PHILADELPHIA, Nov. 10, 2014 /PRNewswire/ --
- Record net daily production of approximately 286.1 million cubic feet equivalents per day for the third quarter 2014, a 9% increase over the second quarter 2014
- Adjusted EBITDA, including discretionary adjustments by the Board of Directors of the General Partner, increased to $107.4 million(1) for the third quarter 2014, an approximate 77% increase from the prior year
- Distributable cash flow, including discretionary adjustments by the Board of Directors of the General Partner, increased to $62.7(1) million for the third quarter 2014, an approximate 66% increase from the prior year
- ARP paid total cash distributions of $0.59 per unit in the third quarter 2014 with a distribution coverage ratio of approximately 1.2x; excluding the effects of the recent Eagle Ford transaction, distribution coverage was 1.0x for the quarter
- ARP provided its initial 2015 financial outlook, including full year distribution guidance of at least $2.40 per unit at approximately 1.1x coverage
- ARP's parent, Atlas Energy, recently agreed to be acquired by Targa Resources Corp.; prior to the closing of the merger with Targa, Atlas Energy will transfer its non-midstream assets, including its interests in ARP, to Atlas Energy Group, LLC and distribute to the Atlas Energy unitholders common units representing a 100% interest in Atlas Energy Group
- Third quarter 2014 financial and operational results will be discussed on a conference call at 9AM ET on Tuesday, November 11th
Atlas Resource Partners, L.P. (NYSE: ARP) ("ARP" or "the Company") has reported operating and financial results for the third quarter 2014.
Matthew A. Jones, President of ARP, stated, "Our solid results this quarter reflect primarily the diversity of our natural gas and oil producing properties."
- Third quarter 2014 Adjusted EBITDA, a non-GAAP measure, including discretionary adjustments by the Board of Directors of the General Partner, was $107.4 million(1), compared to $79.7 million for the second quarter 2014, and $60.7 million for the prior year comparable quarter. The increase from the sequential and prior year quarters was due to the cash flow contribution from recently acquired assets in the Eagle Ford shale in south Texas, the acquisition of the Rangely Field oil and liquids assets in northwest Colorado in June 2014, and the acquisition of the GeoMet natural gas assets in West Virginia in May 2014.
- Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner, a non-GAAP measure, was $62.7 million(1), or approximately $0.72 per common unit, for the third quarter 2014, compared to $50.0 million for the second quarter 2014 and $37.7 million for the prior year comparable quarter. Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner increased due primarily to the increases in cash flow as described above.
- ARP paid monthly cash distributions totaling approximately $0.59 per limited partner unit for the third quarter 2014, an approximate 5% increase over the prior year third quarter distribution. The most recent ARP monthly distribution of $0.1966 per unit ($2.36 per unit on an annual basis) for September 2014 will be paid on November 14, 2014 to holders of record as of November 10, 2014.
- On a GAAP basis, net income was $1.1 million for the third quarter 2014 compared to a net loss of $20.5 million for the second quarter 2014 and a net loss of $39.7 million for the prior year comparable period. The higher level of income in the third quarter 2014 compared to prior quarters was caused principally by higher amounts of non-cash expenses related to acquisitions of oil and natural gas assets in the earlier periods.
2015 Financial Outlook
ARP has provided an initial financial outlook for the full year 2015, which includes expected cash distributions of at least $2.40 per unit with distribution coverage of approximately 1.1x. The following are several of the key assumptions included in the forecast:
- Net production volume per day:
|
|
|
Natural gas (mcfd)
|
221,443
|
|
|
Crude oil (bpd)
|
7,179
|
|
|
NGL (bpd)
|
4,408
|
|
|
Total (mcfed)
|
290,964
|
- Net realized natural gas price after hedges of $3.83/mcf (69% hedged)
- Net realized crude oil price after hedges of $83.35/bbl (68% hedged)
- Total net production costs of $2.08/Mcfe
- Partnership management funds raised of $225.0 million for the year ending December 31, 2014 and $275.0 million for the year ending December 31, 2015
- Total capital expenditures of $200 million for the year ending December 31, 2015, including $71.3 million of maintenance capital expenditures
- ARP's forecast for full year 2015 does not assume any consummated acquisitions or the issuance of limited partner units.
