UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 8-K
CURRENT REPORT
Pursuant
to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 6, 2015
Commission File Number: 001-35317
Atlas
Resource Partners, L.P.
(Exact name of registrant as specified in its charter)
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| Delaware |
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45-3591625 |
| (State or other jurisdiction
of incorporation) |
|
(IRS Employer
Identification No.) |
Park Place Corporate Center One
1000 Commerce Drive, Suite 400
Pittsburgh, PA 15275
(Address of principal executive offices) (Zip code)
(Registrant’s telephone number, including area code: (800) 251-0171
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the
following provisions:
| ¨ |
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ |
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ |
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ |
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
| Item 2.02. |
Results of Operations and Financial Condition. |
On August 6, 2015, Atlas
Resource Partners, L.P. issued an earnings release announcing its financial results for the second quarter of 2015. A copy of the earnings release is included as Exhibit 99.1 and is incorporated herein by reference.
The information provided in this Item 2.02 (including Exhibit 99.1) shall not be deemed to be “filed” for the purposes of
Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be incorporated by reference in any filing made by the Registrant pursuant to the Securities Act of 1933, as amended, other than to the extent that such filing
incorporates by reference any or all of such information by express reference thereto.
| Item 9.01 |
Financial Statements and Exhibits |
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| 99.1 |
|
Atlas Resource Partners, L.P. Press Release dated August 6, 2015 |
Signature(s)
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned hereunto duly authorized.
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ATLAS RESOURCE PARTNERS, L.P. |
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By: |
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Atlas Energy Group, LLC, its general partner |
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| August 6, 2015 |
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By: |
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/s/ Sean McGrath |
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Sean McGrath |
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Chief Financial Officer |
Exhibit 99.1
NEWS RELEASE
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| CONTACT: |
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Brian J. Begley |
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Vice President - Investor Relations |
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Atlas Resource Partners, L.P. |
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(877) 280-2857 |
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(215) 405-2718 (fax) |
ATLAS RESOURCE PARTNERS, L.P. REPORTS OPERATING AND FINANCIAL RESULTS FOR THE SECOND QUARTER 2015
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• |
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Adjusted EBITDA was $64.7 million(1) for the second quarter 2015 and Distributable Cash Flow was $25.4 million(1)
for the second quarter 2015 |
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• |
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Natural gas and oil production in the second quarter 2015 were hedged approximately 73% and 100%, respectively; ARP’s market value of its hedge portfolio is currently $327 million |
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• |
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Production costs have decreased approximately $25 million on an annualized basis when compared to fourth quarter 2014 as a result of the Company’s operational cost reduction efforts |
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• |
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Full year 2015 G&A expense is expected to decrease approximately 20% on a year over year basis |
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• |
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Management will discuss second quarter 2015 financial and operational results on a conference call at 9AM ET on Friday, August 7th |
Philadelphia, PA – August 6, 2015 - Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP” or “the Company”) reported
operating and financial results for the second quarter 2015.
Daniel C. Herz, Chief Executive Officer - ARP, stated, “Our executive team has
successfully navigated similar commodity price cycles in the past. Our business and operations are performing at our expectations, and we continued to benefit this period from our strong natural gas and oil hedge positions. We believe our business
is well-protected by our hedges and the fee income from our partnership management business, which will help us manage through this challenging period. Most importantly, we are presently pursuing strategic activities which would additionally
strengthen the core of our enterprise and position our business to take advantage of opportunities in the current market environment.”
* * *
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• |
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Second quarter 2015 Adjusted EBITDA, a non-GAAP measure, was $64.7 million(1), compared to $70.9 million for the first quarter 2015. The decrease from the first
quarter 2015 was due to historical seasonality of ARP’s partnership management business fee recognition, as well as lower production margin as a result of planned deferral of capital expenditures and well connections until later in 2015.
