Exhibit 99.1
| | |
| Contact: | | Matthew Skelly |
| | | VP – Investor Relations |
| | 1845 Walnut Street |
| | Philadelphia, PA 19103 |
| | (215) 546-5005 |
| | (215) 561-5692 (facsimile) |
ATLAS PIPELINE PARTNERS, L.P.
REPORTS FIRST QUARTER 2011 RESULTS
Philadelphia, PA, May 3, 2011 – Atlas Pipeline Partners, L.P. (NYSE: APL) (“APL”, “Atlas Pipeline”, or the “Partnership”)today reported adjusted earnings before interest, income taxes, depreciation and amortization (“Adjusted EBITDA”), a non-GAAP measure, of $38.6 million in the first quarter of 2011. Versus the first quarter of 2010, the Partnership reported increased volumes and natural gas liquids (NGL) prices on each of its Mid-Continent systems. Comparatively, Adjusted EBITDA was $28.4 million in the first quarter of 2010, excluding (i) approximately $13.8 million in Adjusted EBITDA from the Partnership’s Elk City/Sweetwater system and interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”), both of which have been sold; and (ii) an add-back of $13.4 million related to the early termination of derivatives with equity proceeds. Adjusted EBITDA excludes gains and losses from asset sales outside the ordinary course of business, option premium expense and non-cash items that impact net income. The Partnership believes this measure provides a more accurate comparison of the operating results for the periods presented. Net income was $241.6 million for the first quarter of 2011 compared with net income of $1.9 million for the prior year first quarter. Net income was higher for the first quarter 2011 compared to last year’s first quarter, primarily due to the $255.9 million gain, recognized in the first quarter of 2011, on the sale of the Partnership’s 49% non-controlling ownership interest in Laurel Mountain.
Distributable Cash Flow, a non-GAAP measure, was $26.8 million for the first quarter, a 38% increase compared to the first quarter of 2010 Distributable Cash Flow of $19.4 million. The increase was mainly due to a $14.4 million reduction in interest expense in the first quarter of 2011, along with remaining proceeds from the sale of Laurel Mountain, offset by the Adjusted EBITDA from Elk City/Sweetwater, Laurel Mountain, and the early termination of derivatives, all discussed above. For the first quarter of 2011, Distributable Cash Flow per average common limited partner unit for the quarter was approximately $0.50, or $2.00 annually.
On April 26, 2011, the Partnership declared a distribution for the first quarter of 2011 of $0.40, or $1.60 annualized, per common limited partner unit to holders of record on May 6, 2011, and payable on May 13, 2011. This represents a sequential quarterly growth rate of 8.1% over the fourth quarter of 2010. This distribution represents Distributable Cash Flow coverage of approximately 1.2x for the first quarter of 2011. A reconciliation of non-GAAP measures, including Adjusted EBITDA and Distributable Cash Flow, is provided within the financial tables of this release.
On February 17, 2011, the Partnership completed the sale of its 49% interest in Laurel Mountain to Atlas Energy Resources, LLC for $409.5 million, including closing adjustments and net of expenses. Laurel Mountain owns and operates approximately 1,000 miles of natural gas gathering systems in the Appalachian Basin located in the northeastern United States.
“We are pleased to start 2011 with a successful quarter of results. As compared to a year ago, processing volumes are up over 14% on both gas and liquids across the business. Two of our three gathering and processing assets are essentially full at this point in time as we have had producers on our systems increase their drilling programs over the past year. Additionally, we were able to close on the Laurel Mountain transaction this past quarter and begin the bond redemption process, which successfully completed in early April. As we continue to extract value from the business for our stakeholders, we expect the positive momentum to continue throughout the rest of the year. We thank all of you for your support.” stated Eugene Dubay, Chief Executive Officer of the Partnership.
* * *
1
Capitalization and Liquidity
The Partnership had total liquidity (cash plus available capacity on its revolving credit facility) of $347.0 million as of March 31, 2011, up $70.0 million from December 31, 2010. Total debt outstanding was reduced to $496.1 million at March 31, 2011, from $566.0 million at December 31, 2010, a decrease of $69.9 million. Pro forma for the closing of the Laurel Mountain transaction and subsequent senior note pay down, current outstanding total debt would be $223.9 million, which represents a total leverage of 1.4x and a debt to capital measure of 15%. Pro forma liquidity (as defined above) would be $339.5 million.