Recent Events
Merger Transaction Between Targa Resources, Atlas Energy and Atlas Pipeline
On October 13, 2014, ARP's parent company, Atlas Energy, L.P. (NYSE: ATLS), and ATLS' midstream subsidiary, Atlas Pipeline Partners, L.P. (NYSE: APL), entered into definitive agreements to be acquired by Targa Resources Corp. ("TRC"; NYSE: TRGP) and Targa Resources Partners LP ("TRP"; NYSE: NGLS), respectively.
Immediately prior to the closing of the acquisition of ATLS by TRC, ATLS will transfer its non-midstream assets to Atlas Energy Group, LLC ("Atlas Energy Group"), a wholly owned subsidiary of ATLS, and then distribute to the ATLS unitholders common units representing a 100% limited liability company interest in Atlas Energy Group. The distribution is subject to the satisfaction of certain conditions, including the effectiveness of the Form 10 registration statement filed by Atlas Energy Group, and the satisfaction or waiver of the conditions to the consummation of the acquisition of ATLS by TRC. The acquisition of ATLS by TRC is subject to, among other conditions, the approval of the acquisition by holders of a majority of the outstanding limited partner interests in ATLS and the approval of a majority of the shareholders of TRC voting at the meeting to approve the transaction. The ATLS transaction is also cross-conditioned on the acquisition of APL by TRP, which is subject to, among other conditions, the approval of the acquisition by holders of a majority of the outstanding limited partner interests in APL.
Acquisition of Eagle Ford Properties
On November 5, 2014, ARP completed a transaction in which it acquired primarily oil assets in the Eagle Ford Shale in south Texas. ARP paid approximately $200 million at closing and will pay an additional $24 million of the deferred portion of the purchase price in three quarterly installments beginning in March 31, 2015. Additionally, the original purchase agreement was amended to allow ARP to pay up to $20 million of its deferred portion of the purchase price by issuing to the seller its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units at a price of $25.00 per unit. The acquired assets consist of 22 producing wells and 19 undeveloped locations containing estimated net reserves of approximately 12 million barrels of oil equivalent.
Issuance of additional $75 million of its 9.25% Senior Notes due 2021
On October 14, 2014, ARP issued an additional $75 million of its 9.25% Senior Notes due 2021 in a private placement transaction issued at 100.5%. ARP used the net proceeds from this offering to fund a portion of its previously announced acquisition of primarily oil assets in the Eagle Ford shale in south Texas. 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 third quarter 2014 was 286.1 million cubic feet equivalents per day ("Mmcfed"), a 29% increase from the prior year comparable quarter and approximately 9% higher than the second quarter 2014. The increase in net production as compared to second quarter 2014 was due primarily to production from the Rangely Field assets, which were acquired on June 30, 2014. The increase in net production compared with the third quarter 2013 was due primarily to the acquisition of the Rangely Field assets, as well as the GeoMet natural gas production assets in May 2014.
- ARP's net realized price for natural gas including the effect of hedge positions was $3.55 per mcf for the third quarter 2014, approximately 6% lower than the second quarter 2014. Net realized oil prices including the effect of hedge positions averaged $90.18 per barrel for the third quarter 2014, relatively consistent with $90.66 per barrel realized during the second quarter 2014.
Hedge Positions
- ARP continued to expand its commodity hedge positions on its existing production during the third quarter 2014. A summary of ARP's derivative positions as of November 10, 2014 is provided in the financial tables of this release.
Corporate Expenses & Capital Position
- Cash general and administrative expense was $9.5 million for the third quarter 2014, $1.0 million lower than the second quarter 2014 and consistent with the prior year third quarter. The decrease compared with the second quarter 2014 was due primarily to lower administrative and marketing costs associated with ARP's 2014 partnership program.
- Cash interest expense was $14.1 million for the third quarter 2014, $2.9 million higher than the second quarter 2014 and $6.2 million higher than the prior year third quarter. The increases were primarily due to higher levels of borrowing used to expand ARP's operations over the prior periods.
- ARP had $1.385 billion of total debt, pro forma for the recent acquisition of oil producing assets in the Eagle Ford shale, including $687 million outstanding under its revolving credit facility. ARP had approximately $209 million available on its revolving credit facility pro forma for the Eagle Ford transaction.
Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Resource Partners, L.P.'s third quarter 2014 results on Tuesday, November 11, 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 November 11, 2014 by dialing 855-859-2056, passcode: 19173828.
