SOURCE: Venoco, Inc.

Venoco, Inc.

April 10, 2014 06:30 ET

Venoco, Inc. Announces Year-End 2013 Reserves and 4th Quarter and Full-Year 2013 Financial and Operational Results

8% Increase in Oil Production Over 2012; Adjusted EBITDA of $167.2 Million; Net Pro Forma Proved Reserve Additions of 4.2 Million BOE

DENVER, CO--(Marketwired - Apr 10, 2014) - Venoco, Inc. today reported financial and operational results for the fourth quarter and full-year 2013. The company reported net income for the year of $14.3 million on total revenues of $318 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain one-time charges, were $33 million for the year, and Adjusted EBITDA was $167 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 3.5 million barrels of oil equivalent (MMBOE) for the year, or 9,499 BOE per day (BOE/d); excluding volumes contributed by Sacramento Basin properties held in escrow during the first quarter of 2013, production for the year was 3.4 MMBOE or 9,220 BOE/d.

  • Oil production of 3.2 million barrels for the year, or 8,712 barrels per day (Bbls/d), an 8% increase over 2012 oil production.

  • Proved reserves of 53.1 MMBOE as of December 31, 2013, compared to 52.2 MMBOE as of December 31, 2012. PV-10 was $1.5 billion as of December 31, 2013. 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 well to a probable location in Coal Oil Point, a separate geologic structure in the South Ellwood field and located northeast of Platform Holly.

  • Repayment of $150 million of 11.50% senior unsecured notes as a result of a capital contribution from Denver Parent Corporation.

"2013 was an eventful year as we continued to concentrate our efforts and capital on our oily Southern California assets," said Ed O'Donnell, Venoco's CEO. "We are encouraged by drilling results at both our Montalvo and South Ellwood fields, and look forward to continuing our capital program at those fields in 2014, including drilling our second well into the Coal Oil Point structure at South Ellwood. Additionally, we look forward to reinitiating our drilling program at Platform Gail at the Sockeye field later this year. We will also perform a seismic shoot over our Montalvo field, which should advance the science of the area for future drilling efforts."

Fourth Quarter and Full-Year Production

Production in the fourth quarter of 2013 was 8,511 BOE/d compared to 9,036 BOE/d in the third quarter of 2013 and 8,718 BOE/d in the fourth quarter of 2012, pro forma for the sale of the Sacramento Basin. Also pro forma for the sale of the Sacramento Basin, full year production for 2013 was 9,220 BOE/d compared to 8,433 BOE/d in 2012. Oil production in the fourth quarter of 2013 of 7,946 Bbls/d was down compared to 8,543 Bbls/d in the third quarter of 2013, primarily as a result of scheduled annual maintenance at the company's South Ellwood field. Fourth quarter 2013 oil production of 7,946 was down 5% compared to oil production of 8,348 Bbls/d in the fourth quarter of 2012. Oil production was up 8% for the full year 2013, to 8,712 Bbls/d from 8,033 Bbls/d in 2012, primarily as a result of successful drilling at the company's South Ellwood and West Montalvo fields during 2013.

"Our fourth quarter 2013 production was significantly affected by the scheduled annual maintenance shutdown at South Ellwood, which occurred mainly in early October. The field was down for seven days during the quarter, which resulted in the loss of approximately 325 - 350 BOE/d for the quarter," commented Mr. O'Donnell. "Also, as discussed in our third quarter earnings call, late last year we inserted pressure gauges in several of the wells at South Ellwood to help us evaluate potential communication issues in the field. While analysis remains ongoing, it appears that several wells are in communication. However, the data also shows that production rates from these wells are stabilizing following initial decline."

"Also, we have begun 2014 with a slower start than anticipated as we were alerted in January that the third-party common carrier pipeline which transports our South Ellwood oil would be shut down for several days in March to repair a corroded section of pipe," Mr. O'Donnell continued. "In order to minimize field downtime for the year, we elected to move our annual South Ellwood platform shutdown from October, 2014 up to March to coincide with the shutdown of the pipeline." 

Excluding volumes from properties held in escrow during the first quarter of 2013 following the Sacramento Basin sale, we are expecting to see an increase in production in 2014 compared to 2013. A portion of the production increase is expected to come from a development well in the Coal Oil Point structure at South Ellwood, a follow up to last year's 3242-19 well. 

"Our first Coal Oil Point well yielded positive results in that we intersected the uppermost interval of seven Monterey zones, which is typically not the most productive zone, and found oil. Building upon what we learned in drilling that well, particularly the upthrust nature of the structure, we have designed the wellbore path for the 3242-20 well (the follow-up to our 3242-19 well) to intersect all seven Monterey zones, which we believe will result in enhanced production rates over last year's well," Mr. O'Donnell added.

