SOURCE: Venoco, Inc.

Venoco, Inc.

April 16, 2015 06:00 ET

Venoco, Inc. Announces Year-End 2014 Reserves and 4th Quarter and Full-Year 2014 Financial and Operational Results

Net Income of $120 Million and Adjusted EBITDA of $119 Million for the Year; Announcement of Successful Completion of Series of Strategic Investment Transactions in April 2015

DENVER, CO--(Marketwired - April 16, 2015) - Venoco, Inc. ("Venoco", the "company", "we", or "us") today reported financial and operational results for the fourth quarter and full-year 2014. The company reported net income for the year of $120 million on total revenues of $224 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain one-time charges, were $19 million for the year, and Adjusted EBITDA was $119 million. Please see the end of this release for definitions of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net income/loss.

Highlights include the following:

  • Production of 2.7 million barrels of oil equivalent (MMBOE) for the year, or 7,406 BOE per day (BOE/d); excluding volumes contributed by the West Montalvo field properties which were sold in the fourth quarter of 2014, production for the year was 2.3 MMBOE or 6,233 BOE/d.
  • Successful drilling and completion of a well in the Monterey 2 (M2) zone at the Sockeye field from Platform Gail. 
  • Continuation of our successful development program at the West Montalvo field, preceding the subsequent divestiture of the West Montalvo properties in order to support our deleveraging efforts.
  • Proved reserves of 40.4 MMBOE as of December 31, 2014, having PV-10 of $734 million. Please see the end of this release for a definition of PV-10 and a reconciliation of this measure to standardized measure of discounted future net cash flows.
  • Successful completion of a confirmation well in Coal Oil Point, an analogous but separate geologic structure in the South Ellwood field and located northeast of Platform Holly.
  • Completion and acceptance by the California State Lands Commission of our application to adjust the lease line of our South Ellwood field.

"2014 was a remarkable year with respect to contrast and volatility," said Mark DePuy, Venoco's CEO. "We began the year with oil prices over $100 per barrel and a plan in place to execute on a vigorous drilling program at three of our major fields. Out of the gate, however, we were faced with an unexpected and prolonged shutdown at South Ellwood due to a third-party pipeline repair, which delayed our drilling program considerably. We initially focused our drilling efforts at West Montalvo, continuing a successful development program that we had pursued over the past couple of years. We then shifted attention towards the effort to sell the field in support of our corporate deleveraging efforts. We received excellent value for the property and were able to consummate the deal before oil markets declined very significantly. We also continued drilling at Platform Holly towards Coal Oil Point, confirming our discovery in 2013 and ultimately completing one of the most technical and challenging wells drilled by the company to date. That was followed up later in the year by a successful drilling program at Platform Gail, where we drilled a successful Monterey well and proved up additional reserves." 

"By the end of the year, our entire industry was grappling to adjust to the new commodity price paradigm, and we were no different," Mr. DePuy continued. "We quickly took the necessary steps to weather the latest downturn and to strengthen our company in anticipation of an eventual return to growth, as evidenced by the engagement of some of the industry's top financial and strategic advisors in the fourth quarter." 

"Today, we turn our focus ahead, having successfully completed a major transaction that went a long way towards boosting liquidity and improving our balance sheet," Mr. DePuy added. "While we're pleased with the recent financing round, we'll continue to seek out further opportunities for capital structure improvements, acquisitions, and growth." 

Fourth Quarter and Full-Year Production

Production in the fourth quarter of 2014 was 6,612 BOE/d compared to 7,344 BOE/d in the third quarter of 2014 and 8,511 BOE/d in the fourth quarter of 2013. Pro forma for the sale of the West Montalvo, production was 6,158 BOE/d in the fourth quarter of 2014, 6,013 BOE/d in the third quarter of 2014, and 7,027 BOE/d in the fourth quarter of 2013. Production for the full year 2014 was 7,406 BOE/d compared to 9,499 BOE/d in 2013. Pro forma for West Montalvo, production was 6,233 BOE/d in 2014 compared to 7,606 BOE/d in 2013, which is also pro forma for the sale of certain Sacramento Basin properties in 2013.

"Compared to the third quarter of 2014, our fourth quarter 2014 production was boosted by the successful drilling efforts at Platform Holly and Platform Grace, despite some continued downhole wellbore communication issues at Platform Holly," said Mr. DePuy. "However, production has remained relatively flat through the first part of 2015, and we believe the South Ellwood field decline as a result of the communication has moderated considerably."

