Exhibit 99.1
NEWS RELEASE
| CONTACT: | Matthew Skelly | |
| Vice President – Head of Investor Relations | ||
| Atlas Resource Partners, L.P. | ||
| (877) 280-2857 | ||
| (215) 405-2718 (fax) |
ATLAS RESOURCE PARTNERS, L.P. REPORTS OPERATING AND FINANCIAL
RESULTS FOR THE FOURTH QUARTER AND FULL YEAR 2015
| • | Adjusted EBITDA was $57.8 million(1) and Distributable Cash Flow was $20.7 million(1)for the fourth quarter 2015 |
| • | Natural gas and oil production in the fourth quarter 2015 were hedged approximately 76% and 108%, respectively; ARP’s current market value of its hedge portfolio is approximately $408 million |
| • | Partnership expects to be cash-flow-positive in 2016 |
| • | Management will discuss fourth quarter 2015 financial and operational results on a conference call at 9:00 AM ET on Friday, February 26,2016 |
Fort Worth, TX – February 25, 2016 - Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or the “Company”) reported operating and financial results for the fourth quarter and full year 2015.
Daniel Herz, Chief Executive Officer of ARP, stated, “The current energy environment has presented increasing challenges to all aspects of our business, even since last quarter. We are working strenuously to address all areas, including leverage, liquidity, operating expenses, G&A expenses, capital expenditures, among others. While we have continued to addressed these items, challenges persist.”
| • | Fourth quarter 2015 Adjusted EBITDA, a non-GAAP measure, was $57.8 million(1), compared to $68.1 million for the third quarter 2015, and $82.7 million for the prior year comparable quarter. Full year 2015 Adjusted EBITDA was $261.5 million, compared to full year 2014 Adjusted EBITDA of $295.1 million. The decrease from the prior quarter was primarily due to the shortfall of funds raised within our 2015 Eagle Ford drilling partnership program. The decrease in Adjusted EBITDA compared to the prior year quarter and full year 2014 was due to declines in production volume and commodity prices during the respective periods, and the shortfall of funds raised within our 2015 Eagle Ford drilling partnership program. |
| • | Distributable Cash Flow, a non-GAAP measure, was $20.7 million(1), or approximately $0.20 per common unit, for the fourth quarter 2015, compared to $28.8 million for the third quarter 2015 and $49.5 million for the prior year comparable quarter. Full year 2015 Distributable Cash Flow was $108.3 million, compared to full year 2014 Distributable Cash Flow of $207.8 million. |
| • | ARP paid monthly cash distributions totaling approximately $0.0375 per limited partner unit for the fourth quarter 2015. On January 28, 2016, ARP declared its monthly distribution for the month of December 2015 of $0.0125 per common unit, or $0.15 per unit on an annual basis. The December 2015 distribution was paid Friday, February 12, 2016 to holders of record as of Monday, February 8, 2016. |
| (1) | A reconciliation of GAAP net income (loss) to Adjusted EBITDA and Distributable Cash Flow is provided in the financial tables of this release. Please see footnote 1 to the Financial Information table of this release. |
| • | The Company’s partnership management business raised $59.8 million from its 2015 Atlas Eagle Ford private placement fundraising, in spite of continued declines in commodity prices during peak fundraising periods at the end of the year. The 2015 Atlas Eagle Ford private placement capital is expected to be deployed to drill new wells in the Eagle Ford Shale, which have experienced decreasing drilling costs as low commodity prices have persisted. |
| • | On a GAAP basis, net loss was $288.7 million for the fourth quarter 2015 compared with net loss of $560.9 million for the third quarter 2015 and a net loss of $579.5 million for the prior year comparable period. The net loss for the fourth quarter 2015 was principally generated by non-cash expenses, specifically depreciation and amortization and an asset impairment charge on certain oil and gas properties due to recent declines in forward commodity prices. Full year 2015 net loss was $808.8 million, as compared to a net loss of $607.1 million for the full year 2014. The full year net loss variance was for similar reasons as mentioned above. |
Recent Events
Redetermination and amendment of revolving credit facility
On November 23, 2015, ARP completed its semi-annual redetermination of its credit facility borrowing base, resulting in a revised borrowing base of $700 million, a decrease of approximately 6.7% from the previous level. In order to provide continued flexibility in the current commodity price environment, ARP reached an agreement with its commercial bank lending group to amend certain terms of its revolving credit facility, including improved terms on its leverage covenants. The new terms include:
| • | Suspension of compliance with maximum total leverage covenant until Q1 2017; as well as new maximum total leverage covenants in future periods; including: |
| • | 5.75x beginning in Q1 2017 |
| • | 5.50x beginning in Q3 2017 |
| • | 5.25x beginning in Q1 2018 |
| • | 5.00x beginning in Q2 2018 and thereafter |
| • | Elimination of senior secured leverage covenant |
| • | Addition of maximum first lien secured leverage covenant of 2.75x |
| • | Ability to add additional subordinated secured debt |
Successful completion of consent solicitation of senior unsecured notes
On December 29, 2015, ARP received consent from both issues of unsecured bondholders to amend the indentures of the unsecured bonds to, among other things, increase the fixed dollar amount of secured indebtedness permitted to be incurred under credit facilities pursuant to the indentures to $1.0 billion from $500.0 million, subject to certain conditions. The consent solicitations received support from approximately 97% of bondholders. There is also a cap of the maximum amount of interest expense incurred from senior secured debt of $80 million subject to certain adjustments and tested annually.