* * *
Capital Deployment and Balance Sheet Opportunities
The Partnership redeemed its outstanding 8 1/8% Senior Notes due 2015 (the “2015 Notes”) on April 8, 2011, utilizing proceeds from the sale of its interest in Laurel Mountain. At March 31, 2011, $293.7 million was held in escrow for this redemption. In addition, the Partnership commenced an offer to purchase the 8 3/4% Senior Notes due 2018 (the “2018 Notes”). The Partnership purchased $7.2 million of its 2018 Notes through this tender offer, which expired on April 7, 2011. The following table summarizes the Partnership’s total liquidity and debt balance at March 31, 2011, together with the pro forma impact of the redemption of the 2015 Notes and the purchase of a portion of the 2018 Notes, including payment of premium and accrued interest (in thousands):
| | | | | | | | | | | | |
| | | | | | | | | Pro Forma
March 31, 2011
Balance | |
| | | March 31, 2011
Balance | | | | | |
Impact of Senior Note Redemptions | | | Impact | | |
Cash and cash equivalents | | $ | 167 | | | $ | — | | | $ | 167 | |
Funds held in escrow | | | 293,696 | | | | (293,696 | ) | | | — | |
| | | |
Current portion of long-term debt | | | 213 | | | | — | | | | 213 | |
Revolving credit facility | | | — | | | | 7,427 | | | | 7,427 | |
8.125% Senior notes – due 2015 | | | 272,329 | | | | (272,329 | ) | | | — | |
8.750% Senior notes – due 2018 | | | 223,050 | | | | (7,228 | ) | | | 215,822 | |
Other | | | 478 | | | | — | | | | 478 | |
| | | | | | | | | | | | |
Total debt | | $ | 496,070 | | | $ | (272,130 | ) | | $ | 223,940 | |
| | | | | | | | | | | | |
Liquidity (defined above) | | $ | 346,975 | | | $ | (7,427 | ) | | $ | 339,548 | |
Net debt (Total debt less cash equiv.) | | $ | 495,903 | | | $ | (272,130 | ) | | $ | 223,773 | |
| | | | | | | | | | | | |
Due to the retirement of the 2015 Notes and the purchase of a portion of the 2018 Notes, the Partnership expects to experience interest savings of approximately $23 million annually which, as a positive direct impact to Distributable Cash Flow, would result in a Distributable Cash Flow per unit increase of $0.45 annually, or approximately $0.11 per quarter, a 22% increase over the first quarter of 2011. Including the positive effects for this for the current quarter, Distributable Cash Flow per unit would have been $0.61.
* * *
Risk Management
The Partnership continues to enhance its risk management portfolio. As of May 2, 2011, the Partnership has natural gas, natural gas liquids and condensate hedges in place for the remainder of 2011 for approximately 70% of associated margin value. In addition to this coverage, margin value protection of approximately 42% is in place for 2012. Counterparties to the Partnership’s risk management activities consist primarily of investment grade commercial banks that are lenders under the Partnership’s credit facility, or affiliates of such banks. A table summarizing our risk management portfolio is included in this release.
* * *
Operating Results
Gross margin from continuing operations was $56.3 million for the first quarter 2011, compared to $53.9 million for the same period in the prior year. Gross margin includes natural gas and liquids revenues and transportation, compression and other fees, less purchased product costs and non-cash gains (or losses). The increase in gross margin was primarily due to increased NGL prices and volumes across all systems. Volume increases on the WestTX (Midkiff/Benedum) system are a result of additional development drilling in the Permian Basin. Volumes on the Velma system increased due to production added on the new Madill to Velma gathering system. The increase in volumes on the Partnership’s WestOK (Chaney Dell) system is related to our expansion into Kansas and increased producer activity in the counties along the Oklahoma and Kansas borders.
