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Atlas Resource Partners, L.P. Reports Operating And Financial Results For The Third Quarter 2012

Recent Events

Acquisition of Mississippi Lime Acreage from Equal Energy

On September 24, 2012, ARP entered into and simultaneously closed an agreement with Equal Energy, Ltd. (“Equal”) (NYSE: EQU; TSX: EQU) to acquire the following for approximately $40 million: the remaining 50% interest in Equal’s approximately 8,500 net undeveloped acres in the core of the oil & liquids rich Mississippi Lime play in northwestern Oklahoma, approximately 8 Mmcfe/d of net production in the Mississippi Lime region and substantial salt water disposal infrastructure. This transaction increases ARP’s position in the Mississippi Lime to approximately 20,000 net acres. The acreage position ARP has acquired in the Mississippi Lime is located in Alfalfa, Garfield and Grant Counties, Oklahoma and is almost entirely held by existing production. ARP will be able to increase its drilling activity in the play at its discretion going forward, and ARP intends to activate a second rig in the Mississippi Lime by the end of 2012. ARP financed this transaction with available borrowings under its revolving credit facility.

E&P Operations

  • Average net daily production for the third quarter 2012 was 96.3 Mmcfed, an increase of approximately 33.7 Mmcfed, or 54%, compared with the second quarter 2012. The increase was primarily due to the acquisition of Titan Operating, LLC (“Titan”) in the Barnett Shale in July 2012, a full quarter’s volume from the Partnership’s initial acquisition in the Barnett Shale in April 2012, and additional legacy Marcellus Shale wells connected in southwestern Pennsylvania during the quarter.
  • During the third quarter 2012, ARP continued drilling on initial locations in the oil & natural gas liquids (NGL) rich Mississippi Lime basin in northwestern Oklahoma. Two wells in ARP’s recently expanded Mississippi Lime position have been completed and are currently producing into a sales line, and one well is awaiting completion. ARP also drilled six wells this quarter in Hood County, Texas in the wet gas window of its Barnett Shale position. An additional two wells in the wet gas region of Tarrant County, Texas were also turned into line.

Hedge Positions

  • ARP expanded its natural gas and oil hedge positions during the third quarter 2012. ARP currently has approximately 86.8 billion cubic feet equivalents of its future production hedged through 2017. A summary of ARP’s current derivative positions as of October 31, 2012 is provided in the financial tables of this release.

Corporate Expenses

  • Cash general and administrative expense was $9.0 million for the third quarter 2012, a $4.2 million increase from $4.8 million for the prior year third quarter and an increase of $0.2 million from the second quarter 2012. The increase from prior year third quarter was principally due to approximately $6.2 million of fees recognized in the prior year related to the transition service agreement with Chevron, which expired in the fourth quarter 2011.
  • Cash interest expense was $0.9 million for the third quarter 2012. As of September 30, 2012, ARP had $222.0 million outstanding under its revolving credit facility, which has a current borrowing base of $310 million, and a cash position of $24.3 million.

Interested parties are invited to access the live webcast of an investor call with management regarding Atlas Resource Partners, L.P.’s third quarter 2012 results on Thursday, November 1, 2012 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 11:00 a.m. ET on November 1, 2012 by dialing 888-286-8010, passcode: 31065841.

Atlas Resource Partners, L.P. (NYSE: ARP) is an exploration & production master limited partnership which owns an interest in over 9,900 producing natural gas and oil wells, primarily in Appalachia and the Barnett Shale in Texas. 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 52% 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 11% 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 the midcontinent region of Oklahoma, southern Kansas, and northern and western Texas, APL owns and operates nine active gas processing plants as well as approximately 9,700 miles of active intrastate gas gathering pipeline. APL also has a 20% interest in West Texas LPG Pipeline Limited Partnership, which is operated by Chevron Corporation. For more information, visit the Partnership's website at www.atlaspipeline.com or contact IR@atlaspipeline.com.

Cautionary Note Regarding Forward-Looking Statements

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; 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, reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and ARP assumes no obligation to update such statements, except as may be required by applicable law.

