Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - Titan Energy, LLC | d921761d8k.htm |
Exhibit 99.1
NEWS RELEASE
| CONTACT: | Brian J. Begley | |
| Vice President - 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 FIRST QUARTER 2015
| • | Adjusted EBITDA was $68.9 million(1) for the first quarter 2015 |
| • | Distributable cash flow was $31.4 million(1) for the first quarter 2015, representing distribution coverage of approximately 1.1x |
| • | ARP substantially increased its natural gas and oil financial hedge positions through 2019; approximately 72%, 68% and 63% hedged for natural gas and approximately 94%, 77% and 56% hedged for oil in 2015, 2016 and 2017, respectively, based on first quarter 2015 average production |
| • | Management will discuss first quarter 2015 financial and operational results on a conference call at 9AM ET on Wednesday, May 6th |
Philadelphia, PA – May 5, 2015 - Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) reported operating and financial results for the first quarter 2015.
Daniel C. Herz, President of ARP’s General Partner, stated, “Our company continues to emphasize the core fundamentals of our business – focused and efficient capital spending, as well as further reduction of production costs in all of our key regions. Through our efforts to develop higher margin resources and drive expenses lower, we have been successful in expanding our gross margin per unit of production. We have also seen a substantial improvement in our development and service costs, as much as 40%, and we expect this to have a meaningful impact on our operating and capital expenditures this year. These efforts in improving our foundation will strengthen our operations and prepare ARP for future strategic activities.”
* * *
| • | First quarter 2015 Adjusted EBITDA, a non-GAAP measure was $68.9 million(1), compared to $59.0 million for the prior year first quarter. The increase from the prior year period was due primarily to the added oil-rich production volumes from the acquisition of properties in June 2014 in the Rangely field located in northwestern Colorado, as well the acquisition of producing properties in November 2014 in the Eagle Ford Shale, offset by lower realized commodity prices and lower partnership margin. |
| • | Distributable Cash Flow, a non-GAAP measure, was $31.4 million(1), or approximately $0.36 per common unit, for the first quarter 2015, compared with $32.4 million for the prior year first quarter. |
| • | On February 23, 2015, ARP obtained $250 million in second lien financing from GSO Capital, which matures in 2020. The second lien loan has an effective annual interest rate of LIBOR + 9%, and is subordinate to the Company’s senior secured credit facility. ARP also reached an agreement with its lending group to amend to its senior secured credit facility in order to increase certain leverage covenants as a result of the recent commodity environment. Both the second lien financing and the credit facility amendment have provided ARP with additional financial flexibility and liquidity. |
| • | ARP paid monthly cash distributions totaling $0.325 per common limited partner unit for the first quarter 2015 at a distribution coverage ratio of approximately 1.1x. On April 22, 2015, ARP announced the March 2015 monthly distribution of $0.1083 per common unit ($1.30 per unit on an annualized basis), which will be paid on May 15, 2015 to unitholders of record as of May 8, 2015. |
| • | On a GAAP basis, net income was $85.6 million for the first quarter 2015, compared with a net loss of $10.8 million for the prior year first quarter. Net income in the current period was principally generated by the mark-to-market gain recognized in the period from ARP’s financial hedge positions, as ARP discontinued hedge accounting as of January 1, 2015. |
Operating Results
| • | Average net daily production for the first quarter 2015 was 270.8 million cubic feet equivalents per day (“Mmcfed”), approximately 10% higher than the prior year first quarter. The increase in net production from the prior year first quarter was due primarily to the acquisition of the Eagle Ford assets in November 2014, as well as the Rangely Field assets in June 2014 and the GeoMet natural gas production assets in May 2014. |
| • | ARP’s net realized price for natural gas including the effect of hedge positions was $3.59 per thousand cubic feet (“mcf”) for the first quarter 2015, compared to $3.66/mcf for the fourth quarter 2014. Net realized oil prices including the effect of hedge positions averaged $80.81 per barrel (“bbl”) for the first quarter 2015, compared to $84.81/bbl for the fourth quarter 2014. |
| • | Investment partnership margin contributed $8.8 million to Adjusted EBITDA and distributable cash flow for the first quarter 2015, compared with $11.1 million for the prior year comparable quarter. The decrease in investment partnership margin was due to higher amounts of capital deployed during the prior year quarter from the acceleration of drilling activity in the first quarter 2014. |
Hedge Positions