Year End 2015 Oil & Gas Reserves
As of December 31, 2015, based on the SEC average price assumptions of $2.59 per mcf for natural gas and $50.28 per barrel for crude oil, net proved oil and gas reserves were approximately 0.921 trillion cubic feet equivalent (“Tcfe”), a decrease of approximately 38% from the year end 2014 reserve levels. The year end 2015 reserves were valued at a PV-10 amount of approximately $507 million, which does not include the value of ARP’s commodity derivatives. The fair value of ARP’s commodity derivatives at December 31, 2015 was approximately $357.7 million. Approximately 82% of ARP’s reserves were proved developed, compared to 77% at the end of 2014.
E&P Operating Results
| • | Average net daily production for the fourth quarter 2015 was 249.5 Mmcfed, approximately 16% lower than the prior year comparable quarter. The decrease in net production from the prior year quarter was due primarily to the sale of our Non-Operated interest in the County Line CBM Field in Wyoming effective October 1st as well as shutting in high volume Marcellus wells in Lycoming County, Pennsylvania for over half of the quarter. Average net daily production for the full year 2015 was 266.4 Mmcfed, as compared to 281.5 Mmcfed average for full year 2014. |
| • | ARP’s net realized price for natural gas including the effect of hedge positions was $3.42 per mcf for the fourth quarter 2015, compared to $3.30 per mcf for the third quarter 2015. Net realized oil prices including the effect of hedge positions averaged $85.26 per barrel for the fourth quarter 2015, compared to $88.42 for the third quarter 2015. |
| • | Investment partnership margin contributed $5.0 million to Adjusted EBITDA and distributable cash flow for the fourth quarter 2015 compared with $12.0 million for the sequential quarter. The $7.0 million decrease in investment partnership margin was due to lower amounts of capital deployed during the fourth quarter 2015 due to scheduled changes in well drilling activity. |
Hedge Positions
| • | A summary of ARP’s derivative positions as of February 25, 2016 is provided in the financial tables of this release. During the fourth quarter 2015, ARP was approximately 76% hedged on its net natural gas production and approximately 108% hedged on its net oil production. During the year ended December 31, 2015, the Partnership received approximately $179.1 million of cash from realized natural gas and oil hedge positions. |
Corporate Expenses & Capital Position
| • | Cash general and administrative expense was $15.6 million for the fourth quarter 2015, $3.1 million higher than the third quarter 2015 and $2.5 million higher than the prior year fourth quarter. The increase compared with prior periods was due primarily to lower capitalized selling and administrative costs associated with lower funds raised in our 2015 drilling partnership program. |
| • | Cash interest expense was $21.8 million for the fourth quarter 2015, $0.3 million higher than the third quarter 2015 and $5.5 million higher than the prior year fourth quarter. The increase compared to prior year period was primarily due to the $250 million second lien financing entered into by ARP in February 2015. |
| • | At December 31, 2015, ARP had $1.534 billion of total debt, including $592.0 million outstanding under its revolving credit facility. The level of outstanding debt was consistent with the previous quarter, which had $563.4 million outstanding under its revolving credit facility. |
ARP will be discussing its fourth quarter and full year 2015 results on an investor call with management on Friday, February 26, 2016 at 9:00 am Eastern Time. Interested parties are invited to access the live webcast the investor call by going to the Investor Relations section of Atlas Resource’s website at www.atlasresourcepartners.com. For those unavailable to listen to the live broadcast, the replay of the webcast will be available following the live call on the Atlas Resource website and telephonically beginning at approximately 12:30 p.m. ET on February 26, 2016 by dialing 855-859-2056, passcode: 35819906.
Atlas Resource Partners, L.P. (NYSE: ARP)is an exploration & production master limited partnership which owns an interest in over 14,500 producing natural gas and oil wells, located primarily in Appalachia, the Eagle Ford Shale (TX), the Barnett Shale (TX), the Mississippi Lime (OK), the Raton Basin (NM), Black Warrior Basin (AL), Arkoma Basin (OK) and the Rangely Field in Colorado. ARP is also the largest sponsor of natural gas and oil investment partnerships in the U.S. For more information, please visit our website atwww.atlasresourcepartners.com, or contact Investor Relations atInvestorRelations@atlasenergy.com.
