Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Titan Energy, LLC | d769965d8k.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 SECOND QUARTER 2014
| • | Generated record net daily production of approximately 261.3(1) million cubic feet equivalents per day for the second quarter 2014, a 6% increase over the first quarter 2014 |
| • | Oil production organically grew 33% in the second quarter to approximately 2,100 barrels per day, exclusive of production from ARP’s recent acquisitions |
| • | Closed on both the GeoMet acquisition of low-decline natural gas assets in West Virginia and the oil-rich Rangely Field assets in Colorado, bringing total year to date 2014 acquisitions to over $530 million |
| • | Declared its recent monthly cash distribution of $0.1966 per unit, an 8% year over year increase, and an annualized rate of $2.36 per unit |
| • | Adjusted earnings before interest, income taxes, depreciation and amortization (“Adjusted EBITDA”), a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, increased to $79.2 million(2) for the second quarter 2014 |
| • | Second quarter 2014 financial and operational results will be discussed on a conference call at 9AM ET on Friday, August 8th |
Pittsburgh, PA – August 7, 2014—Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) has reported operating and financial results for the second quarter 2014.
Matthew A. Jones, President of ARP, said, “Our organic growth in oil production offset disappointing natural gas and natural gas liquids prices in the quarter. We are pleased with the progress that we have made so far in developing our liquids-rich regions and we believe that we are well-positioned to take advantage of additional opportunities to grow our enterprise.”
* * *
| • | Second quarter 2014 Adjusted EBITDA, a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, was $79.2 million(2), compared to $68.0 million for the first quarter 2014, and $53.8 million for the prior year comparable quarter. The increase from the sequential and prior year quarters was due to the cash flow contribution from the newly acquired assets both in West Virginia (GeoMet) and oil and liquids production from the Rangely Field assets in northwest Colorado, as well as organic production growth in the Mississippi Lime and Marble Falls regions. |
| • | Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner, a non-GAAP measure, was $54.5 million(2), or approximately $0.57 per common unit, for the second quarter 2014, compared to $42.3 million for the first quarter 2014 and $41.0 million for the prior year comparable quarter. Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner increased compared to the first quarter 2014 due primarily to the increases in production volumes as described above. |
| • | ARP paid monthly cash distributions totaling approximately $0.583 per limited partner unit for the second quarter 2014, an approximate 8% increase over the prior year second quarter distribution. The most recent ARP monthly distribution of $0.1966 per unit ($2.36 per unit on an annual basis) for June 2014 will be paid on August 14, 2014 to holders of record as of August 6, 2014. |
| • | On a GAAP basis, net loss was $20.5 million for the second quarter 2014 compared to a net loss of $10.8 million for the first quarter 2014 and a net loss of $6.2 million for the prior year comparable period. The loss for each period was caused principally by non-cash expenses, specifically depreciation, depletion and amortization in the current period from the larger amount of producing oil & gas assets compared to the prior year period. |
Recent Events
Issuance of additional $100 million 7.75% Senior Notes due 2021
On June 2, 2014, ARP closed its offering of an additional $100 million of its 7.75% Senior Notes due 2021 in a private placement transaction issued at 99.5%. ARP used the net proceeds from this offering to fund a portion of its previously announced acquisition of oil assets in the Rangely Field in northwest Colorado. The senior notes are subject to a registration rights agreement entered in connection with the transaction, which requires ARP, among other things, to file a registration statement with the SEC and exchange the privately placed notes for registered notes by certain dates.