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

                 
                Full Year(2)
Region   4Q 2012   3Q 2013   4Q 2013   2012   2013
Southern California   8,718   9,036   8,511   8,410   9,220
Sacramento Basin   8,221   -   -   8,926   279
Total   16,939   9,036   8,511   17,336   9,499
   
(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) Full year 2013 production from the Sacramento basin relates to properties that were held in escrow pending the receipt of consents regarding the transfer of ownership. On May 1, 2013, title to all remaining properties included in the sale on December 31, 2012 was transferred.
   

Fourth Quarter and Full-Year Costs

Venoco's fourth quarter 2013 lease operating expenses of $29.46 per BOE were up from $21.99 per BOE in the third quarter. The fourth quarter expenses were negatively affected by the scheduled annual maintenance performed at the South Ellwood field during the quarter, which resulted in higher LOE costs and reduced production levels. Pro forma for the sale of the Sacramento Basin properties, the company's full year 2013 lease operating expenses were $22.95 per BOE, down from full year 2012 pro forma lease operating expenses of $24.85 per BOE.

Venoco's fourth quarter G&A costs, excluding non-cash share-based compensation was $14.31 per BOE compared to $9.26 per BOE in the third quarter. The company's full year 2013 G&A costs, excluding the severance costs related to the sale of the Sacramento Basin and non-cash share-based compensation, and also excluding production from the Sacramento Basin properties held in escrow during the first quarter of the year, were $12.10 per BOE, down from $12.64 per BOE in 2012.

Property and production taxes for the full year 2013 were $1.02 per BOE compared to $1.53 per BOE in 2012. The decrease is primarily the result of lower supplemental ad valorem taxes.

         
    Quarter Ended   Year Ended
UNAUDITED (per BOE)   12/31/12   9/30/13     12/31/13   12/31/12   12/31/13
Lease Operating Expenses   $ 15.69   $ 21.99     $ 29.46   $ 14.48   $ 22.44
Property and Production Taxes     0.71     (0.57 )     1.86     1.53     1.02
DD&A Expense     13.53     15.10       15.72     13.68     14.09
G&A Expense (1)     8.47     9.26       14.31     6.13     11.75
                                 
(1) Net of amounts capitalized and excluding non-cash share-based compensation costs, costs related to the going-private transaction and severance costs associated with the sale of our Sacramento Basin assets. See the end of this release for a reconciliation of G&A per BOE.
   

Capital Investment 2013

Venoco's 2013 capital expenditures for exploration, exploitation, development and other spending were $96 million, including $59 million for drilling and rework activities, $13 million for facilities, and the remaining $24 million for land, seismic and capitalized G&A. 

In 2013, the company spent $88 million or 92% of its capital expenditures on its Southern California legacy fields. At the South Ellwood field, the company drilled and completed three wells during 2013. During the first quarter, we completed one well (3242-4RD), which was a re-drill of a wet well originally completed in 2012. During the second quarter, we drilled the 3242-15RD well, which bottoms near the eastern boundary of the lease, and was completed in July. After drilling the 3242-15RD well, we returned to drilling the 3242-19 well, which was suspended earlier in the year. The 3242-19 well, as discussed above, targeted a probable location in a separate geologic structure, Coal Oil Point, northeast of Platform Holly in the South Ellwood field. In addition, during the year, we replaced the existing de-rated power cable to Platform Holly. The new power cable provides the ability to place additional wells on electric submersible pump (in lieu of gas lift), which is expected to improve recovery capabilities. In 2013, $7 million was spent on the power cable installation. 

At the West Montalvo field, the company spud four wells and completed two, all targeting the offshore portion of the field. The remaining two wells were completed in early 2014. Net production at West Montalvo was approximately 1,484 BOE per day in the fourth quarter of 2013. Before wells drilled and completed in this field can be placed on artificial lift, they must be allowed to produce under natural reservoir pressure until production diminishes to a "low-flow" level, a process that may require several months. Production typically increases significantly once the well is placed on artificial lift. Of the two wells we completed in the field in 2013, one is currently on artificial lift, and the other is still free-flowing. Production from those wells averaged approximately 280 gross BOE/d during the beginning of 2014. We spent $26 million at West Montalvo, which was $4 million lower than the original full-year 2013 budget due to a delay in the start of our drilling program due to the unavailability of a drilling rig.

During 2013, no significant development projects were performed at the Sockeye field. 

In 2013, the company had onshore Monterey capital expenditures of $8 million or 8% of its total 2013 capital expenditures. Over the year, the company concentrated on the Sevier area, with approximately $2 million incurred for recompletion work and $6 million on leasehold, facilities and capitalized G&A.

The company's capital expenditure budget for 2014 is $88 million. Of that amount, $84 million is anticipated to be spent at the company's legacy Southern California properties. At South Ellwood, the company's capital budget includes one electric submersible pump installation, which was completed during the first quarter, and the drilling and completion of a development well at Coal Oil Point as discussed above. At Montalvo, the company plans to drill two proved undeveloped locations and two probable locations in 2014. The budget also includes plans for the completion of two Montalvo wells spud in 2013. Also in 2014, the company plans to drill two development wells in the M-2 zone from Platform Gail and to perform one recompletion. Production at Sockeye currently includes production from the M-2 zone, and the 2014 budget contemplates the drilling of infill development wells in the M-2 because we believe it to be an underdeveloped zone.