 
ATLAS RESOURCE PARTNERS, L.P.
CONSOLIDATED COMBINED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except per unit data)

 
Three Months Ended Nine Months Ended
September 30, September 30,
  2012       2011     2012       2011  
Revenues:
Gas and oil production $ 24,699 $ 16,305 $ 61,323 $ 51,654
Well construction and completion 36,317 35,657 92,277 64,336
Gathering and processing 4,134 4,431 10,311 14,048
Administration and oversight 4,440 2,337 8,586 5,073
Well services 5,086 4,910 15,344 15,051
Other, net   67     (50 )   (4,952 )   (115 )
Total revenues   74,743     63,590     182,889     150,047  
 
Costs and expenses:
Gas and oil production 7,295 3,990 16,247 11,953
Well construction and completion 31,581 30,449 79,882 54,754
Gathering and processing 4,558 4,880 13,185 16,377
Well services 2,232 2,043 7,076 6,077
General and administrative 16,147 4,757 48,427 12,275

Estimated expense on Chevron transaction

7,670 7,670
Depreciation, depletion and amortization   13,918     8,071     33,848     24,019  
Total costs and expenses   83,401     54,190     206,335     125,455  
 
Operating income (loss) (8,658 ) 9,400 (23,446 ) 24,592
 
Gain (loss) on asset sales and disposal 2 (7,019 ) 48
Interest expense   (1,423 )       (2,529 )    
 
Net income (loss) (10,079 ) 9,400 (32,994 ) 24,640
 
Preferred limited partner dividends   (1,221 )       (1,221 )    
Net income (loss) attributable to owner’s interest, common limited partners and the general partner

$

(11,300

)

$

9,400

 

$

(34,215

)

$

24,640

 
 
Allocation of net income (loss):
Portion applicable to owner’s interest (period prior to the transfer of assets on March 5, 2012)

$

$ 9,400

$

250

$ 24,640

Portion applicable to common limited partners and general partner’s interests (period subsequent to the transfer of assets on March 5, 2012)

 

 

(11,300

 

)

     

 

(34,465

 

)

   
Net income (loss) attributable to owner’s interest, common limited partners and the general partner $ (11,300 ) $ 9,400   $ (34,215 ) $ 24,640  
 
Allocation of net loss attributable to common limited partners and the general partner:
General partner’s interest $ (226 ) $ $ (689 ) $
Common limited partners’ interest   (11,074 )       (33,776 )    
Net loss attributable to common limited partners and the general partner $ (11,300 )

$

  $ (34,465 )

$

 
 
Net loss attributable to common limited partners per unit:
Basic $ (0.32 ) $   $ (1.06 ) $  
Diluted $ (0.32 ) $   $ (1.06 ) $  
 
Weighted average common limited partner units outstanding:
Basic   35,068         31,865      
Diluted   35,068         31,865      
 
 

ATLAS RESOURCE PARTNERS, L.P.

CONSOLIDATED COMBINED BALANCE SHEETS

(unaudited; in thousands)
   

September 30,

December 31,

ASSETS

 

2012

 

2011

Current assets:

Cash and cash equivalents $ 24,266 $ 54,708
Accounts receivable 29,743 19,319
Current portion of derivative asset 6,518 13,801
Subscriptions receivable 8,495 34,455
Prepaid expenses and other   7,107   7,677
Total current assets 76,129 129,960
 

Property, plant and equipment, net

1,016,110 520,883

Goodwill and intangible assets, net

33,149 33,285

Long-term derivative asset

5,144 16,128

Other assets, net

  8,410   857
$ 1,138,942 $ 701,113
 

LIABILITIES AND PARTNERS’ CAPITAL/EQUITY

 

Current liabilities:

Accounts payable $ 42,831 $ 36,731
Liabilities associated with drilling contracts 5,550 71,719
Current portion of derivative liability 280
Current portion of derivative payable to Drilling Partnerships 13,363 20,900
Accrued well drilling and completion costs 50,169 17,585
Accrued liabilities   33,039   35,952
Total current liabilities 145,232 182,887
 