| • | ARP continued to expand its commodity hedge positions on its existing production. During the first quarter 2015, ARP was approximately 89% hedged on its net oil production and approximately 80% hedged on its net natural gas production. In addition, ARP is approximately hedged 72%, 68% and 63% for its natural gas production at an average price of $4.23/mcf, and hedged approximately 94%, 77% and 56% for oil in 2015, 2016 and 2017, respectively, at an average price of $82/bbl, based on first quarter 2015 average production. A summary of ARP’s derivative positions as of May 5, 2015 is provided in the financial tables of this release. |
Corporate Expenses & Capital Position
| • | Cash general and administrative expense was $11.6 million for the first quarter 2015, consistent with $11.7 million in the prior year comparable period. The slight decrease compared with the prior year period was due primarily to lower corporate spending during the first quarter of 2015. |
| • | Cash interest expense was $18.0 million for the first quarter 2015, compared with $16.0 million in the fourth quarter 2014 and $11.4 million in the prior year period. The increase in interest expense from the fourth quarter 2014 was primarily due to the $250 million second lien financing entered into by ARP in February 2015. The increase compared to the prior year first quarter was due to the issuance of follow-on offerings of $100 million of 7.75% Senior Notes (May 2014) and $75 million of 9.25% Senior Notes (October 2014), both of which mature in 2021. The offerings were issued to partially fund ARP’s acquisitions of oil producing properties in the Rangely Field in northwest Colorado as well properties in the Eagle Ford Shale. |
| • | At March 31, 2015, ARP had $1.493 billion of total debt, including $559.0 million outstanding under its revolving credit facility, compared to total debt of $1.394 billion in the fourth quarter 2014. The increase in total debt from the fourth quarter 2014 was due primarily to the deployment of additional partnership funds raised in the fourth quarter 2014. |
* * *
2
ARP will be discussing its first quarter 2015 results on an investor call with management on Wednesday, May 6, 2015 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 1:00 p.m. ET on May 6, 2015 by dialing 855-859-2056, passcode: 33615010.
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) 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 at www.atlasresourcepartners.com, or contact Investor Relations at InvestorRelations@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 28% 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 its private E&P Development Subsidiary; 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 at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
* * *
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; 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 we assume no obligation to update such statements, except as may be required by applicable law.
3
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)
| Three Months Ended March 31, |
||||||||
| 2015 | 2014 | |||||||
| Revenues: |
||||||||
| Gas and oil production |
$ | 100,972 | $ | 96,245 | ||||
| Well construction and completion |
23,655 | 49,377 | ||||||
| Gathering and processing |
2,184 | 4,468 | ||||||
| Administration and oversight |
1,259 | 1,729 | ||||||
| Well services |
6,624 | 5,479 | ||||||
| Gain on mark-to-market derivatives |
104,523 | — | ||||||
| Other, net |
30 | 47 | ||||||
|
|
|
|
|
|||||
| Total revenues |
239,247 | 157,345 | ||||||
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|
|
|
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| Costs and expenses: |
||||||||
| Gas and oil production |
44,220 | 36,792 | ||||||
| Well construction and completion |
20,570 | 42,936 | ||||||
| Gathering and processing |
2,417 | 4,413 | ||||||
| Well services |
2,198 | 2,482 | ||||||
| General and administrative |
17,131 | 16,455 | ||||||
| Depreciation, depletion and amortization |
41,866 | 50,237 | ||||||
|
|
|
|
|
|||||
| Total costs and expenses |
128,402 | 153,315 | ||||||
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|
|
|
|
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| Operating income |
110,845 | 4,030 | ||||||
| Loss on asset sales and disposal |
(11 | ) | (1,603 | ) | ||||
| Interest expense |
(25,197 | ) | (13,187 | ) | ||||
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|
|
|
|
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| Net income (loss) |
85,637 | (10,760 | ) | |||||
| Preferred limited partner dividends |
(3,653 | ) | (4,399 | ) | ||||
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|
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|
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| Net income (loss) attributable to common limited partners and the general partner |
$ | 81,984 | $ | (15,159 | ) | |||
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|
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| Allocation of net income (loss) attributable to common limited partners and the general partner: |
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| General partner’s interest |