2
WestTX (Midkiff/Benedum)
The WestTX system’s average natural gas processed volume was 172.8 million cubic feet per day (“Mmcfd”) for the first quarter 2011 compared with 149.1 Mmcfd for the prior year comparable quarter, an increase of 15.9%. Average gross NGL production volumes increased to 27,476 barrels per day (“bpd”) for the first quarter 2011, compared to 24,387 bpd in the prior year first quarter, an increase of 12.7%. Increased volumes are primarily due to increased production from its partner, Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”) and significant growth in natural gas volumes from other producers in the Spraberry and Wolfberry Trends, including COG Operating, LLC, and Endeavor Energy Resources, LP. The Partnership expects volumes on this system to continue to increase as Pioneer and other producers continue to pursue their drilling plans for 2011 and beyond. Beginning in the second quarter of 2011, the Partnership expects to re-commission 60 Mmcfd of its Midkiff plant, which will increase processing capacity on the WestTX system to 255 Mmcfd.
WestOK (Chaney Dell)
The WestOK system had average natural gas processed volume of 228.9 Mmcfd, a 10.6% increase, and NGL production of 13,591 bpd, which represents an 8.0% increase, for the first quarter 2011 from the prior year comparable period. The Partnership completed the Woolsey expansion of its WestOK system into Kansas during June 2010 and experienced an increase in processed gas volumes due to this project, as well as increased production from other producers on the system, including Chesapeake Energy Marketing, Inc. and Sandridge Exploration and Production, LLC. The WestOK system is currently operating in excess of capacity and the Partnership expects volumes to continue to increase in 2011 as volumes from these producers in Oklahoma, along with others in Kansas, continue to be added to the system via development in the oil rich Mississippian Limestone formation. The Partnership is currently planning a 200 Mmcfd expansion of this system, which it expects to be completed in 2012, in order to meet the drilling plans of its existing producers. This expansion would result in total processing capacity of 428 Mmcfd on the WestOK system.
Velma
The Velma system’s average natural gas processed volume was 85.2 Mmcfd for the first quarter 2011, an increase of approximately 20.4% compared with the comparable quarter in the prior year. The increase is primarily due to new production gathered on the Madill to Velma pipeline system. Gathered volumes were up 17.4 Mmcfd, or 23.8% compared to the same quarter last year. Average NGL production increased to 10,071 bpd for the first quarter 2011, up approximately 29.8% compared to 7,760 bpd for the prior year first quarter, due to the increased processed volumes. The Partnership continues to evaluate growth opportunities on the Velma system, including additional processing capacity, as producers look to take advantage of high NGL content gas in the Woodford shale.
* * *
Corporate and Other
Net of deferred financing costs, interest expense decreased to $11.2 million for the first quarter 2011, down 54.8% as compared with $24.8 million for the first quarter 2010. This decrease was primarily due to a $705.5 million reduction in debt outstanding since March 31, 2010.
* * *
Interested parties are invited to access the live webcast of an investor call with management regarding the Partnership’s first quarter 2011 results on Tuesday, May 3, 2011 at 10:00 am ET by going to the Investor Relations section of the Partnership’s website at www.atlaspipeline.com. An audio replay of the conference call will also be available beginning at 12:00 pm ET on Tuesday, May 3, 2011. To access the replay, dial 1-888-286-8010 and enter conference code 69215822.
Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In the Mid-Continent region of Oklahoma, southern Kansas, and northern and western Texas, APL owns and operates five active gas processing plants as well as approximately 8,600 miles of active intrastate gas gathering pipeline. For more information, visit the Partnership’s website at www.atlaspipeline.com or contact IR@atlaspipeline.com.
Atlas Energy, L.P. (NYSE: ATLS) is a master 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 5.75 million common limited partner units of APL. Additionally, ATLS owns an interest in over 8,500 producing natural gas and oil wells, representing over 185 Bcfe of net proved developed reserves. For more information, please visit our website at http://www.atlasenergy.com, or contact Investor Relations at InvestorRelations@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. Atlas Pipeline does not undertake any duty to update any statements contained
3
herein (including any forward-looking statements), 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.