E&P Operating Highlights
| • | Average net daily production for the second quarter 2014 was 261.3 million cubic feet equivalents per day (“Mmcfed”), an increase of almost 100% from the prior year comparable quarter and approximately 6% from the first quarter 2014. The second quarter 2014 volumes included a 515 barrel per day (“bpd”), or 33%, increase in crude oil volumes from the first quarter 2014 and a 268 bpd increase, or 8%, in natural gas liquids (“NGL”) volumes from the first quarter 2014, due to higher oil and NGL volumes in the Marble Falls and the Mississippi Lime. Pro forma for the acquired Rangely Field production in Colorado, oil production for the full quarter was approximately 4,600 bpd. The sequential increase in total production was due to the acquisition of producing assets from GeoMet on May 12, 2014, which generated 11.3 million cubic feet per day (“Mmcfd”) for the full quarter (20.5 Mmcfd from the date of acquisition), while the increase in crude oil and NGL volumes was due to additional wells connected during the current quarter in ARP’s Marble Falls and Mississippi Lime regions. The increase in net production from the second quarter 2013 was due primarily to the acquisition of producing assets from GeoMet in May 2014 and EP Energy in July 2013, which are located in the Raton Basin (New Mexico), Black Warrior Basin (Alabama) and County Line region (Wyoming). |
| • | ARP’s realized price for natural gas across all of its regions, excluding the effect of financial hedges, was $4.13 per thousand cubic feet (“mcf”) in the second quarter 2014, compared to $4.68 per mcf in the first quarter 2014, a sequential decrease of approximately 12%. Net realized natural gas prices including the effect of hedge positions was $3.78 per mcf for the second quarter 2014, a decrease of $0.29, or 7%, from the first quarter 2014. ARP’s realized price for oil, excluding the effect of financial hedges, was $98.95 per barrel in the second quarter 2014, compared to $93.18 per mcf in the first quarter 2014, an increase of approximately 6%. Net realized oil prices including the effect of hedge positions averaged $90.66 per barrel for the second quarter 2014, compared to $87.04 per barrel for the first quarter 2014, representing a 4% increase. |
Hedge Positions
| • | ARP continued to expand its commodity hedge positions on its existing production during the second quarter 2014. A summary of ARP’s derivative positions as of August 7, 2014 is provided in the financial tables of this release. |
Corporate Expenses & Capital Position
| • | Cash general and administrative expense was $10.5 million for the second quarter 2014, $1.2 million lower than the first quarter 2014 and $2.1 million higher compared with the prior year second quarter. The decrease compared with the first quarter 2014 was due primarily to certain administrative and marketing costs associated with ARP’s 2014 partnership program, which ARP was able to capitalize in the current quarter. ARP capitalizes certain amounts of its general and administrative costs associated with the partnership programs as a component of its capital contributions to the partnership programs. The increase in expense compared with the prior year second quarter was principally due to larger operations stemming from ARP’s expanded asset position. |
| • | Cash interest expense was $11.2 million for the second quarter 2014, $0.2 million lower than the first quarter 2014 and $7.9 million higher than the prior year second quarter. The increase compared with the prior year quarter was primarily due to higher levels of borrowing used to expand ARP’s operations over the last year. |
| • | As of June 30, 2014, ARP had $1.2 billion of total debt, including $581 million outstanding under its revolving credit facility. ARP had approximately $244 million available on its revolving credit facility as of the end of the second quarter 2014. |
* * *
Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Resource Partners, L.P.’s second quarter 2014 results on Friday, August 8, 2014 at 9:00 am ET 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 1:00 p.m. ET on August 8, 2014 by dialing 855-859-2056, passcode: 74103318.
Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production master limited partnership which owns an interest in over 13,800 producing natural gas and oil wells, located primarily in Appalachia, 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, L.P. (NYSE: ATLS) is a master limited partnership which owns all of the general partner Class A units and incentive distribution rights and an approximate 28% limited partner interest in its upstream oil & gas subsidiary, Atlas Resource Partners, L.P. Additionally, Atlas Energy owns and operates the general partner of its midstream oil & gas subsidiary, Atlas Pipeline Partners, L.P., through all of the general partner interest, all the incentive distribution rights and an approximate 6% limited partner interest. For more information, please visit our website at www.atlasenergy.com, or contact Investor Relations at InvestorRelations@atlasenergy.com.
