Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - Titan Energy, LLC | d90766d8k.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 THIRD QUARTER 2015
| • | Adjusted EBITDA was $68.1 million(1) and Distributable Cash Flow was $28.8 million(1) for the third quarter 2015 |
| • | Gas and oil production costs continued to benefit from effective cost-reduction initiatives, decreasing 22% from the comparable prior year quarter |
| • | Natural gas and oil production in the third quarter 2015 were hedged approximately 71% and 100%, respectively; ARP’s current market value of its hedge portfolio is approximately $360 million |
| • | Management will discuss third quarter 2015 financial and operational results on a conference call at 9:00 AM ET on Tuesday, November 10th |
Philadelphia, PA – November 9, 2015 - Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) reported operating and financial results for the third quarter 2015.
Daniel Herz, Chief Executive Officer of ARP, stated, “The current state of the energy industry has presented a challenging environment, however our business continues to exhibit its solid foundation, including stable producing assets, a strong hedge position through 2019 and fees from our investment partnership business. In addition, our company has continued to make meaningful progress in reducing production costs and capital spending, which we believe is crucial to preserving value during these periods. All of our efforts are ultimately focused on positioning the company to withstand the current markets and expand our businesses as we have in the past.”
* * *
| • | Third quarter 2015 Adjusted EBITDA, a non-GAAP measure, was $68.1 million(1), compared to $64.7 million for the second quarter 2015. The increase from the second quarter 2015 was due to higher fee income from ARP’s partnership management business, partially offset by higher general and administrative expenses related to the timing of fundraising activities from the current year investment program. |
| • | Distributable Cash Flow, a non-GAAP measure, was $28.8 million(1), or approximately $0.29 per common unit, for the third quarter 2015, compared with $25.4 million, or approximately $0.27 per common unit, for the second quarter 2015. The increase was primarily due to similar factors as noted above. |
| • | ARP paid monthly cash distributions totaling $0.325 per common limited partner unit for the third quarter 2015 at a distribution coverage ratio of approximately 0.9x. On October 28, 2015, ARP announced the September 2015 monthly distribution of $0.1083 per common unit ($1.30 per unit on an annualized basis), which will be paid on November 13, 2015 to unitholders of record as of November 9, 2015. |
| • | On a GAAP basis, net loss was $560.9 million for the third quarter 2015, compared with a loss of $46.8 million for the second quarter 2015 and net income of $1.9 million in the prior year third |
| quarter. Net loss in the current period was principally due to non-cash expenses, specifically an asset impairment charge on certain oil and gas properties due to recent declines in forward commodity prices, partially offset by the mark-to-market gains recognized in the current quarter from ARP’s financial hedge positions. |
Operating Results
| • | Average net daily production for the third quarter 2015 was 264.2 million cubic feet equivalents per day (“Mmcfed”), as compared to 270.8 Mmcfed for the second quarter 2015. ARP’s third quarter 2015 production was comprised of 82% natural gas, 11% oil and 7% natural gas liquids (“NGL”). The Company connected two Mississippi Lime wells during the third quarter, and now operates 27 wells in the Eagle Ford shale. ARP is currently connecting additional wells on its Eagle Ford position and expects oil volumes to increase into 2016 as a result of its activity. |
| • | ARP’s net realized price for natural gas including the effect of hedge positions was $3.30 per thousand cubic feet (“mcf”) for the third quarter 2015, compared to $3.33/mcf for the second quarter 2015. Net realized oil prices including the effect of hedge positions averaged $88.42 per barrel (“bbl”) for the third quarter 2015, compared to $83.19/bbl for the second quarter 2015. The Company was hedged approximately 71% on its natural gas production and approximately 100% on its oil production in the third quarter 2015. |
