Exhibit 99.1
| | |
| Contact: | | Matthew Skelly |
| | Vice President, Investor Relations |
| | (215) 832-4120 |
| | (215) 546-5692 (fax) |
ATLAS PIPELINE PARTNERS, L.P.
REPORTS SECOND QUARTER 2010 RESULTS
Philadelphia, PA, August 2, 2010 – Atlas Pipeline Partners, L.P. (NYSE: APL) (“APL” or the “Partnership”)today reported recurring adjusted earnings before interest, income taxes, depreciation and amortization (“Recurring Adjusted EBITDA”), a non-GAAP measure, of $47.1 million in the second quarter 2010, compared to $39.0 million in the second quarter of 2009. Net income was $0.7 million for the second quarter of 2010, compared with net income of $133.4 million for the prior year second quarter, which included $161.0 million from gain on sale of assets in the Appalachia and NOARK areas. Recurring Adjusted EBITDA was higher compared to the second quarter of last year primarily due to higher realized natural gas liquids (“NGL”) and condensate prices in the current quarter. The increase was partially offset by lower processed natural gas volumes and NGL production. Recurring Adjusted EBITDA excludes earnings (including gains and losses) from asset disposals, the impact of legacy hedge positions and other one-time, non-recurring items that impact net income. The Partnership believes this measure provides a more accurate comparison of the operating results for the periods presented.
Distributable Cash Flow, a non-GAAP measure, was $26.5 million for the second quarter of 2010. Distributable Cash Flow per average common limited partner unit for the quarter was $0.50, or $2.00 annually. A reconciliation of non-GAAP measures, including Recurring Adjusted EBITDA and Distributable Cash Flow, is provided within the financial tables of this release.
“We are pleased with our solid second-quarter results and the great progress we continue to make in our operating areas. We are focusing on disciplined execution of our strategies and have grown distributable cash flow for three consecutive quarters, and volumes are up over 9% in gas and liquids across our business since the beginning of the year. Further, we are excited about the positive momentum of the company entering the second half of 2010 and into 2011. The recently announced Elk City transaction will allow us to significantly deleverage the balance sheet, increase liquidity, and de-risk our cash flows by shifting most of our keep-whole exposure to percentage-of-proceeds. Our financial flexibility will allow us to take advantage of our Laurel Mountain Midstream JV in the Marcellus Shale, and overall, our asset base opportunities look very positive,” stated Eugene Dubay, Chief Executive Officer of the Partnership.
On July 28, 2010, the Partnership announced it has entered into a definitive agreement to sell its Elk City system to Enbridge Energy Partners, L.P. (NYSE: EEP) for $682 million in cash, subject to working capital adjustments. The Partnership plans to utilize the proceeds from this transaction to repay its senior secured term loan and a significant portion of its revolving credit facility. The transaction is subject to customary closing conditions and adjustments, including clearance under the Hart-Scott-Rodino Act. The Partnership expects this transaction to close in the third or fourth quarter. Once this transaction is completed, the Partnership believes that it can achieve Adjusted EBITDA between $160 million and $200 million in 2011, or distributable cash flow between $1.80 and $2.60 per unit. A presentation of the Partnership’s debt and liquidity as of June 30, 2010 along with the impact of this transaction, which assumes all of the net proceeds from this sale are used to repay existing indebtedness outstanding, is as follows (in thousands):
| | | | | | | | | | |
Impact of Asset Sale on Outstanding Debt | | June 30, 2010
Balance | | Impact | | | June 30, 2010
Adjusted
Balance |
Current portion of long-term debt | | $ | 600 | | $ | (398 | ) | | $ | 202 |
Revolving credit facility | | | 285,000 | | | (245,155 | ) | | | 39,845 |
Term loan | | | 425,845 | | | (425,845 | ) | | | — |
8.125% Senior notes – due 2015 | | | 271,900 | | | — | | | | 271,900 |
8.75% Senior notes – due 2018 | | | 223,050 | | | — | | | | 223,050 |
Other | | | 1,965 | | | (1,326 | ) | | | 639 |
| | | | | | | | | | |
Total debt | | $ | 1,208,360 | | $ | (672,724 | ) | | $ | 535,636 |
| | | | | | | | | | |
Liquidity(defined below) | | $ | 87,024 | | $ | 245,155 | | | $ | 332,179 |
| | | | | | | | | | |
* * *
4
Capitalization, Liquidity and Hedging
The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $87.0 million as of June 30, 2010, up $42.1 million from December 31, 2009. Total debt outstanding was reduced to $1,208.4 million at June 30, 2010, from $1,254.2 million at December 31, 2009, a decrease of $45.8 million.