The following table details the company's daily production by region (BOE(1)/d):

     
        Full Year(2)
  4Q 2013 3Q 2014 4Q 2014 2013 2014
Southern California (excl. W. Montalvo) 7,027 6,013 6,158 7,606 6,233
 West Montalvo 1,484 1,331 454 1,614 1,173
 Sacramento Basin - - - 279 -
Total Venoco 8,511 7,344 6,612 9,499 7,406
  
(1)Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
(2)2013 production from the Sacramento Basin relates to properties that were held in escrow pending the receipt of consents regarding the transfer of ownership. As of May 1, 2013, title to all properties included in the sale on December 31, 2012 had been transferred.
  

Fourth Quarter and Full-Year Costs

Venoco's fourth quarter 2014 lease operating expenses were $27.07 per BOE compared to $26.96 per BOE in the third quarter. Pro forma for the West Montalvo sale, fourth quarter 2014 lease operating expenses were $28.07 per BOE compared to $27.10 in the third quarter. The increase in lease operating expenses per BOE was primarily due to higher non-recurring surface and subsurface costs at South Ellwood and Sockeye. Full-year 2014 lease operating expenses were $26.77 per BOE compared to $22.44 per BOE for the full-year 2013. Pro forma for the West Montalvo and Sacramento Basin field sales, full-year 2014 lease operating expenses were $27.75 per BOE compared to $23.89 per BOE for the full-year 2013. On an absolute basis, pro forma for the West Montalvo and Sacramento Basin field sales, full-year 2014 lease operating expenses were $63 million, down from $66 million for the full-year 2013. 

Venoco's G&A costs were $922,000 in the fourth quarter of 2014, $1.4 million in the third quarter of 2014, $19.9 million for 2014 as a whole and $50.4 million in 2013. On a per BOE basis, Venoco's fourth quarter 2014 G&A costs, excluding non-cash share-based compensation, were $6.18 per BOE, down from $7.29 per BOE in the third quarter. Excluding production from the West Montalvo field, fourth quarter 2014 G&A costs, excluding non-cash share-based compensation, were $6.64 per BOE, down from $8.91 per BOE in the third quarter 2014. The company's full-year 2014 G&A costs, excluding the severance costs related to the sale of the West Montalvo field and non-cash share-based compensation, were $8.39 per BOE, down from $11.75 per BOE for the full-year 2013. Excluding production from the West Montalvo field, full-year 2014 G&A costs excluding non-cash share-based compensation were $9.97 per BOE, down from $14.67 per BOE for full-year 2013, which also excludes production from the Sacramento Basin properties held in escrow. 

Property and production taxes for the full-year 2014 were $2.82 per BOE compared to $1.02 per BOE in 2013. Pro forma for the sale of West Montalvo, full-year 2014 property and production taxes were $2.94 per BOE compared to $0.91 per BOE for full-year 2013, which is also pro forma for the Sacramento Basin properties held in escrow. The increase is due primarily to higher supplemental and ad valorem taxes. 

        
  Quarter Ended    Year Ended
UNAUDITED (per BOE) 12/31/13 9/30/14 12/31/14  12/31/13 12/31/14
 Lease Operating Expenses $29.46 $26.96 $27.07  $22.44 $26.77
 Property and Production Taxes  1.86  3.14  2.44   1.02  2.82
 DD&A Expense  15.72  17.39  15.35   14.09  16.31
 G&A Expense (1)  14.31  7.29  6.18   11.75  8.39
  
(1)Net of amounts capitalized and excluding non-cash share-based compensation costs, and severance costs associated with the sale of our West Montalvo and Sacramento Basin assets. See the end of this release for a reconciliation of G&A per BOE.
  

Capital Investment 2014

Venoco's 2014 capital expenditures for exploration, exploitation, development and other spending were $77 million, including $62 million for drilling and rework activities, $4 million for facilities, and the remaining $11 million for land, seismic and capitalized G&A.

In 2014, the company spent $73 million or 95% of its capital expenditures on its Southern California legacy fields. During the year, Venoco drilled one well at the Coal Oil Point structure in the South Ellwood field, which is located on the north east side of the field. The lowest zone of the well tested wet, but in August, we completed a higher zone of the well, which proved to be hydrocarbon bearing and was placed on initial production on August 20, 2014. As of December 31, 2014 this zone was producing approximately 440 Bbls/d.

In the Sockeye field, we performed one recompletion and drilled one development well in the M2 zone from Platform Gail. The well began producing on October 15, 2014 and initially produced approximately 610 Bbls/d.

