline Partners, L.P., through which it owns a 2% general partner interest, all the incentive distribution rights and approximately 5.8 million common and 15,000 preferred limited partner units of Atlas Pipeline Partners, L.P.
Atlas Energy Resources, LLC is one of the largest independent natural gas producers in the Appalachian and Michigan Basins. The Company is also the country’s largest sponsor and manager of tax-advantaged energy investment partnerships that finance the exploration and development of the Company’s acreage. For more information, visit Atlas Energy’s website at www.atlasenergyresources.com or contact investor relations at InvestorRelations@atlasamerica.com.
Atlas America, Inc. owns approximately 48% of the Class B common unit interests and all of the management incentive interests in Atlas Energy Resources, LLC. Atlas America, Inc. also owns 1.1 million common units in Atlas Pipeline Partners, L.P. and a 64% interest in Atlas Pipeline Holdings, L.P. For more information, please visit our website at www.atlasamerica.com, or contact Investor Relations at InvestorRelations@atlasamerica.com.
Certain matters discussed within this press release are forward-looking statements. Although Atlas Pipeline Partners, L.P. believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurance that its expectations will be attained. Factors that could cause actual results to differ materially from expectations include financial performance, inability of the Partnership to successfully integrate the operations at the acquired systems, regulatory changes, changes in local or national economic conditions and other risks detailed from time to time in Atlas Pipeline’s reports filed with the SEC, including quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K.
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Financial Summary (unaudited; in thousands) | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2009 | 2008(1) | 2009(1) | 2008(1) | |||||||||||||
Revenue: | ||||||||||||||||
Natural gas and liquids | $ | 176,888 | $ | 430,334 | $ | 332,038 | $ | 789,949 | ||||||||
Transportation, compression and other fees – affiliates | 6,429 | 11,421 | 16,497 | 20,580 | ||||||||||||
Transportation, compression and other fees – third parties | 3,981 | 5,671 | 7,855 | 10,667 | ||||||||||||
Equity income in joint venture | 710 | − | 710 | − | ||||||||||||
Gain on asset sale | 109,941 | − | 109,941 | − | ||||||||||||
Other loss, net | (15,645 | ) | (314,259 | ) | (10,496 | ) | (401,014 | ) | ||||||||
Total revenue and other loss, net | 282,304 | 133,167 | 456,545 | 420,182 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Natural gas and liquids | 129,676 | 349,711 | 264,421 | 623,537 | ||||||||||||
Plant operating | 14,128 | 14,831 | 27,951 | 29,766 | ||||||||||||
Transportation and compression | 2,791 | 2,645 | 6,122 | 4,959 | ||||||||||||
General and administrative | 6,164 | 8,168 | 16,467 | 12,157 | ||||||||||||
Compensation reimbursement – affiliates | 375 | 1,390 | 750 | 2,519 | ||||||||||||
Depreciation and amortization | 22,999 | 20,412 | 45,667 | 40,459 | ||||||||||||
Interest | 26,392 | 19,814 | 47,500 | 40,565 | ||||||||||||
Total costs and expenses | 202,525 | 416,971 | 408,878 | 753,962 | ||||||||||||
Income (loss) from continuing operations | 79,779 | (283,804 | ) | 47,667 | (333,780 | ) | ||||||||||
Discontinued operations: | ||||||||||||||||
Gain on sale of discontinued operations | 51,078 | − | 51,078 | − | ||||||||||||
Income from discontinued operations | 2,541 | 8,245 | 11,417 | 14,491 | ||||||||||||
Income from discontinued operations | 53,619 | 8,245 | 62,495 | 14,491 | ||||||||||||
Net income (loss) | 133,398 | (275,559 | ) | 110,162 | (319,289 | ) | ||||||||||
Income attributable to non-controlling interests | (652 | ) | (3,112 | ) | (1,121 | ) | (5,202 | ) | ||||||||
