NFR Energy LLC Announces 2012 Third Quarter Financial and Operational Results

HOUSTON, Nov. 14, 2012 /PRNewswire/ -- NFR Energy LLC today reported its unaudited third quarter 2012 financial and operating results.

Key Third Quarter Results and Recent Events:

  • Drilled and completed Berckenhoff #1H – second well in the Eagle ford Shale
  • Completed sale of Montana assets for approximately $18 million
  • Post- September 30, executed second farm-out agreement providing NFR to earn 50% of 4,600 acres in Dewitt County in the Eagle Ford Shale.
  • Subsequent to September 30th, the company has completed two Cotton Valley horizontal wells off a single pad in the Minden area. The two wells, the Jones 4H and the Redwine 4H, are producing at a combined gross rate of 12.7 MMCFD gas and 125 BOPD condensate with an additional estimated 370 barrels of NGL liquids per day. The wells are currently restricted due to pipeline constraints. In the next week we anticipate resolving this issue and the wells will be increased to a combined gas rate of 20 MMCFD.  

Results of the Third Quarter 2012

Production volumes during the three months ended September 30, 2012 were 11.5 Bcfe, an increase of 0.5 Bcfe or 4% from third quarter 2011 production.

Revenues from production of oil and natural gas decreased from $52.7 million in the third quarter of 2011 to $42.5 million in the third quarter of 2012, a decrease of 19%. The net decrease in oil and natural gas revenues of $10.2 million in the third quarter of 2012 compared to the third quarter of 2011 resulted mainly from a decrease in average prices per Mcfe of 23%, offset by in an increase in production of 4%.

During the third quarter of 2012, the Company's hedged realized average price for natural gas was $5.64 per Mcf. This is $2.76 per Mcf more than the Company's unhedged realized average price of $2.88 per Mcf. In the third quarter of 2012, approximately 73% of our natural gas volumes and 46% of our oil volumes were hedged, which resulted in a realized gain on such derivative instruments of approximately $27.1 million. In the third quarter of 2011, approximately 79% of our natural gas volumes were hedged, which resulted in a realized gain on such derivative instruments of $18.7 million.

Lease operating expenses increased from $6.8 million in the third quarter of 2011 to $9.0 million in the third quarter of 2012, an increase of 33%. The increase in lease operating expense is due to an increase in production associated with our two recent producing property acquisitions in East Texas (closed in 2H of 2011). Lease operating expenses increased from $0.61 per Mcfe in the third quarter of 2011 to $0.79 per Mcfe in the third quarter of 2012. The increase of $0.18 per Mcfe is primarily due to an increase in production volumes attributed to the vertical well production acquired in the second half of 2011 previously mentioned.

Marketing, gathering, transportation and other expenses was $5.3 million in the third quarters of 2011 and 2012. Marketing, gathering, transportation and other expenses decreased on a per unit basis from $0.48 per Mcfe in the third quarter of 2011 to $0.46 per Mcfe in the third quarter of 2012.

Production and ad valorem taxes decreased from $2.2 million in the third quarter of 2011 to $2.0 million in the third quarter of 2012, a decrease of 11%, primarily as a result of the timing of the approval of high cost gas tax exemptions that are currently received on all of our horizontal gas wells. This decrease is offset by an increase in production and ad valorem taxes as a result of a 4% increase in production. The Company expects future volatility with production taxes as a result of timing of approval for the aforementioned exemptions. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 5% and 4% for the third quarter of 2012 and 2011, respectively.

General and administrative expenses decreased from $5.5 million in the third quarter of 2011 to $5.1 million in the third quarter of 2012, a decrease of $0.4 million, or 7%, primarily as a result of lower due diligence and other acquisition costs in 2012,. General and administrative expenses decreased from $0.50 per Mcfe in the third quarter of 2011 to $0.44 per Mcfe in the third quarter of 2012 primarily as a result of an increase in production volumes without a proportionate increase in general and administrative expenses.