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 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 17 gas processing plants, 18 gas treating facilities, as well as approximately 11,200 miles of active intrastate gas gathering pipeline. For more information, visit APL's website at www.atlaspipeline.com or contact IR@atlaspipeline.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. Risks and uncertainties related to the proposed transaction include, among others: the risk that ATLS's or APL's unitholders or TRC's stockholders do not approve the mergers; the risk that the merger agreement is terminated as a result of a competing proposal, the risk that regulatory approvals required for the mergers are not obtained on the proposed terms and schedule or are obtained subject to conditions that are not anticipated; the risk that the other conditions to the closing of the mergers are not satisfied; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the mergers or the distribution; uncertainties as to the timing of the mergers and the distribution; competitive responses to the proposed mergers and the distribution; unexpected costs, charges or expenses resulting from the mergers and the distribution; litigation relating to the merger and the distribution; the outcome of potential litigation or governmental investigations; Atlas Energy Group's ability to operate the assets and businesses it will acquire in connection with the distribution, and the costs of such distribution; the inability to obtain, or delays in obtaining, the expected distributions of cash from the non-midstream assets; and any changes in general economic and/or industry specific conditions; and other risks, assumptions and uncertainties relating to the non-midstream assets and business that will be acquired in connection with the distribution, which are included in the Form 10 and are detailed from time to time in ATLS', ARP's and APL's reports filed with the U.S. Securities and Exchange Commission, including quarterly reports on Form 10-Q, current reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and we assume no obligation to update such statements, except as may be required by applicable law.
(1) A reconciliation of GAAP net loss to Adjusted EBITDA and Distributable Cash Flow is provided in the financial tables of this release. Please see footnote 8 to the Financial Information table of this release.
|
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except per unit data)
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
September 30,
|
|
September 30,
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Gas and oil production
|
$ 125,394
|
|
$ 80,332
|
|
$ 325,696
|
|
$ 173,490
|
|
Well construction and completion
|
61,204
|
|
10,964
|
|
126,917
|
|
92,293
|
|
Gathering and processing
|
3,061
|
|
3,591
|
|
11,287
|
|
11,639
|
|
Administration and oversight
|
6,177
|
|
4,447
|
|
12,072
|
|
8,923
|
|
Well services
|
6,597
|
|
5,023
|
|
18,441
|
|
14,703
|
|
Other, net
|
261
|
|
(13,272)
|
|
343
|
|
(14,589)
|
|
Total revenues
|
202,694
|
|
91,085
|
|
494,756
|
|
286,459
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
Gas and oil production
|
49,922
|
|
29,419
|
|
128,477
|
|
63,670
|
|
Well construction and completion
|
53,221
|
|
9,534
|
|
110,363
|
|
80,255
|
|
Gathering and processing
|
3,214
|
|
4,395
|
|
11,900
|
|
13,767
|
|
Well services
|
2,617
|
|
2,386
|
|
7,525
|
|
7,009
|
|
General and administrative
|
13,124
|
|
31,983
|
|
50,894
|
|
63,767
|
|
Depreciation, depletion and amortization
|
62,852
|
|
41,656
|
|
171,090
|
|
85,061
|
|
Total costs and expenses
