SOURCE: EV Energy Partners, L.P.

EV Energy Partners, L.P.

March 01, 2013 06:37 ET

EV Energy Partners Announces Fourth Quarter and Full Year 2012 Results, Utica Update, Year End Proved Reserves, 2013 Guidance and Updated Hedge Positions

HOUSTON, TX--(Marketwire - Mar 1, 2013) - EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the fourth quarter and full year 2012 and the filing of its Form 10-K with the Securities and Exchange Commission. In addition, EVEP announced its 2012 year end proved reserves, 2013 guidance and an update of its commodity hedge positions.

Full Year 2012 Results

Adjusted EBITDAX and distributable cash flow for 2012 were $267.5 million and $142.4 million, increases of 26 percent and 13 percent, respectively, over 2011. The increases in Adjusted EBITDAX and Distributable Cash Flow are primarily due to the two Barnett Shale acquisitions made in 2011. Adjusted EBITDAX and distributable cash flow are described in the attached table under "Non-GAAP Measures".

Production for 2012 was 42.5 Bcf of natural gas, 1,110 MBbls of oil and 1,742 MBbls of natural gas liquids, or 59.6 billion cubic feet equivalents (Bcfe). This represents a 45 percent increase over 2011 production of 41.2 Bcfe, primarily due to acquisitions in 2011.

For 2012, EVEP reported a net loss of $16.3 million, or $(0.38) per basic and diluted weighted average limited partner unit outstanding. Included in net loss were $48.3 million of unrealized losses on commodity and interest rate derivatives, $3.9 million of non-cash realized losses on commodity and interest rate derivatives, a $1.7 million non-cash charge to lease operating expense related to oil in tanks purchased in connection with 2011 acquisitions, $6.8 million of dry hole and exploration costs, $0.8 million of non-cash deferred income taxes, $16.4 million of non-cash costs contained in general and administrative expenses, and $1.0 million of due diligence and other transaction costs for acquisitions. Also recognized in 2012 were $34.5 million of impairment charges primarily related to the write-down of certain oil and natural gas properties to their fair value due to the effects of declining natural gas prices on expected future net cash flows. 

For 2011, EVEP reported net income of $102.6 million, or $2.71 and $2.68 per basic and diluted weighted average limited partner unit outstanding, respectively. Included in net income were $35.5 million of unrealized gains on commodity and interest rate derivatives, $0.6 million of non-cash realized losses on commodity and interest rate derivatives and $9.8 million of non-cash costs contained in general and administrative expenses. Also contained in general and administrative expenses were approximately $2.9 million of due diligence and other transaction costs for acquisitions. Other expenses incurred include $12.1 million of dry hole and exploration costs and $11.0 million of impairment costs related to divestitures of non-core oil and natural gas properties and assets held for sale. Also recognized, during 2011, was a $4.0 million gain on sale of assets related to Utica Shale acreage in an agreement with Total and Chesapeake.

Fourth Quarter 2012 Results

Adjusted EBITDAX for the fourth quarter of 2012 was $69.6 million, a 28 percent increase over the fourth quarter of 2011 and a 3 percent increase over the third quarter of 2012. Distributable cash flow for the fourth quarter of 2012 was $37.9 million, a 23 percent increase over the fourth quarter of 2011 and a 7 percent increase over the third quarter of 2012.

Production for the fourth quarter of 2012 was 10.8 Bcf of natural gas, 277 MBbls of oil and 476 MBbls of natural gas liquids, or 15.3 Bcfe. This represents a 38 percent increase over fourth quarter 2011 production of 11.1 Bcfe and a 2 percent increase over third quarter 2012 production of 15.0. The increases in production are primarily due to acquisitions completed during the fourth quarter of 2011. 

EVEP reported a net loss of $9.9 million, or $(0.23) per basic and diluted weighted average limited partner unit outstanding, for the fourth quarter of 2012. Included in net loss were $9.6 million of unrealized losses on commodity and interest rate derivatives, $1.2 million of non-cash realized losses on commodity and interest rate derivatives, $1.1 million of dry hole and exploration costs and $4.0 million of non-cash costs contained in general and administrative expenses. Also recognized during the fourth quarter were $16.7 million of impairment charges primarily related to the write-down of certain oil and natural gas properties to their fair value due to the effects of declining natural gas prices on expected future net cash flows. 