Long-term debt

222,000

Long-term derivative liability

4,051

Long-term derivative payable to Drilling Partnerships

4,483 15,272

Asset retirement obligations and other

54,428 45,779
 

Commitments and contingencies

 

Partners’ Capital/Equity:

General partner’s interest 7,646
Preferred limited partners’ interests 96,110
Common limited partners’ interests 596,348
Equity 427,246
Accumulated other comprehensive income   8,644   29,929
Total partners’ capital/equity   708,748   457,175
$ 1,138,942 $ 701,113
 
 
ATLAS RESOURCE PARTNERS, L.P.
Financial and Operating Highlights
   
Three Months Ended Nine Months Ended
September 30, September 30,
  2012       2011     2012       2011  
 
Net loss attributable to common limited partners per unit - basic $ (0.32 ) $ $ (1.06 ) $
 
Distributable cash flow per unit (1)(2) $ 0.45 $ $ 1.03 $
 
Cash distributions paid per unit (3) $ 0.43 $ $ 0.95 $
 
Production revenues (in thousands):
Natural gas $ 19,945 $ 12,189 $ 47,789 $ 38,383
Oil 2,239 2,255 7,619 7,341
Natural gas liquids   2,515     1,861   5,915     5,930  
Total production revenues $ 24,699   $ 16,305 $ 61,323   $ 51,654  
 
Production volume: (4)(5)

Appalachia : (6)

Natural gas (Mcfd) 39,583 27,088 35,260 28,166
Oil (Bpd) 275 294 290 297
Natural gas liquids (Bpd)   414     408   422     448  
Total (Mcfed)   43,716     31,304   39,533     32,637  

Barnett : (7)

Natural gas (Mcfd) 49,440 21,278
Oil (Bpd) 2 1
Natural gas liquids (Bpd)   865       230      
Total (Mcfed)   54,642       22,663      

Mississippi Lime (8) :

Natural gas (Mcfd) 7,391 216
Oil (Bpd)
Natural gas liquids (Bpd)              
Total (Mcfed)   7,391       216      

New Albany/Antrim :

Natural gas (Mcfd) 3,111 3,081 3,054 3,172
Oil (Bpd)
Natural gas liquids (Bpd)              
Total (Mcfed)   3,111     3,081   3,054     3,172  

Niobrara :

Natural gas (Mcfd) 792 461 723 (349 )
Oil (Bpd)
Natural gas liquids (Bpd)              
Total (Mcfed)   792     461   723     (349 )

Total (7)(8) :

Natural gas (Mcfd) 88,208 30,629 60,531 31,687
Oil (Bpd) 277 294 291 297
Natural gas liquids (Bpd)   1,067     408   652     448  
Total (Mcfed)   96,275     34,845   66,189     36,158  
 
Average sales prices: (5)
Natural gas (per Mcf) (9) $ 3.01 $ 5.10 $ 3.42 $ 5.24
Oil (per Bbl) (10) $ 87.86 $ 83.34 $ 95.70 $ 90.65
Natural gas liquids (per Bbl) $ 25.61 $ 49.52 $ 33.09 $ 48.43
 
Production costs: (5)(11)
Lease operating expenses per Mcfe (12) $ 0.75 $ 1.12 $ 0.80 $ 1.05
Production taxes per Mcfe   0.13     0.11   0.12     0.10  
Total production costs per Mcfe (12) $ 0.88 $ 1.23 $ 0.92 $ 1.15
 
Depletion per Mcfe (5) $ 1.42 $ 2.15 $ 1.64 $ 2.09
 

(1)

  A reconciliation from net income to distributable cash flow is provided in the financial tables of this release.
 
(2) Calculation consists of distributable cash flow divided by 40,726,017 and 35,466,019 limited partner and Class A general partner units for the three and nine months ended September 30, 2012, respectively, which represent the weighted average limited partner and Class A general partner units which were paid cash distributions for the respective period subsequent to March 5, 2012, the date of the transfer of assets. Prior to March 5, 2012, no limited partner or Class A general partner units were outstanding.
 