DD&A increased from $20.2 million in the third quarter of 2011 to $20.3 million in the third quarter of 2012, an increase of $0.1 million, as a result of the impact of the increased production. Depletion, depreciation, and amortization decreased from $1.84 per Mcfe in the third quarter of 2011 to $1.77 per Mcfe in the third quarter of 2012 due to a lower depletion and amortization base resulting from divested assets in the third quarter of 2012.

There were non-cash impairment charges primarily related to oil and natural gas properties in the third quarter of 2012 of $233.5 million and impairments related to the write-down of carrying value of certain sizes of casing inventory of $0.4 million. In the third quarter of 2011, we did not record an impairment charge as a result of full cost ceiling limitation or for other assets. The impairment charges in 2012 are due to the carrying value of proved oil and gas properties in excess of the ceiling limitation as a result of the decline in the average of the historical unweighted first-day-of-the-month natural gas prices from the prior twelve month periods ended June 30, 2012 to September 30, 2012 of $3.15 to $2.83, respectively.

Interest expense, excluding capitalized interest of $1.5 million and $1.0 million, respectively, increased from $9.9 million for the third quarter of 2011 to $11.4 million for the third quarter of 2012, an increase of $1.5 million, primarily as a result of additional borrowings on our senior secured revolving credit facility that were used to fund capital expenditures.

Certain of the Company's derivative contracts are not eligible for hedge accounting, and as a result, are required to be marked-to-market  each period, with all gains or losses on such contracts, (realized or unrealized) being recognized in our results of operations. During the three months ended September 30, 2012 and 2011, the company recognized an $8.2 million loss and a $3.6 million loss on derivative instruments, respectively. The amount of future gain or loss recognized on derivative instruments is dependent upon future natural gas prices, which will affect the value of the contracts, and the eligibility of the contract for hedge accounting treatment.

Along with the sale of the Company's producing assets in the Bear Paws, the Company also closed on the sale of its controlling ownership interests in the associated Montana gathering entities of Lodge Creek Pipelines, LLC and Willow Greek Gathering, LLC on August 31, 2012, which resulted in a loss of $9.9 million.

Results of the nine months ended September 30, 2012

Production volumes during the nine months ended September 30, 2012 were 37.6 Bcfe, an increase of 7.0 Bcfe or 23% from nine months ended September 30, 2011 production. The increase in production is attributed to positive results from the Company's drilling program and continued success of its recent acquisitions.

Revenues from production of oil and natural gas decreased from $147.4 million in the first nine months of 2011 to $131.8 million in the first nine months of 2012, a decrease of 11%. The net decrease in oil and natural gas revenues of $15.6 million in the first nine months of 2012 compared to the first nine months of 2011 resulted from the decrease in average prices per Mcfe of 27% offset by an increase in production due to acquisitions and drilling success of 23%.

During the nine months ended September 30, 2012, the Company's hedged realized average price for natural gas was $5.20 per Mcf. This is $2.64 per Mcf more than the Company's unhedged realized average price of $2.56 per Mcf. In the first nine months of 2012, approximately 66% of our natural gas volumes and 45% of our oil volumes were hedged, which resulted in a realized gain on such derivative instruments of approximately $85.1 million. In the first nine months of 2011, approximately 73% of our natural gas volumes were hedged, which resulted in a realized gain on such derivative instruments of $48.5 million.

Lease operating expenses increased from $18.0 million in the first nine months of 2011 to $32.3 million in the first nine months of 2012, an increase of 80%. The increase in lease operating expense is due to an increase in production associated with our two recent producing property acquisitions in East Texas. Lease operating expenses increased from $0.59 per Mcfe in the first nine months of 2011 to $0.86 per Mcfe in the first nine months of 2012. The increase of $0.27 per Mcfe is primarily due to acquisition related transition services costs, one-time costs for compliance improvements and operating efficiency efforts of approximately $3.0 million and an increase in production volumes associated with vertical wells acquired in the second half of 2011 with higher operating costs compared to the first nine months of 2011.