Preferred unit dividends | − | (650 | ) | (900 | ) | (787 | ) | |||||||||
Preferred unit imputed dividend cost | − | − | − | (505 | ) | |||||||||||
Net income (loss) attributable to common limited partners and the general partner | $ | 132,746 | $ | (279,321 | ) | $ | 108,141 | $ | (325,783 | ) | ||||||
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Financial Summary (unaudited; in thousands, except per unit amounts) | |||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2009 | 2008(1) | 2009(1) | 2008(1) | ||||||||||||
Allocation of net income (loss) attributable to common limited partners and the general partner: | |||||||||||||||
Common limited partner interest: | |||||||||||||||
Continuing operations | $ | 77,537 | $ | (289,855 | ) | $ | 44,729 | $ | (348,363 | ) | |||||
Discontinued operations | 52,541 | 8,079 | 61,239 | 14,200 | |||||||||||
130,078 | (281,776 | ) | 105,968 | (334,163 | ) | ||||||||||
General partner interest: | |||||||||||||||
Continuing operations | 1,590 | 2,289 | 917 | 8,089 | |||||||||||
Discontinued operations | 1,078 | 166 | 1,256 | 291 | |||||||||||
2,668 | 2,455 | 2,173 | 8,380 | ||||||||||||
Net income (loss) attributable to common limited partners and the general partner: | |||||||||||||||
Continuing operations | 79,127 | (287,566 | ) | 45,646 | (340,274 | ) | |||||||||
Discontinued operations | 53,619 | 8,245 | 62,495 | 14,491 | |||||||||||
$ | 132,746 | $ | (279,321 | ) | $ | 108,141 | $ | (325,783 | ) | ||||||
Net income (loss) attributable to common limited partners per unit: | |||||||||||||||
Basic: | |||||||||||||||
Continuing operations | $ | 1.62 | $ | (7.34 | ) | $ | 0.95 | $ | (8.88 | ) | |||||
Discontinued operations | 1.11 | 0.21 | 1.31 | 0.36 | |||||||||||
$ | 2.73 | $ | (7.13 | ) | $ | 2.26 | $ | (8.52 | ) | ||||||
Diluted: | |||||||||||||||
Continuing operations | $ | 1.62 | $ | (7.34 | ) | $ | 0.95 | $ | (8.88 | ) | |||||
Discontinued operations | 1.11 | 0.21 | 1.31 | 0.36 | |||||||||||
$ | 2.73 | $ | (7.13 | ) | $ | 2.26 | $ | (8.52 | ) | ||||||
Weighted average common limited partner units outstanding: | |||||||||||||||
Basic | 47,529 | 39,329 | 46,755 | 39,046 | |||||||||||
Diluted | 47,529 | 39,329 | 46,755 | 39,046 | |||||||||||
Capital expenditure data: | |||||||||||||||
Maintenance capital expenditures | $ | 1,557 | $ | 1,971 | $ | 2,101 | $ | 3,486 | |||||||
Expansion capital expenditures | 56,742 | 64,210 | 128,393 | 138,568 | |||||||||||
Total | $ | 58,299 | $ | 66,181 | $ | 130,494 | $ | 142,054 | |||||||
June 30, | December 31, | ||||||||
Balance sheet data (at period end): | 2009 | 2008(1) | |||||||
Cash and cash equivalents | $ | 947 | $ | 1,445 | |||||
Total assets | 2,169,644 | 2,413,196 | |||||||
Total debt | 1,276,300 | 1,493,427 | |||||||
Total partners’ capital | 731,819 | 650,842 | |||||||
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Segment Information (in thousands) | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008(1) | 2009(1) | 2008(1) | |||||||||||||
Mid-Continent | ||||||||||||||||
Revenue: | ||||||||||||||||
Natural gas and liquids | $ | 176,674 | $ | 429,211 | $ | 331,453 | $ | 787,866 | ||||||||
Transportation, compression and other fees | 3,519 | 5,350 | 7,012 | 10,099 | ||||||||||||
Other loss, net | (15,711 | ) | (314,348 | ) | (10,635 | ) | (401,214 | ) | ||||||||
Total revenue and other loss, net | 164,482 | 120,213 | 327,830 | 396,751 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Natural gas and liquids | 129,595 | 349,206 | 264,151 | 622,550 | ||||||||||||
Plant operating | 14,128 | 14,831 | 27,951 | 29,766 | ||||||||||||
General and administrative | 4,956 | 6,514 | 13,270 | 8,663 | ||||||||||||
Depreciation and amortization | 21,619 | 18,868 | 42,368 | 37,533 | ||||||||||||
Total costs and expenses | 170,298 | 389,419 | 347,740 | 698,512 | ||||||||||||