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• |
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Distributable Cash Flow, a non-GAAP measure, was $25.4 million(1), or approximately $0.27 per common unit, for the second quarter 2015, compared with $52.9 million
for the prior year second quarter. |
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• |
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ARP paid monthly cash distributions totaling $0.325 per common limited partner unit for the second quarter 2015 at a distribution coverage ratio of approximately 0.83x. Distribution coverage for the first half of 2015
was approximately 1.0x. On July 22, 2015, ARP announced the June 2015 monthly distribution of $0.1083 per common unit ($1.30 per unit on an annualized basis), which will be paid on August 14, 2015 to unitholders of record as of
August 7, 2015. |
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• |
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On a GAAP basis, net loss was $46.8 million for the second quarter 2015, compared with a net loss of $19.4 million for the prior year second quarter. Net loss in the current period was principally generated by the
mark-to-market loss recognized in the period from ARP’s financial hedge positions, as ARP discontinued hedge accounting as of January 1, 2015. |
Arkoma Asset Acquisition from Atlas Energy
On June 5, 2015, ARP acquired natural gas producing properties in the Arkoma basin from its parent company, Atlas Energy Group, LLC (NYSE:ATLS), for
approximately $35.5 million. The Arkoma assets consist of approximately 41 billion cubic feet (“Bcf”) of mature, low-decline natural gas reserves, which currently produce approximately 10.5 million cubic feet per day from over 550
active wells. ARP accounted for the Arkoma acquisition as a transaction between entities under common control, and accordingly recast the comparative prior periods presented as if the transaction had occurred at the beginning of the respective
periods.
Operating Results
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• |
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Average net daily production for the second quarter 2015 was 270.8 million cubic feet equivalents per day (“Mmcfed”), as compared to 273.0 Mmcfed for the prior year second quarter. ARP’s second
quarter 2015 production was comprised of 81% natural gas, 12% oil and 7% natural gas liquids (“NGL”). Oil volumes increased to 5,293 barrels per day (“bpd”) in the second quarter 2015, compared to 2,084 bpd in the prior year
quarter. The increase in oil volumes was due primarily to the acquisition of oil-rich production in the Eagle Ford Shale and Rangely field in 2014. |
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• |
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ARP’s net realized price for natural gas including the effect of hedge positions was $3.33 per thousand cubic feet (“mcf”) for the second quarter 2015, compared to $3.79/mcf for the prior year second
quarter. Net realized oil prices including the effect of hedge positions averaged $83.19 per barrel (“bbl”) for the second quarter 2015, compared to $90.66/bbl for the prior year second quarter. The Company was hedged approximately 73% on
its natural gas production in the second quarter 2015 and approximately 100% on its oil production. |
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• |
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Investment partnership margin was $6.7 million in the second quarter 2015, compared with $10.2 million for the prior year comparable quarter. The decrease in investment partnership margin was due to more partnership
wells being initiated in the prior year quarter, which generated higher administration and oversight fees. |
Hedge Positions
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• |
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ARP’s hedge portfolio is comprised entirely of fixed-price swap and costless collar positions through 2019, and is valued at $327 million as of August 6, 2015. |
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• |
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For the remainder of 2015 and the full years 2016, 2017, and 2018, ARP is hedged approximately 72%, 67%, 62% and 51%, respectively, for its natural gas production at an average price of $4.17/mcf, and is hedged
approximately 100%, 85%, 62% and 59%, respectively, for oil at an average price of approximately $78/bbl based on second quarter 2015 average production. A summary of ARP’s derivative positions as of August 6, 2015 is provided in the
financial tables of this release. |
Corporate Expenses & Capital Position
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• |
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Cash general and administrative expense was $10.7 million for the second quarter 2015, which was consistent with $10.5 million in the prior year comparable period. ARP expects full year 2015 general and administrative
expense to decrease approximately 20% compared to the full year 2014 due primarily to labor and other cost reductions. |
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• |
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Cash interest expense was $21.2 million for the second quarter 2015, compared with $11.6 million for the prior year period. The increase compared to the prior year second quarter was due to the issuance in follow-on
offerings of $100 million of 7.75% Senior Notes due 2021 in May 2014 and $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. |
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At June 30, 2015, ARP had $1.5 billion of total debt, which was consistent with the balance at March 31, 2015. The outstanding debt balance included $550.0 million outstanding under its revolving credit
facility with a borrowing base of $750 million, which was reconfirmed on July 29, 2015. ARP had approximately $196 million of availability under its revolving credit facility at June 30, 2015. |
* * *
ARP will be
discussing its second quarter 2015 results on an investor call with management on Friday, August 7, 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 ARP website and telephonically
beginning at approximately 1:00 p.m. ET on August 7, 2015 by dialing (855) 859-2056, passcode: 87417314.