$ | 1,640 | $ | 2,004 | ||||
| Common limited partners’ interest |
80,344 | (17,163 | ) | |||||
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|
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| Net income (loss) attributable to common limited partners and the general partner |
$ | 81,984 | $ | (15,159 | ) | |||
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| Net income (loss) attributable to common limited partners per unit: |
||||||||
| Basic |
$ | 0.93 | $ | (0.28 | ) | |||
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|
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| Diluted |
$ | 0.91 | $ | (0.28 | ) | |||
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| Weighted average common limited partner units outstanding: |
||||||||
| Basic |
85,505 | 61,219 | ||||||
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| Diluted |
89,985 | 61,219 | ||||||
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4
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
| March 31, | December 31, | |||||||
| 2015 | 2014 | |||||||
| ASSETS | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 2,582 | $ | 15,247 | ||||
| Accounts receivable |
94,150 | 112,038 | ||||||
| Advances to affiliates |
21,328 | — | ||||||
| Current portion of derivative asset |
145,499 | 141,366 | ||||||
| Subscriptions receivable |
— | 32,398 | ||||||
| Prepaid expenses and other |
27,856 | 26,011 | ||||||
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|
|
|
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| Total current assets |
291,415 | 327,060 | ||||||
| Property, plant and equipment, net |
2,198,436 | 2,208,171 | ||||||
| Goodwill and intangible assets, net |
14,271 | 14,330 | ||||||
| Long-term derivative asset |
186,718 | 127,933 | ||||||
| Other assets, net |
56,736 | 50,081 | ||||||
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|
|
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| $ | 2,747,576 | $ | 2,727,575 | |||||
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| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 93,548 | $ | 109,049 | ||||
| Advances from affiliates |
— | 4,271 | ||||||
| Liabilities associated with drilling contracts |
16,956 | 40,611 | ||||||
| Accrued well drilling and completion costs |
42,552 | 80,404 | ||||||
| Distribution payable |
12,405 | 20,876 | ||||||
| Accrued liabilities |
41,745 | 83,847 | ||||||
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|
|
|
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| Total current liabilities |
207,206 | 339,058 | ||||||
| Long-term debt |
1,500,178 | 1,394,460 | ||||||
| Asset retirement obligations and other |
110,562 | 108,561 | ||||||
| Commitments and contingencies |
||||||||
| Partners’ Capital: |
||||||||
| General partner’s interest |
(13,842 | ) | (13,697 | ) | ||||
| Preferred limited partners’ interests |
182,968 | 163,522 | ||||||
| Common limited partners’ interests |
600,015 | 548,586 | ||||||
| Class C common limited partner warrants |
1,176 | 1,176 | ||||||
| Accumulated other comprehensive income |
159,313 | 185,909 | ||||||
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|
|
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| Total partners’ capital |
929,630 | 885,496 | ||||||
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|
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| $ | 2,747,576 | $ | 2,727,575 | |||||
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5
ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2015 | 2014 | |||||||
| Net income (loss) attributable to common limited partners per unit - basic |
$ | 0.93 | $ | (0.28 | ) | |||
| Cash distributions paid per unit(1) |
$ | 0.325 | $ | 0.580 | ||||
| Production revenues (in thousands): |
||||||||
| Natural gas |
$ | 63,264 | $ | 74,190 | ||||
| Oil |
32,385 | 12,283 | ||||||
| Natural gas liquids |
5,323 | 9,772 | ||||||
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|
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| Total production revenues |
$ | 100,972 | $ | 96,245 | ||||
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| Production volume:(2)(3) |
||||||||
| Appalachia: (4) |
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| Natural gas (Mcfd) |
32,219 | 41,146 | ||||||
| Oil (Bpd) |
334 | 415 | ||||||
| Natural gas liquids (Bpd) |
35 | 29 | ||||||
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|
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| Total (Mcfed) |
34,436 | 43,810 | ||||||
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|
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| Coal-bed Methane: (4) |
||||||||
| Natural gas (Mcfd) |
123,481 | 108,368 | ||||||
| Oil (Bpd) |
— | — | ||||||
| Natural gas liquids (Bpd) |
— | — | ||||||
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|
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| Total (Mcfed) |
123,481 | 108,368 | ||||||
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|
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| Barnett/Marble Falls: |
||||||||
| Natural gas (Mcfd) |
49,617 | 57,898 | ||||||
| Oil (Bpd) |
749 | 834 | ||||||