| • | Lease operating expenses decreased 6% from the second quarter 2015 to $1.30/mcf, and overall production costs of $1.74/mcf in the third quarter 2015 were 22% lower than the prior year comparable quarter. The decrease in expenses is due to the Company’s ongoing production cost-reduction efforts, namely focused on water disposal, compression and fuel costs. |
| • | Investment partnership margin was approximately $12.0 million in the third quarter 2015, compared with $6.7 million for the second quarter 2015. The increase in investment partnership margin was due to increased deployment of partnership capital during the current quarter, which generated higher fee income, specifically Administration and Oversight Fees realized from the drilling of new investment program wells. |
Hedge Positions
| • | ARP’s hedge portfolio is comprised entirely of fixed-price swap and costless collar positions through 2019, and is valued at approximately $360 million as of November 9, 2015. |
| • | The Company’s oil production is hedged approximately 88%, 64%, 61% and 30% based on third quarter 2015 average production for the years 2016 through 2019, respectively, at an average price of approximately $76/bbl. ARP’s natural gas production is hedged 68%, 63% and 52% for 2016, 2017 and 2018, respectively, based on third quarter 2015 production at an average price of approximately $4.20/mcf, with additional hedges in 2019. A summary of ARP’s derivative positions as of November 9, 2015 is provided in the financial tables of this release. |
Corporate Expenses & Capital Position
| • | Cash general and administrative expense was $12.5 million for the third quarter 2015, compared to $10.7 million for the second quarter 2015. The increase from the prior period was primarily due to timing of activity related to the Company’s partnership activities, and other seasonal corporate expenses. |
| • | Cash interest expense was $21.5 million for the third quarter 2015, compared with $21.2 million for the second quarter 2015 and $14.1 million for the prior year comparable quarter. The increase compared to the prior year third quarter was due to the follow-on offering of $75 million of 9.25% Senior Notes due 2021 in October 2014 to partially fund ARP’s acquisitions of oil producing properties in the Rangely Field and the Eagle Ford Shale, as well as the $250 million second lien financing entered into by ARP in February 2015. |
| • | At September 30, 2015, ARP had approximately $1.5 billion of total debt outstanding, which was consistent with the balance at June 30, 2015. The outstanding debt balance included $563.4 million borrowed under its revolving credit facility with a borrowing base of $750 million. |
* * *
ARP will be discussing its third quarter 2015 results on an investor call with management on Tuesday, November 10, 2015 at 9:00 a.m. 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 ARP website and telephonically beginning at approximately 1:00 p.m. ET on November 10, 2015 by dialing (855) 859-2056, passcode: 66843641.
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 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 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 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 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 September 30, |
Nine Months Ended September 30 |
|||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Revenues: |
||||||||||||||||
| Gas and oil production |
$ | 90,734 | $ | 129,399 | $ | 292,243 | $ | 337,893 | ||||||||
| Well construction and completion |
23,054 | 61,204 | 63,665 | 126,917 | ||||||||||||
| Gathering and processing |
1,685 | 3,061 | 6,046 | 11,287 | ||||||||||||
| Administration and oversight |
5,495 | 6,177 | 7,301 | 12,072 | ||||||||||||
| Well services |
5,842 | 6,597 | 18,568 | 18,441 | ||||||||||||
| Gain on mark-to-market derivatives |
131,065 | — | 209,706 | — | ||||||||||||
| Other, net |
20 | 261 | 80 | 343 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
257,895 | 206,699 | 597,609 | 506,953 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Costs and expenses: |
||||||||||||||||
| Gas and oil production |
41,591 | 51,391 | 130,224 | 133,038 | ||||||||||||
| Well construction and completion |
20,046 | 53,221 | 55,361 | 110,363 | ||||||||||||
| Gathering and processing |
2,473 | 3,214 | 7,406 | 11,900 | ||||||||||||