Marketing, gathering, transportation and other expenses increased from $14.4 million in the first nine months of 2011 to $16.0 million in the first nine months of 2012, an increase of 11%. The increase is due to an increase in production volumes by 23%. Marketing, gathering, transportation and other expenses decreased on a per unit basis from $0.47 per Mcfe in the first nine months of 2011 to $0.42 per Mcfe in the first nine months of 2012.  The decrease is due primarily to the Company's ability to secure favorable marketing and transportation contract terms with respect to the property acquisitions completed in 2011.

Production and ad valorem taxes decreased from $5.8 million in the first nine months of 2011 to $5.1 million in the first nine months of 2012, a decrease of 13%, primarily as a result of the timing of the approval of high cost gas tax exemptions that are currently received on all of our horizontal gas wells. This decrease is offset by an increase in production and ad valorem taxes as a result of a 23% increase in production. The Company expects future volatility with production taxes as a result of timing of approval for the aforementioned exemptions. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 4% for the first nine months of 2012 and 2011.

General and administrative expenses decreased from $17.4 million in the first nine months of 2011 to $15.3 million in the first nine months of 2012, a decrease of $2.1 million, or 12%, primarily as a result of lower due diligence and other acquisition costs in 2012. General and administrative expenses decreased from $0.57 per Mcfe in the first nine months of 2011 to $0.41 per Mcfe in the first nine months of 2012 primarily as a result of an increase in production volumes without a proportionate increase in general and administrative expenses.

DD&A increased from $55.1 million in the first nine months of 2011 to $71.6 million in the first nine months of 2012, an increase of $16.5 million, or 30%, as a result of the impact of the increased production. Depletion, depreciation, and amortization increased from $1.80 per Mcfe in the first nine months of 2011 to $1.90 per Mcfe in the first nine months of 2012 due to higher depletion and amortization base resulting from acquired assets and capital expenditures.

There were non-cash impairment charges primarily related to oil and natural gas properties in the first nine months of 2012 of $654 million, impairment charges for gas gathering and processing equipment of $11.5 million and impairments related to the write-down of carrying value of certain sizes of casing inventory of $0.7 million. In the first nine months of 2011, we did not record an impairment charge as a result of full cost ceiling limitation; however, impairment charges of $0.7 million were recorded related to the write-down of carrying value of certain sizes of casing inventory. The impairment charges in 2012 are due to the carrying value of proved oil and gas properties in excess of the ceiling limitation as a result of the decline in the average of the historical unweighted first-day-of-the-month natural gas prices from the prior twelve month periods ended December 31, 2011 to September 30, 2012 of $4.12 to $2.83, respectively.

Interest expense, excluding capitalized interest of $4.8 million and $3.2 million, respectively, increased from $28.4 million for the first nine months of 2011 to $34.5 million for the first nine months of 2012, an increase of $6.1 million, primarily as a result of additional borrowings on our senior secured revolving credit facility that were used to fund our capital expenditures.

Certain of our derivative contracts are not eligible for hedge accounting, and as a result, are required to be marked-to-market each period, with all gains or losses (realized or unrealized) on such contracts, being  recognized in our results of operations. During the nine months ended September 30, 2012 and 2011, the company recognized a $13.3 million loss and a $19.0 million loss on derivative instruments, respectively. The amount of future gain or loss recognized on derivative instruments is dependent upon future natural gas prices, which will affect the value of the contracts, and the eligibility of the contract for hedge accounting treatment.

Along with the sale of the Company's producing assets in the Bear Paws, the Company also closed on the sale of its controlling ownership interests in the associated Montana gathering entities of Lodge Creek Pipelines, LLC and Willow Greek Gathering, LLC on August 31, 2012, which resulted in a loss of $9.9 million.

Debt/Liquidity

As of September 30, 2012, our borrowing base under our senior secured revolving credit facility was $570.9 million, and we had total outstanding indebtedness of approximately $398 million. As of October 19, 2012, our borrowing base has been redetermined and reduced from $570.9 million to $525 million. After giving the effect to our redetermined borrowing base, we were able to incur approximately $127 million of secured indebtedness under our credit facility. As of November 13, 2012, the Company has repaid $3.0 million and had an outstanding balance of $395 million.