| Natural gas liquids (Bpd) |
2,274 | 2,570 | ||||||
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|
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| Total (Mcfed) |
67,755 | 78,319 | ||||||
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|
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| Rangely/Eagle Ford: (4) |
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| Natural gas (Mcfd) |
500 | — | ||||||
| Oil (Bpd) |
3,911 | — | ||||||
| Natural gas liquids (Bpd) |
359 | — | ||||||
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|
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| Total (Mcfed) |
26,115 | — | ||||||
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|
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| Mississippi Lime/Hunton: |
||||||||
| Natural gas (Mcfd) |
7,579 | 5,873 | ||||||
| Oil (Bpd) |
514 | 301 | ||||||
| Natural gas liquids (Bpd) |
615 | 485 | ||||||
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|
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| Total (Mcfed) |
14,357 | 10,587 | ||||||
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|
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| Other Operating Areas: (4) |
||||||||
| Natural gas (Mcfd) |
3,291 | 3,402 | ||||||
| Oil (Bpd) |
25 | 19 | ||||||
| Natural gas liquids (Bpd) |
204 | 338 | ||||||
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|
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| Total (Mcfed) |
4,668 | 5,544 | ||||||
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|
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| Total Production: (3) |
||||||||
| Natural gas (Mcfd) |
216,687 | 216,688 | ||||||
| Oil (Bpd) |
5,533 | 1,568 | ||||||
| Natural gas liquids (Bpd) |
3,488 | 3,422 | ||||||
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|
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| Total (Mcfed) |
270,811 | 246,628 | ||||||
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|
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| Average sales prices: (3) |
||||||||
| Natural gas (per Mcf) (5) |
$ | 3.59 | $ | 4.07 | ||||
| Oil (per Bbl)(6) |
$ | 80.81 | $ | 87.04 | ||||
| Natural gas liquids (per Bbl) (7) |
$ | 22.49 | $ | 31.73 | ||||
| Production costs:(3)(8) |
||||||||
| Lease operating expenses per Mcfe |
$ | 1.37 | $ | 1.17 | ||||
| Production taxes per Mcfe |
0.24 | 0.27 | ||||||
| Transportation and compression expenses per Mcfe |
0.22 | 0.29 | ||||||
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|
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| Total production costs per Mcfe |
$ | 1.84 | $ | 1.73 | ||||
| Depletion per Mcfe(3) |
$ | 1.60 | $ | 2.16 | ||||
6
| (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 County Line area of Wyoming; 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/Antrim and Niobrara Shales. |
| (5) | ARP’s average sales prices for natural gas before the effects of financial hedging were $2.53 per Mcf and $4.68 per Mcf for the three months ended March 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 $3.53 per Mcf ($2.48 per Mcf before the effects of financial hedging) and $3.80 per Mcf ($4.42 per Mcf before the effects of financial hedging) for the three months ended March 31, 2015 and 2014, respectively. |
| (6) | ARP’s average sales prices for oil before the effects of financial hedging were $43.46 per barrel and $93.18 per barrel for the three months ended March 31, 2015 and 2014, respectively. |
| (7) | ARP’s average sales prices for natural gas liquids before the effects of financial hedging were $14.10 per barrel and $35.65 per barrel for the three months ended March 31, 2015 and 2014, respectively. |
| (8) | 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 $1.35 per Mcfe ($1.81 per Mcfe for total production costs) and $1.10 per Mcfe ($1.66 per Mcfe for total production costs) for the three months ended March 31, 2015 and 2014, respectively. |
7
ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
| March 31, 2015 |
December 31, 2014 |
|||||||
| Total debt |
$ | 1,500,178 | $ | 1,394,460 | ||||
| Less: Cash |
(2,582 | ) | (15,247 | ) | ||||
|
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|
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| Total net debt/(cash) |
1,497,596 | 1,379,213 | ||||||
| Partners’ capital |
929,630 | 885,496 | ||||||
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|
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| Total capitalization |
$ | 2,427,226 | $ | 2,264,709 | ||||
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| Ratio of net debt to capitalization |
0.62x | 0.61x | ||||||
ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2015 | 2014 | |||||||
| Maintenance capital expenditures (1) |
$ | 15,427 | $ | 10,800 | ||||
| Expansion capital expenditures |
27,071 | 29,097 | ||||||
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| Total |
$ | 42,498 | $ | 39,897 | ||||
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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 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. |
8
ATLAS RESOURCE PARTNERS, L.P.