The Partnership had available borrowings under its revolving credit facility of $86.9 million at June 30, 2010. The Partnership had $1,208.4 million of total debt which includes $425.8 million outstanding on its term loan that matures in 2014, $495.0 million of 8 1/8% and 8 3/4% senior unsecured notes that mature in 2015 and 2018, respectively, and $285.0 million of outstanding borrowings under its $380.0 million revolving credit facility that matures in 2013. Additionally, the Partnership has $8.1 million of letters of credit outstanding.
The Partnership continues to enhance its risk management portfolio. During the second quarter 2010, the Partnership terminated a portion of its April through December 2010 sold crude call positions for $11.9 million. As of August 1, 2010, the Partnership has natural gas liquids and condensate protection in place for the remainder of 2010 and into 2011. Based on volume exclusive of the Elk City system, as of June 30, 2010, the Partnership has price protection in place for approximately 62% of margin value for the fourth quarter of 2010; and approximately 49% for first half 2011. Counterparties to the Partnership’s risk management activities consist primarily of investment grade commercial banks that are lenders under the Partnership’s credit facilities, or affiliates of such banks.
* * *
Operating Results
Gross margin was $69.4 million for the second quarter 2010, compared to $42.0 million for the prior year period. Gross margin includes total revenues and other income (or loss) less natural gas and liquids expense. The increase in gross margin was primarily due to increased commodity prices, along with increased volumes on our Midkiff/Benedum system, partially offset by the contribution of Appalachia assets to Laurel Mountain Midstream, LLC (“Laurel Mountain”) and lower production volumes on our other systems. Year-over-year volume increases on Midkiff/Benedum are a direct result of the completion of the Partnership’s Consolidator Plant during 2009 to support additional development drilling in the Permian Basin. Compared to the second quarter of 2009, volumes on Elk City/Sweetwater and Chaney Dell are lower due to decreased producer drilling activity in these areas for much of last year, which was specifically driven by lower commodity prices during the first three quarters of 2009. Volumes on our Velma system for the current quarter are consistent with same quarter last year.
Midkiff/Benedum
The Midkiff/Benedum system’s average natural gas processed volume was 164.1 million cubic feet per day (“Mmcfd”) for the second quarter 2010, compared with 150.1 Mmcfd for the prior year comparable quarter. Average gross NGL production volumes increased to 26,609 barrels per day (“bpd”), up 30.0% when compared to the prior year comparable quarter. Increased volumes are primarily due to the completion of the new Consolidator Plant, which processes gas in the growing Spraberry and Wolfberry Trends. The plant offers increased capacity and higher ethane and propane recoveries over the legacy facility. The Partnership expects volumes on this system to continue to increase through utilization of the Consolidator Plant and as its partner, Pioneer Natural Resources Company (NYSE: PXD), continues to pursue its 440 well drilling plan for 2010 and 700 wells in 2011. The Partnership has also been successful in adding natural gas volumes from other producers in the Spraberry and Wolfberry Trends.
5
Elk City/Sweetwater & Chaney Dell
The western Oklahoma assets, comprised of the Elk City/Sweetwater and Chaney Dell systems, had average NGL production of 21,597 bpd and average natural gas processed volume of 404.3 Mmcfd for the second quarter 2010, which represent a 14.4% and 7.3% reduction, respectively, from the prior year comparable period. System volumes were lower in the second quarter 2010 due to decreased drilling in western Oklahoma. The Partnership completed an expansion of its Chaney Dell system into Kansas during June 2010, on-time and on-budget and expects to see increased volumes from this expansion during the second half of the year and into 2011.
Velma
The Velma system’s average natural gas processed volume was 72.6 Mmcfd for the second quarter 2010, a decrease of approximately 6.0% compared with the prior year comparable quarter. The decrease is primarily due to downtime at the Velma plant for maintenance. Gathered volumes were down only 1.1 Mmcfd, or 1.3% compared to the same quarter last year. Average NGL production decreased to 8,230, or approximately 3.1%, compared to 8,497 bpd for the prior year second quarter due to the decreased processed volumes resulting from the downtime.