|
184,950
|
|
119,373
|
|
480,249
|
|
313,529
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
17,744
|
|
(28,288)
|
|
14,507
|
|
(27,070)
|
|
|
|
|
|
|
|
|
|
Loss on asset sales and disposal
|
(92)
|
|
(661)
|
|
(1,686)
|
|
(2,035)
|
|
Interest expense
|
(16,577)
|
|
(10,748)
|
|
(43,028)
|
|
(22,145)
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
1,075
|
|
(39,697)
|
|
(30,207)
|
|
(51,250)
|
|
|
|
|
|
|
|
|
|
Preferred limited partner dividends
|
(4,475)
|
|
(3,564)
|
|
(13,298)
|
|
(7,592)
|
|
Net loss attributable to common limited partners and the general partner
|
$ (3,400)
|
|
$ (43,261)
|
|
$ (43,505)
|
|
$ (58,842)
|
|
|
|
|
|
|
|
|
|
Allocation of net loss attributable to common limited partners and the general partner:
|
|
General partner's interest
|
$ 2,993
|
|
$ 812
|
|
$ 7,374
|
|
$ 2,135
|
|
Common limited partners' interest
|
(6,393)
|
|
(44,073)
|
|
(50,879)
|
|
(60,977)
|
|
Net loss attributable to common limited partners and the general partner
|
$ (3,400)
|
|
$ (43,261)
|
|
$ (43,505)
|
|
$ (58,842)
|
|
|
|
|
|
|
|
|
|
Net loss attributable to common limited partners per unit:
|
|
Basic and Diluted
|
$ (0.08)
|
|
$ (0.74)
|
|
$ (0.70)
|
|
$ (1.21)
|
|
|
|
|
|
|
|
|
|
Weighted average common limited partner units outstanding:
|
|
Basic and Diluted
|
81,522
|
|
59,440
|
|
72,288
|
|
50,197
|
|
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands)
|
|
|
|
September 30,
|
|
December 31,
|
|
ASSETS
|
|
2014
|
|
2013
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ 5,167
|
|
$ 1,828
|
|
Accounts receivable
|
|
99,656
|
|
58,822
|
|
Current portion of derivative asset
|
|
21,050
|
|
1,891
|
|
Subscriptions receivable
|
|
62,840
|
|
47,692
|
|
Prepaid expenses and other
|
|
24,783
|
|
10,097
|
|
Total current assets
|
|
213,496
|
|
120,330
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
2,657,060
|
|
2,120,818
|
|
Goodwill and intangible assets, net
|
|
32,543
|
|
32,747
|
|
Long-term derivative asset
|
|
30,826
|
|
27,084
|
|
Other assets, net
|
|
52,477
|
|
42,821
|
|
|
$ 2,986,402
|
|
$ 2,343,800
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS' CAPITAL
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$ 104,275
|
|
$ 69,346
|
|
Advances from affiliates
|
|
26,342
|
|
26,742
|
|
Liabilities associated with drilling contracts
|
|
—
|
|
49,377
|
|
Current portion of derivative liability
|
|
1,792
|
|
6,353
|
|
Accrued well drilling and completion costs
|
|
100,226
|
|
40,481
|
|
Distribution payable
|
|
18,901
|
|
—
|
|
Accrued liabilities
|
|
34,997
|
|
51,416
|
|
Total current liabilities
|
|
286,533
|
|
243,715
|
|
|
|
|
|
|
Long-term debt
|
|
1,283,022
|
|
942,334
|
|
Asset retirement obligations and other
|
|
103,219
|
|
90,460
|
|
|
|
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
Partners' Capital:
|
|
|
|
|
|
General partner's interest
|
|
(890)
|
|
4,482
|
|
Preferred limited partners' interests
|
|
180,568
|
|
183,477
|
|
Common limited partners' interests
|
|
1,079,476
|
|
852,457
|
|
Class C common limited partner warrants
|
|
1,176
|
|
1,176
|
|
Accumulated other comprehensive income
|
|
53,298
|
|
25,699
|
|
Total partners' capital
|
|
1,313,628
|
|
1,067,291
|
|
|
$ 2,986,402
|
|
$ 2,343,800
|
|
ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
(unaudited)
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
September 30,
|
|
September 30,
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
|
|
|
|
|
|
|
|
Net loss attributable to common limited partners per unit - basic
|
$ (0.08)
|
|
$ (0.74)
|
|
$ (0.70)
|
|
$ (1.21)
|
|
|
|
|
|
|
|
|
|
Cash distributions paid per unit(1)