4
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary (1)
(unaudited; in thousands)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2011 | | | 2010(2) | |
Revenue: | | | | | | | | |
Natural gas and liquids | | $ | 266,309 | | | $ | 223,338 | |
Transportation, processing and other fees(3) | | | 9,410 | | | | 10,095 | |
Other income (loss), net | | | (18,856 | ) | | | 6,720 | |
| | | | | | | | |
Total revenue and other income (loss), net | | | 256,863 | | | | 240,153 | |
| | | | | | | | |
Costs and expenses: | | | | | | | | |
Natural gas and liquids | | | 218,292 | | | | 179,759 | |
Plant operating | | | 12,774 | | | | 11,959 | |
Transportation and compression | | | 184 | | | | 189 | |
General and administrative(4) | | | 7,840 | | | | 9,628 | |
General and administrative – non-cash unit-based compensation(4) | | | 1,177 | | | | 123 | |
Depreciation and amortization | | | 18,905 | | | | 18,457 | |
Interest | | | 12,445 | | | | 26,403 | |
| | | | | | | | |
Total costs and expenses | | | 271,617 | | | | 246,518 | |
| | | | | | | | |
Equity income in joint venture | | | 462 | | | | 1,462 | |
Gain on asset sale and other | | | 255,947 | | | | — | |
| | | | | | | | |
Income (loss) from continuing operations | | | 241,655 | | | | (4,903 | ) |
| | | | | | | | |
Discontinued operations: | | | | | | | | |
Loss on sale of discontinued operations | | | (81 | ) | | | — | |
Earnings from discontinued operations | | | — | | | | 6,781 | |
| | | | | | | | |
Income (loss) from discontinued operations | | | (81 | ) | | | 6,781 | |
Net income | | | 241,574 | | | | 1,878 | |
Income attributable to non-controlling interests | | | (1,187 | ) | | | (1,317 | ) |
Preferred unit dividends | | | (240 | ) | | | — | |
| | | | | | | | |
Net income attributable to common limited partners and the general partner | | $ | 240,147 | | | $ | 561 | |
| | | | | | | | |
| (1) | Based on the GAAP statements of operations to be included in Form 10-Q, with additional detail of certain items included. |
| (2) | Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems. |
| (3) | Includes affiliate revenues related to transportation and processing provided to Atlas Energy Resources, LLC. |
| (4) | 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 the GAAP statements of operations to be included in Form 10-Q. General and administrative also includes any compensation reimbursement to affiliates. |
5
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Financial Summary (continued)
(unaudited; in thousands, except per unit amounts)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2011 | | | 2010(1) | |
Net income (loss) attributable to common limited partners per unit: | | | | | | | | |
Basic: | | | | | | | | |
Continuing operations | | $ | 4.37 | | | $ | (0.12 | ) |
Discontinued operations | | | — | | | | 0.13 | |
| | | | | | | | |
| | $ | 4.37 | | | $ | 0.01 | |
| | | | | | | | |
| | |
Diluted: | | | | | | | | |
Continuing operations | | $ | 4.37 | | | $ | (0.12 | ) |
Discontinued operations | | | — | | | | 0.13 | |
| | | | | | | | |
| | $ | 4.37 | | | $ | 0.01 | |
| | | | | | | | |
| | |
Weighted average common limited partner units outstanding: | | | | | | | | |
Basic | | | 53,375 | | | | 52,849 | |
| | | | | | | | |
Diluted | | | 53,846 | | | | 52,849 | |
| | | | | | | | |
| | |
Summary Cash Flow Data: | | | | | | | | |
Cash provided by operating activities | | $ | 3,727 | | | $ | 47,502 | |
Cash provided by (used in) investing activities | | | 381,405 | | | | (8,398 | ) |
Cash used in financing activities | | | (385,129 | ) | | | (39,966 | ) |
| | |
Capital Expenditure Data: | | | | | | | | |
Maintenance capital expenditures | | $ | 3,260 | | | $ | 875 | |
Expansion capital expenditures | | | 15,073 | | | | 6,802 | |
Cash contributions to Laurel Mountain JV | | | 12,250 | | | | — | |
| | | | | | | | |
Total | | $ | 30,583 | | | $ | 7,677 | |
| | | | | | | | |
| (1) | Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems. |
6
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(unaudited; in thousands)
| | | | | | | | |
| | | March 31,
2011 | | | December 31,
2010 | |
| ASSETS | | | | | | | | |
| | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 167 | | | $ | 164 | |
Other current assets | | | 126,937 | | | | 114,877 | |