Appalachia
Volumes on the Laurel Mountain system averaged 101.8 Mmcfd during the second quarter 2010, up 3.7% compared to the second quarter 2009. Volumes on this system continue to increase and are expected to grow more significantly as expansion projects on this system are beginning to come online. The first significant looping project in eastern Greene County in southwestern Pennsylvania was completed in June 2010 and average volumes for the month were approximately 12% higher than the quarterly average. Additional projects are expected to come online throughout the rest of 2010 and 2011. Laurel Mountain is the joint venture established between the Partnership and The Williams Companies, Inc. (NYSE: WMB) in June 2009, in which APL has a 49% ownership interest. Laurel Mountain will benefit from Atlas Energy, Inc.’s (NASDAQ: ATLS) future production growth in the Marcellus Shale.
* * *
Corporate and Other
General and administrative expense, including amounts reimbursed to affiliates and non-cash compensation expense, decreased $0.3 million to $6.2 million for the second quarter 2010, compared with $6.5 million for the prior year comparable period. The decrease from second quarter 2009 was primarily related to a $0.3 million decrease in salaries and wages resulting from a credit to compensation expense related to the re-measurement of the fair value of share based awards.
Depreciation and amortization expense was $22.9 million for the second quarter 2010, compared with $23.0 million for the prior year comparable quarter. Depreciation in the Mid-Continent increased $1.1 million due primarily to expansion capital expenditures incurred subsequent to March 31, 2009, offset by a decrease of $1.2 million in Appalachia due to the sale of assets in the second quarter 2009.
Net of deferred financing costs, interest expense increased to $23.0 million for the second quarter 2010 as compared with $22.8 million for the prior year. This increase was primarily due to an increase in the interest rate on the Partnership’s revolver and senior secured term loans, offset by a $67.9 million reduction in debt outstanding since June 30, 2009.
* * *
Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s second quarter 2010 results on Tuesday, August 3, 2010 at 9:00 am ET by going to the Investor Relations section of the Partnership’s website atwww.atlaspipelinepartners.com. An audio replay of the conference call will also be available beginning at 12:00 pm ET on Tuesday, August 3, 2010. To access the replay, dial 1-888-286-8010 and enter conference code 11134056.
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Atlas Pipeline Partners, L.P. is active in the 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 9,100 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 a natural gas gathering system focused on the Marcellus Shale in southwestern Pennsylvania. For more information, visit the Partnership’s website atwww.atlaspipelinepartners.com or contactinvestorrelations@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 1.9% general partner interest, all the incentive distribution rights and approximately 5.8 million common and 15,000 $1,000 par value 12% preferred limited partner units of Atlas Pipeline Partners, L.P.
Atlas Energy, Inc. is one of the largest independent natural gas producers in the Appalachian and Michigan Basins and a leading producer in the Marcellus Shale in Pennsylvania. Atlas Energy, Inc. is also the country’s largest sponsor and manager of tax-advantaged energy investment partnerships. Atlas Energy also owns 1.1 million common units in Atlas Pipeline Partners, L.P. and a 64% interest in Atlas Pipeline Holdings. For more information, please visit our website atwww.atlasenergy.com, or contact Investor Relations atInvestorRelations@atlasenergy.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. We do not undertake any duty to update any forward-looking statement except as required by law. Factors that could cause actual results to differ materially from expectations include general industry considerations, regulatory changes, changes in commodity process and 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.