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 25% 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)
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Three Months Ended
June 30, |
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Six Months Ended
June 30, |
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2015 |
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2014 |
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2015 |
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2014 |
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| Revenues: |
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| Gas and oil production |
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$ |
97,260 |
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$ |
108,237 |
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$ |
201,509 |
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$ |
208,494 |
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| Well construction and completion |
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16,956 |
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16,336 |
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|
40,611 |
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65,713 |
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| Gathering and processing |
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|
2,177 |
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|
3,758 |
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4,361 |
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|
|
8,226 |
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| Administration and oversight |
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|
547 |
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4,166 |
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1,806 |
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5,895 |
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| Well services |
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6,102 |
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6,365 |
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12,726 |
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11,844 |
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| Gain (loss) on mark-to-market derivatives |
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(26,944 |
) |
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— |
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78,641 |
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— |
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| Other, net |
|
|
27 |
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35 |
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60 |
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82 |
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| Total revenues |
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96,125 |
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138,897 |
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339,714 |
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300,254 |
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| Costs and expenses: |
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| Gas and oil production |
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43,135 |
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43,122 |
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88,633 |
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81,647 |
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| Well construction and completion |
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14,745 |
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14,206 |
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35,315 |
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57,142 |
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| Gathering and processing |
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2,516 |
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4,273 |
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|
4,933 |
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|
8,686 |
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| Well services |
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|