NFR will host a conference call at 9:30 a.m. CDT on November 14, 2012. To participate in the call, dial 1-888-606-5934 and international participants should dial 1-517-308-9375.  The participant passcode is NFR2012. A replay of the conference call will be available through the Company's website at http://www.nfrenergy.com for the three months ended September 30, 2012.

NFR Energy LLC is a privately‐held natural gas and oil company based in Houston, Texas. The Company's current operations are principally located in East Texas, with production from the Haynesville Shale and Cotton Valley Sand formations and in South Texas, with production from the Eagle Ford Shale formation.

This press release includes "forward-looking statements." All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include, but are not limited to forward-looking statements about plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, hedging activities, capital expenditure levels and other guidance. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow, access to capital and the timing of development expenditures.  See "Risk Factors" in the Company's Annual Report posted at www.nfrenergy.com and other public filings and press releases.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

 

NFR ENERGY LLC









Operational and Financial Statistics




















Three Months Ended


Nine Months Ended



September 30, 


September 30, 



2012


2011


2012


2011

Oil, natural gas and NGL sales by product (in thousands):









Natural gas


$ 28,259


$ 40,168


$   82,415


$ 112,103

Oil


6,934


3,021


21,059


10,795

NGL


7,269


9,510


28,358


24,466

Total


$ 42,462


$ 52,699


$ 131,832


$ 147,364










Production data:









Natural gas (Bcf)


9.81


9.71


32.20


27.03

Oil (MBbl)


70.70


35.39


215.21


121.01

NGL (MBbl)


200.88


179.37


689.95


480.90

Combined (Bcfe)(1)


11.44


11.00


37.63


30.64










Average prices before effects of hedges (2):









Natural gas (per Mcf)


$     2.88


$     4.14


$       2.56


$       4.15

Oil (per Bbl)


$   98.08


$   85.36


$     97.85


$     89.21

NGL (per Bbl)


$   36.19


$   53.02


$     41.10


$     50.88

Combined (per Mcfe)(1)


$     3.71


$     4.79


$       3.50


$       4.81










Average realized prices after effects of hedges (2):









Natural gas (per Mcf)


$     5.64


$     6.06


$       5.20


$       5.94

Oil (per Bbl)


$   98.08


$   85.36


$     97.85


$     89.21

NGL (per Bbl)


$   36.19


$   53.02


$     41.10


$     50.88

Combined (per Mcfe)(1)


$     6.08


$     6.49


$       5.77


$       6.39










Average costs (per Mcfe)(1):









Lease operating 


$     0.79


$     0.61


$       0.86


$       0.59

Workover 


$     0.04


$     0.09


$       0.05


$       0.08

Marketing, gathering, transportation and other


$     0.46


$     0.48


$       0.42


$       0.47

Production and ad valorem taxes


$     0.17


$     0.20


$       0.13


$       0.19

General and administrative


$     0.44


$     0.50


$       0.41


$       0.57

Depletion, depreciation and amortization


$     1.77


$     1.84


$       1.90


$       1.80


(1)

Oil production was converted at six Mcf per Bbl to calculate combined production and per Mcfe amounts.

(2)

Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivatives.



NFR ENERGY LLC








CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

















Three Months Ended September 30,


Nine Months Ended September 30,




2012


2011


2012


2011










(in thousands)


(in thousands)









Revenues








     Oil, natural gas and natural gas liquids sales

$  42,462


$ 52,699


$ 131,832


$ 147,364

     Gain on derivative instruments

27,060


18,678


85,135


48,472

     Other 

48


21


(53)


103

Total revenues

69,570


71,398


216,914


195,939

Operating expenses








     Lease operating

9,019


6,758


32,304


17,972

     Workover

498


988


1,757


2,556

     Marketing, gathering, transportation and other

5,301


5,277


15,982


14,425

     Production and ad valorem taxes

1,976


2,222


5,059


5,823

     General and administrative 

5,058


5,463


15,292


17,385

     Depletion, depreciation and amortization

20,296


20,215


71,592


55,094

     Gain on bargain purchase

-


(54,459)


-


(81,183)