7
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary(1)
(unaudited; in thousands)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
June 30, | | | Six Months Ended
June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
Revenue: | | | | | | | | | | | | | | | | |
Natural gas and liquids | | $ | 230,941 | | | $ | 166,436 | | | $ | 491,890 | | | $ | 310,569 | |
Transportation, processing and other fees– affiliates | | | 155 | | | | 6,429 | | | | 331 | | | | 16,497 | |
Transportation, processing and other fees– third parties | | | 14,544 | | | | 14,433 | | | | 28,623 | | | | 29,324 | |
Other income (loss), net | | | 10,540 | | | | (15,645 | ) | | | 17,109 | | | | (10,496 | ) |
| | | | | | | | | | | | | | | | |
Total revenue and other income (loss), net | | | 256,180 | | | | 171,653 | | | | 537,953 | | | | 345,894 | |
| | | | | | | | | | | | | | | | |
| | | | |
Costs and expenses: | | | | | | | | | | | | | | | | |
Natural gas and liquids | | | 186,796 | | | | 129,676 | | | | 393,459 | | | | 264,421 | |
Plant operating | | | 15,694 | | | | 14,128 | | | | 31,228 | | | | 27,951 | |
Transportation and compression | | | 232 | | | | 2,791 | | | | 421 | | | | 6,122 | |
General and administrative(2) | | | 3,935 | | | | 5,812 | | | | 13,231 | | | | 16,208 | |
General and administrative – non-cash unit-based compensation(2) | | | 1,904 | | | | 352 | | | | 2,027 | | | | 259 | |
Compensation reimbursement – affiliates | | | 375 | | | | 375 | | | | 750 | | | | 750 | |
Depreciation and amortization | | | 22,899 | | | | 22,999 | | | | 45,645 | | | | 45,667 | |
Interest | | | 24,582 | | | | 26,392 | | | | 51,013 | | | | 47,500 | |
| | | | | | | | | | | | | | | | |
Total costs and expenses | | | 256,417 | | | | 202,525 | | | | 537,774 | | | | 408,878 | |
| | | | | | | | | | | | | | | | |
Equity income in joint venture | | | 888 | | | | 710 | | | | 2,350 | | | | 710 | |
Gain on asset sale | | | — | | | | 109,941 | | | | — | | | | 109,941 | |
| | | | | | | | | | | | | | | | |
Income from continuing operations | | | 651 | | | | 79,779 | | | | 2,529 | | | | 47,667 | |
| | | | | | | | | | | | | | | | |
| | | | |
Discontinued operations: | | | | | | | | | | | | | | | | |
Gain on sale of discontinued operations | | | — | | | | 51,078 | | | | — | | | | 51,078 | |
Earnings from discontinued operations | | | — | | | | 2,541 | | | | — | | | | 11,417 | |
| | | | | | | | | | | | | | | | |
Income from discontinued operations | | | — | | | | 53,619 | | | | — | | | | 62,495 | |
Net income | | | 651 | | | | 133,398 | | | | 2,529 | | | | 110,162 | |
Income attributable to non-controlling interests | | | (945 | ) | | | (652 | ) | | | (2,262 | ) | | | (1,121 | ) |
Preferred unit dividends | | | — | | | | — | | | | — | | | | (900 | ) |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to common limited partners and the general partner | | $ | (294 | ) | | $ | 132,746 | | | $ | 267 | | | $ | 108,141 | |
| (1) | Based on the GAAP statements of operations included in Form 10-Q, with additional detail of certain items included. |
| (2) | Non-cash costs associated with unit-based compensation, which have been reflected in the general and administrative costs and expenses, the category associated with the direct personnel cash costs in Form 10-Q. Includes approximately $1.8 million associated with the conversion of equity-indexed cash bonus units into phantom units during the three months ended June 30, 2010. This conversion resulted in a reduction of general and administrative costs and an increase to general and administrative – non cash unit based compensation during the quarter ended June 30, 2010. |
8
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary (continued)
(unaudited; in thousands, except per unit amounts)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
June 30, | | | Six Months Ended
June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | | |
Net income (loss) attributable to common limited partners per unit: | | | | | | | | | | | | | | | | |
Basic: | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (0.01 | ) | | $ | 1.62 | | | $ | — | | | $ | 0.95 | |