Atlas Energy Group, LLC (NYSE: ATLS)is a limited liability company which owns the following interests: all of the general partner interest, incentive distribution rights and an approximate 23% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P.; the general partner interests, incentive distribution rights and limited partner interests in Atlas Growth Partners, L.P.; and a general partner interest in Lightfoot Capital Partners, an entity that invests directly in energy-related businesses and assets. For more information, please visit our website atwww.atlasenergy.com, or contact Investor Relations atInvestorRelations@atlasenergy.com.
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Cautionary Note Regarding Forward-Looking Statements
Certain matters discussed within this press release are forward-looking statements. Although Atlas Resource 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 Resource Partners does not undertake any duty to update any statements contained herein (including any forward-looking statements), except as required by law. This document contains forward-looking statements that involve a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those contained in the forward-looking statements. ARP cautions readers that any forward-looking information is not a guarantee of future performance. Such forward-looking statements include, but are not limited to, statements about future financial and operating results, resource potential, ARP’s plans, objectives, expectations and intentions and other statements that are not historical facts. Risks, assumptions and uncertainties that could cause actual results to materially differ from the forward-looking statements include, but are not limited to, those associated with general economic and business conditions; ARP’s ability to realize
the benefits of its acquisitions; changes in commodity prices; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; ARP’s level of indebtedness, leverage and liquidity, including borrowing base availability and covenant compliance; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; and other risks, assumptions and uncertainties detailed from time to time in ARP’s reports filed with the U.S. Securities and Exchange Commission, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and ARP assumes no obligation to update such statements, except as may be required by applicable law.
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
Revenues: | ||||||||||||||||
Gas and oil production | $ | 64,756 | $ | 132,158 | $ | 356,999 | $ | 470,051 | ||||||||
Well construction and completion | 12,840 | 46,647 | 76,505 | 173,564 | ||||||||||||
Gathering and processing | 1,385 | 2,820 | 7,431 | 14,107 | ||||||||||||
Administration and oversight | 511 | 3,492 | 7,812 | 15,564 | ||||||||||||
Well services | 5,254 | 6,518 | 23,822 | 24,959 | ||||||||||||
Gain on mark-to-market derivatives | 57,517 | 2,819 | 267,223 | 2,819 | ||||||||||||
Other, net | 161 | 247 | 241 | 590 | ||||||||||||
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Total revenues | 142,424 | 194,701 | 740,033 | 701,654 | ||||||||||||
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Costs and expenses: | ||||||||||||||||
Gas and oil production | 39,429 | 49,188 | 169,653 | 182,226 | ||||||||||||
Well construction and completion | 11,165 | 40,562 | 66,526 | 150,925 | ||||||||||||
Gathering and processing | 2,207 | 3,625 | 9,613 | 15,525 | ||||||||||||
Well services | 2,427 | 2,482 | 9,162 | 10,007 | ||||||||||||
General and administrative | 21,568 | 21,455 | 65,968 | 72,349 | ||||||||||||
Depreciation, depletion and amortization | 32,030 | 63,846 | 157,978 | 239,923 | ||||||||||||
Asset impairment | 294,389 | 573,774 | 966,635 | 573,774 | ||||||||||||
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Total costs and expenses | 403,215 | 754,932 | 1,445,535 | 1,244,729 | ||||||||||||
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Operating loss | (260,791 | ) | (560,231 | ) | (705,502 | ) | (543,075 | ) | ||||||||
Loss on asset sales and disposal | (905 | ) | (183 | ) | (1,181 | ) | (1,869 | ) | ||||||||
Interest expense | (27,028 | ) | (19,116 | ) | (102,133 | ) | (62,144 | ) | ||||||||
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Net loss | (288,724 | ) | (579,530 | ) | (808,816 | ) | (607,088 | ) | ||||||||
Preferred limited partner dividends | (4,289 | ) | (5,969 | ) | (16,469 | ) | (19,267 | ) | ||||||||
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Net loss attributable to common limited partners and the general partner | $ | (293,013 | ) | $ | (585,499 | ) | $ | (825,285 | ) | $ | (626,355 | ) | ||||
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Allocation of net loss attributable to common limited partners and the general partner: | ||||||||||||||||
General partner’s interest | $ | (5,860 | ) | $ | (8,649 | ) | $ | (16,505 | ) | $ | (1,222 | ) | ||||
Common limited partners’ interest | (287,153 | ) | (576,850 | ) | (808,780 | ) | (625,133 | ) | ||||||||