| Well services |
2,398 | 2,617 | 6,735 | 7,525 | ||||||||||||
| General and administrative |
13,978 | 13,124 | 44,400 | 50,894 | ||||||||||||
| Depreciation, depletion and amortization |
40,463 | 64,578 | 125,948 | 176,077 | ||||||||||||
| Asset impairment |
672,246 | — | 672,246 | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total costs and expenses |
793,195 | 188,145 | 1,042,320 | 489,797 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income (loss) |
(535,300 | ) | 18,554 | (444,711 | ) | 17,156 | ||||||||||
| Loss on asset sales and disposal |
(362 | ) | (92 | ) | (276 | ) | (1,686 | ) | ||||||||
| Interest expense |
(25,192 | ) | (16,577 | ) | (75,105 | ) | (43,028 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) |
(560,854 | ) | 1,885 | (520,092 | ) | (27,558 | ) | |||||||||
| Preferred limited partner dividends |
(4,293 | ) | (4,475 | ) | (12,180 | ) | (13,298 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net loss attributable to common limited partners and the general partner |
$ | (565,147 | ) | $ | (2,590 | ) | $ | (532,272 | ) | $ | (40,856 | ) | ||||
|
|
|
|
|
|
|
|
|
|||||||||
| Allocation of net loss attributable to common limited partners and the general partner: |
||||||||||||||||
| General partner’s interest |
$ | (11,303 | ) | $ | 3,009 | $ | (10,645 | ) | $ | 7,427 | ||||||
| Common limited partners’ interest |
(553,844 | ) | (5,599 | ) | (521,627 | ) | (48,283 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net loss attributable to common limited partners and the general partner |
$ | (565,147 | ) | $ | (2,590 | ) | $ | (532,272 | ) | $ | (40,856 | ) | ||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net loss attributable to common limited partners per unit: |
||||||||||||||||
| Basic |
$ | (5.73 | ) | $ | (0.07 | ) | $ | (5.74 | ) | $ | (0.67 | ) | ||||
|
|
|
|
|
|
|
|
|
|||||||||
| Diluted |
$ | (5.73 | ) | $ | (0.07 | ) | $ | (5.74 | ) | $ | (0.67 | ) | ||||
|
|
|
|
|
|
|
|
|
|||||||||
| Weighted average common limited partner units outstanding: |
||||||||||||||||
| Basic |
96,660 | 81,521 | 90,943 | 72,288 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Diluted |
96,660 | 81,521 | 90,943 | 72,288 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
| ASSETS | September 30, 2015 |
December 31, 2014 |
||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 2,418 | $ | 15,247 | ||||
| Accounts receivable |
89,402 | 114,520 | ||||||
| Advances to affiliates |
1,178 | — | ||||||
| Current portion of derivative asset |
146,622 | 144,259 | ||||||
| Subscriptions receivable |
23,054 | 32,398 | ||||||
| Prepaid expenses and other |
25,407 | 26,296 | ||||||
|
|
|
|
|
|||||
| Total current assets |
288,081 | 332,720 | ||||||
| Property, plant and equipment, net |
1,534,718 | 2,263,820 | ||||||
| Goodwill and intangible assets, net |
14,154 | 14,330 | ||||||
| Long-term derivative asset |
205,979 | 130,602 | ||||||
| Other assets, net |
53,826 | 50,081 | ||||||
|
|
|
|
|
|||||
| $ | 2,096,758 | $ | 2,791,553 | |||||
|
|
|
|
|
|||||
| LIABILITIES AND PARTNERS’ CAPITAL |
||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 82,209 | $ | 111,198 | ||||
| Advances from affiliates |
— | 2,249 | ||||||
| Liabilities associated with drilling contracts |
— | 40,611 | ||||||
| Accrued well drilling and completion costs |
56,300 | 80,404 | ||||||
| Distribution payable |
14,234 | 20,876 | ||||||
| Accrued liabilities |
77,002 | 84,235 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
229,745 | 339,573 | ||||||
| Long-term debt |
1,505,047 | 1,394,460 | ||||||
| Asset retirement obligations and other |
117,089 | 109,983 | ||||||
| Commitments and contingencies |
||||||||
| Partners’ Capital: |
||||||||
| General partner’s interest |
(27,465 | ) | (13,697 | ) | ||||
| Preferred limited partners’ interests |
188,910 | 163,522 | ||||||
| Common limited partners’ interests |
35,854 | 605,065 | ||||||
| Class C common limited partner warrants |
1,176 | 1,176 | ||||||
| Accumulated other comprehensive income |
46,402 | 191,471 | ||||||
|
|
|
|
|
|||||
| Total partners’ capital |
244,877 | 947,537 | ||||||
|
|
|
|
|
|||||
| $ | 2,096,758 | $ | 2,791,553 | |||||
|
|
|
|
|
|||||
ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Net loss attributable to common limited partners per unit - basic |
$ | (5.73 | ) | $ | (0.07 | ) | $ | (5.74 | ) | $ | (0.67 | ) | ||||