(3) Represents the cash distributions declared per limited partner unit for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter. The cash distribution declared of $0.12 per limited partner unit for the 1 st quarter 2012 reflects a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.
 
(4) 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.
 
(5) “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.
 
(6) Appalachia consists of ARP’s production located in Pennsylvania, Ohio, New York, West Virginia and Tennessee.
 
(7) Volumetric production per day for Barnett for the three months ended September 30, 2012 includes production per day associated with the Titan operational assets for the 68-day period from July 25, 2012, the date of acquisition, through September 30, 2012. Total Barnett production per day for the nine months ended September 30, 2012 represents Barnett volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.
 
(8) Volumetric production per day for Mississippi Lime for the three months ended September 30, 2012 includes production per day associated with the acquisition of the remaining 50% interest in Equal’s operational assets for the 7-day period from September 24, 2012, the date of acquisition, through September 30, 2012. Total Mississippi Lime production per day for the nine months ended September 30, 2012 represents volume production for the full 274-day period. Total production per day represents total production volume over the 92 and 274 days within the three and nine months ended September 30, 2012, respectively.
 
(9) ARP’s average sales prices for natural gas before the effects of financial hedging were $2.46 per Mcf and $4.90 per Mcf for the three months ended September 30, 2012 and 2011, respectively, and $2.60 per Mcf and $4.69 per Mcf for the nine months ended September 30, 2012 and 2011, 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 $2.46 per Mcf ($1.91 per Mcf before the effects of financial hedging) and $4.33 per Mcf ($4.13 per Mcf before the effects of financial hedging) for the three months ended September 30, 2012 and 2011, respectively, and $2.88 per Mcf ($2.07 per Mcf before the effects of financial hedging) and $4.44 per Mcf ($3.89 per Mcf before the effects of financial hedging) for the nine months ended September 30, 2012 and 2011, respectively.
 
(10) ARP’s average sales prices for oil before the effects of financial hedging were $84.30 per barrel and $81.85 per barrel for the three months ended September 30, 2012 and 2011, respectively, and $93.38 per barrel and $89.79 per barrel for the nine months ended September 30, 2012 and 2011, respectively.
 
(11) Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead. 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 $0.45 per Mcfe ($0.58 per Mcfe for total production costs) and $0.73 per Mcfe ($0.84 per Mcfe for total production costs) for the three months ended September 30, 2012 and 2011, respectively, and $0.51 per Mcfe ($0.63 per Mcfe for total production costs) and $0.71 per Mcfe ($0.82 per Mcfe for total production costs) for the nine months ended September 30, 2012 and 2011, respectively.
 
(12) The amount for the nine months ended September 30, 2011 was adjusted to reflect current period classification resulting from the misclassification of lease operating production expenses and transportation production expenses.
 
   

ATLAS RESOURCE PARTNERS, L.P.

CAPITALIZATION INFORMATION

 (unaudited; in thousands)

 

September 30, 2012

December 31, 2011

Total debt $ 222,000 $
Less: Cash   (24,266 )   (54,708 )
Total net debt/(cash) 197,734 (54,708 )
 
Partners’ capital/equity   708,748     457,175  
 
Total capitalization $ 906,482   $ 402,467  
 
Ratio of net debt to capitalization 0.22x 0.00x
 
 

ATLAS RESOURCE PARTNERS, L.P.

CAPITAL EXPENDITURE DATA

 (unaudited; in thousands)

   
Three Months Ended Nine Months Ended
September 30, September 30,
2012   2011 2012   2011
Maintenance capital expenditures $ 3,350 $ 2,300 $ 6,850 $ 7,533
Expansion capital expenditures   24,377   19,588   66,529   28,737
Total $ 27,727 $ 21,888 $ 73,379 $ 36,270
 
 

ATLAS RESOURCE PARTNERS, L.P.