Atlas Pipeline Partners, L.P. (NYSE: APL) is active in the gathering and processing segments of the midstream natural gas industry. In Oklahoma, southern Kansas, Texas, and Tennessee, APL owns and operates 16 active gas processing plants, 18 gas treating facilities, as well as approximately 11,200 miles of active intrastate gas gathering pipeline. For more information, visit the Partnership’s website at www.atlaspipeline.com or contact IR@atlaspipeline.com.
* * *
Cautionary Note Regarding Forward-Looking Statements
This press release 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 and production 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 anticipated benefits of its acquisitions; changes in commodity prices and hedge positions; changes in the estimates of maintenance capital expense; 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, 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 COMBINED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Revenues: |
||||||||||||||||
| Gas and oil production |
$ | 104,057 | $ | 47,094 | $ | 200,302 | $ | 93,158 | ||||||||
| Well construction and completion |
16,336 | 24,851 | 65,713 | 81,329 | ||||||||||||
| Gathering and processing |
3,758 | 4,463 | 8,226 | 8,048 | ||||||||||||
| Administration and oversight |
4,166 | 3,391 | 5,895 | 4,476 | ||||||||||||
| Well services |
6,365 | 4,864 | 11,844 | 9,680 | ||||||||||||
| Other, net |
35 | (1,337 | ) | 82 | (1,317 | ) | ||||||||||
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| Total revenues |
134,717 | 83,326 | 292,062 | 195,374 | ||||||||||||
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| Costs and expenses: |
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| Gas and oil production |
41,763 | 19,035 | 78,555 | 34,251 | ||||||||||||
| Well construction and completion |
14,206 | 21,609 | 57,142 | 70,721 | ||||||||||||
| Gathering and processing |
4,273 | 4,959 | 8,686 | 9,372 | ||||||||||||
| Well services |
2,426 | 2,305 | 4,908 | 4,623 | ||||||||||||
| General and administrative |
21,315 | 14,217 | 37,770 | 31,784 | ||||||||||||
| Depreciation, depletion and amortization |
58,001 | 22,197 | 108,238 | 43,405 | ||||||||||||
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| Total costs and expenses |
141,984 | 84,322 | 295,299 | 194,156 | ||||||||||||
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| Operating income (loss) |
(7,267 | ) | (996 | ) | (3,237 | ) | 1,218 | |||||||||
| Gain (loss) on asset sales and disposal |
9 | (672 | ) | (1,594 | ) | (1,374 | ) | |||||||||
| Interest expense |
(13,263 | ) | (4,508 | ) | (26,451 | ) | (11,397 | ) | ||||||||
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| Net loss |
(20,521 | ) | (6,176 | ) | (31,282 | ) | (11,553 | ) | ||||||||
| Preferred limited partner dividends |
(4,424 | ) | (2,071 | ) | (8,823 | ) | (4,028 | ) | ||||||||
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| Net loss attributable to common limited partners and the general partner |
$ | (24,945 | ) | $ | (8,247 | ) | $ | (40,105 | ) | $ | (15,581 | ) | ||||
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| Allocation of net loss attributable to common limited partners and the general partner: |
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| General partner’s interest |
$ | 2,377 | $ | 1,022 | $ | 4,381 | $ | 1,323 | ||||||||
| Common limited partners’ interest |
(27,322 | ) | (9,269 | ) | (44,486 | ) | (16,904 | ) | ||||||||
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| Net loss attributable to common limited partners and the general partner |
$ | (24,945 | ) | $ | (8,247 | ) | $ | (40,105 | ) | $ | (15,581 | ) | ||||
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| Net loss attributable to common limited partners per unit: |
||||||||||||||||
| Basic and Diluted |
$ | (0.37 | ) | $ | (0.20 | ) | $ | (0.66 | ) | $ | (0.37 | ) | ||||