|
$ 0.590
|
|
$ 0.560
|
|
$ 1.753
|
|
$ 1.610
|
|
|
|
|
|
|
|
|
|
Production revenues (in thousands):
|
|
|
|
|
|
|
|
|
Natural gas
|
$ 75,246
|
|
$ 57,350
|
|
$ 227,036
|
|
$ 114,789
|
|
Oil
|
38,151
|
|
12,993
|
|
67,626
|
|
32,394
|
|
Natural gas liquids
|
11,997
|
|
9,989
|
|
31,034
|
|
26,307
|
|
Total production revenues
|
$ 125,394
|
|
$ 80,332
|
|
$ 325,696
|
|
$ 173,490
|
|
|
|
|
|
|
|
|
|
Production volume:(2)(3)
|
|
|
|
|
|
|
|
|
Appalachia: (4)
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
38,218
|
|
38,594
|
|
39,083
|
|
33,651
|
|
Oil (Bpd)
|
367
|
|
312
|
|
390
|
|
291
|
|
Natural gas liquids (Bpd)
|
46
|
|
12
|
|
40
|
|
5
|
|
Total (Mcfed)
|
40,693
|
|
40,541
|
|
41,661
|
|
35,428
|
|
Coal-bed Methane: (4)(5)
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
128,444
|
|
115,354
|
|
118,833
|
|
25,775
|
|
Oil (Bpd)
|
—
|
|
—
|
|
—
|
|
—
|
|
Natural gas liquids (Bpd)
|
—
|
|
—
|
|
—
|
|
—
|
|
Total (Mcfed)
|
128,444
|
|
115,354
|
|
118,833
|
|
25,775
|
|
Barnett/Marble Falls:
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
57,726
|
|
66,145
|
|
58,445
|
|
66,208
|
|
Oil (Bpd)
|
1,273
|
|
899
|
|
1,114
|
|
847
|
|
Natural gas liquids (Bpd)
|
2,861
|
|
2,961
|
|
2,732
|
|
2,757
|
|
Total (Mcfed)
|
82,535
|
|
89,306
|
|
81,523
|
|
87,834
|
|
Rangely: (4)
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
—
|
|
—
|
|
—
|
|
—
|
|
Oil (Bpd)
|
2,567
|
|
—
|
|
865
|
|
—
|
|
Natural gas liquids (Bpd)
|
263
|
|
—
|
|
89
|
|
—
|
|
Total (Mcfed)
|
16,978
|
|
—
|
|
5,721
|
|
—
|
|
Mississippi Lime/Hunton:
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
6,679
|
|
5,475
|
|
6,295
|
|
4,739
|
|
Oil (Bpd)
|
366
|
|
285
|
|
368
|
|
144
|
|
Natural gas liquids (Bpd)
|
545
|
|
366
|
|
524
|
|
285
|
|
Total (Mcfed)
|
12,145
|
|
9,382
|
|
11,651
|
|
7,315
|
|
Other Operating Areas:(4)
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
3,195
|
|
4,321
|
|
3,287
|
|
4,571
|
|
Oil (Bpd)
|
25
|
|
21
|
|
24
|
|
19
|
|
Natural gas liquids (Bpd)
|
334
|
|
395
|
|
337
|
|
394
|
|
Total (Mcfed)
|
5,349
|
|
6,815
|
|
5,453
|
|
7,044
|
|
Total Production:(3)
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
234,263
|
|
191,020
|
|
225,943
|
|
134,945
|
|
Oil (Bpd)
|
4,598
|
|
1,517
|
|
2,761
|
|
1,301
|
|
Natural gas liquids (Bpd)
|
4,048
|
|
3,734
|
|
3,722
|
|
3,441
|
|
Total (Mcfed)
|
286,143
|
|
222,529
|
|
264,843
|
|
163,397
|
|
|
|
|
|
|
|
|
|
Average sales prices: (3)
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) (6)
|
$ 3.55
|
|
$ 3.46
|
|
$ 3.79
|
|
$ 3.39
|
|
Oil (per Bbl)(7)
|
$ 90.18
|
|
$ 93.07
|
|
$ 89.71
|
|
$ 91.19
|
|
Natural gas liquids (per Bbl) (8)
|
$ 32.21
|
|
$ 29.08
|
|
$ 30.54
|
|
$ 28.01
|
|
|
|
|
|
|
|
|
|
Production costs:(3)(9)
|
|
|
|
|
|
|
|
|
Lease operating expenses per Mcfe
|
$ 1.39
|
|
$ 1.15
|
|
$ 1.27
|
|
$ 1.12
|
|
Production taxes per Mcfe
|
0.30
|
|
0.11
|
|
0.27
|
|
0.17
|
|
Transportation and compression expenses per Mcfe
|
0.22
|
|
0.24
|
|
0.26
|
|
0.22
|
|
Total production costs per Mcfe
|
$ 1.91
|
|
$ 1.50
|
|
$ 1.80
|
|
$ 1.51
|
|
|
|
|
|
|
|
|
|
Depletion per Mcfe(3)
|
$ 2.28
|
|
$ 1.95
|
|
$ 2.26
|
|
$ 1.80
|
|
|
|
|
|
|
|
|
|
(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; Coal-bed methane includes ARP's production located in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama, the Cedar Bluff area of West Virginia and Virginia, and the County Line area of Wyoming; Rangely includes ARP's 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado; Other operating areas include ARP's production located in the Chattanooga, New Albany/Antrim and Niobrara Shales.