Financial Information

(unaudited; in thousands)

 
Three Months Ended Nine Months Ended
September 30, September 30,
Adjusted EBITDA and Distributable Cash Flow Summary: 2012   2011 2012   2011
Gas and oil production margin $ 18,060 $ 12,148 $ 49,594 $ 39,201
Well construction and completion margin 4,736 5,208 12,395 9,582
Administration and oversight margin 4,440 2,337 8,586 5,073
Well services margin 2,854 2,867 8,268 8,974
Gathering   (424 )   (449 )   (2,874 )   (2,329 )
Gross Margin 29,666 22,111 75,969 60,501
Estimated Gross Margin for Acquisitions (1)   2,010         3,810      
Adjusted Gross Margin 31,676 22,111 79,779 60,501
Cash general and administrative expenses (9,027 ) (4,757 ) (27,067 ) (12,275 )
Other, net   92     (50 )   49     (99 )
Adjusted EBITDA (2) 22,741 17,304 52,761 48,127
Cash interest expense (3) (925 ) (1,501 )
Maintenance capital expenditures   (3,350 )   (2,300 )   (6,850 )   (7,533 )
Distributable Cash Flow (2) 18,466 15,004 44,410 40,594
Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets) (5)  

 

   

 

(15,004

 

)

 

 

(7,880

 

)

 

 

(40,594

 

)

Distributable Cash Flow attributable to limited partners (2)

$

18,466

 

$

 

$

36,530

 

$

 
 
Distributions Paid (4) $ 17,512 $ $ 33,874 $
per limited partner unit $ 0.43 $ $ 0.95 $
 
 
Reconciliation of non-GAAP measures to net income (loss) (4) :
Distributable cash flow attributable to limited

partners and the general partner

$

18,466

$

$

36,530

$

Distributable cash flow not attributable to limited partners and the general partner prior to March 5, 2012 (the date of transfer of assets) (5)

 

 

15,004

 

7,880

 

40,594

Estimated gross margin for acquisitions (1) (2,010 ) (3,810 )
Acquisition and related costs (2,274 ) (13,499 )
Depreciation, depletion and amortization (13,918 ) (8,071 ) (33,848 ) (24,019 )
Amortization of deferred finance costs (498 ) (1,028 )
Non-cash stock compensation expense (4,846 ) (7,861 )
Maintenance capital expenditures 3,350 2,300 6,850 7,533
Gain (loss) on asset disposal 2 (7,019 ) 48

Estimated expense on Chevron transaction

(7,670 ) (7,670 )
Adjustment to reflect cash impact of derivatives (656 ) (4,518 )
Premiums paid on swaption derivative contracts (Carrizo Barnett acquisition)

(25

)

(5,001

)

Other non-cash adjustments (6)       167         484  
Net income (loss) $ (10,079 ) $ 9,400   $ (32,994 ) $ 24,640  
 
(1)   Includes estimated gross margin generated for the month of April 2012 for Carrizo, estimated gross margin for the majority of July for Titan, and the majority of the 3 rd quarter 2012 for Equal. ARP consummated the acquisition of the Barnett assets from Carrizo on April 30, 2012, with ARP receiving all of the net cash generated by the assets from January 1, 2012 through April 30, 2012 as an acquisition adjustment, which is not included within ARP’s gross margin for the period. In addition, ARP consummated the acquisition of the Barnett assets from Titan on July 25, 2012, with ARP receiving all of the net cash generated by the assets from July 1, 2012 through July 25, 2012 as an acquisition adjustment, which is not included within ARP’s gross margin for the period. Also, ARP consummated the acquisition of the remainder of the Equal assets on September 24, 2012, with ARP receiving all of the net cash generated by the assets from July 1, 2012 through September 24, 2012 as an acquisition adjustment, which is not included within ARP’s gross margin for the period. As such, ARP has included the portion of cash received attributable to the month of April 2012 for Carrizo, the 25 days in July for Titan, and the 85 days for the 3 rd quarter 2012 for Equal as it paid or will pay a full quarter’s cash distribution for the respective quarterly period.
 