2,139 |
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2,426 |
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4,337 |
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|
|
4,908 |
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| General and administrative |
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13,287 |
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21,315 |
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30,422 |
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|
37,770 |
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| Depreciation, depletion and amortization |
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|
42,494 |
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|
59,680 |
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85,485 |
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|
111,499 |
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| Total costs and expenses |
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|
118,316 |
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|
|
145,022 |
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|
|
249,125 |
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301,652 |
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| Operating income (loss) |
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|
(22,191 |
) |
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|
(6,125 |
) |
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|
90,589 |
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|
|
(1,398 |
) |
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| Gain (loss) on asset sales and disposal |
|
|
97 |
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|
|
9 |
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|
|
86 |
|
|
|
(1,594 |
) |
| Interest expense |
|
|
(24,716 |
) |
|
|
(13,263 |
) |
|
|
(49,913 |
) |
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|
(26,451 |
) |
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| Net income (loss) |
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(46,810 |
) |
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|
(19,379 |
) |
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|
40,762 |
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|
|
(29,443 |
) |
| Preferred limited partner dividends |
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|
(4,234 |
) |
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|
(4,424 |
) |
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|
(7,887 |
) |
|
|
(8,823 |
) |
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| Net income (loss) attributable to common limited partners and the general partner |
|
$ |
(51,044 |
) |
|
$ |
(23,803 |
) |
|
$ |
32,875 |
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|
$ |
(38,266 |
) |
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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 |
|
$ |
(1,021 |
) |
|
$ |
2,400 |
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$ |
658 |
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$ |
4,418 |
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| Common limited partners’ interest |
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|
(50,023 |
) |
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|
(26,203 |
) |
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|
32,217 |
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(42,684 |
) |
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| Net income (loss) attributable to common limited partners and the general partner |
|
$ |
(51,044 |
) |
|
$ |
(23,803 |
) |
|
$ |
32,875 |
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|
$ |
(38,266 |
) |
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| Net income (loss) attributable to common limited partners per unit: |
|
|
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|
|
|
|
|
|
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| Basic |
|
$ |
(0.55 |
) |
|
$ |
(0.35 |
) |
|
$ |
0.36 |
|
|
$ |
(0.63 |
) |
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|
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|
|
|
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| Diluted |
|
$ |
(0.55 |
) |
|
$ |
(0.35 |
) |
|
$ |
0.36 |
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|
$ |
(0.63 |