For the fourth quarter of 2011, EVEP reported net income of $9.7 million, or $0.27 per basic and diluted weighted average limited partner unit outstanding. Included in net income were $2.3 million of unrealized gains on commodity and interest rate derivatives, $1.1 million of non-cash realized losses on commodity and interest rate derivatives, $10.5 million of dry hole and exploration costs, $4.4 million of impairment costs primarily related to assets held for sale, a $4.0 million gain on the sale of assets related to Utica Shale acreage in an agreement with Total and Chesapeake and $3.2 million of non-cash costs contained in general and administrative expenses. Also contained in general and administrative expenses were approximately $2.3 million of due diligence and other transaction costs for acquisitions completed during the quarter. 

For the third quarter of 2012, EVEP reported a net loss of $50.0 million, or $(1.15) per basic and diluted weighted average limited partner unit outstanding. Included in net loss were $65.9 million of unrealized losses on commodity and interest rate derivatives, $1.4 million of non-cash realized losses related to commodity and interest rate derivatives, $1.8 million of dry hole and exploration costs, $0.9 million of impairment charges, $(0.2) million of non-cash deferred income tax benefit and $4.3 million of non-cash costs contained in general and administrative expenses.

"We had a solid year of performance in our base assets in 2012, and made initial investments in two exciting Utica Shale midstream projects," said John B. Walker, Executive Chairman. "While it is clearly taking longer than we expected, we remain in substantive negotiations with potential purchasers on a majority of our Utica Shale acreage, and will announce deals as agreements are signed."

Year End 2012 Estimated Net Proved Reserves

EVEP's year end 2012 estimated net proved reserves were 904.7 Bcfe, a 21 percent decrease over year end 2011 estimated net proved reserves, primarily due to the significant decline in natural gas and natural gas liquids pricing year over year. Approximately 67 percent of these reserves were natural gas, 24 percent were natural gas liquids and 9 percent were oil. In addition, 76 percent were categorized as proved developed.

At December 31, 2012, the present value of future net pre-tax cash flows discounted at 10 percent was $874.3 million and the standardized measure of estimated net proved reserves was $866.9 million. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the "SEC"), without giving effect to non-property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. Standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because EVEP is a partnership and is not subject to federal income taxes.

     
    Estimated Net Proved Reserves
   
Oil
(MMBbls)
 
Natural Gas (Bcf)
  Natural
Gas Liquids (MMBbls)
 

Bcfe
                 
Barnett Shale   1.1   369.8   26.0   532.4
Appalachian Basin   4.8   71.4   0.2   101.4
Mid-Continent area   3.0   45.0   1.1   69.6
San Juan Basin   1.1   32.5   2.4   53.5
Central and East Texas   2.8   19.9   2.1   49.3
Permian Basin   0.7   16.0   3.9   43.6
Monroe Field   -   30.7   -   30.7
Michigan   -   24.2   -   24.2
Total   13.5   609.5   35.7   904.7
                 

The prices used in determining estimated net proved reserves at December 31, 2012 were $94.71 per Bbl of oil and $2.76 per MMBtu of natural gas as compared to $96.19 per Bbl of oil and $4.12 per MMBtu of natural gas at December 31, 2011. The decrease in oil and natural gas prices from 2011 to 2012 had a significant impact on EVEP's estimated net proved reserves at December 31, 2012. This change caused reserves to decrease by 270 Bcfe, or approximately 24 percent. Had the commodity prices used in calculating year end 2012 proved reserves been the same as those in effect at December 31, 2011, EVEP's estimated net proved reserves at December 31, 2012 would have increased by approximately 3 percent over those at December 31, 2011. The reserve replacement ratio, on a price-neutral basis, was 151 percent of 2012 production.