| Cash distributions paid per unit(1) |
$ | 0.325 | $ | 0.590 | $ | 0.975 | $ | 1.753 | ||||||||
| Production revenues (in thousands): |
||||||||||||||||
| Natural gas |
$ | 57,919 | $ | 79,251 | $ | 181,008 | $ | 239,233 | ||||||||
| Oil |
28,854 | 38,151 | 97,100 | 67,626 | ||||||||||||
| Natural gas liquids |
3,961 | 11,997 | 14,135 | 31,034 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total production revenues |
$ | 90,734 | $ | 129,399 | $ | 292,243 | $ | 337,893 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Production volume:(2)(3) |
||||||||||||||||
| Appalachia: (4) |
||||||||||||||||
| Natural gas (Mcfd) |
33,950 | 38,218 | 32,522 | 39,083 | ||||||||||||
| Oil (Bpd) |
326 | 367 | 343 | 390 | ||||||||||||
| Natural gas liquids (Bpd) |
30 | 46 | 34 | 40 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mcfed) |
36,087 | 40,693 | 34,782 | 41,661 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Coal-bed Methane: (4) |
||||||||||||||||
| Natural gas (Mcfd) |
128,560 | 140,177 | 131,314 | 130,393 | ||||||||||||
| Oil (Bpd) |
— | — | — | — | ||||||||||||
| Natural gas liquids (Bpd) |
— | — | — | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mcfed) |
128,560 | 140,177 | 131,314 | 130,393 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Barnett/Marble Falls: |
||||||||||||||||
| Natural gas (Mcfd) |
43,685 | 57,726 | 46,868 | 58,445 | ||||||||||||
| Oil (Bpd) |
495 | 1,273 | 625 | 1,114 | ||||||||||||
| Natural gas liquids (Bpd) |
1,898 | 2,861 | 2,088 | 2,732 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mcfed) |
58,043 | 82,535 | 63,144 | 81,523 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Rangely/Eagle Ford: (4)(5) |
||||||||||||||||
| Natural gas (Mcfd) |
313 | — | 337 | — | ||||||||||||
| Oil (Bpd) |
3,573 | 2,567 | 3,790 | 865 | ||||||||||||
| Natural gas liquids (Bpd) |
313 | 263 | 324 | 89 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mcfed) |
23,631 | 16,978 | 25,024 | 5,721 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Mississippi Lime/Hunton: |
||||||||||||||||
| Natural gas (Mcfd) |
6,763 | 6,679 | 6,921 | 6,295 | ||||||||||||
| Oil (Bpd) |
433 | 366 | 443 | 368 | ||||||||||||
| Natural gas liquids (Bpd) |
569 | 545 | 572 | 524 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mcfed) |
12,771 | 12,145 | 13,014 | 11,651 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Other Operating Areas: (4) |
||||||||||||||||
| Natural gas (Mcfd) |
3,143 | 3,195 | 3,197 | 3,287 | ||||||||||||
| Oil (Bpd) |
16 | 25 | 19 | 24 | ||||||||||||
| Natural gas liquids (Bpd) |
311 | 334 | 248 | 337 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mcfed) |
5,104 | 5,349 | 4,799 | 5,453 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total Production: |
||||||||||||||||
| Natural gas (Mcfd) |
216,414 | 245,996 | 221,159 | 237,503 | ||||||||||||
| Oil (Bpd) |
4,842 | 4,598 | 5,220 | 2,761 | ||||||||||||
| Natural gas liquids (Bpd) |
3,121 | 4,048 | 3,266 | 3,722 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (Mcfed) |
264,196 | 297,876 | 272,077 | 276,403 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Average sales prices: (3) |
||||||||||||||||
| Natural gas (per Mcf) (6) |
$ | 3.30 | $ | 3.56 | $ | 3.41 | $ | 3.79 | ||||||||
| Oil (per Bbl)(7) |
$ | 88.42 | $ | 90.18 | $ | 83.99 | $ | 89.71 | ||||||||
| Natural gas liquids (per Bbl) (8) |
$ | 21.42 | $ | 32.21 | $ | 22.17 | $ | 30.54 | ||||||||
| Production costs:(3)(9) |
$ | 1.30 | $ | 1.37 | $ | 1.34 | $ | 1.26 | ||||||||
| Lease operating expenses per Mcfe |
0.19 | 0.30 | 0.20 | 0.27 | ||||||||||||
| Production taxes per Mcfe |
0.24 | 0.23 | 0.24 | 0.26 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Transportation and compression expenses per Mcfe |
$ | 1.74 | $ | 1.89 | $ | 1.78 | $ | 1.79 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total production costs per Mcfe |
||||||||||||||||
| Depletion per Mcfe(3) |
$ | 1.53 | $ | 2.26 | $ | 1.57 | $ | 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, the Arkoma Basin in eastern Oklahoma 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) | Production volumes and production volumes per day reflect only volumes related to the Rangely field during the three and nine months ended September 30, 2014. Production volumes and volumes per day for the Eagle Ford Acquisition were included effective November 5, 2014. |