) |
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| Weighted average common limited partner units outstanding: |
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|
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| Basic |
|
|
90,516 |
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|
|
73,900 |
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|
|
88,036 |
|
|
|
67,595 |
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|
|
|
|
|
|
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|
|
|
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|
|
|
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| Diluted |
|
|
90,516 |
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|
|
73,900 |
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|
|
88,616 |
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|
|
67,595 |
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ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
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June 30,
2015 |
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December 31,
2014 |
|
| ASSETS |
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| Current assets: |
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| Cash and cash equivalents |
|
$ |
607 |
|
|
$ |
15,247 |
|
| Accounts receivable |
|
|
89,169 |
|
|
|
114,520 |
|
| Advances to affiliates |
|
|
24,856 |
|
|
|
— |
|
| Current portion of derivative asset |
|
|
114,710 |
|
|
|
144,259 |
|
| Subscriptions receivable |
|
|
— |
|
|
|
32,398 |
|
| Prepaid expenses and other |
|
|
24,321 |
|
|
|
26,296 |
|
|
|
|
|
|
|
|
|
|
| Total current assets |
|
|
253,663 |
|
|
|
332,720 |
|
|
|
|
| Property, plant and equipment, net |
|
|
2,226,817 |
|
|
|
2,263,820 |
|
| Goodwill and intangible assets, net |
|
|
14,213 |
|
|
|
14,330 |
|
| Long-term derivative asset |
|
|
150,162 |
|
|
|
130,602 |
|
| Other assets, net |
|
|
56,239 |
|
|
|
50,081 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,701,094 |
|
|
$ |
2,791,553 |
|
|
|
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|
|
|
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|
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| LIABILITIES AND PARTNERS’ CAPITAL |
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| Current liabilities: |
|
|
|
|
|
|
|
|
| Accounts payable |
|
$ |
77,603 |
|
|
$ |
111,198 |
|
| Advances from affiliates |
|
|
— |
|
|
|
2,249 |
|
| Liabilities associated with drilling contracts |
|
|
— |
|
|
|
40,611 |
|
| Accrued well drilling and completion costs |
|
|
25,565 |
|
|
|
80,404 |
|
| Distribution payable |
|
|
13,541 |
|
|
|
20,876 |
|
| Accrued liabilities |
|
|
54,050 |
|
|
|
84,235 |
|
|
|
|
|
|
|
|
|
|
| Total current liabilities |
|
|
170,759 |
|
|
|
339,573 |
|
|
|
|
| Long-term debt |
|
|
1,491,612 |
|
|
|
1,394,460 |
|
| Asset retirement obligations and other |
|
|
114,422 |
|
|
|
109,983 |
|
|
|
|
| Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
| Partners’ Capital: |
|
|
|
|
|
|
|
|
| General partner’s interest |
|
|
(15,474 |
) |
|
|
(13,697 |
) |
| Preferred limited partners’ interests |
|
|
188,948 |
|
|
|
163,522 |
|
| Common limited partners’ interests |
|
|
611,301 |
|
|
|
605,065 |
|
| Class C common limited partner warrants |
|
|
1,176 |
|
|
|
1,176 |
|
| Accumulated other comprehensive income |
|
|
138,350 |
|
|
|
191,471 |
|
|
|
|
|
|
|
|
|
|
| Total partners’ capital |
|
|
924,301 |
|
|
|
947,537 |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,701,094 |
|
|
$ |
2,791,553 |
|
|
|
|
|
|
|
|
|
|
ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
| |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
| Net income (loss) attributable to common limited partners per unit - basic |
|
$ |
(0.55 |
) |
|
$ |
(0.35 |
) |
|
$ |
0.36 |
|
|
$ |
(0.63 |
) |
|
|
|
|
|
| Cash distributions paid per unit(1) |
|
$ |
0.325 |
|
|
$ |
0.583 |
|
|
$ |
0.650 |
|
|
$ |
1.163 |
|
|
|
|
|
|
| Production revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas |
|
$ |
56,548 |
|
|
$ |
81,780 |
|
|
$ |
123,089 |
|
|
$ |
159,982 |
|
| Oil |
|
|
35,861 |
|
|
|
17,192 |
|
|
|
68,246 |
|
|
|
29,475 |
|
| Natural gas liquids |
|
|
4,851 |
|
|
|
9,265 |
|
|
|
10,174 |
|
|
|
19,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total production revenues |
|
$ |
97,260 |
|
|
$ |
108,237 |
|
|
$ |
201,509 |
|
|
$ |