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| Weighted average common limited partner units outstanding: |
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| Basic and Diluted |
73,900 | 47,007 | 67,595 | 45,499 | ||||||||||||
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ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
| June 30, | December 31, | |||||||
| 2014 | 2013 | |||||||
| ASSETS | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 3,993 | $ | 1,828 | ||||
| Accounts receivable |
85,419 | 58,822 | ||||||
| Current portion of derivative asset |
255 | 1,891 | ||||||
| Subscriptions receivable |
16,336 | 47,692 | ||||||
| Prepaid expenses and other |
21,023 | 10,097 | ||||||
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| Total current assets |
127,026 | 120,330 | ||||||
| Property, plant and equipment, net |
2,666,718 | 2,120,818 | ||||||
| Goodwill and intangible assets, net |
32,611 | 32,747 | ||||||
| Long-term derivative asset |
3,415 | 27,084 | ||||||
| Other assets, net |
51,516 | 42,821 | ||||||
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| $ | 2,881,286 | $ | 2,343,800 | |||||
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| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 96,778 | $ | 69,346 | ||||
| Advances from affiliates |
27,838 | 26,742 | ||||||
| Liabilities associated with drilling contracts |
— | 49,377 | ||||||
| Current portion of derivative liability |
19,983 | 6,353 | ||||||
| Accrued well drilling and completion costs |
70,319 | 40,481 | ||||||
| Distribution payable |
18,497 | — | ||||||
| Accrued liabilities |
40,816 | 51,416 | ||||||
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| Total current liabilities |
274,231 | 243,715 | ||||||
| Long-term debt |
1,203,973 | 942,334 | ||||||
| Asset retirement obligations and other |
102,606 | 90,460 | ||||||
| Commitments and contingencies |
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| Partners’ Capital: |
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| General partner’s interest |
249 | 4,482 | ||||||
| Preferred limited partners’ interests |
180,566 | 183,477 | ||||||
| Common limited partners’ interests |
1,132,694 | 852,457 | ||||||
| Class C common limited partner warrants |
1,176 | 1,176 | ||||||
| Accumulated other comprehensive income (loss) |
(14,209 | ) | 25,699 | |||||
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| Total partners’ capital |
1,300,476 | 1,067,291 | ||||||
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| $ | 2,881,286 | $ | 2,343,800 | |||||
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ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Net loss attributable to common limited partners per unit—basic |
$ | (0.37 | ) | $ | (0.20 | ) | $ | (0.66 | ) | $ | (0.37 | ) | ||||
| Cash distributions paid per unit(1) |
$ | 0.583 | $ | 0.540 | $ | 1.163 | $ | 1.050 | ||||||||
| Production revenues (in thousands): |
||||||||||||||||
| Natural gas |
$ | 77,600 | $ | 28,383 | $ | 151,790 | $ | 57,439 | ||||||||
| Oil |
17,192 | 10,595 | 29,475 | 19,401 | ||||||||||||
| Natural gas liquids |
9,265 | 8,116 | 19,037 | 16,318 | ||||||||||||
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| Total production revenues |
$ | 104,057 | $ | 47,094 | $ | 200,302 | $ | 93,158 | ||||||||
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| Production volume:(2)(3) |
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| Appalachia: (4) |
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| Natural gas (Mcfd) |
37,916 | 30,715 | 39,522 | 31,139 | ||||||||||||
| Oil (Bpd) |
388 | 283 | 401 | 280 | ||||||||||||
| Natural gas liquids (Bpd) |
45 | 2 | 37 | 2 | ||||||||||||
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| Total (Mcfed) |
40,513 | 32,421 | 42,152 | 32,830 | ||||||||||||