| (6) | ARP’s average sales prices for natural gas before the effects of financial hedging were $2.28 per Mcf and $3.48 per Mcf for the three months ended September 30, 2015 and 2014, respectively, and $2.32 per Mcf and $4.05 per Mcf for the nine months ended September 30, 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 $3.25 per Mcf ($2.23 per Mcf before the effects of financial hedging) and $3.50 per Mcf ($3.43 per Mcf before the effects of financial hedging) for the three months ended September 30, 2015 and 2014, respectively, and $3.35 per Mcf ($2.27 per Mcf before the effects of financial hedging) and $3.69 per Mcf ($3.97 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2015 and 2014, respectively. |
| (7) | ARP’s average sales prices for oil before the effects of financial hedging were $43.25 per barrel and $91.08 per barrel for the three months ended September 30, 2015 and 2014, respectively, and $46.74 per barrel and $93.45 per barrel for the nine months ended September 30, 2015 and 2014, respectively. |
| (8) | ARP’s average sales prices for natural gas liquids before the effects of financial hedging were $11.01 per barrel and $32.18 per barrel for the three months ended September 30, 2015 and 2014, respectively, and $13.00 per barrel and $32.16 per barrel for the nine months ended September 30, 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 $1.28 per Mcfe ($1.71 per Mcfe for total production costs) and $1.35 per Mcfe ($1.88 per Mcfe for total production costs) for the three months ended September 30, 2015 and 2014, respectively, and $1.32 per Mcfe ($1.75 per Mcfe for total production costs) and $1.23 per Mcfe ($1.76 per Mcfe for total production costs) for the nine months ended September 30, 2015 and 2014, respectively. |
ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
| September 30, 2015 |
December 31, 2014 |
|||||||
| Total debt |
$ | 1,505,047 | $ | 1,394,460 | ||||
| Less: Cash |
(2,418 | ) | (15,247 | ) | ||||
|
|
|
|
|
|||||
| Total net debt/(cash) |
1,502,629 | 1,379,213 | ||||||
| Partners’ capital |
244,877 | 947,537 | ||||||
|
|
|
|
|
|||||
| Total capitalization |
$ | 1,747,506 | $ | 2,326,750 | ||||
|
|
|
|
|
|||||
| Ratio of net debt to capitalization |
0.86 | x | 0.59 | x | ||||
ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Maintenance capital expenditures (1) |
$ | 13,456 | $ | 22,400 | $ | 42,788 | $ | 46,300 | ||||||||
| Expansion capital expenditures |
19,343 | 33,530 | 59,502 | 104,279 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 32,799 | $ | 55,930 | $ | 102,290 | $ | 150,579 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (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. |
ATLAS RESOURCE PARTNERS, L.P.
Financial Information
(unaudited; in thousands, except per unit amounts)
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Reconciliation of net income (loss) to non-GAAP measures(1): |
||||||||||||||||
| Net income (loss) |
$ | (560,854 | ) | $ | 1,885 | $ | (520,092 | ) | $ | (27,558 | ) | |||||
| Acquisition and related costs |
1,154 | 1,595 | 5,035 | 12,765 | ||||||||||||
| Depreciation, depletion and amortization |
40,463 | 64,578 | 125,948 | 176,077 | ||||||||||||
| Asset impairment |
672,246 | — | 672,246 | — | ||||||||||||
| Amortization of deferred finance costs |
3,661 | 2,436 | 14,398 | 6,290 | ||||||||||||
| Non-cash stock compensation expense |
289 | 1,988 | 4,498 | 6,342 | ||||||||||||
| Maintenance capital expenditures(2) |
(13,456 | ) | (13,100 | ) | (42,788 | ) | (34,250 | ) | ||||||||
| Preferred unit distributions |
(4,275 | ) | (4,475 | ) | (12,613 | ) | (13,298 | ) | ||||||||
| Loss on asset sales and disposal |
362 | 92 | 276 | 1,686 | ||||||||||||
| Cash settlements on commodity derivative contracts(3) |
20,282 | — | 50,407 | — | ||||||||||||
| Unrealized gain on mark-to-market derivatives |
(131,065 | ) | — | (209,706 | ) | — | ||||||||||
| Other |
39 | (18 | ) | 22 | (16 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Distributable cash flow attributable to limited partners and the general partner(1) |
$ | 28,846 | $ | 54,981 | $ | 87,631 | $ | 128,038 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Supplemental Adjusted EBITDA and Distributable Cash Flow Summary: |
||||||||||||||||
| Gas and oil production margin |
$ | 69,425 | $ | 78,008 | $ | 212,426 | $ | 204,855 | ||||||||