In 2014, the company had onshore Monterey capital expenditures of $4 million or 5% of its total 2014 capital expenditures. Over the year, the company concentrated on the Sevier area, with capital expenditures primarily on recompletion work and on leasehold, facilities and capitalized G&A.

In the West Montalvo field, we drilled and completed two new well locations and concluded the drilling and completion of two wells that were spud in 2013 prior to selling the property in October, 2014.

"In light of the weakened commodities markets, we have significantly reduced our capital program in 2015 compared to prior years. We remain poised to initiate development drilling activities should economic or market conditions improve," Mr. DePuy added. "Our current capital expenditure budget for 2015 is about $18 million with the focus primarily on operational improvements, regulatory, health, safety and environmental compliance and advancing some of our significant future long-lead projects."

"We've also enacted comprehensive expense reduction programs across our assets," Mr. DePuy added. "Our increased focus on optimizing our operational efficiencies will also help us manage the macro environment and also preserve liquidity." 

Reserves Review

The company's year-end 2014 total proved reserves were 40.4 million BOE, compared to year-end 2013 reserves of 53.1 million BOE. 

The company's 2014 roll forward of proved reserves is as follows:

    
2014 Reserve Roll forward MBOE(1)   
Beginning of the year reserves 53,060   
Revisions of previous estimates (3,361 ) 
Extensions and discoveries 281   
Purchases of reserves in place -   
Production (2,703 ) 
Sales of reserves in place (6,895 ) 
End of year reserves 40,382   
      
Proved developed reserves:     
Beginning of year 36,240   
End of year 27,777   
  
(1)Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
  

The company's 40.4 MMBOE of reserves, and the $734 million pre-tax PV-10 value of those reserves, is based on the year-end 2014 reserve report using SEC benchmark pricing of constant WTI Oil price of $94.99 per barrel and constant Henry Hub Gas price of $4.35 per MMBTU.

The following table details the company's reserve categories and PV-10 for the last three years:

         
Net Proved Reserves (end of period) 2012  2013  2014
Oil (MBbls)           
 Developed  35,115   34,508   26,287
 Undeveloped  15,320   16,266   12,273
  Total  50,435   50,774   38,560
            
Natural Gas (MMcf)           
 Developed  7,255   10,394   8,941
 Undeveloped  3,595   3,322   1,992
  Total  10,850   13,716   10,933
            
Total Proved Reserves (MBOE)(1)  52,243   53,060   40,382
            
PV-10 ($000)           
 Developed $1,076,145  $1,008,760  $495,231
 Undeveloped  433,588   449,142   239,082
  Total $1,509,733  $1,457,902  $734,313
  
(1)Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
  

Investor Presentation

In order to provide an update to investors and other interested parties, a Venoco Corporate Presentation has been uploaded to the Events & Presentations page under the Investor Relations section of the company's website at http://www.venocoinc.com.

About the Company

Venoco is an independent energy company primarily engaged in the acquisition, exploitation and development of oil and natural gas properties primarily in California. Venoco operates three offshore platforms in the Santa Barbara Channel, has non-operated interests in three other platforms and operates onshore properties in Southern California.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, capital expenditures and development projects, and all other statements except statements of historical fact, are forward-looking statements. Forward-looking statements herein include those relating to future development and other opportunities, capital expenditure plans and future liquidity. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the company's future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher than expected production costs and other expenses, pipeline curtailments by third parties, and a potential inability to complete transactions as anticipated. The company's projects are subject to numerous operating, geological and other risks and may not be successful. All forward-looking statements are made only as of the date hereof and the company undertakes no obligation to update any such statement. Further information on risks and uncertainties that may affect the company's operations and financial performance, and the forward-looking statements made herein, is available in the company's filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein.