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| Coal-bed Methane: (4) |
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| Natural gas (Mcfd) |
119,465 | — | 113,948 | — | ||||||||||||
| Oil (Bpd) |
— | — | — | — | ||||||||||||
| Natural gas liquids (Bpd) |
— | — | — | — | ||||||||||||
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| Total (Mcfed) |
119,465 | — | 113,948 | — | ||||||||||||
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| Barnett/Marble Falls: |
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| Natural gas (Mcfd) |
59,711 | 66,407 | 58,810 | 66,239 | ||||||||||||
| Oil (Bpd) |
1,231 | 863 | 1,034 | 821 | ||||||||||||
| Natural gas liquids (Bpd) |
2,762 | 2,748 | 2,666 | 2,653 | ||||||||||||
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| Total (Mcfed) |
83,669 | 88,070 | 81,009 | 87,086 | ||||||||||||
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| Mississippi Lime/Hunton: |
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| Natural gas (Mcfd) |
6,325 | 3,978 | 6,100 | 4,365 | ||||||||||||
| Oil (Bpd) |
437 | 115 | 369 | 72 | ||||||||||||
| Natural gas liquids (Bpd) |
543 | 245 | 514 | 244 | ||||||||||||
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| Total (Mcfed) |
12,205 | 6,138 | 11,400 | 6,265 | ||||||||||||
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| Other Operating Areas: (4) |
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| Natural gas (Mcfd) |
3,267 | 4,538 | 3,334 | 4,699 | ||||||||||||
| Oil (Bpd) |
27 | 20 | 23 | 17 | ||||||||||||
| Natural gas liquids (Bpd) |
340 | 392 | 339 | 393 | ||||||||||||
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| Total (Mcfed) |
5,470 | 7,012 | 5,506 | 7,161 | ||||||||||||
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| Total Production: (3) |
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| Natural gas (Mcfd) |
226,684 | 105,638 | 221,714 | 106,442 | ||||||||||||
| Oil (Bpd) |
2,084 | 1,281 | 1,827 | 1,191 | ||||||||||||
| Natural gas liquids (Bpd) |
3,689 | 3,386 | 3,556 | 3,292 | ||||||||||||
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| Total (Mcfed) |
261,323 | 133,641 | 254,016 | 133,341 | ||||||||||||
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| Average sales prices: (3) |
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| Natural gas (per Mcf) (5) |
$ | 3.78 | $ | 3.31 | $ | 3.92 | $ | 3.32 | ||||||||
| Oil (per Bbl)(6) |
$ | 90.66 | $ | 90.90 | $ | 89.12 | $ | 89.97 | ||||||||
| Natural gas liquids (per Bbl) (7) |
$ | 27.60 | $ | 26.34 | $ | 29.57 | $ | 27.39 | ||||||||
| Production costs:(3)(8) |
||||||||||||||||
| Lease operating expenses per Mcfe |
$ | 1.24 | $ | 1.21 | $ | 1.21 | $ | 1.09 | ||||||||
| Production taxes per Mcfe |
0.24 | 0.23 | 0.26 | 0.23 | ||||||||||||
| Transportation and compression expenses per Mcfe |
0.27 | 0.24 | 0.28 | 0.20 | ||||||||||||
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| Total production costs per Mcfe |
$ | 1.76 | $ | 1.68 | $ | 1.74 | $ | 1.51 | ||||||||
| Depletion per Mcfe(3) |
$ | 2.34 | $ | 1.69 | $ | 2.25 | $ | 1.67 | ||||||||
| (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; Raton/Black Warrior includes ARP’s production located in the Raton Basin in northern New Mexico and the Black Warrior Basin in central Alabama; 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 $4.13 per Mcf and $3.47 per Mcf for the three months ended June 30, 2014 and 2013, respectively, and $4.40 per Mcf and $3.18 per Mcf for the six months ended June 30, 2014 and 2013, 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 $3.76 per Mcf ($4.11 per Mcf before the effects of financial hedging) and $2.95 per Mcf ($3.10 per Mcf before the effects of financial hedging) for the three months ended June 30, 2014 and 2013, respectively, and $3.78 per Mcf ($4.26 per Mcf before the effects of financial hedging) and $2.98 per Mcf ($2.85 per Mcf before the effects of financial hedging) for the six months ended June 30, 2014 and 2013, respectively. |