|
|
|
|
(5)
|
Volumetric production per day for coal-bed methane for the three months ended September 30, 2013 includes production per day for the 61-day period from August 1, 2013, the date ARP began recognizing production from the assets following the completion of the EP Energy Acquisition, through September 30, 2013. Total coal-bed methane production per day for the nine months ended September 30, 2013 represents volume production for the full 273-day period. Total production per day represents total production volume over the 92 and 273 days within the three and nine months ended September 30, 2014, respectively.
|
|
|
|
(6)
|
ARP's average sales prices for natural gas before the effects of financial hedging were $3.47 per Mcf and $3.20 per Mcf for the three months ended September 30, 2014 and 2013, respectively, and $4.07 per Mcf and $3.19 per Mcf for the nine months ended September 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 $3.49 per Mcf ($3.41 per Mcf before the effects of financial hedging) and $3.26 per Mcf ($3.01 per Mcf before the effects of financial hedging) for the three months ended September 30, 2014 and 2013, respectively, and $3.68 per Mcf ($3.96 per Mcf before the effects of financial hedging) and $3.12 per Mcf ($2.92 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2014 and 2013, respectively.
|
|
|
|
(7)
|
ARP's average sales prices for oil before the effects of financial hedging were $91.08 per barrel and $104.03 per barrel for the three months ended September 30, 2014 and 2013, respectively, and $93.45 per barrel and $96.50 per barrel for the nine months ended September 30, 2014 and 2013, respectively.
|
|
|
|
(8)
|
ARP's average sales prices for natural gas liquids before the effects of financial hedging were $32.18 per barrel and $30.10 per barrel for the three months ended September 30, 2014 and 2013, respectively, and $32.16 per barrel and $28.52 per barrel for the nine months ended September 30, 2014 and 2013, respectively.
|
|
|
|
(9)
|
Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, production overhead and transportation expenses. These amounts exclude the effects of ARP's proportionate share of lease operating expenses associated with subordination of production revenue to investor partners within ARP's investor partnerships. Including the effects of these costs, lease operating expenses per Mcfe were $1.37 per Mcfe ($1.90 per Mcfe for total production costs) and $1.09 per Mcfe ($1.44 per Mcfe for total production costs) for the three months ended September 30, 2014 and 2013, respectively, and $1.25 per Mcfe ($1.78 per Mcfe for total production costs) and $1.04 per Mcfe ($1.43 per Mcfe for total production costs) for the nine months ended September 30, 2014 and 2013, respectively.
|
|
ATLAS RESOURCE PARTNERS, L.P.
CAPITALIZATION INFORMATION
(unaudited; in thousands)
|
|
|
September 30,
2014
|
|
December 31,
2013
|
|
Total debt
|
$ 1,283,022
|
|
$ 942,334
|
|
Less: Cash
|
(5,167)
|
|
(1,828)
|
|
Total net debt/(cash)
|
1,277,855
|
|
940,506
|
|
|
|
|
|
Partners' capital
|
1,313,628
|
|
1,067,291
|
|
|
|
|
|
Total capitalization
|
$ 2,591,483
|
|
$ 2,007,797
|
|
|
|
|
|
Ratio of net debt to capitalization
|
0.49x
|
|
0.47x
|
|
ATLAS RESOURCE PARTNERS, L.P.