| | | | | | | | |
Total current assets | | | 127,104 | | | | 115,041 | |
Property, plant and equipment, net | | | 1,348,671 | | | | 1,341,002 | |
Intangible assets, net | | | 120,603 | | | | 126,379 | |
Investment in joint venture | | | — | | | | 153,358 | |
Long-term note receivable | | | 8,500 | | | | — | |
Long-term funds held in escrow | | | 286,670 | | | | — | |
Other assets, net | | | 27,704 | | | | 29,068 | |
| | | | | | | | |
| | $ | 1,919,252 | | | $ | 1,764,848 | |
| | | | | | | | |
| | |
| LIABILITIES AND EQUITY | | | | | | | | |
Current liabilities | | $ | 151,229 | | | $ | 151,606 | |
Long-term portion of derivative liability | | | 7,217 | | | | 5,608 | |
Long-term debt, less current portion | | | 495,857 | | | | 565,764 | |
Other long-term liability | | | 159 | | | | 223 | |
Commitments and contingencies | | | | | | | | |
Total partners’ capital | | | 1,297,364 | | | | 1,074,184 | |
Non-controlling interest | | | (32,574 | ) | | | (32,537 | ) |
| | | | | | | | |
Total equity | | | 1,264,790 | | | | 1,041,647 | |
| | | | | | | | |
| | $ | 1,919,252 | | | $ | 1,764,848 | |
| | | | | | | | |
7
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Reconciliation of Non-GAAP Measures
(unaudited; in thousands)
| | | | | | | | |
| | | Three Months Ended
March 31, | |
| | | 2011 | | | 2010(1) | |
Reconciliation of net income (loss) to other non-GAAP measures(2): | | | | | | | | |
Net income (loss) | | $ | 241,574 | | | $ | 1,878 | |
Income attributable to non-controlling interests | | | (1,187 | ) | | | (1,317 | ) |
Depreciation and amortization | | | 18,905 | | | | 18,457 | |
Interest expense(3) | | | 12,445 | | | | 26,862 | |
Depreciation, amortization and interest of discontinued operations | | | — | | | | 4,317 | |
| | | | | | | | |
EBITDA | | | 271,737 | | | | 50,197 | |
Adjust for cash flow from investment in joint venture | | | 1,302 | | | | 2,529 | |
Non-cash (gain) loss on derivatives | | | 18,360 | | | | (12,412 | ) |
Early termination cash derivative expense(4) | | | — | | | | 9,617 | |
Premium expense on derivative instruments | | | 3,005 | | | | 6,654 | |
Gain on asset sales and other | | | (255,866 | ) | | | — | |
Other non-cash (gains) losses(5) | | | 63 | | | | 301 | |
Discontinued operations adjustments(6) | | | — | | | | (1,285 | ) |
| | | | | | | | |
Adjusted EBITDA | | | 38,601 | | | | 55,601 | |
Interest expense(3) | | | (12,445 | ) | | | (26,862 | ) |
Amortization of deferred financing costs | | | 1,267 | | | | 1,623 | |
Preferred unit dividends | | | (240 | ) | | | — | |
Laurel Mountain proceeds remaining(7) | | | 5,850 | | | | — | |
Maintenance capital expenditures | | | (3,260 | ) | | | (875 | ) |
Premiums expense on derivative instruments | | | (3,005 | ) | | | (6,654 | ) |
Discontinued operations adjustments(8) | | | — | | | | (3,457 | ) |
| | | | | | | | |
Distributable Cash Flow | | $ | 26,768 | | | $ | 19,376 | |
| | | | | | | | |
| (1) | Restated to reflect amounts reclassified to discontinued operations due to the Partnership’s sale of the Elk City gas gathering and processing systems and modifications to the Partnership’s credit facility Consolidated EBITDA definition and covenant calculations. |
| (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. Adjusted EBITDA is also similar to the Consolidated EBITDA calculation that is utilized within the Partnership’s financial covenants under its credit facility, with the exception that Adjusted EBITDA includes (i) EBITDA from the discontinued operations related to the sale of the Partnership’s Elk City/Sweetwater system; and (ii) other non-cash items specifically excluded under the credit facility. EBITDA, 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. |
| (3) | For the three months ended March 31, 2010, includes the cost of interest rate swaps that were previously recognized in interest expense prior to becoming ineffective in June 2009. They were subsequently recorded in other income (loss), net in the Partnership’s income statement. |
| (4) | During the three months ended March 31, 2010, the Partnership made net payments of $13.4 million related to the early termination of derivative contracts, including $3.8 million related to Elk City derivatives included in discontinued operations adjustments. The Partnership’s credit facility definition of Consolidated EBITDA allows for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of equity. |