208,494 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Production volume:(2)(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Appalachia:(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (Mcfd) |
|
|
31,378 |
|
|
|
37,916 |
|
|
|
31,796 |
|
|
|
39,522 |
|
| Oil (Bpd) |
|
|
369 |
|
|
|
388 |
|
|
|
352 |
|
|
|
401 |
|
| Natural gas liquids (Bpd) |
|
|
35 |
|
|
|
45 |
|
|
|
35 |
|
|
|
37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (Mcfed) |
|
|
33,804 |
|
|
|
40,513 |
|
|
|
34,118 |
|
|
|
42,152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Coal-bed Methane:(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (Mcfd) |
|
|
131,310 |
|
|
|
131,156 |
|
|
|
132,714 |
|
|
|
125,420 |
|
| Oil (Bpd) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| Natural gas liquids (Bpd) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (Mcfed) |
|
|
131,310 |
|
|
|
131,156 |
|
|
|
132,714 |
|
|
|
125,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Barnett/Marble Falls: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (Mcfd) |
|
|
47,369 |
|
|
|
59,711 |
|
|
|
48,487 |
|
|
|
58,810 |
|
| Oil (Bpd) |
|
|
633 |
|
|
|
1,231 |
|
|
|
691 |
|
|
|
1,034 |
|
| Natural gas liquids (Bpd) |
|
|
2,095 |
|
|
|
2,762 |
|
|
|
2,184 |
|
|
|
2,666 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (Mcfed) |
|
|
63,740 |
|
|
|
83,669 |
|
|
|
65,736 |
|
|
|
81,009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Rangely/Eagle Ford:(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (Mcfd) |
|
|
200 |
|
|
|
— |
|
|
|
349 |
|
|
|
— |
|
| Oil (Bpd) |
|
|
3,890 |
|
|
|
— |
|
|
|
3,900 |
|
|
|
— |
|
| Natural gas liquids (Bpd) |
|
|
302 |
|
|
|
— |
|
|
|
330 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (Mcfed) |
|
|
25,354 |
|
|
|
— |
|
|
|
25,732 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Mississippi Lime/Hunton: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (Mcfd) |
|
|
6,429 |
|
|
|
6,325 |
|
|
|
7,001 |
|
|
|
6,100 |
|
| Oil (Bpd) |
|
|
383 |
|
|
|
437 |
|
|
|
448 |
|
|
|
369 |
|
| Natural gas liquids (Bpd) |
|
|
534 |
|
|
|
543 |
|
|
|
574 |
|
|
|
514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (Mcfed) |
|
|
11,931 |
|
|
|
12,205 |
|
|
|
13,137 |
|
|
|
11,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other Operating Areas:(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (Mcfd) |
|
|
3,158 |
|
|
|
3,267 |
|
|
|
3,224 |
|
|
|
3,334 |
|
| Oil (Bpd) |
|
|
17 |
|
|
|
27 |
|
|
|
21 |
|
|
|
23 |
|
| Natural gas liquids (Bpd) |
|
|
227 |
|
|
|
340 |
|
|
|
216 |
|
|
|
339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (Mcfed) |
|
|
4,622 |
|
|
|
5,470 |
|
|
|
4,645 |
|
|
|
5,506 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total Production:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (Mcfd) |
|
|
219,844 |
|
|
|
238,375 |
|
|
|
223,571 |
|
|
|
233,186 |
|
| Oil (Bpd) |
|
|
5,293 |
|
|
|
2,084 |
|
|
|
5,412 |
|
|
|
1,827 |
|
| Natural gas liquids (Bpd) |
|
|
3,194 |
|
|
|
3,689 |
|
|
|
3,340 |
|
|
|
3,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total (Mcfed) |
|
|
270,761 |
|
|
|
273,014 |
|
|
|
276,083 |
|
|
|
265,488 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Average sales prices:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Natural gas (per Mcf)(5) |
|
$ |
3.33 |
|
|
$ |
3.79 |
|
|
$ |
3.46 |
|
|
$ |
3.92 |
|
| Oil (per Bbl)(6) |
|
$ |
83.19 |
|
|
$ |
90.66 |
|
|
$ |
81.98 |
|
|
$ |
89.12 |
|
| Natural gas liquids (per Bbl)(7) |
|
$ |
22.58 |
|
|
$ |
27.60 |
|
|
$ |
22.53 |
|
|
$ |
29.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Production costs:(3)(8) |
|
$ |
1.36 |
|
|
$ |
1.22 |
|
|
$ |
1.36 |
|
|
$ |
1.19 |
|
| Lease operating expenses per Mcfe |
|
|
0.16 |
|
|
|
0.24 |
|
|
|
0.20 |
|
|
|
0.26 |
|
| Production taxes per Mcfe |
|
|
0.24 |
|
|
|
0.27 |
|
|
|
0.24 |
|
|
|
0.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Transportation and compression expenses per Mcfe |
|
$ |
1.77 |
|
|
$ |
1.73 |
|
|
$ |
1.79 |
|
|
$ |
1.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total production costs per Mcfe |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Depletion per Mcfe(3) |
|
$ |
1.60 |
|
|
$ |
2.30 |
|
|
$ |
1.59 |
|
|
$ |
2.22 |
|
| (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) |