Financial Information
(unaudited; in thousands, except per unit amounts)
| Three Months Ended | ||||||||
| March 31, | ||||||||
| 2015 | 2014 | |||||||
| Reconciliation of net income (loss) to non-GAAP measures(1): |
||||||||
| Net income (loss) |
$ | 85,637 | $ | (10,760 | ) | |||
| Acquisition and related costs |
2,171 | 2,379 | ||||||
| Depreciation, depletion and amortization |
41,866 | 50,237 | ||||||
| Amortization of deferred finance costs |
7,199 | 1,811 | ||||||
| Non-cash stock compensation expense |
3,346 | 2,345 | ||||||
| Maintenance capital expenditures(2) |
(15,427 | ) | (10,500 | ) | ||||
| Preferred unit distributions |
(4,085 | ) | (4,399 | ) | ||||
| Loss on asset sales and disposal |
11 | 1,603 | ||||||
| Cash settlements on commodity derivative contracts(3) |
15,203 | — | ||||||
| Unrealized gain on mark-to-market derivatives |
(104,523 | ) | — | |||||
| Other |
(12 | ) | (3 | ) | ||||
|
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|
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| Distributable cash flow attributable to limited partners and the general partner(1) |
$ | 31,386 | $ | 32,713 | ||||
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| Supplemental Adjusted EBITDA and Distributable Cash Flow Summary: |
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| Gas and oil production margin |
$ | 71,955 | $ | 59,453 | ||||
| Well construction and completion margin |
3,085 | 6,441 | ||||||
| Administration and oversight margin |
1,259 | 1,729 | ||||||
| Well services margin |
4,426 | 2,997 | ||||||
| Gathering and processing margin |
(233 | ) | 55 | |||||
| Cash general and administrative expenses(4) |
(11,614 | ) | (11,731 | ) | ||||
| Other, net |
18 | 44 | ||||||
|
|
|
|
|
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| Adjusted EBITDA(1) |
68,896 | 58,988 | ||||||
| Cash interest expense(5) |
(17,998 | ) | (11,376 | ) | ||||
| Preferred unit distributions |
(4,085 | ) | (4,399 | ) | ||||
| Maintenance capital expenditures(2) |
(15,427 | ) | (10,500 | ) | ||||
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|
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| Distributable Cash Flow attributable to limited partners and the general partner(1) |
$ | 31,386 | $ | 32,713 | ||||
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|
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| Discretionary adjustments considered by the Board of Directors of the General Partner in the determination of quarterly cash distributions: |
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| Net cash from acquisitions from the effective date through closing date(6) |
— | 5,197 | ||||||
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|
|
|
|
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| Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(7) |
$ | 31,386 | $ | 37,910 | ||||
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|
|
|
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| Distributions Paid(8) |
$ | 28,483 | $ | 41,332 | ||||
| per limited partner unit |
$ | 0.325 | $ | 0.580 | ||||
| Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(9) |
$ | 2,903 | $ | (3,422 | ) | |||
| (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 |
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| 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 Amended 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 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 March 31, 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to March 31, 2014 of $5.5 million, less estimated maintenance capital expenditures of $0.3 million. |
| (7) | Including the discretionary adjustments by the Board of Directors of the General Partner in the determination of quarterly cash distributions, Adjusted EBITDA would have been $64.5 million for the three months ended March 31, 2014. |
| (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. |
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| (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. |
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ATLAS RESOURCE PARTNERS, L.P.