| (6) | ARP’s average sales prices for oil before the effects of financial hedging were $98.95 per barrel and $92.33 per barrel for the three months ended June 30, 2014 and 2013, respectively, and $96.49 per barrel and $91.63 per barrel for the six months ended June 30, 2014 and 2013, respectively. |
| (7) | ARP’s average sales prices for natural gas liquids before the effects of financial hedging were $28.93 per barrel and $26.54 per barrel for the three months ended June 30, 2014 and 2013, respectively, and $32.15 per barrel and $27.60 per barrel for the six months ended June 30, 2014 and 2013, 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 $1.24 per Mcfe ($1.76 per Mcfe for total production costs) and $1.10 per Mcfe ($1.57 per Mcfe for total production costs) for the three months ended June 30, 2014 and 2013, respectively, and $1.17 per Mcfe ($1.71 per Mcfe for total production costs) and $1.00 per Mcfe ($1.42 per Mcfe for total production costs) for the six months ended June 30, 2014 and 2013, respectively. |
ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
| June 30, 2014 |
December 31, 2013 |
|||||||
| Total debt |
$ | 1,203,973 | $ | 942,334 | ||||
| Less: Cash |
(3,993 | ) | (1,828 | ) | ||||
|
|
|
|
|
|||||
| Total net debt/(cash) |
1,199,980 | 940,506 | ||||||
| Partners’ capital |
1,300,476 | 1,067,291 | ||||||
|
|
|
|
|
|||||
| Total capitalization |
$ | 2,500,456 | $ | 2,007,797 | ||||
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|
|
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| Ratio of net debt to capitalization |
0.48 | x | 0.47 | x | ||||
ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Maintenance capital expenditures (1) |
$ | 13,100 | $ | 7,000 | $ | 23,900 | $ | 11,000 | ||||||||
| Expansion capital expenditures |
41,558 | 64,565 | 70,655 | 119,052 | ||||||||||||
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|
|
|
|
|
|
|
|||||||||
| Total |
$ | 54,658 | $ | 71,565 | $ | 94,555 | $ | 130,052 | ||||||||
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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. |
ATLAS RESOURCE PARTNERS, L.P.
Financial Information
(unaudited; in thousands, except per unit amounts)
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Reconciliation of net loss to non-GAAP measures(1): |
||||||||||||||||
| Net loss |
$ | (20,521 | ) | $ | (6,176 | ) | $ | (31,282 | ) | $ | (11,553 | ) | ||||
| Acquisition and related costs |
8,791 | 2,766 | 11,170 | 6,480 | ||||||||||||
| Depreciation, depletion and amortization |
58,001 | 22,197 | 108,238 | 43,405 | ||||||||||||
| Amortization of deferred finance costs |
2,042 | 1,153 | 3,854 | 5,795 | ||||||||||||
| Non-cash stock compensation expense |
2,009 | 3,002 | 4,354 | 7,249 | ||||||||||||
| Maintenance capital expenditures(2) |
(10,650 | ) | (4,500 | ) | (21,150 | ) | (8,500 | ) | ||||||||
| Loss (gain) on asset sales and disposal |
(9 | ) | 672 | 1,594 | 1,374 | |||||||||||
| Premiums paid on swaption derivative contracts associated with asset acquisitions(3) |
— | 1,309 | — | 1,309 | ||||||||||||
| Other |
5 | — | 2 | — | ||||||||||||
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| Distributable cash flow attributable to limited partners and the general partner(1) |
$ | 39,668 | $ | 20,423 | $ | 76,780 | $ | 45,559 | ||||||||
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| Supplemental Adjusted EBITDA and Distributable Cash Flow Summary: |
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| Gas and oil production margin |
$ | 62,294 | $ | 28,059 | $ | 121,747 | $ | 58,907 | ||||||||
| Well construction and completion margin |
2,130 | 3,242 | 8,571 | 10,608 | ||||||||||||
| Administration and oversight margin |
4,166 | 3,391 | 5,895 | 4,476 | ||||||||||||