     Accretion

199


168


680


446

     Bad debt

-


-


-


3

     Impairments

233,923


-


666,223


656

     Loss on sale of assets

9,880


-


9,880


-

Total operating expenses

286,150


(13,368)


818,769


33,177

Other income (expenses)








     Interest 

(11,396)


(9,938)


(34,456)


(28,377)

     Loss on derivative instruments

(8,212)


(3,555)


(13,340)


(19,026)

     Other income (expenses)

16


37


(292)


(53)

Total other expenses

(19,592)


(13,456)


(48,088)


(47,456)

Net income (loss) including noncontrolling interests

(236,172)


71,310


(649,943)


115,306

Less:  Net income (loss) applicable to noncontrolling interests

(14)


(18)


17


(86)









Net income (loss) applicable to controlling interests

$(236,186)


$  71,292


$(649,926)


$  115,220

NFR ENERGY LLC









ADJUSTED EBITDA




















Three Months Ended


Nine Months Ended



September 30, 


September 30, 



2012


2011


2012


2011



(in thousands)










Net income (loss) applicable to controlling interests


$ (236,186)


$ 71,292


$ (649,926)


$ 115,220










Reconciliation to derive Adjusted EBITDA (1):









Interest expense, net of capitalized interest


11,396


9,938


34,456


28,377

Depletion, depreciation and amortization


20,296


20,215


71,592


55,094

Impairments


233,923


-


666,223


656

Loss on derivative instruments


7,528


2,958


11,482


17,497

Gain on bargain purchase


-


(54,459)


-


(81,183)

Pro forma adjustments


-


2,096


-


11,551

Loss on sale of assets


9,880


-


9,880


-

Other


52


35


572


265

Net (income) loss applicable to noncontrolling interests


14


18


(17)


86

Adjusted EBITDA (1)


$    46,903


$ 52,093


$  144,262


$ 147,563

(1)

Adjusted EBITDA are non-GAAP financial measures. We use Adjusted EBITDA as a supplemental financial measure. Adjusted EBITDA is calculated in a manner consistent with the indenture governing our 2017 Notes and our senior secured revolving credit facility as net income (loss) before interest, taxes, depreciation and amortization, as further adjusted to include other adjustments, such as impairment, accretion expense, unrealized hedge gains or losses and other non-cash charges and pro forma adjustments for acquisitions and divestitures that may not be comparable to similarly titled measures, employed by other companies. Adjusted EBITDA are measures of performance calculated in accordance with GAAP. Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDA provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDA do not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, and other commitments and obligations. However, our management team believes Adjusted EBITDA are useful to an investor in evaluating our company because these measures:






>

are widely used by investors in the natural gas and oil industry to measure a company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;





>

help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and





>

are used by our management team for various purposes, including strategic planning and forecasting. Adjusted EBITDA is also the basis for covenants under the indenture governing our 2017 Notes regulating future debt issuance and restricted payments and pursuant to maintenance covenants under our senior secured revolving credit facility.

 

NFR ENERGY LLC






Selected Balance Sheet Data









September 30,


December 31,




2012


2011




(in thousands)

Assets:






    Total current assets



$           81,443


$        125,665

    Total property plant and equipment, net



813,147


1,507,862

    Other noncurrent assets



26,656


51,589

Total assets



$         921,246


$      1,685,116







Liabilities and member's capital:






    Total current liabilities



$           65,811


$        106,550

    Credit facility



398,000


418,000

    Senior notes



347,253


346,782

    Other noncurrent liabilities



35,803


33,611

Total Liabilities 



846,867


904,943







    Member's capital



74,379


780,173







Total Liabilities and member's capital



$         921,246


$      1,685,116













Selected Cash Flow Data









Nine Months Ended September 30,




2012


2011




(in thousands)

Net cash provided by operating activities



$         106,973


$        101,432

Net cash used in investing activities



(88,762)


(414,196)

Net cash provided by (used in) financing activities



(20,183)


312,126

Net decrease in cash and cash equivalents



(1,972)


(638)







Cash and cash equivalents, beginning of period



4,306


4,437

Cash and cash equivalents, end of period



$             2,334


$            3,799

 

SOURCE NFR Energy LLC



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