ARP’s average sales prices for natural gas before the effects of financial hedging were $2.14 per Mcf and $4.13 per Mcf for the three months ended June 30, 2015 and 2014, respectively, and $2.34 per Mcf and
$4.39 per Mcf for the six months ended June 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 $3.28 per Mcf ($2.09 per Mcf before the effects of financial hedging) and $3.77 per Mcf ($4.12 per Mcf before the effects of financial hedging) for the three months ended June 30, 2015 and 2014,
respectively, and $3.40 per Mcf ($2.29 per Mcf before the effects of financial hedging) and $3.79 per Mcf ($4.26 per Mcf before the effects of financial hedging) for the six months ended June 30, 2015 and 2014, respectively. |
| (6) |
ARP’s average sales prices for oil before the effects of financial hedging were $53.35 per barrel and $98.95 per barrel for the three months ended June 30, 2015 and 2014, respectively, and $48.32 per barrel
and $96.49 per barrel for the six months ended June 30, 2015 and 2014, respectively. |
| (7) |
ARP’s average sales prices for natural gas liquids before the effects of financial hedging were $13.78 per barrel and $28.93 per barrel for the three months ended June 30, 2015 and 2014, respectively, and
$13.95 per barrel and $32.15 per barrel for the six months ended June 30, 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 $1.34 per Mcfe ($1.75 per Mcfe for total production costs) and $1.23 per Mcfe ($1.74 per Mcfe for total production costs) for the three months ended June 30, 2015 and 2014, respectively, and $1.34 per Mcfe
($1.77 per Mcfe for total production costs) and $1.16 per Mcfe ($1.70 per Mcfe for total production costs) for the six months ended June 30, 2015 and 2014, respectively. |
ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
|
|
|
|
|
|
|
|
|
| |
|
June 30,
2015 |
|
|
December 31,
2014 |
|
| Total debt |
|
$ |
1,491,612 |
|
|
$ |
1,394,460 |
|
| Less: Cash |
|
|
(607 |
) |
|
|
(15,247 |
) |
|
|
|
|
|
|
|
|
|
| Total net debt/(cash) |
|
|
1,491,005 |
|
|
|
1,379,213 |
|
|
|
|
| Partners’ capital |
|
|
924,301 |
|
|
|
947,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total capitalization |
|
$ |
2,415,306 |
|
|
$ |
2,326,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Ratio of net debt to capitalization |
|
|
0.62x |
|
|
|
0.59x |
|
ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
| |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
| Maintenance capital expenditures(1) |
|
$ |
13,905 |
|
|
$ |
13,100 |
|
|
$ |
29,332 |
|
|
$ |
23,900 |
|
| Expansion capital expenditures |
|
|
13,088 |
|
|
|
41,618 |
|
|
|
40,159 |
|
|
|
70,749 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
$ |
26,993 |
|
|
$ |
54,718 |
|
|
$ |
69,491 |
|
|
$ |
94,649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (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
June 30, |
|
|
Six Months Ended
June 30, |
|
| |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
| Reconciliation of net income (loss) to non-GAAP measures(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net income (loss) |
|
$ |
(46,810 |
) |
|
$ |
(19,379 |
) |
|
$ |
40,762 |
|
|
$ |
(29,443 |
) |
| Acquisition and related costs |
|
|
1,710 |
|
|
|
8,791 |
|
|
|
3,881 |
|
|
|
11,170 |
|
| Depreciation, depletion and amortization |
|
|
42,494 |
|
|
|
59,680 |
|
|
|
85,485 |
|
|
|
111,499 |
|
| Amortization of deferred finance costs |
|
|
3,538 |
|
|
|
2,042 |
|
|
|
10,737 |
|
|
|
3,854 |
|
| Non-cash stock compensation expense |
|
|
863 |
|
|
|
2,009 |
|
|
|
4,209 |
|
|
|
4,354 |
|
| Maintenance capital expenditures(2) |
|
|
(13,905 |
) |
|
|
(10,650 |
) |
|
|
(29,332 |
) |
|
|
(21,150 |
) |
| Preferred unit distributions |
|
|
(4,253 |
) |
|
|
(4,424 |
) |
|
|
(8,338 |
) |
|
|
(8,823 |
) |
| (Gain) loss on asset sales and disposal |
|
|
(97 |
) |
|
|
(9 |
) |
|
|
(86 |
) |
|
|
1,594 |
|
| Cash settlements on commodity derivative contracts(3) |
|
|
14,922 |
|
|
|
— |
|
|
|
30,125 |
|
|
|
— |
|
| Unrealized (gain) loss on mark-to-market derivatives |
|
|
26,944 |
|
|
|
— |
|
|
|
(78,641 |
) |
|
|
— |
|
| Other |
|
|
(5 |
) |
|
|
5 |
|
|
|
(17 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Distributable cash flow attributable to limited partners and the general
partner(1) |
|
$ |
25,401 |
|
|
$ |
38,065 |
|
|
$ |
58,785 |
|
|
$ |
73,057 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Supplemental Adjusted EBITDA and Distributable Cash Flow Summary: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Gas and oil production margin |