Discontinued operations | | | — | | | | 1.11 | | | | — | | | | 1.31 | |
| | | | | | | | | | | | | | | | |
| | $ | (0.01 | ) | | $ | 2.73 | | | $ | — | | | $ | 2.26 | |
| | | | | | | | | | | | | | | | |
| | | | |
Diluted: | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (0.01 | ) | | $ | 1.62 | | | $ | — | | | $ | 0.95 | |
Discontinued operations Diluted | | | — | | | | 1.11 | | | | — | | | | 1.31 | |
| | | | | | | | | | | | | | | | |
| | $ | (0.01 | ) | | $ | 2.73 | | | $ | — | | | $ | 2.26 | |
| | | | | | | | | | | | | | | | |
| | | | |
Weighted average common limited partner units outstanding: | | | | | | | | | | | | | | | | |
Basic | | | 53,214 | | | | 47,529 | | | | 53,033 | | | | 46,755 | |
| | | | | | | | | | | | | | | | |
Diluted | | | 53,214 | | | | 47,529 | | | | 53,163 | | | | 46,755 | |
| | | | | | | | | | | | | | | | |
| | | | |
Summary Cash Flow data (from continuing operations): | | | | | | | | | | | | | | | | |
Cash provided by (used in) operating activities | | $ | 9,624 | | | $ | (25,962 | ) | | $ | 57,126 | | | $ | 25,358 | |
Cash provided by (used in) investing activities | | | (20,979 | ) | | | 27,310 | | | | (29,377 | ) | | | (45,045 | ) |
Cash provided by (used in) financing activities | | | 11,356 | | | | (298,007 | ) | | | (28,610 | ) | | | (288,340 | ) |
| | | | |
Capital expenditure data: | | | | | | | | | | | | | | | | |
Maintenance capital expenditures | | $ | 3,142 | | | $ | 1,557 | | | $ | 4,313 | | | $ | 2,101 | |
Expansion capital expenditures | | | 12,644 | | | | 56,742 | | | | 22,387 | | | | 128,393 | |
Cash contributions to Laurel Mountain JV | | | 5,614 | | | | — | | | | 5,614 | | | | — | |
| | | | | | | | | | | | | | | | |
Total | | $ | 21,400 | | | $ | 58,299 | | | $ | 32,314 | | | $ | 130,494 | |
| | | | | | | | | | | | | | | | |
9
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(unaudited, in thousands)
| | | | | | |
| | | June 30,
2010 | | December 31,
2009 |
| ASSETS | | | | | | |
Current assets: | | | | | | |
Cash and cash equivalents | | $ | 160 | | $ | 1,021 |
Other current assets | | | 86,146 | | | 117,123 |
| | | | | | |
Total current assets | | | 86,306 | | | 118,144 |
| | |
Property, plant and equipment, net | | | 1,679,581 | | | 1,684,384 |
Intangible assets, net | | | 155,313 | | | 168,091 |
Investment in joint venture | | | 134,504 | | | 132,990 |
Long-term portion of derivative asset | | | 513 | | | 361 |
Other assets, net | | | 30,758 | | | 33,993 |
| | | | | | |
| | $ | 2,086,975 | | $ | 2,137,963 |
| | | | | | |
| | |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | | | |
| | |
Current liabilities | | $ | 104,509 | | $ | 148,729 |
| | |
Long-term portion of derivative liability | | | 4,778 | | | 11,126 |
Long-term debt, less current portion | | | 1,207,760 | | | 1,254,183 |
Other long-term liability | | | 315 | | | 398 |
Commitments and contingencies | | | | | | |
| | |
Total Partners’ capital | | | 769,613 | | | 723,527 |
| | | | | | |
| | $ | 2,086,975 | | $ | 2,137,963 |
| | | | | | |
10
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Reconciliation of Non-GAAP Measures
(unaudited; in thousands)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
June 30, | | | Six Months Ended
June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
Reconciliation of net income (loss) to other non-GAAP measures(1): | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 651 | | | $ | 133,398 | | | $ | 2,529 | | | $ | 110,162 | |
Income attributable to non-controlling interests | | | (945 | ) | | | (652 | ) | | | (2,262 | ) | | | (1,121 | ) |
Depreciation and amortization | | | 22,899 | | | | 22,999 | | | | 45,645 | | | | 45,667 | |
Interest expense, net of ineffective interest rate swaps(2) | | | 24,727 | | | | 26,392 | | | | 51,617 | | | | 47,500 | |
NOARK depreciation, amortization and interest(3) | | | — | | | | 764 | | | | — | | | | 2,802 | |
| | | | | | | | | | | | | | | | |
EBITDA | | | 47,332 | | | | 182,901 | | | | 97,529 | | | | 205,010 | |
Adjust for cash flow from equity investment | | | 1,571 | | | | (546 | ) | | | 4,100 | | | | (546 | ) |