Hedge Position Summary
(as of May 5, 2015)
Natural Gas
Fixed Price Swaps
| Production Period Ended December 31, |
Average Fixed Price (per mmbtu)(a) |
Volumes (mmbtus)(a) |
||||||
| 2015(b) |
$ | 4.21 | 40,053,369 | |||||
| 2016 |
$ | 4.23 | 53,546,320 | |||||
| 2017 |
$ | 4.22 | 49,920,000 | |||||
| 2018 |
$ | 4.17 | 40,800,000 | |||||
| 2019 |
$ | 4.02 | 15,960,000 | |||||
Costless Collars
| Production Period Ended December 31, |
Average Floor Price (per mmbtu)(a) |
Average Ceiling Price (per mmbtu)(a) |
Volumes (mmbtus)(a) |
|||||||||
| 2015(b) |
$ | 4.21 | $ | 5.09 | 2,520,000 | |||||||
Put Options – Drilling Partnerships
| Production Period Ended December 31, |
Average Fixed Price (per mmbtu)(a) |
Average Volumes (mmbtus)(a) |
||||||
| 2015(b) |
$ | 4.00 | 1,080,000 | |||||
| 2016 |
$ | 4.15 | 1,440,000 | |||||
WAHA Basis Swaps
| Production Period Ended December 31, |
Average Fixed Price (per mmbtu)(a) |
Average Volumes (mmbtus)(a) |
||||||
| 2015(b) |
$ | (0.0821 | ) | 3,600,000 | ||||
Crude Oil
Fixed Price Swaps
| Production Period Ended December 31, |
Average Fixed Price (per bbl)(a) |
Volumes (bbls)(a) |
||||||
| 2015(b) |
$ | 87.59 | 1,445,000 | |||||
| 2016 |
$ | 81.47 | 1,557,000 | |||||
| 2017 |
$ | 77.28 | 1,140,000 | |||||
| 2018 |
$ | 76.28 | 1,080,000 | |||||
| 2019 |
$ | 68.37 | 540,000 | |||||
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Costless Collars
| Production Period Ended December 31, |
Average Floor Price (per bbl)(a) |
Average Ceiling Price (per bbl)(a) |
Volumes (bbls)(a) |
|||||||||
| 2015(b) |
$ | 83.85 | $ | 110.65 | 19,500 | |||||||
Natural Gas Liquids
Crude Oil Fixed Price Swaps
| Production Period Ended December 31, |
Average Fixed Price (per bbl)(a) |
Volumes (bbls)(a) |
||||||
| 2016 |
$ | 85.65 | 84,000 | |||||
| 2017 |
$ | 83.78 | 60,000 | |||||
Mt Belvieu Propane Swaps
| Production Period Ended December 31, |
Average Fixed Price (per gallon) |
Volumes (bbls)(a) | ||
| 2015(b) |
$1.0161 | 144,000 | ||
Mt Belvieu Butane Swaps
| Production Period Ended December 31, |
Average Fixed Price (per gallon) |
Volumes (bbls)(a) |
||||||
| 2015(b) |
$ | 1.2481 | 24,000 | |||||
Mt Belvieu Iso-Butane Swaps
| Production Period Ended December 31, |
Average Fixed Price (per gallon) |
Volumes (bbls)(a) |
||||||
| 2015(b) |
$ | 1.2631 | 27,000 | |||||
Mt Belvieu Natural Gasoline Swaps
| Production Period Ended December 31, |
Average Fixed Price (per gallon) |
Volumes (bbls)(a) |
||||||
| 2015(b) |
$ | 1.9558 | 90,000 | |||||
| (a) | “mmbtu” represents million metric British thermal units.; “bbl” represents barrel. |
| (b) | Reflects hedges covering the last nine months of 2015. |
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