| (5) | Includes the non-cash impact of commodity price movements on pipeline linefill inventory and non-cash compensation. |
| (6) | Discontinued operation adjustments for Adjusted EBITDA include (i) early termination cash derivative expense; (ii) premium expense on derivative instruments; and (iii) non-cash (gain) loss on derivatives. |
| (7) | Net proceeds remaining from the sale of Laurel Mountain after the repayment of the amount outstanding on the Partnership’s revolving credit facility, redemption of its 8.125% Senior Notes due 2015 and purchase of certain 8.75% Senior Notes due 2018. |
| (8) | Discontinued operation adjustments for Distributable Cash Flow include (i) maintenance capital expenditures; (ii) interest expense and (iii) premiums expense on derivative instruments. |
8
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Operating Highlights (1)
| | | | | | | | | | | | |
| | | Three Months Ended
March 31, | | | | |
| | | 2011 | | | 2010 | | | % Change | |
Pricing | | | | | | | | | | | | |
Mid-Continent Weighted Average NGL sales ($/gallon): | | | | | | | | | | | | |
Conway hub | | $ | 1.08 | | | $ | 1.01 | | | | 6.9 | % |
Mt. Belvieu hub | | | 1.21 | | | | 1.11 | | | | 9.0 | % |
| | | |
Unhedged natural gas sales ($/Mcf): | | | | | | | | | | | | |
Velma | | | 3.98 | | | | 5.19 | | | | (23.3 | )% |
WestOK | | | 3.94 | | | | 5.19 | | | | (24.1 | )% |
WestTX | | | 3.92 | | | | 5.15 | | | | (23.9 | )% |
Weighted Average | | | 3.94 | | | | 5.16 | | | | (23.6 | )% |
| | | |
Unhedged NGL sales ($/gallon): | | | | | | | | | | | | |
Velma | | | 1.03 | | | | 1.00 | | | | 3.0 | % |
WestOK | | | 1.06 | | | | 1.02 | | | | 3.9 | % |
WestTX | | | 1.18 | | | | 1.10 | | | | 7.3 | % |
Weighted Average | | | 1.10 | | | | 1.05 | | | | 4.8 | % |
| | | |
Unhedged Condensate sales ($/barrel): | | | | | | | | | | | | |
Velma | | | 92.24 | | | | 77.19 | | | | 19.5 | % |
WestOK | | | 84.72 | | | | 74.57 | | | | 13.6 | % |
WestTX | | | 89.80 | | | | 75.53 | | | | 18.9 | % |
Weighted Average | | | 88.29 | | | | 75.57 | | | | 16.8 | % |
| | | |
Volumes:(1) | | | | | | | | | | | | |
Appalachia | | | | | | | | | | | | |
Tennessee system | | | | | | | | | | | | |
Average throughput volume – mcfd | | | 8,079 | | | | 9,001 | | | | (10.2 | )% |
Mid-Continent | | | | | | | | | | | | |
Velma: | | | | | | | | | | | | |
Gathered gas volume – mcfd | | | 90,614 | | | | 73,220 | | | | 23.8 | % |
Processed gas volume – mcfd | | | 85,158 | | | | 70,742 | | | | 20.4 | % |
Residue gas volume – mcfd | | | 69,714 | | | | 55,482 | | | | 25.7 | % |
NGL volume – bpd | | | 10,071 | | | | 7,760 | | | | 29.8 | % |
Condensate volume – bpd | | | 530 | | | | 477 | | | | 11.1 | % |
WestOK: | | | | | | | | | | | | |
Gathered gas volume – mcfd | | | 242,965 | | | | 222,004 | | | | 9.4 | % |
Processed gas volume – mcfd | | | 228,865 | | | | 206,912 | | | | 10.6 | % |
Residue gas volume – mcfd | | | 198,640 | | | | 188,232 | | | | 5.5 | % |
NGL volume – bpd | | | 13,591 | | | | 12,580 | | | | 8.0 | % |
Condensate volume – bpd | | | 859 | | | | 759 | | | | 13.2 | % |
WestTX(2): | | | | | | | | | | | | |
Gathered gas volume – mcfd | | | 185,918 | | | | 157,693 | | | | 17.9 | % |
Processed gas volume – mcfd | | | 172,817 | | | | 149,084 | | | | 15.9 | % |
Residue gas volume – mcfd | | | 115,917 | | | | 99,640 | | | | 16.3 | % |
NGL volume – bpd | | | 27,476 | | | | 24,387 | | | | 12.7 | % |
Condensate volume – bpd | | | 1,024 | | | | 690 | | | | 48.4 | % |
| (1) | “Mcf” represents thousand cubic feet; “Mcfd” represents thousand cubic feet per day; “Bpd” represents barrels per day. |
| (2) | Operating data for the WestTX system represent 100% of its operating activity. |
9
ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
Unaudited Current Commodity Risk Management Positions through December 31, 2012
(as of May 2, 2011)
Note: The natural gas, natural gas liquid and condensate price risk management positions shown below represent the majority of the contracts in place through December 31, 2012. APL’s price risk management position in its entirety will be disclosed in the Partnership’s Form 10-Q.