CAPITAL EXPENDITURE DATA
(unaudited; in thousands)
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
September 30,
|
|
September 30,
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Maintenance capital expenditures(1)
|
$ 22,400
|
|
$ 10,000
|
|
$ 46,300
|
|
$ 21,000
|
|
Expansion capital expenditures
|
33,530
|
|
63,944
|
|
104,185
|
|
182,996
|
|
Total
|
$ 55,930
|
|
$ 73,944
|
|
$ 150,485
|
|
$ 203,996
|
|
|
|
|
|
|
|
|
|
(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
|
|
Nine Months Ended
|
|
September 30,
|
|
September 30,
|
|
Reconciliation of net income (loss) to non-GAAP measures(1):
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Net income (loss)
|
$ 1,075
|
|
$ (39,697)
|
|
$ (30,207)
|
|
$ (51,250)
|
|
Acquisition and related costs
|
1,595
|
|
19,417
|
|
12,765
|
|
25,897
|
|
Depreciation, depletion and amortization
|
62,852
|
|
41,656
|
|
171,090
|
|
85,061
|
|
Amortization of deferred finance costs
|
2,436
|
|
2,847
|
|
6,290
|
|
8,642
|
|
Non-cash stock compensation expense
|
1,988
|
|
2,959
|
|
6,342
|
|
10,208
|
|
Maintenance capital expenditures(2)
|
(13,100)
|
|
(9,167)
|
|
(34,250)
|
|
(17,667)
|
|
Preferred unit distribution
|
(4,475)
|
|
(4,248)
|
|
(13,298)
|
|
(8,277)
|
|
Loss on asset sales and disposal
|
92
|
|
661
|
|
1,686
|
|
2,035
|
|
Premiums paid on swaption derivative contracts associated with asset acquisitions(3)
|
−
|
|
13,308
|
|
−
|
|
14,617
|
|
Other
|
(18)
|
|
−
|
|
(16)
|
|
−
|
|
Distributable cash flow attributable to limited partners and the general partner(1)
|
$ 52,445
|
|
$ 27,736
|
|
$ 120,402
|
|
$ 69,266
|
|
|
|
|
|
|
|
|
|
Supplemental Adjusted EBITDA and Distributable Cash Flow Summary:
|
|
|
|
|
|
Gas and oil production margin
|
$ 75,472
|
|
$ 50,913
|
|
$ 197,219
|
|
$ 109,820
|
|
Well construction and completion margin
|
7,983
|
|
1,430
|
|
16,554
|
|
12,038
|
|
Administration and oversight margin
|
6,177
|
|
4,447
|
|
12,072
|
|
8,923
|
|
Well services margin
|
3,980
|
|
2,637
|
|
10,916
|
|
7,694
|
|
Gathering and processing margin
|
(153)
|
|
(804)
|
|
(613)
|
|
(2,128)
|
|
Cash general and administrative expenses(4)
|
(9,541)
|
|
(9,607)
|
|
(31,787)
|
|
(27,662)
|
|
Other, net
|
243
|
|
36
|
|
327
|
|
28
|
|
Adjusted EBITDA(1)
|
84,161
|
|
49,052
|
|
204,688
|
|
108,713
|
|
Cash interest expense(5)
|
(14,141)
|
|
(7,901)
|
|
(36,738)
|
|
(13,503)
|
|
Preferred unit distribution
|
(4,475)
|
|
(4,248)
|
|
(13,298)
|
|
(8,277)
|
|
Maintenance capital expenditures(2)
|
(13,100)
|
|
(9,167)
|
|
(34,250)
|
|
(17,667)
|
|
Distributable Cash Flow attributable to limited partners and the general partner(1)
|
$ 52,445
|
|
$ 27,736
|
|
$ 120,402
|
|
$ 69,266
|
|
|
|
|
|
|
|
|
|
Discretionary adjustments considered by the Board of Directors of the General Partner in the determination of quarterly cash distributions:
|
|
|
|
|
|
Net cash from acquisitions from the effective date through closing date(6)
|
10,214
|
|
5,244
|
|
30,202
|
|
25,791
|
|
Well construction and completion margin earned(7)
|
—
|
|
4,760
|
|
—
|
|
4,760
|
|
Distributable Cash Flow with discretionary adjustments by the Board of Directors of the General Partner(8)
|
$ 62,659
|
|
$ 37,740
|
|
$ 150,604
|
|
$ 99,817
|
|
|
|
|
|
|
|
|
|
Distributions Paid(9)
|
$ 52,225
|
|
$ 35,733
|
|
$ 145,011
|
|
$ 93,083
|
|
per limited partner unit
|
$ 0.590
|
|
$ 0.560
|
|
$ 1.753
|
|
$ 1.610
|
|
|
|
|
|
|
|
|
|
Excess of distributable cash flow with discretionary adjustments by the Board of Directors of the General Partner after distributions to unitholders(10)
|
$ 10,434
|
|
$ 2,007
|
|
$ 5,593
|
|
$ 6,734
|
|
|
|
|
|
|
|
|
|
(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 3rd quarter 2014, such amounts include net cash generated by the Eagle Ford assets from July 1, 2014 to September 30, 2014 of $23.2 million, less pro forma interest expense of $2.0 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $9.3 million. For the 3rd quarter 2013, such amounts include pro forma net cash generated by the EP Energy assets from July 1, 2013 to July 31, 2013 of $6.9 million, less pro forma interest expense of $0.8 million and estimated maintenance capital expenditures of $0.8 million. For the nine months ended September 30, 2014, such amounts include net cash generated by the GeoMet assets from January 1, 2014 to May 11, 2014, the Rangely assets from April 1, 2014 to June 30, 2014, and the Eagle Ford assets from July 1, 2014 to September 30, 2014 of $46.3 million, less pro forma interest expense of $2.4 million, pro-forma preferred unit cash distributions of $1.7 million, and estimated maintenance capital expenditures of $12.0 million. For the nine months ended September 30, 2013, such amounts include pro forma net cash generated by the EP Energy assets from April 1, 2013 to July 31, 2013 of $32.4 million, less pro forma interest expense of $3.3 million and estimated maintenance capital expenditures of $3.3 million.