| Well construction and completion margin |
3,008 | 7,983 | 8,304 | 16,554 | ||||||||||||
| Administration and oversight margin |
5,495 | 6,177 | 7,301 | 12,072 | ||||||||||||
| Well services margin |
3,444 | 3,980 | 11,833 | 10,916 | ||||||||||||
| Gathering and processing margin |
(788 | ) | (153 | ) | (1,360 | ) | (613 | ) | ||||||||
| Cash general and administrative expenses(4) |
(12,535 | ) | (9,541 | ) | (34,867 | ) | (31,787 | ) | ||||||||
| Other, net |
59 | 243 | 102 | 327 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted EBITDA(1) |
68,108 | 86,697 | 203,739 | 212,324 | ||||||||||||
| Cash interest expense(5) |
(21,531 | ) | (14,141 | ) | (60,707 | ) | (36,738 | ) | ||||||||
| Preferred unit distributions |
(4,275 | ) | (4,475 | ) | (12,613 | ) | (13,298 | ) | ||||||||
| Maintenance capital expenditures(2) |
(13,456 | ) | (13,100 | ) | (42,788 | ) | (34,250 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Distributable Cash Flow attributable to limited partners and the general partner(1) |
$ | 28,846 | $ | 54,981 | $ | 87,631 | $ | 128,038 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 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) |
— | 10,214 | — | 30,202 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(7) |
$ | 28,846 | $ | 65,195 | $ | 87,631 | $ | 158,240 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Distributions Paid(8) |
$ | 32,292 | $ | 52,225 | $ | 91,330 | $ | 145,011 | ||||||||
| per limited partner unit |
$ | 0.325 | $ | 0.590 | $ | 0.975 | $ | 1.753 | ||||||||
| Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(9) |
$ | (3,446 | ) | $ | 12,970 | $ | (3,699 | ) | $ | 13,229 | ||||||
| (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 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 September 30, 2014, such amounts include net cash generated by the Eagle Ford assets from July 1, 2014 to September 30, 2014 of $23.2 million, less pro forma interest expense of $2.0 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $9.3 million. For the nine months ended September 30, 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 September 30, 2014 of $46.3 million, less pro forma interest expense of $2.4 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $12.0 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 $109.9 million and $258.6 million for the three and nine months ended September 30, 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 November 9, 2015)
Natural Gas
| Fixed Price Swaps | ||||||||||||
| Production Period Ended December 31, |
Average Fixed Price (per mmbtu)(a) |
Volumes (mmbtus)(a) |
||||||||||
| 2015(b) |
$ | 4.19 | 18,018,000 | |||||||||
| 2016 |
$ | 4.23 | 53,546,000 | |||||||||
| 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) |
$ | 4.06 | $ | 4.84 | 920,000 | |||||||
| Put Options – Drilling Partnerships |
||||||||||||
| Production Period Ended December 31, |
Average Fixed Price (per mmbtu)(a) |
Average Volumes (mmbtus)(a) |
||||||||||
| 2015(b) |
$ | 4.00 | 480,000 | |||||||||
| 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 | ) | 1,600,000 | ||||||||
| Crude Oil |
||||||||||||
| Fixed Price Swaps | ||||||||||||
| Production Period Ended December 31, |
Average Fixed Price (per bbl)(a) |
Volumes (bbls)(a) |
||||||||||
| 2015(b) |
$ | 87.62 | 647,000 | |||||||||
| 2016 |
$ | 81.47 | 1,557,000 | |||||||||
| 2017 |
$ | 77.28 | 1,140,000 | |||||||||
| 2018 |
$ | 76.28 | 1,080,000 | |||||||||
| 2019 |
$ | 68.37 | 540,000 | |||||||||
| 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 | 3,250 | |||||||
| 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 | 64,000 | |||||||||
| Mt Belvieu Butane Swaps | ||||||||||||
| Production Period Ended December 31, |
Average Fixed Price (per gallon) |
Volumes (bbls)(a) |
||||||||||
| 2015(b) |
$ | 1.2481 | 12,000 | |||||||||
| Mt Belvieu Iso-Butane Swaps |
||||||||||||
| Production Period Ended December 31, |
Average Fixed Price (per gallon) |
Volumes (bbls)(a) |
||||||||||
| 2015(b) |
$ | 1.2631 | 12,000 | |||||||||
| Mt Belvieu Natural Gasoline Swaps |
||||||||||||
| Production Period Ended December 31, |
Average Fixed Price (per gallon) |
Volumes (bbls)(a) |
||||||||||
| 2015(b) |
$ | 1.9294 | 40,000 | |||||||||
| (a) | “mmbtu” represents million metric British thermal units; “bbl” represents barrel. |
| (b) | Reflects hedges covering the last three months of 2015. |