Segment loss | $ | (5,816 | ) | $ | (269,206 | ) | $ | (19,910 | ) | $ | (301,761 | ) | ||||
Appalachia | ||||||||||||||||
Revenue: | ||||||||||||||||
Natural gas and liquids | $ | 214 | $ | 1,123 | $ | 585 | $ | 2,083 | ||||||||
Transportation, compression and other fees – affiliates | 6,429 | 11,421 | 16,497 | 20,580 | ||||||||||||
Transportation, compression and other fees – third parties | 462 | 321 | 843 | 568 | ||||||||||||
Equity income in joint venture | 710 | – | 710 | – | ||||||||||||
Gain on asset sale | 109,941 | – | 109,941 | – | ||||||||||||
Other income, net | 66 | 89 | 139 | 200 | ||||||||||||
Total revenue and other income, net | 117,822 | 12,954 | 128,715 | 23,431 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Natural gas and liquids | 81 | 505 | 270 | 987 | ||||||||||||
Transportation and compression | 2,791 | 2,645 | 6,122 | 4,959 | ||||||||||||
General and administrative | 792 | 1,523 | 1,974 | 3,007 | ||||||||||||
Depreciation and amortization | 1,380 | 1,544 | 3,299 | 2,926 | ||||||||||||
Total costs and expenses | 5,044 | 6,217 | 11,665 | 11,879 | ||||||||||||
Segment profit | $ | 112,778 | $ | 6,737 | $ | 117,050 | $ | 11,552 | ||||||||
Reconciliation of segment profit (loss) to net income (loss): | ||||||||||||||||
Segment profit (loss): | ||||||||||||||||
Mid-Continent | $ | (5,816 | ) | $ | (269,206 | ) | $ | (19,910 | ) | $ | (301,761 | ) | ||||
Appalachia | 112,778 | 6,737 | 117,050 | 11,552 | ||||||||||||
Total segment income (loss) | 106,962 | (262,469 | ) | 97,140 | (290,209 | ) | ||||||||||
Corporate general and administrative expenses | (791 | ) | (1,521 | ) | (1,973 | ) | (3,006 | ) | ||||||||
Interest expense | (26,392 | ) | (19,814 | ) | (47,500 | ) | (40,565 | ) | ||||||||
Income (loss) from continuing operations | 79,779 | (283,804 | ) | 47,667 | (333,780 | ) | ||||||||||
Income from discontinued operations | 53,619 | 8,245 | 62,495 | 14,491 | ||||||||||||
Net income (loss) | $ | 133,398 | $ | (275,559 | ) | $ | 110,162 | $ | (319,289 | ) | ||||||
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES (unaudited; in thousands) | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2009 | 2008 (1) | 2009 | 2008 (1) | |||||||||||||
Reconciliation of net income (loss) to other non-GAAP measures(2): | ||||||||||||||||
Net income (loss) | $ | 133,398 | $ | (275,559 | ) | $ | 110,162 | $ | (319,289 | ) | ||||||
Income attributable to non-controlling interests | (652 | ) | (3,112 | ) | (1,121 | ) | (5,202 | ) | ||||||||
Depreciation and amortization | 22,999 | 20,412 | 45,667 | 40,459 | ||||||||||||
Interest expense | 26,392 | 19,814 | 47,500 | 40,565 | ||||||||||||
NOARK depreciation and amortization (included within income from discontinued operations) | 761 | 1,803 | 2,773 | 3,600 | ||||||||||||
NOARK asset impairment (included within income from discontinued operations) | − | 3,981 | − | 7,962 | ||||||||||||
NOARK interest expense (income) (included within income from discontinued operations) | 3 | (429 | ) | 29 | (799 | ) | ||||||||||
EBITDA | 182,901 | (233,090 | ) | 205,010 | (232,704 | ) | ||||||||||
Non-cash derivative expense | 2,497 | 181,147 | 46,515 | 258,003 | ||||||||||||
Early termination cash derivative expense(3) | − | 116,125 | 5,000 | 116,125 | ||||||||||||
Non-recurring crude oil to natural gas liquids price correlation impact(4) | − | 10,653 | − | 10,653 | ||||||||||||
Non-cash portion of gain on asset sale(5) | (79,733 | ) | − | (79,733 | ) | − | ||||||||||
Non-cash linefill (gain) loss(6) | (1,747 | ) | (1,215 | ) | (2,216 | ) | (2,356 | ) | ||||||||
Non-cash compensation expense (income) | 352 | 1,195 | 259 | (1,600 | ) | |||||||||||
Adjusted EBITDA | 104,270 | 74,815 | 174,835 | 148,121 | ||||||||||||
Interest expense | (26,392 | ) | (19,814 | ) | (47,500 | ) | (40,565 | ) | ||||||||