Utica Midstream Investment

While the monetization process for a portion of EVEP's net working interest acreage in the Utica is on-going, EVEP is making a significant investment in two Utica midstream projects, Utica East Ohio Midstream (UEO) and Cardinal Gas Services (CGS). During the fourth quarter, EVEP increased its ownership from eight percent to 21 percent in UEO, a high-pressure gathering, processing and fractionation system which will have 800 MMcf/d of wet gas processing capacity and 135 MBbls/d of natural gas liquids fractionation capacity, and onsite working storage of approximately 870 MBbls once completed. EVEP also owns nine percent of CGS, a low-pressure gathering system currently in service and with significant further expansion underway in eastern Ohio. The Partnership estimates that its share of total net capital for these two midstream projects will be $335 to $395 million through 2016 with $230 to $250 million budgeted to be spent in 2013. Once both systems are complete and fully utilized, EVEP expects these investments to generate $50 to $70 million of EBITDAX per year and to be accretive to distributable cash flow per unit.

Annual Report on Form 10-K and Unitholders' Schedule K-1

EVEP's financial statements and related footnotes are available on our 2012 Form 10-K, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.

Also available for download on our website by March 7, 2012 will be unitholders' Schedule K-1's for the tax year 2012. For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-800-973-7551.

Conference Call and Supporting Materials

As announced on February 22, 2012, EV Energy Partners, L.P. will host an investor conference call on March 1, 2013, at 9 a.m. Eastern Time (8 a.m. Central). Investors interested in participating in the call may dial (480) 629-9818 (quote conference ID 4600344) at least 5 minutes prior to the start time, or may listen live over the Internet through the Investor Relations section of the EVEP website at http://www.evenergypartners.com. Interested investors also may access the accompanying slide presentation to be available on our website, also in the Investor Relations section under Presentation & Event Schedule.

EV Energy Partners, L.P. is a master limited partnership engaged in acquiring, producing and developing oil and gas properties. More information about EVEP is available on the Internet at http://www.evenergypartners.com.

(code #: EVEP/G)

This press release may include statements that are not historical facts which are "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. These statements include information about the sale of our Utica Shale assets, our midstream investments, future plans and other statements which include words such as "anticipates," "plans," "projects," "expects," "intends," "believes," "should," and similar expressions of forward-looking information. Forward-looking statements are inherently uncertain and necessarily involve risks that may affect the business prospects and performance of EV Energy Partners, L.P. Actual results may differ materially from those contained in the press release. Such risks and uncertainties include, but are not limited to, changes in commodity prices, changes in reserve estimates, requirements and actions of purchasers of properties (including the Utica Shale), changes in the metrics and procedures used to value midstream assets, exploration and development activities in the Utica Shale and elsewhere, the availability and cost of financing, the returns on our capital investments and acquisition strategies, the availability of sufficient cash flow to pay distributions and execute our business plan and general economic conditions. Additional information on risks and uncertainties that could affect our business prospects and performance are provided in the most recent reports of EV Energy Partners with the Securities and Exchange Commission. All forward-looking statements included in this press release are expressly qualified in their entirety by the foregoing cautionary statements.

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

                   
2013 Guidance                  
                   
  1st Qtr 2013 2nd Qtr 2013 3rd Qtr 2013
Net Production:                  
  Natural Gas (MMcf) 9,400 - 10,300 9,500 - 10,400 9,700 - 10,600
  Crude Oil (MBbls) 250 - 280 260 - 290 260 - 290
  Natural Gas Liquids (MBbls) 450 - 500 480 - 520 500 - 540
Total Mmcfe 13,790 - 14,980 13,940 - 15,260 14,260 - 15,580
                   
Average Daily Production (Mmcfe/d) 153.2 - 166.4 153.2 - 167.7 155.0 - 169.3
                   
Average Price Differential vs NYMEX                  
  Natural Gas (% of NYMEX Natural Gas) 92% - 98% 92% - 98% 92% - 98%
  Crude Oil (% of NYMEX Crude Oil) 94% - 100% 93% - 99% 93% - 99%
                   