|
|
|
|
(7)
|
This amount reflects well construction and completion margin from the deployment of capital for the investment partnership programs during the 3rd quarter 2013 for which ARP was required to defer recognition under GAAP until additional investor funds were received. Under ARP's annual investment partnership programs, investor funds must be received by the particular investment partnership by December 31st of that calendar year to be eligible for an investment in that program.
|
|
|
|
(8)
|
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 $107.4 million and $60.7 million for the three months ended September 30, 2014 and 2013, respectively, and $251.1 million and $145.9 million for the nine months ended September 30, 2014 and 2013, respectively.
|
|
|
|
(9)
|
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.
|
|
|
|
(10)
|
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 November 10, 2014)
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
Fixed Price Swaps
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Production Period
|
|
Fixed Price
|
|
Volumes
|
|
|
|
Ended December 31,
|
|
(per mmbtu)(a)
|
|
(mmbtus)(a)
|
|
|
|
|
|
|
|
|
|
|
2014(b)
|
|
$ 4.15
|
|
15,038,244
|
|
|
|
2015
|
|
$ 4.24
|
|
52,584,492
|
|
|
|
2016
|
|
$ 4.31
|
|
45,746,320
|
|
|
|
2017
|
|
$ 4.37
|
|
35,640,000
|
|
|
|
2018
|
|
$ 4.38
|
|
18,960,000
|
|
|
|
|
|
|
|
|
|
|
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
|
|
960,000
|
|
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
|
|
450,000
|
|
|
|
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)
|
|
2,700,000
|
|
|
|
2015
|
|
$ (0.0675)
|
|
3,000,000
|
|
|
|
|
|
|
|
|
|
|
NGPL Basis Swaps
|
|
|
|
|
|
|
|
|
Average
|
|
Average
|
|
|
|
Production Period
|
|
Fixed Price
|
|
Volumes
|
|
|
|
Ended December 31,
|
|
(per mmbtu)(a)
|
|
(mmbtus)(a)
|
|
|
|
|
|
|
|
|
|
|
2014(b)
|
|
$ (0.1080)
|
|
2,250,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
15,000
|
|
|
|
|
|
|
|
|
|
|
Mt Belvieu Propane Swaps
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Production Period
|
|
Fixed Price
|
|
Volumes
|
|
|
|
Ended December 31,
|
|
(per gallon)
|
|
(bbls)(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014(b)
|
|
$ 0.9996
|
|
73,500
|
|
|
|
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
|
|
9,000
|
|
|
|
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
|
|
9,000
|
|
|
|
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
|
|
33,000
|
|
|
|
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)
|
|
$ 95.09
|
|
439,500
|
|
|
|
2015
|
|
$ 90.65
|
|
1,743,000
|
|
|
|
2016
|
|
$ 87.36
|
|
1,209,000
|
|
|
|
2017
|
|
$ 85.67
|
|
672,000
|
|
|
|
2018
|
|
$ 85.47
|
|
540,000
|
|
|
|
|
|
|
|
|
|
|
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
|
|
10,290
|
|
2015
|
|
$ 83.85
|
|
$ 110.65
|
|
29,250
|
_______________________________________________________________
|
(a)
|
"mmbtu" represents million metric British thermal units.; "bbl" represents barrel.
|
|
(b)
|
Reflects hedges covering the last three months of 2014.
|
SOURCE Atlas Resource Partners, L.P.