(2) Adjusted EBITDA and distributable cash flow are non-GAAP (generally accepted accounting principles) financial measures under the rules of the Securities and Exchange Commission. Management of ARP believes that adjusted EBITDA and distributable cash flow provide additional information for evaluating ARP’s performance, among other things. These measures are widely used by commercial banks, investment bankers, rating agencies and investors in evaluating performance relative to peers and pre-set performance standards. Adjusted EBITDA is also a financial measurement that, with certain negotiated adjustments, is utilized within ARP’s financial covenants under its credit facility. Adjusted EBITDA and distributable cash flow are not measures of financial performance under GAAP and, accordingly, should not be considered as a substitute for net income, operating income, or cash flows from operating activities in accordance with GAAP.
 
(3) Excludes non-cash amortization of deferred financing costs.
(4) Represents the cash distributions declared for the respective period and paid by ARP within 45 days after the end of each quarter, based upon the distributable cash flow generated during the respective quarter. The nine months ended September 30, 2012 includes a cash distribution payment of $0.12 per limited partner unit for the 1 st quarter 2012, which reflected a prorated cash distribution for the 27-day period from March 5, 2012, the date of transfer of the assets to ARP, to March 31, 2012.
 
(5)

In accordance with prevailing accounting literature, ARP has adjusted its historical financial statements to present them combined with the historical financial results of the spin-off assets for all periods prior to its spin-off date of March 5, 2012.

 
(6)

Includes $0.2 million and $0.5 million of Pennsylvania impact fee for the three and nine months ended September 30, 2011, respectively. The fee was instituted by the state of Pennsylvania subsequent to December 31, 2011 for the full year 2011. ARP allocated the fee pro rata to each of the quarterly periods for 2011.

 
     
ATLAS RESOURCE PARTNERS, L.P.
Hedge Position Summary
(as of October 31, 2012)
 

Natural Gas

 

Fixed Price Swaps

Production PeriodEnded December 31, AverageFixed Price(per mcf) (a)(b) Volumes(per mcf) (a)
2012 (c) $ 3.44 5,486,709
2013 $ 3.97 21,029,668
2014 $ 4.31 15,901,547
2015 $ 4.49 11,594,492
2016 $ 4.75 11,129,177
2017 $ 5.05 5,142,857
 
       

Costless Collars

Production PeriodEnded December 31, AverageFloor Price(per mcf) (a)(b) AverageCeiling Price(per mcf) (a)(b) Volumes(per mcf) (a)
2012 (c) $ 4.45 $ 5.71 1,028,571
2013 $ 4.78 $ 5.88 5,257,143
2014 $ 4.60 $ 5.54 3,657,143
2015 $ 4.61 $ 5.55 3,314,286
 
     

Put Options

Production PeriodEnded December 31, AverageFixed Price(per mcf) (a)(b) Volumes(per mcf) (a)
2012 (c) $ 3.06 741,429
2013 $ 3.31 1,020,000
 
     

Crude Oil

 

Fixed Price Swaps

Production PeriodEnded December 31, AverageFixed Price(per bbl) (a) Volumes(per bbl) (a)
2012 (c) $ 103.80 6,750
2013 $ 100.67 18,600
2014 $ 97.69 36,000
2015 $ 89.50 45,000
       

Costless Collars

Production PeriodEnded December 31, AverageFloor Price(per bbl) (a) AverageCeiling Price(per bbl) (a) Volumes(bbls) (a)
2012 (c) $ 90.00 $ 117.91 15,000
2013 $ 90.00 $ 116.40 60,000
2014 $ 84.17 $ 113.31 41,160
2015 $ 83.85 $ 110.65 29,250
 
(a)   “Mcf” represents thousand cubic feet; “bbl” represents barrel.
(b) Includes an estimated positive basis differential and Btu (British thermal units) adjustment.
(c) Reflects hedges covering the last three months of 2012.




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