Non-cash (gain) loss on derivatives(4) | | | (19,080 | ) | | | 2,527 | | | | (39,663 | ) | | | 46,545 | |
Early termination cash derivative expense(5) | | | 20,367 | | | | — | | | | 33,737 | | | | 5,000 | |
Non-cash portion of gain on asset sale | | | — | | | | (79,733 | ) | | | — | | | | (79,733 | ) |
Other non-cash (gains) losses(6) | | | 2,647 | | | | (1,395 | ) | | | 2,948 | | | | (1,958 | ) |
| | | | | | | | | | | | | | | | |
Adjusted EBITDA | | | 52,837 | | | | 103,754 | | | | 98,651 | | | | 174,318 | |
Interest expense, net of ineffective interest rate swaps(2) | | | (24,727 | ) | | | (26,392 | ) | | | (51,617 | ) | | | (47,500 | ) |
Amortization of deferred financing costs | | | 1,559 | | | | 3,636 | | | | 3,182 | | | | 4,653 | |
Preferred unit dividends | | | — | | | | — | | | | — | | | | (900 | ) |
Maintenance capital expenditures | | | (3,142 | ) | | | (1,557 | ) | | | (4,313 | ) | | | (2,101 | ) |
NOARK interest expense and maintenance capital expenditures(3) | | | — | | | | (306 | ) | | | — | | | | (483 | ) |
| | | | | | | | | | | | | | | | |
Distributable Cash Flow | | $ | 26,527 | | | $ | 79,135 | | | $ | 45,903 | | | $ | 127,987 | |
| | | | | | | | | | | | | | | | |
| | | | |
Reconciliation of Adjusted EBITDA to Recurring Adjusted EBITDA(1): | | | | | | | | | | | | | | | | |
Adjusted EBITDA | | $ | 52,837 | | | $ | 103,754 | | | $ | 98,651 | | | $ | 174,318 | |
Adjusted EBITDA from asset disposals (including gain/loss on sale of assets)(7) | | | — | | | | (88,170 | ) | | | — | | | | (103,185 | ) |
Gain on early settlement of derivatives | | | (8,421 | ) | | | — | | | | (8,421 | ) | | | (19,520 | ) |
Loss recognized from legacy derivative positions | | | 2,664 | | | | 23,427 | | | | 7,668 | | | | 13,785 | |
| | | | | | | | | | | | | | | | |
Recurring Adjusted EBITDA | | $ | 47,080 | | | $ | 39,011 | | | $ | 97,898 | | | $ | 65,398 | |
| | | | | | | | | | | | | | | | |
| (1) | EBITDA, Adjusted EBITDA, Recurring 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, Recurring 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. Adjusted EBITDA is also a financial measurement that is utilized within the Partnership’s financial covenants under its credit facility. EBITDA, Adjusted EBITDA, Recurring Adjusted EBITDA and Distributable Cash Flow are not measures of financial performance under GAAP and, accordingly, should not be considered in isolation or as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP. |
| (2) | Includes the cost of interest rate swaps that were previously recognized in interest expense prior to becoming ineffective in June 2009. They are now recorded in other income (loss), net in the Partnership’s income statement. |
| (3) | Included within income from discontinued operations. |
| (4) | The Partnership includes the unrealized gain/loss on premiums paid and received in non-cash (gain) loss on derivatives. The gain/loss is realized and recognized in Adjusted EBITDA in the period the option is exercised or expires. |
| (5) | During the quarter ended June 30, 2010 the Partnership made net payments of $20.4 million related to the early termination of derivative contracts. The Partnership’s credit facility definition of Consolidated EBITDA allows 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. |
| (6) | Includes the non-cash impact of commodity price movements on pipeline linefill inventory and non-cash compensation. |
| (7) | Represents earnings from disposed assets, including the NOARK gas gathering and interstate pipeline system and the 51% interest in the assets contributed to Laurel Mountain. |
11
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights(1)
| | | | | | | | | | | | |
| | | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | | 2010 | | 2009 | | 2010 | | 2009 |
Pricing | | | | | | | | | | | | |
Mid-Continent Weighted Average Prices: | | | | | | | | | | | | |
NGL price per gallon – Conway hub | | $ | 0.81 | | $ | 0.59 | | $ | 0.92 | | $ | 0.57 |
NGL price per gallon – Mt. Belvieu hub | | $ | 0.97 | | $ | 0.68 | | $ | 1.04 | | $ | 0.64 |