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Net loss attributable to common limited partners and the general partner | $ | (293,013 | ) | $ | (585,499 | ) | $ | (825,285 | ) | $ | (626,355 | ) | ||||
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Net loss attributable to common limited partners per unit: |
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Basic | $ | (2.81 | ) | $ | (7.04 | ) | $ | (8.63 | ) | $ | (8.37 | ) | ||||
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Diluted | $ | (2.81 | ) | $ | (7.04 | ) | $ | (8.63 | ) | $ | (8.37 | ) | ||||
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Weighted average common limited partner units outstanding: |
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Basic | 102,061 | 81,919 | 93,745 | 74,716 | ||||||||||||
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Diluted | 102,061 | 81,919 | 93,745 | 74,716 | ||||||||||||
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ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
| ASSETS | December 31, 2015 | December 31, 2014 | ||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,353 | $ | 15,247 | ||||
Accounts receivable | 63,367 | 114,520 | ||||||
Advances to affiliates | — | 6,567 | ||||||
Current portion of derivative asset | 159,460 | 144,259 | ||||||
Subscriptions receivable | 19,877 | 32,398 | ||||||
Prepaid expenses and other | 22,935 | 26,296 | ||||||
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Total current assets | 266,992 | 339,287 | ||||||
Property, plant and equipment, net | 1,191,611 | 2,263,820 | ||||||
Goodwill and intangible assets, net | 14,095 | 14,330 | ||||||
Long-term derivative asset | 198,262 | 130,602 | ||||||
Other assets, net | 60,044 | 50,081 | ||||||
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| $ | 1,731,004 | $ | 2,798,120 | |||||
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| LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT) | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 49,249 | $ | 111,198 | ||||
Advances from affiliates | 9,924 | 8,816 | ||||||
Liabilities associated with drilling contracts | 21,483 | 40,611 | ||||||
Accrued well drilling and completion costs | 26,914 | 80,404 | ||||||
Distribution payable | 4,334 | 20,876 | ||||||
Accrued liabilities | 50,096 | 84,235 | ||||||
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Total current liabilities | 162,000 | 346,140 | ||||||
Long-term debt | 1,534,482 | 1,394,460 | ||||||
Asset retirement obligations and other | 119,150 | 109,983 | ||||||
Commitments and contingencies | ||||||||
Partners’ Capital (Deficit): | ||||||||
General partner’s interest | (33,642 | ) | (13,697 | ) | ||||
Preferred limited partners’ interests | 188,739 | 163,522 | ||||||
Common limited partners’ interests | (260,276 | ) | 605,065 | |||||
Class C common limited partner warrants | 1,176 | 1,176 | ||||||
Accumulated other comprehensive income | 19,375 | 191,471 | ||||||
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Total partners’ capital (deficit) | (84,628 | ) | 947,537 | |||||
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| $ | 1,731,004 | $ | 2,798,120 | |||||
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ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
Net loss attributable to common limited partners per unit - basic | $ | (2.81 | ) | $ | (7.04 | ) | $ | (8.63 | ) | $ | (8.37 | ) | ||||
Cash distributions paid per unit(1) | $ | 0.038 | $ | 0.590 | $ | 1.013 | $ | 2.343 | ||||||||
Production revenues (in thousands): | ||||||||||||||||
Natural gas | $ | 36,228 | $ | 79,687 | $ | 217,236 | $ | 318,920 | ||||||||
Oil | 25,173 | 42,444 | 122,273 | 110,070 | ||||||||||||
Natural gas liquids | 3,355 | 10,027 | 17,490 | 41,061 | ||||||||||||
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Total production revenues | $ | 64,756 | $ | 132,158 | $ | 356,999 | $ | 470,051 | ||||||||
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Production volume:(2)(3) | ||||||||||||||||
Appalachia: (4) | ||||||||||||||||
Natural gas (Mcfd) | 30,173 | 35,420 | 31,930 | 38,160 | ||||||||||||
Oil (Bpd) | 312 | 355 | 335 | 381 | ||||||||||||
Natural gas liquids (Bpd) | 31 | 43 | 33 | 41 | ||||||||||||
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Total (Mcfed) | 32,230 | 37,807 | 34,139 | 40,689 | ||||||||||||
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Coal-bed Methane:(4) | ||||||||||||||||
Natural gas (Mcfd) | 123,928 | 137,943 | 129,453 | 132,296 | ||||||||||||
Oil (Bpd) | — | — | — | — | ||||||||||||
Natural gas liquids (Bpd) | — | — | — | — | ||||||||||||
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Total (Mcfed) | 123,928 | 137,943 | 129,453 | 132,296 | ||||||||||||
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Barnett/Marble Falls: | ||||||||||||||||
Natural gas (Mcfd) | 40,327 | 54,143 | 45,220 | 57,361 | ||||||||||||
Oil (Bpd) | 383 | 923 | 564 | 1,066 | ||||||||||||
Natural gas liquids (Bpd) | 1,709 | 2,598 | 1,992 | 2,698 | ||||||||||||