  Transportation Margin ($ thous) (a) 400 - 450 400 - 450 400 - 450
                   
Expenses:                  
Operating Expenses:                  
  LOE and other ($ thous) 23,300 - 25,600 23,900 - 26,400 24,000 - 26,600
  Production Taxes (as % of revenue) 3.9% - 4.2% 3.9% - 4.1% 3.8% - 4.1%
                   
General and administrative expense ($ thous) (b) 6,450 - 7,200 4,850 - 5,600 4,850 - 5,600
                   
Utica Shale Midstream and ORRI EBITDAX 300 - 500 600 - 1,000 2,180 - 3,630
                   
E&P Capital Expenditures ($ thous) (c) 24,000 - 29,000 23,000 - 28,000 28,000 - 34,000
Midstream Investment ($ thous) 66,000 - 70,000 68,000 - 72,000 53,000 - 59,000
                   
  4th Qtr 2013       Full Year 2013
Net Production:                  
  Natural Gas (MMcf) 9,800 - 10,700       38,400 - 42,000
  Crude Oil (MBbls) 270 - 290       1,040 - 1,150
  Natural Gas Liquids (MBbls) 510 - 550       1,940 - 2,110
Total Mmcfe 14,480 - 15,740       56,280 - 61,560
                   
Average Daily Production (Mmcfe/d) 157.4 - 171.1       154.2 - 168.7
                   
Average Price Differential vs NYMEX                  
  Natural Gas (% of NYMEX Natural Gas) 92% - 98%       92% - 98%
  Crude Oil (% of NYMEX Crude Oil) 93% - 99%       93% - 100%
                   
  Transportation Margin ($ thous) (a) 400 - 450       1,600 - 1,800
                   
Expenses:                  
Operating Expenses:                  
  LOE and other ($ thous) 23,800 - 26,400       95,000 - 105,000
  Production Taxes (as % of revenue) 3.9% - 4.2%       3.9% - 4.2%
                   
General and administrative expense ($ thous) (b) 4,850 - 5,600       21,000 - 24,000
                   
Utica Shale Midstream and ORRI EBITDAX 2,920 - 4,870       6,000 - 10,000
                   
E&P Capital Expenditures ($ thous) (c) 15,000 - 19,000       90,000 - 110,000
Midstream Investment ($ thous) 43,000 - 49,000       230,000 - 250,000
                   
     
(a)   Represents estimated transportation and marketing-related revenues less cost of purchased natural gas.
(b)   Excludes non-cash general and administrative expense, of which non-cash unit based compensation is a part, also excludes any amounts for future acquisition related due diligence and transaction costs.
(c)   Represents estimates for drilling and related capital expenditures. Does not include any amounts for acquisitions of oil and gas properties.
     
Operating Statistics              
               
  Three Months Ended December 31,   Twelve Months Ended December 31,
  2012   2011   2012   2011
Production data:                      
  Oil (MBbls)   277     235     1,110     891
  Natural gas liquids (MBbls)   476     269     1,742     1,096
  Natural gas (MMcf)   10,779     8,103     42,536     29,247
  Net production (MMcfe)   15,298     11,125     59,647     41,169
Average sales price per unit: (1)                      
  Oil (Bbl) $ 86.83   $ 92.39   $ 91.94   $ 91.72
  Natural gas liquids (Bbl)   31.72     53.82     36.02     52.99
  Natural gas (Mcf)   3.27     3.64     2.75     3.99
  Mcfe   4.86     5.90     4.72     6.23
Average unit cost per Mcfe:                      
  Production costs:                      
    Lease operating expenses (2) $ 1.66   $ 1.78   $ 1.74   $ 1.81
    Production taxes   0.16     0.25     0.18     0.27
    Total   1.82     2.03     1.92     2.08
Asset retirement obligations accretion expense   0.09     0.10     0.09     0.10
Depreciation, depletion and amortization   2.11     1.84     1.90     1.82
General and administrative expenses   0.66     1.00     0.72     0.85
 
(1) Prior to $28.4 and $18.9 million of net hedge gains and settlements on commodity derivatives for the three months ended December 31, 2012 and December 31, 2011, respectively and $123.0 and $65.2 million for the twelve months ended December 31, 2012 and December 31, 2011.
(2) Lease operating expenses for the twelve months ended December 31, 2012 contain $1.7 million ($0.03 per Mcfe) of non-cash charges related to oil in tanks purchased in connection with 2011 acquisitions.
 