| | | | |
Unhedged natural gas sales ($/Mcf): | | | | | | | | | | | | |
Velma | | $ | 3.89 | | $ | 2.73 | | $ | 4.56 | | $ | 3.07 |
Elk City/Sweetwater | | $ | 3.93 | | $ | 2.77 | | $ | 4.52 | | $ | 3.05 |
Chaney Dell | | $ | 3.91 | | $ | 2.74 | | $ | 4.55 | | $ | 3.05 |
Midkiff/Benedum | | $ | 3.88 | | $ | 2.78 | | $ | 4.53 | | $ | 3.15 |
Weighted Average | | $ | 3.90 | | $ | 2.75 | | $ | 4.46 | | $ | 3.07 |
| | | | |
Unhedged NGL sales ($/gallon): | | | | | | | | | | | | |
Velma | | $ | 0.83 | | $ | 0.60 | | $ | 0.92 | | $ | 0.58 |
Elk City/Sweetwater | | $ | 0.86 | | $ | 0.63 | | $ | 0.96 | | $ | 0.60 |
Chaney Dell | | $ | 0.82 | | $ | 0.61 | | $ | 0.92 | | $ | 0.59 |
Midkiff/Benedum | | $ | 0.98 | | $ | 0.68 | | $ | 1.04 | | $ | 0.62 |
Weighted Average | | $ | 0.88 | | $ | 0.63 | | $ | 0.96 | | $ | 0.60 |
| | | | |
Unhedged Condensate sales ($/barrel): | | | | | | | | | | | | |
Velma | | $ | 76.21 | | $ | 57.49 | | $ | 76.64 | | $ | 49.29 |
Elk City/Sweetwater | | $ | 74.04 | | $ | 52.84 | | $ | 73.64 | | $ | 44.52 |
Chaney Dell | | $ | 70.22 | | $ | 56.96 | | $ | 72.38 | | $ | 44.68 |
Midkiff/Benedum | | $ | 72.85 | | $ | 57.92 | | $ | 73.54 | | $ | 52.89 |
Weighted Average | | $ | 72.80 | | $ | 56.82 | | $ | 73.75 | | $ | 47.58 |
| | | | |
Volumes | | | | | | | | | | | | |
Laurel Mountain Midstream, LLC: | | | | | | | | | | | | |
Average throughput volume – mcfd | | | 101,821 | | | 98,162 | | | 99,200 | | | 96,716 |
Mid-Continent | | | | | | | | | | | | |
Velma: | | | | | | | | | | | | |
Gathered gas volume – mcfd | | | 79,007 | | | 80,068 | | | 76,396 | | | 73,050 |
Processed gas volume – mcfd | | | 72,629 | | | 77,300 | | | 71,096 | | | 70,625 |
Residue gas volume – mcfd | | | 60,043 | | | 61,354 | | | 57,923 | | | 55,794 |
NGL volume – bpd | | | 8,230 | | | 8,497 | | | 7,996 | | | 7,770 |
Condensate volume – bpd | | | 386 | | | 416 | | | 431 | | | 381 |
Elk City/Sweetwater(2): | | | | | | | | | | | | |
Gathered gas volume – mcfd | | | 269,435 | | | 221,192 | | | 249,397 | | | 237,445 |
Processed gas volume – mcfd | | | 231,226 | | | 216,804 | | | 202,089 | | | 235,258 |
Residue gas volume – mcfd | | | 209,607 | | | 196,613 | | | 192,583 | | | 214,228 |
NGL volume – bpd | | | 12,092 | | | 11,581 | | | 10,752 | | | 11,650 |
Condensate volume – bpd | | | 494 | | | 337 | | | 495 | | | 432 |
Chaney Dell: | | | | | | | | | | | | |
Gathered gas volume – mcfd | | | 223,098 | | | 276,901 | | | 222,554 | | | 289,889 |
Processed gas volume – mcfd | | | 173,096 | | | 219,129 | | | 189,910 | | | 223,468 |
Residue gas volume – mcfd | | | 156,057 | | | 240,518 | | | 172,120 | | | 248,204 |
NGL volume – bpd | | | 9,505 | | | 13,663 | | | 11,022 | | | 13,674 |
Condensate volume – bpd | | | 625 | | | 909 | | | 691 | | | 918 |
Midkiff/Benedum: | | | | | | | | | | | | |
Gathered gas volume – mcfd | | | 180,960 | | | 161,355 | | | 169,391 | | | 157,687 |
Processed gas volume – mcfd | | | 164,111 | | | 150,111 | | | 156,639 | | | 148,094 |
Residue gas volume – mcfd | | | 105,315 | | | 99,106 | | | 102,493 | | | 102,155 |
NGL volume – bpd | | | 26,609 | | | 20,473 | | | 25,504 | | | 21,555 |
Condensate volume – bpd | | | 1,490 | | | 1,533 | | | 1,092 | | | 1,163 |
| (1) | “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day. |
| (2) | Gathered gas volume for the Elk City/Sweetwater system includes 36,315 Mcfd and 39,946 Mcfd transferred from the Chaney Dell system for the three months ended June 2010 and 2009, respectively and 18,517 Mcfd and 41,446 Mcfd for the six months ended June 2010 and 2009, respectively. |
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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Hedge Positions through September 30, 2011
(as of August 1, 2010)
Note: The natural gas, natural gas liquid and condensate hedge positions shown below represent the hedge contracts in place through September 30, 2011. APL’s hedge position in its entirety, including any hedges for periods after September 30, 2011, will be disclosed in the Partnership’s Form 10-Q.