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Total (Mcfed) | 52,874 | 75,264 | 60,555 | 79,946 | ||||||||||||
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Rangely/Eagle Ford:(4)(5) | ||||||||||||||||
Natural gas (Mcfd) | 250 | 693 | 315 | 175 | ||||||||||||
Oil (Bpd) | 3,902 | 3,535 | 3,818 | 1,538 | ||||||||||||
Natural gas liquids (Bpd) | 308 | 421 | 320 | 173 | ||||||||||||
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Total (Mcfed) | 25,513 | 24,433 | 25,147 | 10,438 | ||||||||||||
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Mississippi Lime/Hunton: | ||||||||||||||||
Natural gas (Mcfd) | 5,529 | 8,339 | 6,570 | 6,810 | ||||||||||||
Oil (Bpd) | 289 | 599 | 404 | 427 | ||||||||||||
Natural gas liquids (Bpd) | 467 | 669 | 546 | 561 | ||||||||||||
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Total (Mcfed) | 10,059 | 15,948 | 12,269 | 12,734 | ||||||||||||
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Other Operating Areas:(4) | ||||||||||||||||
Natural gas (Mcfd) | 2,914 | 3,152 | 3,126 | 3,253 | ||||||||||||
Oil (Bpd) | 13 | 27 | 17 | 25 | ||||||||||||
Natural gas liquids (Bpd) | 309 | 310 | 263 | 330 | ||||||||||||
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Total (Mcfed) | 4,845 | 5,177 | 4,811 | 5,384 | ||||||||||||
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Total Production: | ||||||||||||||||
Natural gas (Mcfd) | 203,121 | 239,690 | 216,613 | 238,054 | ||||||||||||
Oil (Bpd) | 4,898 | 5,440 | 5,139 | 3,436 | ||||||||||||
Natural gas liquids (Bpd) | 2,824 | 4,040 | 3,155 | 3,802 | ||||||||||||
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Total (Mcfed) | 249,450 | 296,571 | 266,374 | 281,486 | ||||||||||||
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Average sales prices: (3) | ||||||||||||||||
Natural gas (per Mcf)(6) | $ | 3.42 | $ | 3.66 | $ | 3.41 | $ | 3.76 | ||||||||
Oil (per Bbl)(7) | $ | 85.26 | $ | 84.81 | $ | 84.30 | $ | 87.76 | ||||||||
Natural gas liquids (per Bbl)(8) | $ | 23.17 | $ | 26.97 | $ | 22.40 | $ | 29.59 | ||||||||
Production costs:(3)(9) | $ | 1.33 | $ | 1.32 | $ | 1.34 | $ | 1.27 | ||||||||
Lease operating expenses per Mcfe | 0.17 | 0.28 | 0.19 | 0.27 | ||||||||||||
Production taxes per Mcfe | 0.23 | 0.22 | 0.24 | 0.25 | ||||||||||||
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Transportation and compression expenses per Mcfe | $ | 1.73 | $ | 1.82 | $ | 1.76 | $ | 1.80 | ||||||||
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Total production costs per Mcfe | ||||||||||||||||
Depletion per Mcfe(3) | $ | 1.25 | $ | 2.23 | $ | 1.49 | $ | 2.23 | ||||||||
| (1) | Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each month within each quarter, based upon the distributable cash flow generated during the respective period. |
| (2) | Production quantities consist of the sum of (i) ARP’s proportionate share of production from wells in which it has a direct interest, based on ARP’s proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the investment partnerships in which ARP has an interest, based on its equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells. |
| (3) | “Mcf” and “Mcfd” represent thousand cubic feet and thousand cubic feet per day; “Mcfe” and “Mcfed” represent thousand cubic feet equivalents and thousand cubic feet equivalents per day, and “Bbl” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of six Mcf’s to one barrel. |
| (4) | Appalachia includes ARP’s production located in Pennsylvania, Ohio, New York and West Virginia (excluding the Cedar Bluff area); Coal-bed methane includes ARP’s production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Cedar Bluff area of West Virginia and Virginia, and the Arkoma Basin in eastern Oklahoma; Rangely/Eagle Ford includes ARP’s 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado and its production located in southern Texas; Other operating areas include ARP’s production located in the Chattanooga, New Albany and Niobrara Shales |
| (5) | Volumetric production per day for Rangely/Eagle Ford for the year ended December 31, 2014 includes Rangely production from July 1, 2014, the date of the acquisition, through December 31, 2014; Eagle Ford includes production from November 5, 2014, the date of the acquisition, through December 31, 2014. Production per day for Rangely/Eagle Ford and total production per day represents total production volume over the 92 and 365 days within the three months and year ended December 31, 2014, respectively. |
| (6) | ARP’s average sales prices for natural gas before the effects of financial hedging were $1.96 per Mcf and $3.52 per Mcf for the three months ended December 31, 2015 and 2014, respectively, and $2.23 per Mcf and $3.93 per Mcf for the years ended December 31, 2015 and 2014, respectively. These amounts exclude the impact of subordination of production revenues to investor partners within the investor partnerships. Including the effects of subordination, average natural gas sales prices were $3.39 per Mcf ($1.93 per Mcf before the effects of financial hedging) and $3.61 per Mcf ($3.46 per Mcf before the effects of financial hedging) for the three months ended December 31, 2015 and 2014, respectively, and $3.36 per Mcf ($2.19 per Mcf before the effects of financial hedging) and $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging) for the years ended December 31, 2015 and 2014, respectively. |