           
Consolidated Balance Sheets          
(in $ thousands, except number of units)          
           
  December 31, 2012     December 31, 2011  
ASSETS              
Current assets:              
  Cash and cash equivalents $ 7,486     $ 30,312  
  Accounts receivable:              
    Oil, natural gas and natural gas liquids revenues   34,909       36,926  
    Related party   1,422       -  
    Other   11,263       459  
  Derivative asset   40,771       81,772  
  Other current assets   1,750       3,084  
  Assets held for sale   -       6,597  
    Total current assets   97,601       159,150  
               
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2012, $389,206; December 31, 2011, $244,092   1,875,890       1,768,529  
Other property, net of accumulated depreciation and amortization; December 31, 2012, $598; December 31, 2011, $447   1,325       1,345  
Long-term derivative asset   45,839       57,643  
Other assets   44,759       16,557  
Total assets $ 2,065,414     $ 2,003,224  
               
               
LIABILITIES AND OWNERS' EQUITY              
Current liabilities:              
  Accounts payable and accrued liabilities:              
    Third party $ 40,171     $ 34,705  
    Related party   -       870  
  Derivative liability   -       618  
  Liabilities held for sale   -       602  
    Total current liabilities   40,171       36,795  
               
Asset retirement obligations   102,707       90,803  
Long-term debt   859,218       953,023  
Other long-term liabilities   3,494       2,564  
               
Commitments and contingencies              
               
Owners' equity:              
  Common unitholders - 42,320,707 units and 34,173,650 units issued and outstanding as of December 31, 2012 and December 31, 2011, respectively   1,072,175       935,425  
  Class B unitholders - zero units and 3,873,357 units issued and outstanding as of December 31, 2012 and December 31, 2011, respectively   -       232  
  General partner interest   (12,351 )     (15,618 )
    Total owners' equity   1,059,824       920,039  
Total liabilities and owners' equity $ 2,065,414     $ 2,003,224  
               
                     
Consolidated Statements of Operations                    
(in $ thousands, except per unit data)                      
                       
  Three Months Ended
December 31,
    Twelve Months Ended
December 31,
 
  2012     2011     2012     2011  
Revenues:                              
  Oil, natural gas and natural gas liquids revenues $ 74,408     $ 65,679     $ 281,749     $ 256,370  
  Transportation and marketing-related revenues   1,088       1,157       3,731       5,470  
    Total revenues   75,496       66,836       285,480       261,840  
                               
Operating costs and expenses:                              
  Lease operating expenses   25,334       19,824       103,605       74,419  
  Cost of purchased natural gas   792       836       2,600       4,078  
  Dry hole and exploration costs   1,107       10,528       6,771       12,140  
  Production taxes   2,517       2,832       10,911       11,247  
  Asset retirement obligations accretion expense   1,353       1,058       5,116       3,914  
  Depreciation, depletion and amortization   32,254       20,491       113,381       74,723  
  General and administrative expenses   10,120       11,117       42,682       34,968  
  Impairment of oil and natural gas properties   16,701       4,419       34,453       11,037  
  Gain on sales of oil and natural gas properties   -       (4,017 )     -       (4,017 )
    Total operating costs and expenses   90,178       67,088       319,519       222,509  
                               
Operating (loss) income   (14,682 )     (252 )     (34,039 )     39,331  
                               
Other income (expense), net:                              
  Realized gains on derivatives, net   26,372       16,704       115,000       58,402  
  Unrealized (losses) gains on derivatives, net   (9,594 )     2,293       (48,266 )     35,505  
  Interest expense   (12,202 )     (9,113 )     (48,689 )     (30,568 )
  Other income, net   323       217       705       325  
    Total other income, net   4,899       10,101       18,750       63,664  
                               