 
 
OIL AND NATURAL GAS PRODUCTION AND PRICES
           
  Quarter Ended  Quarter Ended  Year Ended  
UNAUDITED 9/30/14  12/31/14 % Change  12/31/13  12/31/14 % Change  12/31/13  12/31/14  % Change  
 Production Volume:                                
 Oil (MBbls) (1)  642   578 -10 % 731   578 -21 % 3,180   2,555  -20 %
 Natural Gas (MMcf)  202   181 -10 % 312   181 -42 % 1,724   883  -49 %
 MBOE  676   608 -10 % 783   608 -22 % 3,467   2,702  -22 %
 Daily Average Production Volume:                                
 Oil (Bbls/d)  6,980   6,283 -10 % 7,946   6,283 -21 % 8,712   7,002  -20 %
 Natural Gas (Mcf/d)  2,196   1,976 -10 % 3,391   1,976 -42 % 4,723   2,422  -49 %
 BOE/d  7,346   6,612 -10 % 8,511   6,612 -22 % 9,499   7,406  -22 %
 Oil Price per Barrel Produced (in dollars):                                
 Realized price before hedging $87.84  $61.37 -30 %$90.55  $61.37 -32 %$95.79  $85.68  -11 %
 Realized hedging gain (loss)  (2.15 ) 16.26 -856 % (5.63 ) 16.26 -389 % (7.66 ) (0.01 )-100 %
 Net realized price $85.69  $77.63 -9 %$84.92  $77.63 -9 %$88.13  $85.67  -3 %
 Natural Gas Price per Mcf (in dollars):                                
 Realized price before hedging $4.98  $4.45 -11 %$4.48  $4.45 -1 %$4.06  $5.29  30 %
 Realized hedging gain (loss)  0.11   0.52 373 % -   0.52 0 % -   0.13  0 %
 Net realized price $5.09  $4.97 -2 %$4.48  $4.97 11 %$4.06  $5.42  33 %
 Expense per BOE (in dollars):                                
 Lease operating expenses $26.96  $27.07 0 %$29.46  $27.07 -8 %$22.44  $26.77  19 %
 Production and property taxes $3.14  $2.44 -22 %$1.86  $2.44 31 %$1.02  $2.82  176 %
 Transportation expenses $0.08  $0.07 -13 %$0.06  $0.07 17 %$0.05  $0.07  40 %
 Depreciation, depletion and amortization $17.39  $15.35 -12 %$15.72  $15.35 -2 %$14.09  $16.31  16 %
 General and administrative (2) $2.00  $1.52 -24 %$25.15  $1.52 -94 %$14.54  $7.37  -49 %
 Interest expense $20.17  $20.86 3 %$16.84  $20.86 24 %$18.78  $19.47  4 %
  
(1)Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on pipeline inventories, and oil pipeline sales nominations.
  
(2)Net of amounts capitalized.
  
  
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
           
  Quarter Ended  Quarter Ended  Year Ended  
UNAUDITED (In thousands) 9/30/14  12/31/14  12/31/13  12/31/14  12/31/13  12/31/14  
 REVENUES:                         
Oil and natural gas sales $57,242  $35,709  $66,269  $35,709  $313,373  $222,052  
Other  609   613   666   613   4,129   2,157  
Total revenues  57,851   36,322   66,935   36,322   317,502   224,209  
EXPENSES:                         
Lease operating expense  18,225   16,459   23,067   16,459   77,786   72,337  
Property and production taxes  2,124   1,481   1,459   1,481   3,521   7,611  
Transportation expense  51   44   48   44   181   201  
Depletion, depreciation and amortization  11,759   9,335   12,311   9,335   48,840   44,064  
Impairment  -   -   -   -   -   817  
Accretion of asset retirement obligation  629   639   611   639   2,477   2,491  
General and administrative  1,352   922   19,695   922   50,403   19,926  
Total expenses  34,140   28,880   57,191   28,880   183,208   147,447  
Income from operations  23,711   7,442   9,744   7,442   134,294   76,762  
FINANCING COSTS AND OTHER:                         
Interest expense  13,635   12,683   13,185   12,683   65,114   52,609  
Amortization of deferred loan costs  887   685   818   685   3,705   3,268  
Loss on extinguishment of debt  -   2,347   465   2,347   38,549   2,347  
Commodity derivative realized (gains) losses  1,355   (9,493 ) 4,118   (9,493 ) 28,128   (83 )
Commodity derivative unrealized (gains) losses and amortization of derivative premiums  (31,691 ) (78,885 ) 10,926   (78,885 ) (15,521 ) (101,816 )
Total financing costs and other  (15,814 ) (72,663 ) 29,512   (72,663 ) 119,975   (43,675 )
Income (loss) before taxes  39,525   80,105   (19,768 ) 80,105   14,319   120,437  
Income tax provision (benefit)  -   -   -   -   -   -  
Net income (loss) $39,525  $80,105  $(19,768 )$80,105  $14,319  $120,437  
                   