NOARK interest income (expense) (included within income from discontinued operations) | (3 | ) | 429 | (29 | ) | 799 | ||||||||||
Amortization of deferred financing costs | 3,636 | 1,929 | 4,653 | 2,608 | ||||||||||||
Preferred unit dividends | − | (650 | ) | (900 | ) | (787 | ) | |||||||||
Maintenance capital expenditures | (1,557 | ) | (1,971 | ) | (2,101 | ) | (3,486 | ) | ||||||||
NOARK maintenance capital expenditures (included within discontinued operations) | (303 | ) | (74 | ) | (454 | ) | (178 | ) | ||||||||
Distributable cash flow | $ | 79,651 | $ | 54,664 | $ | 128,504 | $ | 106,512 |
(1) | Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of its NOARK gas gathering and interstate pipeline system. | |||
(2) | EBITDA, adjusted EBITDA and distributable cash flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission. Management of the Partnership believes that EBITDA, adjusted EBITDA and distributable cash flow provide additional information for evaluating the Partnership’s ability to make distributions to its common unitholders and the general partner, among other things. These measures are widely used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards. EBITDA and adjusted EBITDA are also financial measurements that, with certain negotiated adjustments, are utilized within the Partnership’s financial covenants under its credit facility. EBITDA, adjusted EBITDA and distributable cash flow are not measures of financial performance under GAAP and, accordingly, should not be considered as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP. | |||
(3) | During the three months ended March 31, 2009, the Partnership made net payments of $5.0 million related to the early termination of derivative contracts for second quarter 2009 production periods. These payments were funded through the Partnership’s March 2009 issuance of 5,000 12.0% convertible preferred units of limited partner interests to Atlas Pipeline Holdings, L.P. (NYSE: AHD), the owner of the Partnership’s general partner, for cash consideration of $1,000 per preferred unit. The Partnership had previously entered into an amendment to its credit facility to revise the definition of Consolidated EBITDA to allow for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of equity. | |||
(4) | Represents the non-recurring impact generated from the decline in the price correlation of crude oil and natural gas liquids during the second quarter 2008 and the resulting impact it had on certain crude oil derivative instruments (“proxy hedges”) which the Partnership intended to mitigate the effect of commodity price movements on the ethane and propane portion of its natural gas liquid production volume. These derivative instruments were put in place simultaneously with the Partnership’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and have become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. During 2008, the Partnership closed the derivative positions it had on approximately 85% of the ethane and propane portion of its NGL production volume for the periods from principally the 2nd quarter 2008 through the 4th quarter of 2009 for an aggregate net cost of $274.0 million. As such, the Partnership’s future cash flow should more accurately reflect the revenues generated from its ethane and propane volumes produced in its natural gas processing operations. | |||
(5) | Represents the portion of the gain on sale recognized upon the sale of the Partnership’s Appalachia gathering system related to the $25.5 million note receivable from which the Partnership has preferential rights to the net proceeds and the portion of the gain attributed to the increase of the Partnership’s investment in the Laurel Mountain joint venture to fair value. | |||