NATURAL GAS HEDGES
Swap Contracts
| | | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | MMBTU | | Avg. Fixed Price | |
3Q 2010 | | Sold | | Natural Gas Basis | | 1,140,000 | | $ | (0.70 | ) |
3Q 2010 | | Purchased | | Natural Gas Basis | | 1,140,000 | | | (0.71 | ) |
4Q 2010 | | Sold | | Natural Gas Basis | | 1,140,000 | | | (0.70 | ) |
4Q 2010 | | Purchased | | Natural Gas Basis | | 1,140,000 | | | (0.71 | ) |
1Q 2011 | | Sold | | Natural Gas Basis | | 480,000 | | | (0.73 | ) |
1Q 2011 | | Purchased | | Natural Gas Basis | | 480,000 | | | (0.76 | ) |
2Q 2011 | | Sold | | Natural Gas Basis | | 480,000 | | | (0.73 | ) |
2Q 2011 | | Purchased | | Natural Gas Basis | | 480,000 | | | (0.76 | ) |
3Q 2011 | | Sold | | Natural Gas Basis | | 480,000 | | | (0.73 | ) |
3Q 2011 | | Purchased | | Natural Gas Basis | | 480,000 | | | (0.76 | ) |
Option Contracts
| | | | | | | | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | MMBTU | | Avg. Strike Price |
3Q 2010 | | Purchased | | Call | | Natural Gas | | 2,100,000 | | $ | 5.50 |
4Q 2010 | | Purchased | | Call | | Natural Gas | | 2,100,000 | | | 6.50 |
NATURAL GAS LIQUIDS AND CONDENSATE HEDGES
Swap Contracts - NGLS
| | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | Gallons | | Avg. Fixed Price |
3Q 2010 | | Sold | | Propane | | 8,820,000 | | $ | 1.10 |
4Q 2010 | | Sold | | Propane | | 8,820,000 | | | 1.12 |
4Q 2010 | | Sold | | Normal Butane | | 1,890,000 | | | 1.55 |
4Q 2010 | | Sold | | Natural Gasoline | | 1,512,000 | | | 1.93 |
Swap Contracts - Crude
| | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | Barrels | | Avg. Fixed Price |
1Q 2011 | | Sold | | Crude | | 39,000 | | $ | 92.61 |
2Q 2011 | | Sold | | Crude | | 39,000 | | | 93.13 |
Option Contracts - NGLs
| | | | | | | | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | Gallons | | Avg. Strike Price |
3Q 2010 | | Purchased | | Put | | Propane | | 6,048,000 | | $ | 1.11 |
3Q 2010 | | Purchased | | Put | | Normal Butane | | 2,772,000 | | | 1.44 |
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Option Contracts – Crude
| | | | | | | | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | Barrels | | Avg. Strike Price |
3Q 2010 | | Purchased | | Put | | Crude Oil | | 174,000 | | $ | 74.15 |
3Q 2010 | | Sold | | Call | | Crude Oil | | 273,000 | | | 100.05 |
3Q 2010 | | Purchased | | Call | | Crude Oil | | 87,000 | | | 120.00 |
4Q 2010 | | Purchased | | Put | | Crude Oil | | 150,000 | | | 74.40 |
4Q 2010 | | Sold | | Call | | Crude Oil | | 273,000 | | | 100.05 |
4Q 2010 | | Purchased | | Call | | Crude Oil | | 87,000 | | | 120.00 |
1Q 2011 | | Purchased | | Put | | Crude Oil | | 210,000 | | | 89.00 |
1Q 2011 | | Sold | | Call | | Crude Oil | | 169,500 | | | 94.68 |
1Q 2011 | | Purchased | | Call | | Crude Oil | | 63,000 | | | 120.00 |
2Q 2011 | | Purchased | | Put | | Crude Oil | | 210,000 | | | 89.00 |
2Q 2011 | | Sold | | Call | | Crude Oil | | 169,500 | | | 94.68 |
2Q 2011 | | Purchased | | Call | | Crude Oil | | 63,000 | | | 120.00 |
3Q 2011 | | Sold | | Call | | Crude Oil | | 169,500 | | | 94.68 |
3Q 2011 | | Purchased | | Call | | Crude Oil | | 63,000 | | | 120.00 |
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