                   
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
        
UNAUDITED ($ in thousands) 12/31/12  12/31/13  
ASSETS         
  Cash and cash equivalents $53,818  $828  
  Accounts receivable  108,356   23,737  
  Inventories  5,101   5,166  
  Other current assets  4,448   4,587  
  Commodity derivatives  153   340  
 Total current assets  171,876   34,658  
 Net property, plant and equipment  648,602   662,629  
 Total other assets  25,603   17,569  
TOTAL ASSETS $846,081  $714,856  
LIABILITIES AND STOCKHOLDERS' EQUITY         
  Accounts payable and accrued liabilities $57,315  $32,966  
  Interest payable  27,862   17,408  
  Current maturities of long-term debt  104,494   -  
  Commodity derivatives  20,607   13,464  
  Share based compensation  10,424   20,723  
 Total current liabilities  220,702   84,561  
LONG-TERM DEBT  849,190   705,000  
COMMODITY DERIVATIVES  20,287   10,601  
ASSET RETIREMENT OBLIGATIONS  41,119   35,982  
SHARE BASED COMPENSATION  10,441   16,721  
 Total liabilities  1,141,739   852,865  
 Total stockholders' equity  (295,658 ) (138,009 )
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $846,081  $714,856  
       
       
UNAUDITED ($ in thousands) 12/31/13  12/31/14  
ASSETS         
  Cash and cash equivalents $828  $15,455  
  Accounts receivable  23,737   14,912  
  Inventories  5,166   3,370  
  Other current assets  4,587   4,715  
  Commodity derivatives  340   48,298  
  Total current assets  34,658   86,750  
  Net property, plant and equipment  662,629   488,514  
 Total other assets  17,569   40,990  
 TOTAL ASSETS $714,856  $616,254  
   LIABILITIES AND STOCKHOLDERS' EQUITY         
Accounts payable and accrued liabilities $32,966  $20,535  
Interest payable  17,408   17,329  
  Income taxes payable  -   -  
  Commodity derivatives  13,464   -  
  Share based compensation  20,723   2,236  
  Total current liabilities  84,561   40,100  
  LONG-TERM DEBT  705,000   565,000  
 DEFERRED INCOME TAXES  -   -  
COMMODITY DERIVATIVES  10,601   -  
ASSET RETIREMENT OBLIGATIONS  35,982   30,351  
SHARE BASED COMPENSATION  16,721   648  
Total liabilities  852,865   636,099  
Total stockholders' equity  (138,009 ) (19,845 )
 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $714,856  $616,254  
        
        

GAAP RECONCILIATIONS

Adjusted Earnings and Adjusted EBITDA

In addition to net income (loss) determined in accordance with GAAP, we have provided in this release our Adjusted Earnings and Adjusted EBITDA for recent periods. Both Adjusted Earnings and Adjusted EBITDA are non-GAAP financial measures that we use as supplemental measures of our performance.

We define Adjusted Earnings as net income (loss) before the effects of the items listed in the table below. We calculate the tax effect of reconciling items by re-performing our period-end tax calculation excluding the reconciling items from earnings. The difference between this calculation and the tax expense/benefit recorded for the period results in the tax effect disclosed below. We believe that Adjusted Earnings facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties. Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to our ongoing operations.

We define Adjusted EBITDA as net income (loss) before the effects of the items listed in the table below. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.

We present Adjusted Earnings and Adjusted EBITDA because we consider them to be important supplemental measures of our performance. Neither Adjusted Earnings nor Adjusted EBITDA is a measurement of our financial performance under GAAP and neither should be considered as an alternative to net income (loss), operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted Earnings or Adjusted EBITDA amounts shown are comparable to similarly named measures disclosed by other companies.

     
        
  Quarter Ended  Year Ended  
UNAUDITED ($ in thousands) 12/31/12  9/30/13  12/31/13  12/31/12  12/31/13  
Adjusted Earnings Reconciliation                     
 Net Income $(3,138 )$(2,911 )$(19,768 )$(46,587 )$14,319  
 Plus:                     
 Unrealized commodity (gains) losses  (14,480 ) 8,893   9,908   87,514   (19,523 )
 Going private related costs  5,240   -   -   9,997   -  
 Severance costs  1,496   -   -   1,496   -  
 Loss on extinguishment of debt  1,520   16,787   465   1,520   38,549  
 Tax effects  -   -   -   -   -  
 Adjusted Earnings $(9,362 )$22,769  $(9,395 )$53,940  $33,345  
                 