| Well services margin |
3,939 | 2,559 | 6,936 | 5,057 | ||||||||||||
| Gathering and processing margin |
(515 | ) | (496 | ) | (460 | ) | (1,324 | ) | ||||||||
| Cash general and administrative expenses(4) |
(10,515 | ) | (8,449 | ) | (22,246 | ) | (18,055 | ) | ||||||||
| Other, net |
40 | (28 | ) | 84 | (8 | ) | ||||||||||
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| Adjusted EBITDA(1) |
61,539 | 28,278 | 120,527 | 59,661 | ||||||||||||
| Cash interest expense(5) |
(11,221 | ) | (3,355 | ) | (22,597 | ) | (5,602 | ) | ||||||||
| Maintenance capital expenditures(2) |
(10,650 | ) | (4,500 | ) | (21,150 | ) | (8,500 | ) | ||||||||
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| Distributable Cash Flow attributable to limited partners and the general partner(1) |
$ | 39,668 | $ | 20,423 | $ | 76,780 | $ | 45,559 | ||||||||
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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) |
14,791 | 20,547 | 19,988 | 20,547 | ||||||||||||
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| Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(7) |
$ | 54,459 | $ | 40,970 | $ | 96,768 | $ | 66,106 | ||||||||
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|||||||||
| Distributions Paid(8) |
$ | 55,893 | $ | 36,053 | $ | 101,624 | $ | 61,384 | ||||||||
| per limited partner unit |
$ | 0.583 | $ | 0.540 | $ | 1.163 | $ | 1.050 | ||||||||
| Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(9) |
$ | (1,434 | ) | $ | 4,917 | $ | (4,856 | ) | $ | 4,722 | ||||||
| (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 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; |
| • | 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; 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; 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) | Swaption derivative contracts grant ARP the option to enter into a swap derivative transaction to hedge future production period sales prices for a stated option period, which generally have a duration of a few months and commences upon entering into the derivative contract, in return for an upfront premium. The amounts included within the reconciliation reflect the amortization of premiums ARP paid to enter into swaption derivative contracts for certain acquired volumes over the option period. Generally, ARP enters into swaption derivative contracts to hedge acquired volumes after the announcement of the signed definitive purchase and sale agreement to acquire the oil and gas properties, but before it closes on the transaction, as its senior secured revolving credit agreement does not allow it to hedge production volume until it owns such volumes. ARP excludes such costs in its determination of DCF, Adjusted EBITDA and cash distributions for the respective period as they are specific to the related transaction. |
| (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 2nd quarter 2014, such amounts include net cash generated by the GeoMet assets from April 1, 2014 to May 11, 2014, and the Rangely assets from April 1, 2014 to June 30, 2014 of $17.6 million, less pro forma interest expense of $0.4 million and estimated maintenance capital expenditures of $2.4 million. For the 2nd quarter 2013, such amounts include pro forma net cash generated by the EP Energy assets from April 1, 2013 to June 30, 2013 of $25.5 million, less pro forma interest expense of $2.5 million and estimated maintenance capital expenditures of $2.5 million. For the six months ended June 30, 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to May 11, 2014, and the Rangely assets from April 1, 2014 to June 30, 2014 of $23.1 million, less pro forma interest expense of $0.4 million and estimated maintenance capital expenditures of $2.7 million. For the six months ended June 30, 2013, such amounts include pro forma net cash generated by the EP Energy assets from April 1, 2013 to June 30, 2013 of $25.5 million, less pro forma interest expense of $2.5 million and estimated maintenance capital expenditures of $2.5 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 $79.2 million and $53.8 million for the three months ended June 30, 2014 and 2013, respectively, and $143.7 million and $85.2 million for the six months ended June 30, 2014 and 2013, 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. The Partnership’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 August 7, 2014)