(6) | Includes the non-cash impact of commodity price movements on pipeline linefill inventory. | |||
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Operating Highlights | ||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||
2009 | 2008 | 2009 | 2008 | |||||
Mid-Continent – Velma System(1) | ||||||||
Natural Gas | ||||||||
Gross natural gas gathered – mcfd | 80,068 | 65,519 | 73,050 | 63,960 | ||||
Gross natural gas processed – mcfd | 77,300 | 62,148 | 70,625 | 61,008 | ||||
Gross residue natural gas – mcfd | 61,354 | 49,033 | 55,794 | 48,086 | ||||
Natural Gas Liquids | ||||||||
Gross NGL sales – bpd | 8,497 | 6,993 | 7,770 | 6,841 | ||||
Condensate | ||||||||
Gross condensate sales – bpd | 416 | 296 | 381 | 277 | ||||
Mid-Continent – Elk City/Sweetwater System(1) | ||||||||
Natural Gas | ||||||||
Gross natural gas gathered – mcfd | 221,192 | 292,544 | 237,445 | 298,961 | ||||
Gross natural gas processed – mcfd | 216,804 | 229,673 | 235,258 | 233,038 | ||||
Gross residue natural gas – mcfd | 196,613 | 207,859 | 214,228 | 210,495 | ||||
Natural Gas Liquids | ||||||||
Gross NGL sales – bpd | 11,581 | 10,452 | 11,650 | 10,565 | ||||
Condensate | ||||||||
Gross condensate sales – bpd | 337 | 284 | 432 | 324 | ||||
Mid-Continent – Chaney Dell System(1) | ||||||||
Natural Gas | ||||||||
Gross natural gas gathered – mcfd | 276,901 | 284,528 | 289,889 | 268,008 | ||||
Gross natural gas processed – mcfd | 219,129 | 256,835 | 223,468 | 252,348 | ||||
Gross residue natural gas – mcfd | 240,518 | 243,465 | 248,204 | 231,830 | ||||
Natural Gas Liquids | ||||||||
Gross NGL sales – bpd | 13,663 | 13,358 | 13,674 | 12,880 | ||||
Condensate | ||||||||
Gross condensate sales – bpd | 909 | 855 | 918 | 781 | ||||
Mid-Continent – Midkiff/Benedum System(1) | ||||||||
Natural Gas | ||||||||
Gross natural gas gathered – mcfd | 161,355 | 150,157 | 157,687 | 146,350 | ||||
Gross natural gas processed – mcfd | 150,111 | 141,240 | 148,094 | 138,947 | ||||
Gross residue natural gas – mcfd | 99,106 | 96,160 | 102,155 | 96,386 | ||||
Natural Gas Liquids | ||||||||
Gross NGL sales – bpd | 20,473 | 20,830 | 21,555 | 20,590 | ||||
Condensate | ||||||||
Gross condensate sales – bpd | 1,533 | 1,567 | 1,163 | 1,144 | ||||
Appalachia(1) | ||||||||
Average throughput volume – mcfd(2) | 107,428 | 84,475 | 103,003 | 80,054 | ||||
(1) | “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day. | |
(2) | Effective May 31, 2009, this amount represents 100% of the throughput volume of Laurel Mountain, a joint venture in which the Partnership has a 49% ownership interest, for the period from May 31, 2009, the date of inception, through June 30, 2009 and the throughput volume of its Tennessee gathering system. | |
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES Current Hedge Positions through 2010 (as of August 6, 2009) |
Note: The natural gas, natural gas liquid and condensate hedge positions shown below represent the hedge contracts in place through December 31, 2010. Atlas Pipeline’s hedge position in its entirety, including any hedges for periods after December 31, 2010, will be disclosed in the Partnership’s Form 10-Q. |
INTEREST RATE HEDGES Swap Contracts | |||||||
Notional | |||||||
Term | Amount | Type | |||||
January 2008- | |||||||
January 2010 | $200,000,000 | Pay 2.88% —Receive LIBOR | |||||
April 2008- | |||||||
April 2010 | $250,000,000 | Pay 3.14% —Receive LIBOR | |||||
NATURAL GAS HEDGES | |||||||||||||
Natural Gas Sales - Fixed Price Swaps | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (MMBTU)¹ | 120,000 | 120,000 | - | - | - | - | |||||||
Average Fixed Price | $8.000 | $8.000 | - | - | - | - | |||||||
Natural Gas Basis Sales | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (MMBTU)¹ | 1,230,000 | 1,230,000 | 1,110,000 | 1,110,000 | - | - | |||||||