                 
  Quarter Ended  Year Ended  
UNAUDITED ($ in thousands) 12/31/13  9/30/14  12/31/14  12/31/13  12/31/14  
Adjusted Earnings Reconciliation                     
 Net Income $(19,768 )$39,525  $80,105  $14,319  $120,437  
 Plus:                     
 Unrealized commodity (gains) losses  9,908   (32,895 ) (80,088 ) (19,523 ) (106,631 )
One-Time Severance Costs  -   -   (208 ) -   2,816  
 Loss on extinguishment of debt  465   -   2,347   38,549   2,347  
 Tax effects  -   -   -   -   -  
 Adjusted Earnings $(9,395 )$6,630  $2,156  $33,345  $18,969  
                 
                 
  Quarter Ended  Year Ended  
UNAUDITED ($ in thousands) 12/31/13  9/30/14  12/31/14  12/31/13  12/31/14  
Adjusted EBITDA Reconciliation                     
Net income $(19,768 )$39,525  $80,105  $14,319  $120,437  
Interest expense  13,185   13,635   12,683   65,114   52,609  
Income taxes  -   -   -   -   -  
DD&A  12,311   11,759   9,335   48,840   44,064  
Impairment  -   -   -   -   817  
Accretion of asset retirement obligation  611   629   639   2,477   2,491  
Amortization of deferred loan costs  818   887   685   3,705   3,268  
Loss on extinguishment of debt  465   -   2,347   38,549   2,347  
 Share-based compensation  8,492   (4,801 ) (5,051 ) 9,680   (8,942 )
Restructuring Costs  -   -   535   -   535  
One-Time Severance Costs  -   -   (208 ) -   2,816  
Amortization of derivative premiums  1,018   1,204   1,203   4,002   4,815  
Unrealized commodity derivative (gains) losses  9,908   (32,895 ) (80,088 ) (19,523 ) (106,631 )
Adjusted EBITDA $27,040  $29,943  $22,185  $167,163  $118,626  
                
                

We also provide per BOE G&A expenses excluding severance costs related to the asset sales and non-cash share-based compensation charges. We believe that these non-GAAP measures are useful in that the items excluded do not represent cash expenses directly related to our ongoing operations. These non-GAAP measures should not be viewed as an alternative to per BOE G&A expenses as determined in accordance with GAAP.

       
       
UNAUDITED ($ in thousands, except per BOE amounts) Quarter Ended Year Ended  
  12/31/13  9/30/14 12/31/14 12/31/13  12/31/14  
G&A per BOE Reconciliation                   
                    
 G&A expense $19,695  $1,352 $922 $50,403  $19,926  
 Less:                   
 Non-cash share-based compensation expense  (8,492 ) 3,574  2,837  (9,680 ) 5,761  
One-Time Severance Costs  -   -  -  -   (3,024 )
 G&A Expense Excluding Share-Based Comp and Severance Costs  11,203   4,926  3,759  40,723   22,663  
 MBOE  783   676  608  3,467   2,702  
G&A Expense per BOE Excluding Share-Based Comp and Severance Costs $14.31  $7.29 $6.18 $11.75  $8.39  
 MBOE excluding production from Sold Assets  645   553  566  2,773   2,271  
G&A Expense per BOE Excluding Non-Cash Share-Based Comp -Excluding Production from Sold Assets $17.37  $8.91 $6.64 $14.69  $9.98  
              
              

PV-10

The present value of future net cash flows (PV-10 value) is a non-GAAP measure because it excludes income tax effects. Management believes that before-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company's unique tax position and strategies, can make after-tax amounts less comparable. We derive PV-10 value based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using the arithmetic twelve-month average of the first of the month prices without giving effect to hedging activities or future escalation, and costs as of the date of estimate without future escalation, excluding non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%.

The following table reconciles the standardized measure of future net cash flows to PV-10 value (in thousands):

       
UNAUDITED ($ in thousands) 12/31/2011 12/31/2012 12/31/2013
          
 Standardized measure of discounted future net cash flows $1,364,146 $1,157,452 $1,153,717
 Add: Present value of future income tax discounted at 10%  442,355  352,281  304,185
 PV-10 at year end SEC prices $1,806,501 $1,509,733 $1,457,902
       
UNAUDITED ($ in thousands) 12/31/2012 12/31/2013 12/31/2014
          
 Standardized measure of discounted future net cash flows $1,157,452 $1,153,717 $648,154
 Add: Present value of future income tax discounted at 10%  352,281  304,185  38,270
 PV-10 at year end SEC prices $1,509,733 $1,457,902 $734,313
        

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