Natural Gas
| Fixed Price Swaps | ||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per mmbtu)(a) | (mmbtus)(a) | ||||||
| 2014(b) |
$ | 4.15 | 30,076,488 | |||||
| 2015 |
$ | 4.24 | 51,924,492 | |||||
| 2016 |
$ | 4.31 | 45,746,320 | |||||
| 2017 |
$ | 4.53 | 24,840,000 | |||||
| 2018 |
$ | 4.62 | 9,360,000 | |||||
| Costless Collars | ||||||||||||
| Average | Average | |||||||||||
| Production Period | Floor Price | Ceiling Price | Volumes | |||||||||
| Ended December 31, |
(per mmbtu)(a) | (per mmbtu)(a) | (mmbtus)(a) | |||||||||
| 2014(b) |
$ | 4.22 | $ | 5.12 | 1,920,000 | |||||||
| 2015 |
$ | 4.23 | $ | 5.13 | 3,480,000 | |||||||
| Put Options – Drilling Partnerships |
||||||||
| Average | Average | |||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per mmbtu)(a) | (mmbtus)(a) | ||||||
| 2014(b) |
$ | 3.80 | 900,000 | |||||
| 2015 |
$ | 4.00 | 1,440,000 | |||||
| 2016 |
$ | 4.15 | 1,440,000 | |||||
| WAHA Basis Swaps | ||||||||
| Average | Average | |||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per mmbtu)(a) | (mmbtus)(a) | ||||||
| 2014(b) |
$ | (0.1100 | ) | 5,400,000 | ||||
| NGPL Basis Swaps | ||||||||
| Average | Average | |||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per mmbtu)(a) | (mmbtus)(a) | ||||||
| 2014(b) |
$ | (0.1082 | ) | 4,200,000 | ||||
Natural Gas Liquids
| Crude Oil Fixed Price Swaps | ||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per bbl)(a) | (bbls)(a) | ||||||
| 2016 |
$ | 85.65 | 84,000 | |||||
| 2017 |
$ | 83.78 | 60,000 | |||||
| Mt Belvieu Ethane Purity Swaps | ||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per gallon) | (bbls)(a) | ||||||
| 2014(b) |
$ | 0.3025 | 30,000 | |||||
| Mt Belvieu Propane Swaps |
||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per gallon) | (bbls)(a) | ||||||
| 2014(b) |
$ | 0.9996 | 147,000 | |||||
| 2015 |
$ | 1.0161 | 192,000 | |||||
| Mt Belvieu Butane Swaps | ||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per gallon) | (bbls)(a) | ||||||
| 2014(b) |
$ | 1.3075 | 18,000 | |||||
| 2015 |
$ | 1.2481 | 36,000 | |||||
| Mt Belvieu Iso-Butane Swaps |
||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per gallon) | (bbls)(a) | ||||||
| 2014(b) |
$ | 1.3225 | 18,000 | |||||
| 2015 |
$ | 1.2631 | 36,000 | |||||
| Mt Belvieu Natural Gasoline Swaps | ||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per gallon) | (bbls)(a) | ||||||
| 2014(b) |
$ | 2.1225 | 55,000 | |||||
| 2015 |
$ | 1.9831 | 120,000 | |||||
Crude Oil
| Fixed Price Swaps | ||||||||
| Average | ||||||||
| Production Period | Fixed Price | Volumes | ||||||
| Ended December 31, |
(per bbl)(a) | (bbls)(a) | ||||||
| 2014(b) |
$ | 95.83 | 651,000 | |||||
| 2015 |
$ | 90.85 | 1,443,000 | |||||
| 2016 |
$ | 88.65 | 1,029,000 | |||||
| 2017 |
$ | 87.75 | 492,000 | |||||
| 2018 |
$ | 88.28 | 360,000 | |||||
| Costless Collars | ||||||||||||
| Average | Average | |||||||||||
| Production Period | Floor Price | Ceiling Price | Volumes | |||||||||
| Ended December 31, |
(per bbl)(a) | (per bbl)(a) | (bbls)(a) | |||||||||
| 2014(b) |
$ | 84.17 | $ | 113.31 | 20,580 | |||||||
| 2015 |
$ | 83.85 | $ | 110.65 | 29,250 | |||||||
| (a) | “mmbtu” represents million metric British thermal units.; “bbl” represents barrel. |
| (b) | Reflects hedges covering the last six months of 2014. |