SWAP CONTRACTS
NATURAL GAS HEDGES
| | | | | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | MMBTU | | | Avg. Fixed Price | |
2Q 2011 | | Sold | | Natural Gas | | | 900,000 | | | | 4.41 | |
3Q 2011 | | Sold | | Natural Gas | | | 1,200,000 | | | | 4.54 | |
4Q 2011 | | Sold | | Natural Gas | | | 1,200,000 | | | | 4.91 | |
NATURAL GAS LIQUIDS HEDGES
| | | | | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | Gallons | | | Avg. Fixed Price | |
2Q 2011 | | Sold | | Ethane | | | 5,040,000 | | | | 0.50 | |
2Q 2011 | | Sold | | Propane | | | 4,284,000 | | | | 1.11 | |
3Q 2011 | | Sold | | Propane | | | 4,284,000 | | | | 1.16 | |
3Q 2011 | | Sold | | Isobutane | | | 504,000 | | | | 1.61 | |
3Q 2011 | | Sold | | Normal Butane | | | 1,386,000 | | | | 1.57 | |
3Q 2011 | | Sold | | Natural Gasoline | | | 3,276,000 | | | | 2.04 | |
4Q 2011 | | Sold | | Propane | | | 4,284,000 | | | | 1.19 | |
4Q 2011 | | Sold | | Isobutane | | | 504,000 | | | | 1.63 | |
4Q 2011 | | Sold | | Normal Butane | | | 1,386,000 | | | | 1.59 | |
4Q 2011 | | Sold | | Natural Gasoline | | | 3,276,000 | | | | 2.04 | |
1Q 2012 | | Sold | | Propane | | | 4,410,000 | | | | 1.37 | |
1Q 2012 | | Sold | | Normal Butane | | | 630,000 | | | | 1.98 | |
1Q 2012 | | Sold | | Natural Gasoline | | | 1,008,000 | | | | 2.42 | |
2Q 2012 | | Sold | | Propane | | | 4,788,000 | | | | 1.24 | |
2Q 2012 | | Sold | | Normal Butane | | | 630,000 | | | | 1.88 | |
2Q 2012 | | Sold | | Natural Gasoline | | | 1,008,000 | | | | 2.40 | |
3Q 2012 | | Sold | | Propane | | | 5,040,000 | | | | 1.25 | |
3Q 2012 | | Sold | | Normal Butane | | | 630,000 | | | | 1.88 | |
3Q 2012 | | Sold | | Natural Gasoline | | | 1,008,000 | | | | 2.39 | |
4Q 2012 | | Sold | | Propane | | | 3,780,000 | | | | 1.36 | |
4Q 2012 | | Sold | | Normal Butane | | | 630,000 | | | | 1.89 | |
4Q 2012 | | Sold | | Natural Gasoline | | | 1,134,000 | | | | 2.39 | |
CONDENSATE HEDGES
| | | | | | | | | | | | |
Production Period | | Purchased /Sold | | Commodity | | Barrels | | | Avg. Fixed Price | |
2Q 2011 | | Sold | | Crude | | | 39,000 | | | | 93.13 | |
3Q 2011 | | Sold | | Crude | | | 30,000 | | | | 90.60 | |
4Q 2011 | | Sold | | Crude | | | 30,000 | | | | 90.75 | |
1Q 2012 | | Sold | | Crude | | | 45,000 | | | | 104.56 | |
2Q 2012 | | Sold | | Crude | | | 45,000 | | | | 104.05 | |
3Q 2012 | | Sold | | Crude | | | 45,000 | | | | 103.45 | |
4Q 2012 | | Sold | | Crude | | | 45,000 | | | | 103.02 | |
10
Unaudited Current Commodity Risk Management Positions through December 31, 2012