(Loss) income before income taxes and equity in losses of unconsolidated affiliates   (9,783 )     9,849       (15,289 )     102,995  
Income taxes   (174 )     (190 )     (1,078 )     (354 )
(Loss) income before equity in income of unconsolidated affiliates   (9,957 )     9,659       (16,367 )     102,641  
Equity in income of unconsolidated affiliates   78       -       18       -  
Net (loss) income $ (9,879 )   $ 9,659     $ (16,349 )   $ 102,641  
General partner's interest in net (loss) income, including incentive distribution rights $ (197 )   $ 193     $ ( 327 )   $ 10,886  
Limited partners' interest net (loss) income $ (9,682 )   $ 9,466     $ (16,022 )   $ 91,755  
Net (loss) income per limited partner unit:                              
  Basic $ (0.23 )   $ 0.27     $ (0.38 )   $ 2.71  
  Diluted $ (0.23 )   $ 0.27     $ (0.38 )   $ 2.68  
Weighted average limited partner units outstanding:                              
  Basic   42,452       35,231       41,952       33,895  
  Diluted   42,452       35,571       41,952       34,183  
                               
Distributions declared per unit $ 0.767     $ 0.763     $ 3.062     $ 3.046  
                               
           
Consolidated Statements of Cash Flows          
(in $ thousands)          
  Twelve Months Ended
December 31,
 
  2012     2011  
Cash flows from operating activities:              
  Net (loss) income $ (16,349 )   $ 102,641  
  Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:              
    Dry hole costs   1,100       9,220  
    Asset retirement obligations accretion expense   5,116       3,914  
    Depreciation, depletion and amortization   113,381       74,723  
    Equity-based compensation   16,433       9,834  
    Impairment of oil and natural gas properties   34,453       11,037  
    Gain on sales of oil and natural gas properties   -       (4,017 )
    Non-cash derivative activity   49,632       (40,187 )
    Amortization of deferred loan costs   2,183       1,348  
    Equity in income of unconsolidated affiliates   (18 )     -  
    Dividends from unconsolidated affiliates   79       -  
    Other   2,165       563  
    Changes in operating assets and liabilities:              
      Accounts receivable   (1,773 )     (6,505 )
      Other current assets   51       (342 )
      Accounts payable and accrued liabilities   5,185       7,362  
      Other, net   (2,123 )     (2,379 )
Net cash flows provided by operating activities   209,515       167,212  
               
Cash flows from investing activities:              
  Acquisitions of oil and natural gas properties   (120,033 )     (463,624 )
  Additions to oil and natural gas properties   (129,783 )     (75,913 )
  Investments in unconsolidated affiliates   (33,811 )     -  
  Proceeds from sales of oil and natural gas properties   5,522       14,012  
  Dividends from unconsolidated affiliates   19       -  
  Settlements from acquired derivatives   4,578       6,563  
Net cash flows used in investing activities   (273,508 )     (518,962 )
               
Cash flows from financing activities:              
  Long-term debt borrowings   160,000       477,500  
  Repayments of long-term debt borrowings   (460,000 )     (436,500 )
  Proceeds from debt offering   206,000       292,500  
  Loan costs paid   (4,152 )     (7,698 )
  Proceeds from public equity offerings   262,833       147,108  
  Offering costs   (304 )     (347 )
  Contributions from general partner   5,714       3,191  
  Distributions paid   (128,924 )     (115,101 )
  Distribution related to acquisition   -       (1,718 )
Net cash flows provided by (used in) financing activities   41,167       358,935  
               
(Decrease) increase in cash and cash equivalents   (22,826 )     7,185  
Cash and cash equivalents - beginning of year   30,312       23,127  
Cash and cash equivalents - end of year $ 7,486     $ 30,312  
               

Non GAAP Measures

We define Adjusted EBITDAX as net (loss) income plus income taxes, interest expense, net, realized losses on interest rate swaps, depreciation, depletion and amortization, asset retirement obligations accretion expense, non-cash realized losses on derivatives, unrealized losses (gains) on derivatives, non-cash equity compensation, impairment of oil and natural gas properties, gain on sales of oil and natural gas properties, non-cash inventory write down expense, and dry hole and exploration costs. Distributable Cash Flow is defined as Adjusted EBITDAX less income cash income taxes, cash interest expense, net, realized losses on interest rate swaps, and estimated maintenance capital expenditures.