| (7) | ARP’s average sales prices for oil before the effects of financial hedging were $36.13 per barrel and $65.29 per barrel for the three months ended December 31, 2015 and 2014, respectively, and $44.19 per barrel and $82.22 per barrel for the years ended December 31, 2015 and 2014, respectively. |
| (8) | ARP’s average sales prices for natural gas liquids before the effects of financial hedging were $11.99 per barrel and $21.80 per barrel for the three months ended December 31, 2015 and 2014, respectively, and $12.77 per barrel and $29.39 per barrel for the years ended December 31, 2015 and 2014, respectively. |
| (9) | Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, production overhead and transportation expenses. These amounts exclude the effects of ARP’s proportionate share of lease operating expenses associated with subordination of production revenue to investor partners within ARP’s investor partnerships. Including the effects of these costs, lease operating expenses per Mcfe were $1.32 per Mcfe ($1.72 per Mcfe for total production costs) and $1.31 per Mcfe ($1.80 per Mcfe for total production costs) for the three months ended December 31, 2015 and 2014, respectively, and $1.32 per Mcfe ($1.74 per Mcfe for total production costs) and $1.25 per Mcfe ($1.77 per Mcfe for total production costs) for the years ended December 31, 2015 and 2014, respectively. |
ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
| December 31, 2015 | December 31, 2014 | |||||||
Total debt | $ | 1,534,482 | $ | 1,394,460 | ||||
Less: Cash | (1,353 | ) | (15,247 | ) | ||||
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Total net debt/(cash) | 1,533,129 | 1,379,213 | ||||||
Partners’ capital (deficit) | (84,628 | ) | 947,537 | |||||
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Total capitalization | $ | 1,448,501 | $ | 2,326,750 | ||||
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Ratio of net debt to capitalization | 1.06x | 0.59x | ||||||
ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
Maintenance capital expenditures(1) | $ | 11,000 | $ | 19,000 | $ | 53,788 | $ | 65,300 | ||||||||
Expansion capital expenditures | 13,848 | 43,149 | 73,350 | 147,428 | ||||||||||||
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Total | $ | 24,848 | $ | 62,149 | $ | 127,138 | $ | 212,728 | ||||||||
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| (1) | Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its Distributable Cash Flow and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including the Eagle Ford Shale, Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures – generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. |
ATLAS RESOURCE PARTNERS, L.P.
Financial Information
(unaudited; in thousands, except per unit amounts)
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
Reconciliation of net loss to non-GAAP measures(1): | ||||||||||||||||
Net loss | $ | (288,724 | ) | $ | (579,530 | ) | $ | (808,816 | ) | $ | (607,088 | ) | ||||
Acquisition and related costs | 5,562 | 5,049 | 10,597 | 17,814 | ||||||||||||
Depreciation, depletion and amortization | 32,030 | 63,846 | 157,978 | 239,923 | ||||||||||||
Asset impairment | 294,389 | 573,774 | 966,635 | 573,774 | ||||||||||||
Amortization of deferred finance costs | 5,240 | 3,155 | 19,638 | 9,445 | ||||||||||||
Non-cash stock compensation expense | 447 | 1,725 | 4,945 | 8,067 | ||||||||||||
Maintenance capital expenditures(2) | (11,000 | ) | (16,300 | ) | (53,788 | ) | (50,550 | ) | ||||||||
Preferred unit distributions | (4,291 | ) | (4,707 | ) | (16,904 | ) | (18,005 | ) | ||||||||
Loss on asset sales and disposal | 905 | 183 | 1,181 | 1,869 | ||||||||||||
Non-cash valuation allowance | — | 1,590 | — | 1,590 | ||||||||||||
Cash settlements on commodity derivative contracts(3) | 43,779 | — | 94,186 | — | ||||||||||||
Unrealized gain on mark-to-market derivatives | (57,517 | ) | (2,819 | ) | (267,223 | ) | (2,819 | ) | ||||||||
Other | (132 | ) | (188 | ) | (110 | ) | (204 | ) | ||||||||
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Distributable cash flow attributable to limited partners and the general partner(1) | $ | 20,688 | $ | 45,778 | $ | 108,319 | $ | 173,816 | ||||||||
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Supplemental Adjusted EBITDA and Distributable Cash Flow Summary: |
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Gas and oil production margin | $ | 69,106 | $ | 82,970 | $ | 281,532 | $ | 287,825 | ||||||||
Well construction and completion margin | 1,675 | 6,085 | 9,979 | 22,639 | ||||||||||||
Administration and oversight margin | 511 | 3,492 | 7,812 | 15,564 | ||||||||||||