(as of May 2, 2011)
OPTION CONTRACTS
NATURAL GAS LIQUIDS AND CONDENSATE HEDGES
Option Contracts – NGLs
| | | | | | | | | | | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | Gallons | | | Avg. Strike Price | |
2Q 2011 | | Purchased | | Put | | Propane | | | 4,410,000 | | | | 1.21 | |
3Q 2011 | | Purchased | | Put | | Propane | | | 5,166,000 | | | | 1.24 | |
4Q 2011 | | Purchased | | Put | | Propane | | | 5,040,000 | | | | 1.38 | |
1Q 2012 | | Purchased | | Put | | Propane | | | 6,300,000 | | | | 1.47 | |
2Q 2012 | | Purchased | | Put | | Propane | | | 5,040,000 | | | | 1.37 | |
3Q 2012 | | Purchased | | Put | | Propane | | | 5,040,000 | | | | 1.38 | |
4Q 2012 | | Purchased | | Put | | Propane | | | 1,260,000 | | | | 1.36 | |
Option Contracts – Crude
| | | | | | | | | | | | | | |
Production Period | | Purchased/Sold | | Type | | Commodity | | Barrels | | | Avg. Strike Price | |
2Q 2011 | | Purchased | | Put | | Crude Oil | | | 210,000 | | | | 89.00 | |
2Q 2011 | | Sold | | Call | | Crude Oil | | | 169,500 | | | | 93.35 | |
2Q 2011 | | Purchased | | Call | | Crude Oil | | | 63,000 | | | | 125.20 | |
3Q 2011 | | Purchased | | Put | | Crude Oil | | | 99,000 | | | | 96.87 | |
3Q 2011 | | Sold | | Call | | Crude Oil | | | 169,500 | | | | 93.35 | |
3Q 2011 | | Purchased | | Call | | Crude Oil | | | 63,000 | | | | 125.20 | |
4Q 2011 | | Purchased | | Put | | Crude Oil | | | 93,000 | | | | 99.45 | |
4Q 2011 | | Sold | | Call | | Crude Oil | | | 169,500 | | | | 93.35 | |
4Q 2011 | | Purchased | | Call | | Crude Oil | | | 63,000 | | | | 125.20 | |
1Q 2012 | | Purchased | | Put | | Crude Oil | | | 39,000 | | | | 108.56 | |
1Q 2012 | | Sold | | Call | | Crude Oil | | | 124,500 | | | | 94.69 | |
1Q 2012 | | Purchased | | Call | | Crude Oil | | | 45,000 | | | | 125.20 | |
2Q 2012 | | Purchased | | Put | | Crude Oil | | | 39,000 | | | | 107.58 | |
2Q 2012 | | Sold | | Call | | Crude Oil | | | 124,500 | | | | 94.69 | |
2Q 2012 | | Purchased | | Call | | Crude Oil | | | 45,000 | | | | 125.20 | |
3Q 2012 | | Purchased | | Put | | Crude Oil | | | 39,000 | | | | 106.56 | |
3Q 2012 | �� | Sold | | Call | | Crude Oil | | | 124,500 | | | | 94.69 | |
3Q 2012 | | Purchased | | Call | | Crude Oil | | | 45,000 | | | | 125.20 | |
4Q 2012 | | Purchased | | Put | | Crude Oil | | | 39,000 | | | | 105.80 | |
4Q 2012 | | Sold | | Call | | Crude Oil | | | 124,500 | | | | 94.69 | |
4Q 2012 | | Purchased | | Call | | Crude Oil | | | 45,000 | | | | 125.20 | |
11