Average Fixed Price | $(0.558) | $(0.558) | $(0.575) | $(0.575) | - | - | |||||||
Natural Gas Purchases - Fixed Price Swaps | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (MMBTU)¹ | 2,580,000 | 2,580,000 | 2,190,000 | 2,190,000 | - | - | |||||||
Average Fixed Price | $8.687 | $8.687 | $8.635 | $8.635 | - | - | |||||||
Natural Gas Basis Purchases | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (MMBTU)¹ | 3,690,000 | 3,690,000 | 3,300,000 | 3,300,000 | - | - | |||||||
Average Fixed Price | $(0.659) | $(0.659) | $(0.560) | $(0.560) | - | - | |||||||
NATURAL GAS LIQUID (NGLs) HEDGES | |||||||||||||
NGLs Sales - Fixed Price Swaps | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (gallons) | 5,544,000 | 5,544,000 | - | - | - | - | |||||||
Average Fixed Price | $0.736 | $0.754 | - | - | - | - | |||||||
Ethane Put Options Purchased | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (gallons) | - | 630,000 | - | - | - | - | |||||||
Average Price(2) | - | $0.340 | - | - | - | - | |||||||
Propane Put Options Purchased | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (gallons) | 15,498,000 | 15,246,000 | - | - | - | - | |||||||
Average Price(2) | $0.767 | $0.820 | - | - | - | - | |||||||
Isobutane Put Options Purchased | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (gallons) | 1,008,000 | 126,000 | - | - | - | - | |||||||
Average Price(2) | $1.017 | $0.589 | - | - | - | - | |||||||
Normal Butane Put Options Purchased | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (gallons) | 5,670,000 | 3,654,000 | 3,654,000 | - | - | - | |||||||
Average Price(2) | $0.979 | $0.943 | $1.038 | - | - | - | |||||||
Natural Gasoline Put Options Purchased | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (gallons) | 5,670,000 | 3,906,000 | 3,906,000 | - | - | - | |||||||
Average Price(2) | $1.278 | $1.341 | $1.345 | - | - | - | |||||||
Crude Oil Put Options Purchased (associated with NGLs ) | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (barrels) | 69,000 | 165,000 | 172,500 | 181,500 | 66,000 | 66,000 | |||||||
Average Price(2) | $54.85 | $63.53 | $62.82 | $64.38 | $58.81 | $58.81 | |||||||
Crude Oil Call Options Sold (associated with NGLs ) | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (barrels) | 527,700 | 527,700 | 1,314,750 | 1,314,750 | 249,000 | 249,000 | |||||||
Average Price(2) | $84.70 | $84.80 | $82.81 | $82.89 | $103.85 | $103.85 | |||||||
Crude Oil Call Options Purchased (associated with NGLs) 3 | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (barrels) | - | - | 270,000 | 270,000 | 87,000 | 87,000 | |||||||
Average Price(2) | - | - | $131.93 | $131.93 | $132.93 | $132.93 | |||||||
CONDENSATE HEDGES | |||||||||||||
Crude Oil Sales (associated with condensate) | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (barrels) | 9,000 | 6,000 | - | - | - | - | |||||||
Average Price(2) | $62.70 | $62.70 | - | - | - | - | |||||||
Crude Oil Put Options Purchased (associated with condensate) | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (barrels) | 114,000 | 117,000 | 121,500 | 121,500 | 24,000 | 24,000 | |||||||
Average Price(2) | $61.85 | $64.15 | $64.30 | $65.57 | $58.81 | $58.81 |
Crude Oil Call Options Sold (associated with condensate) | |||||||||||||
3Q 2009 | 4Q 2009 | 1Q 2010 | 2Q 2010 | 3Q 2010 | 4Q 2010 | ||||||||
Volumes (barrels) | 76,500 | 76,500 | 85,500 | 85,500 | 31,500 | 31,500 | |||||||
Average Price(2) | $84.81 | $84.96 | $83.92 | $83.96 | $99.33 | $99.35 | |||||||
(1) | MMBTU represents million British Thermal Units | |
(2) | Average price for options is based upon average strike price adjusted by the premium paid or received. | |
(3) | Calls were purchased for 2010 to offset positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise. |
Contacts:
Brian J. Begley
Vice
President, Investor Relations
215-546-5005
215-553-8455 (fax)