Well services margin | 2,827 | 4,036 | 14,660 | 14,952 | ||||||||||||
Gathering and processing margin | (822 | ) | (805 | ) | (2,182 | ) | (1,418 | ) | ||||||||
Cash general and administrative expenses(4) | (15,559 | ) | (13,091 | ) | (50,426 | ) | (44,878 | ) | ||||||||
Other, net | 29 | 59 | 131 | 386 | ||||||||||||
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Adjusted EBITDA(1) | 57,767 | 82,746 | 261,506 | 295,070 | ||||||||||||
Cash interest expense(5) | (21,788 | ) | (15,961 | ) | (82,495 | ) | (52,699 | ) | ||||||||
Preferred unit distributions | (4,291 | ) | (4,707 | ) | (16,904 | ) | (18,005 | ) | ||||||||
Maintenance capital expenditures(2) | (11,000 | ) | (16,300 | ) | (53,788 | ) | (50,550 | ) | ||||||||
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Distributable Cash Flow attributable to limited partners and the general partner(1) | $ | 20,688 | $ | 45,778 | $ | 108,319 | $ | 173,816 | ||||||||
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Discretionary adjustments considered by the Board of Directors of the General Partner in the determination of quarterly cash distributions: | ||||||||||||||||
Net cash from acquisitions from the effective date through closing date(6) | — | 3,757 | — | 33,959 | ||||||||||||
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Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(7) | $ | 20,688 | $ | 49,535 | $ | 108,319 | $ | 207,775 | ||||||||
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Distributions Paid(8) | $ | 3,948 | $ | 53,729 | $ | 95,278 | $ | 198,740 | ||||||||
per limited partner unit | $ | 0.038 | $ | 0.590 | $ | 1.013 | $ | 2.343 | ||||||||
Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(9) | $ | 16,740 | $ | (4,194 | ) | $ | 13,041 | $ | 9,035 | |||||||
| (1) | Although not prescribed under generally accepted accounting principles (“GAAP”), ARP’s management believes the presentation of EBITDA, Adjusted EBITDA and Distributable Cash Flow (“DCF”) is relevant and useful, because it helps ARP’s investors understand its operating performance, allows for easier comparison of its results with other master limited partnerships (“MLP”), and is a critical component in the determination of quarterly cash distributions. As a MLP, ARP is required to distribute 100% of available cash, as defined in its limited partnership agreement (“Available Cash”) and subject to cash reserves established by its general partner, to investors on a quarterly basis. ARP refers to Available Cash prior to the establishment of cash reserves as DCF. EBITDA, Adjusted EBITDA and DCF should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. While ARP’s management believes that its methodology of calculating EBITDA, Adjusted EBITDA and DCF is generally consistent with the common practice of other MLPs, such metrics may not be consistent and, as such, |
| may not be comparable to measures reported by other MLPs, who may use other adjustments related to their specific businesses. EBITDA, Adjusted EBITDA and DCF are supplemental financial measures used by the ARP’s management and by external users of ARP’s financial statements such as investors, lenders under ARP’s credit facility, research analysts, rating agencies and others to assess its: |
| • | Operating performance as compared to other publicly traded partnerships and other companies in the upstream energy sector, without regard to financing methods, historical cost basis or capital structure; |
| • | Ability to generate sufficient cash flows to support its distributions to unitholders; |
| • | Ability to incur and service debt and fund capital expansion; |
| • | The viability of potential acquisitions and other capital expenditure projects; and |
| • | Ability to comply with financial covenants in its Credit Facility, which is calculated based upon Adjusted EBITDA. |
DCF is determined by calculating EBITDA, adjusting it for non-cash, non-recurring and other items to achieve Adjusted EBITDA, and then deducting cash interest expense and maintenance capital expenditures. ARP defines EBITDA as net income (loss) plus the following adjustments:
| • | Interest expense; |
| • | Income tax expense; and |
| • | Depreciation, depletion and amortization. |
ARP defines Adjusted EBITDA as EBITDA plus the following adjustments:
| • | Asset impairments; |
| • | Acquisition and related costs; |
| • | Non-cash stock compensation; |
| • | (Gains) losses on asset disposal; |
| • | Cash proceeds received from monetization of derivative transactions; |
| • | Premiums paid on swaption derivative contracts; |
| • | Non-cash valuation allowances; and |
| • | Other items. |
ARP adjusts DCF for non-cash, non-recurring and other items for the sole purpose of evaluating its cash distribution for the quarterly period, with EBITDA and Adjusted EBITDA adjusted in the same manner for consistency. ARP defines DCF as Adjusted EBITDA less the following adjustments:
| • | Cash interest expense; |
| • | Preferred unit cash distributions; and |
| • | Maintenance capital expenditures. |