|
$ |
69,047 |
|
|
$ |
65,115 |
|
|
$ |
143,001 |
|
|
$ |
126,847 |
|
| Well construction and completion margin |
|
|
2,211 |
|
|
|
2,130 |
|
|
|
5,296 |
|
|
|
8,571 |
|
| Administration and oversight margin |
|
|
547 |
|
|
|
4,166 |
|
|
|
1,806 |
|
|
|
5,895 |
|
| Well services margin |
|
|
3,963 |
|
|
|
3,939 |
|
|
|
8,389 |
|
|
|
6,936 |
|
| Gathering and processing margin |
|
|
(339 |
) |
|
|
(515 |
) |
|
|
(572 |
) |
|
|
(460 |
) |
| Cash general and administrative expenses(4) |
|
|
(10,714 |
) |
|
|
(10,515 |
) |
|
|
(22,332 |
) |
|
|
(22,246 |
) |
| Other, net |
|
|
22 |
|
|
|
40 |
|
|
|
43 |
|
|
|
84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Adjusted EBITDA(1) |
|
|
64,737 |
|
|
|
64,360 |
|
|
|
135,631 |
|
|
|
125,627 |
|
| Cash interest expense(5) |
|
|
(21,178 |
) |
|
|
(11,221 |
) |
|
|
(39,176 |
) |
|
|
(22,597 |
) |
| Preferred unit distributions |
|
|
(4,253 |
) |
|
|
(4,424 |
) |
|
|
(8,338 |
) |
|
|
(8,823 |
) |
| Maintenance capital expenditures(2) |
|
|
(13,905 |
) |
|
|
(10,650 |
) |
|
|
(29,332 |
) |
|
|
(21,150 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Distributable Cash Flow attributable to limited partners and the general
partner(1) |
|
$ |
25,401 |
|
|
$ |
38,065 |
|
|
$ |
58,785 |
|
|
$ |
73,057 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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) |
|
|
— |
|
|
|
14,791 |
|
|
|
— |
|
|
|
19,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(7) |
|
$ |
25,401 |
|
|
$ |
52,856 |
|
|
$ |
58,785 |
|
|
$ |
93,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Distributions Paid(8) |
|
$ |
30,555 |
|
|
$ |
51,469 |
|
|
$ |
59,038 |
|
|
$ |
92,801 |
|
| per limited partner unit |
|
$ |
0.325 |
|
|
$ |
0.583 |
|
|
$ |
0.650 |
|
|
$ |
1.163 |
|
|
|
|
|
|
| Excess (shortfall) of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after
distributions to unitholders(9) |
|
$ |
(5,154 |
) |
|
$ |
1,387 |
|
|
$ |
(253 |
) |
|
$ |
244 |
|
| (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:
| |
• |
|
Income tax expense; and |
| |
• |
|
Depreciation, depletion and amortization. |
ARP defines Adjusted EBITDA as EBITDA plus the
following adjustments:
| |
• |
|
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 |
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:
| |
• |
|
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 June 30, 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 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. |
| (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 $82.0 million and $148.8 million for
the three and six months ended June 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 August 6, 2015)
Natural
Gas
|
|
|
|
|
|
|
|
|
| Fixed Price Swaps |
|
|
|
|
|
|
| Production Period Ended December 31, |
|
Average
Fixed Price
(per mmbtu)(a) |
|
|
Volumes
(mmbtus)(a) |
|
|
|
|
| 2015(b) |
|
$ |
4.19 |
|
|
|
26,832,246 |
|
| 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) |
|
$ |
4.16 |
|
|
$ |
5.00 |
|
|
|
1,560,000 |
|
|
|
|
|
|
|
|
|
|
| Put Options – Drilling Partnerships |
|
|
|
|
|
|
| Production Period Ended December 31, |
|
Average
Fixed Price
(per mmbtu)(a) |
|
|
Average
Volumes
(mmbtus)(a) |
|
|
|
|
| 2015(b) |
|
$ |
4.00 |
|
|
|
720,000 |
|
| 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) |
|
$ |
87.65 |
|
|
|
966,000 |
|
| 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 |
|
|
|
9,750 |
|
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 |
|
|
|
96,000 |
|
|
|
|
|
|
|
|
|
|
| Mt Belvieu Butane Swaps |
|
| Production Period Ended December 31, |
|
Average
Fixed Price
(per gallon) |
|
|
Volumes
(bbls)(a) |
|
|
|
|
| 2015(b) |
|
$ |
1.2481 |
|
|
|
21,000 |
|
|
|
|
| Mt Belvieu Iso-Butane Swaps |
|
|
|
|
|
|
|
|
| Production Period Ended December 31, |
|
Average
Fixed Price
(per gallon) |
|
|
Volumes
(bbls)(a) |
|
|
|
|
| 2015(b) |
|
$ |
1.2631 |
|
|
|
21,000 |
|
|
|
|
|
|
|
|
|
|
| Mt Belvieu Natural Gasoline Swaps |
|
| Production Period Ended December 31, |
|
Average
Fixed Price
(per gallon) |
|
|
Volumes
(bbls)(a) |
|
|
|
|
| 2015(b) |
|
$ |
1.9446 |
|
|
|
70,000 |
|
| (a) |
“mmbtu” represents million metric British thermal units.; “bbl” represents barrel. |
| (b) |
Reflects hedges covering the last six months of 2015. |