Adjusted EBITDAX and Distributable Cash Flow are used by our management to provide additional information and statistics relative to the performance of our business, including (prior to the creation of any reserves) the cash available to pay distributions to our unitholders. These financial measures indicate to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDAX and Distributable Cash Flow are also quantitative standards used throughout the investment community with respect to performance of publicly-traded partnerships. Adjusted EBITDAX and Distributable Cash Flow should not be considered as alternatives to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDAX and Distributable Cash Flow exclude some, but not all, items that affect net income and operating income and these measures may vary among companies. Therefore, our Adjusted EBITDAX and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

         
Reconciliation of Net Income (Loss) to Adjusted EBITDAX and Distributable Cash Flow        
(in $ thousands)                      
                       
  Three Months Ended
December 31,
    Twelve Months Ended
December 31,
 
  2012     2011     2012     2011  
                               
Net (loss) income $ (9,879 )   $ 9,659     $ (16,349 )   $ 102,641  
Add:                              
Income taxes   174       190       1,078       354  
Interest expense, net   12,199       9,110       48,668       30,551  
Realized losses on interest rate swaps   860       1,095       4,032       6,171  
Depreciation, depletion and amortization   32,254       20,491       113,381       74,723  
Asset retirement obligations accretion expense   1,353       1,058       5,116       3,914  
Non-cash realized losses on derivatives   1,203       1,061       3,920       577  
Unrealized losses (gains) on derivatives   9,594       (2,293 )     48,266       (35,505 )
Non-cash equity compensation expense   4,043       3,221       16,433       9,834  
Impairment of oil and natural gas properties   16,701       4,419       34,453       11,037  
Gain on sales of oil and natural gas properties   -       (4,017 )     -       (4,017 )
Non-cash inventory write down expense   -       -       1,729       -  
Dry hole and exploration costs   1,107       10,528       6,771       12,140  
Adjusted EBITDAX $ 69,609     $ 54,522     $ 267,498     $ 212,418  
                               
                               
Less:                              
Cash income taxes   79       190       243       354  
Cash interest expense, net   11,599       8,504       46,289       28,680  
Realized losses on interest rate swaps   860       1,095       4,032       6,171  
Estimated maintenance capital expenditures (1)   19,123       13,908       74,559       50,968  
Distributable Cash Flow $ 37,948     $ 30,825     $ 142,375     $ 126,246  
                               
                               
(1) Estimated maintenance capital expenditures are those expenditures estimated to be necessary to maintain the production levels of our oil and gas properties over the long term and the operating capacity of our other assets over the long term.  
   
     
Summary of New Hedge Positions (since December 31, 2012)    
             
        Swap   Swap
Period   Index   Volume   Price
Natural Gas       (Mmmbtu/Mbbls)    
2014   NYMEX   10,950.0   $3.97
2015   NYMEX   10,950.0   $4.18
             
Crude Oil            
2014   WTI   365.0   $90.69
2015   WTI   730.0   $90.09
             
Hedge Summary Table (as of February 28, 2013)        
        Swap   Swap
Period   Index   Volume   Price
Natural Gas       (Mmmbtu/Mbbls)    
2013   NYMEX   33,689.5   $4.83
    El Paso Permian   1,095.0   $6.77
    El Paso San Juan   1,095.0   $6.66
             
1Q-3Q 2014   NYMEX   19,396.8   $5.00
4Q 2014   NYMEX   6,737.2   $4.95
             
2015   NYMEX   26,097.5   $5.22
             
Crude            
1Q 2013   WTI   384.8   $89.22
2Q 2013   WTI   384.5   $89.11
3Q 2013   WTI   381.8   $88.99
4Q 2013   WTI   381.8   $88.99
             
1H 2014   WTI   760.2   $89.78
2H 2014   WTI   757.5   $92.61
             
2015   WTI   730.0   $90.09
             
Interest Rate Swap Agreements       Notional Amount   Fixed Rate
        (in $ mill)    
January 2013 - July 2015       110   3.315%
             

Contact Information