| (2) | Production from oil and gas assets naturally declines in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such declines in production margin for the purpose of stabilizing its DCF and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including the Eagle Ford Shale, Marcellus Shale, Utica Shale, Mississippi Lime, and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. Estimates for maintenance capital expenditures in the current year are the sum of the estimate calculated in the prior year plus estimates for the decline in production margin from wells connected during the current year and production acquired through acquisitions. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures – generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. |
| (3) | Includes cash settlements on commodity derivative contracts not previously recorded within accumulated other comprehensive income following the de-designation of hedges on January 1, 2015. |
| (4) | Excludes non-cash stock compensation expense and certain acquisition and related costs. |
| (5) | Excludes non-cash amortization of deferred financing costs. |
| (6) | These amounts reflect net cash proceeds received from the respective effective date through the respective closing date of assets acquired, less estimated and pro forma amounts of maintenance capital expenditures and financing costs. The management of ARP believes these amounts are critical in its evaluation of DCF and cash distributions for the period. Under GAAP, such amounts are characterized as purchase price adjustments and are reflected in the net purchase price paid for the acquired assets, rather than reflected as components of net income or loss for the period. For the three months ended December 31, 2014, such amounts include net cash generated by the Eagle Ford assets from October 1, 2014 to November 4, 2014 of $6.8 million, less pro forma interest expense of $0.4 million and estimated maintenance capital expenditures of $2.7 million. For the year ended December 31, 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to May 11, 2014, the Rangely assets from April 1, 2014 to June 30, 2014, and the Eagle Ford assets from July 1, 2014 to November 4, 2014 of $53.2 million, less pro forma interest expense of $2.8 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $14.7 million. |
| (7) | Including the discretionary adjustments by the Board of Directors of ARP’s General Partner in the determination of quarterly cash distributions, Adjusted EBITDA would have been $89.6 million for the three months ended December 31, 2014 and $348.3 million for the year ended December 31, 2014, respectively. |
| (8) | Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each month within each quarter, based upon the distributable cash flow generated during the respective period. |
| (9) | ARP seeks to at least maintain its current cash distribution in future quarterly periods, and expects to only increase such cash distributions when future Distributable Cash Flow amounts allow for it and are expected to be sustained. ARP’s determination of quarterly cash distributions and its resulting determination of the amount of excess (shortfall) those cash distributions generate in comparison to Distributable Cash Flow are based upon its assessment of numerous factors, including but not limited to future commodity price and interest rate movements, variability of well productivity, weather effects, and financial leverage. ARP also considers its historical trailing four quarters of excess or shortfalls and future forecasted excess or shortfalls that its cash distributions generate in comparison to Distributable Cash Flow due to the variability of its Distributable Cash Flow generated each quarter, which could cause it to have more or less excess (shortfalls) generated from quarter to quarter. |
ATLAS RESOURCE PARTNERS, L.P.
Hedge Position Summary
(as of February 25, 2016)
Natural Gas
Fixed Price Swaps
Production Period Ended December 31, | Average Fixed Price (per mmbtu)(a) | Volumes (mmbtus)(a) | ||||||
2016(b) | $ | 4.23 | 53,546,300 | |||||
2017 | $ | 4.22 | 49,920,000 | |||||
2018 | $ | 4.17 | 40,800,000 | |||||
2019 | $ | 4.02 | 15,960,000 | |||||
Put Options – Drilling Partnerships
Production Period Ended December 31, | Average Fixed Price (per mmbtu)(a) | Average Volumes (mmbtus)(a) | ||||||
2016(b) | $ | 4.15 | 1,440,000 | |||||
Crude Oil
Fixed Price Swaps
Production Period Ended December 31, | Average Fixed Price (per bbl)(a) | Volumes (bbls)(a) | ||||||
2016(b) | $ | 81.47 | 1,557,000 | |||||
2017 | $ | 77.28 | 1,140,000 | |||||
2018 | $ | 76.28 | 1,080,000 | |||||
2019 | $ | 68.37 | 540,000 | |||||
Natural Gas Liquids
Crude Fixed Price Swaps
Production Period Ended December 31, | Average Fixed Price (per bbl)(a) | Volumes (bbls)(a) | ||||||
2016(b) | $ | 85.65 | 84,000 | |||||
2017 | $ | 83.78 | 60,000 | |||||
| (a) | “mmbtu” represents million metric British thermal units; “bbl” represents barrel. |
| (b) | Reflects hedges covering the full twelve months of 2016. |