The company's 2014 capital expenditure budget for the onshore Monterey shale project has been further reduced from 2013 levels to $4 million in 2014. Similar to 2013, the company's focus with respect to the onshore Monterey shale will be on the Sevier field, as the capital expenditure budget contemplates only minimal spending on leasehold and capitalized G&A. The agreement governing the company's revolving credit facility limits the amount of capital that can be deployed in onshore Monterey activities.

Reserves Review

The company's year-end 2013 total proved reserves were 53.1 million BOE, compared to year-end 2012 reserves of 52.2 million BOE. Pro forma for the sale of the Sacramento Basin, after adjusting for 2013 production, the company added reserves of 4.2 million BOE, including revisions, extensions and discoveries, which is primarily related to successful wells drilled at South Ellwood and Montalvo during the year, and due to higher proved developed producing estimates at Sockeye.

The company's 2013 rollforward of proved reserves is as follows:

     
2013 Reserve Rollforward MBOE(1)  
Beginning of the year reserves 52,243  
Revisions of previous estimates (874 )
Extensions and discoveries 5,056  
Purchases of reserves in place -  
Production(2) (3,365 )
Sales of reserves in place -  
End of year reserves 53,060  
     
Proved developed reserves:    
Beginning of year 36,324  
End of year 36,240  
(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) Excludes volumes from Sacramento Basin properties held in escrow during the first quarter of 2013.
   

The $1.5 billion pre-tax PV-10 value of the company's 53.1 MMBOE of reserves is based on SEC benchmark pricing of $98.37 per barrel of oil, $79.04 for NGLs, and $4.41 per MMBTU for gas. 

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

             
Net Proved Reserves (end of period)   2011   2012   2013
Oil (MBbls)                  
  Developed     25,131     35,115     34,508
  Undeveloped     22,282     15,320     16,266
    Total     47,413     50,435     50,774
                   
Natural Gas (MMcf)                  
  Developed     141,806     7,255     10,394
  Undeveloped     149,018     3,595     3,322
    Total     290,824     10,850     13,716
                   
Total Proved Reserves (MBOE)(1)     95,884     52,243     53,060
                   
PV-10 ($000)                  
  Developed   $ 990,303   $ 1,076,145   $ 1,008,760
  Undeveloped     816,198     433,588     449,142
    Total   $ 1,806,501   $ 1,509,733   $ 1,457,902
(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.
   

Earnings Conference Call

Venoco will host a conference call to discuss results Thursday, April 10, 2014 at 11:00 a.m. Eastern time (9 a.m. Mountain). The conference call will be webcast and those wanting to listen may do so by using a link on the Investor Relations page of the company's website at http://www.venocoinc.com. Those wanting to participate in the Q & A portion can call (888) 680-0890 and use conference code 22583542. International participants can call (617) 213-4857 and use the same conference code.

A replay of the conference call will be available for one week by calling (888) 286-8010 or, for international callers, (617) 801-6888, and using passcode 49245216. The replay will also be available on the Venoco website for 30 days.

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 several onshore properties in Southern California.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, reserves, expenses, capital expenditures and development projects, and all other statements except statements of historical fact, are forward-looking statements. 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, and pipeline curtailments by third parties. The company's activities with respect to the onshore Monterey Shale and other projects are subject to numerous operating, geological and other risks and may not be successful. The company's results in the onshore Monterey Shale will be subject to greater risks than in areas where it has more data and drilling and production experience. Results from the company's onshore Monterey Shale project will depend on, among other things, its ability to identify productive intervals and drilling and completion techniques necessary to achieve commercial production from those intervals. 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.

References to reserve estimates other than proved are by their nature more uncertain than estimates of proved reserves, and are subject to substantially greater risk of not actually being realized by the company.

For further information, please contact Zach Shulman, Investor Relations, (303) 583-1637; http://www.venocoinc.com; E-Mail investor@venocoinc.com.

 
OIL AND NATURAL GAS PRODUCTION AND PRICES
   
    Quarter Ended     Quarter Ended     Year Ended  
UNAUDITED   9/30/13     12/31/13     % Change     12/31/12     12/31/13     % Change     12/31/12     12/31/13     % Change  
Production Volume:                                                                  
Oil (MBbls) (1)     786       731     -7 %     768       731     -5 %     2,940       3,180     8 %
Natural Gas (MMcf)     272       312     15 %     4,742       312     -93 %     20,430       1,724     -92 %
MBOE     831       783     -6 %     1,558       783     -50 %     6,345       3,467     -45 %
Daily Average Production Volume:                                                                  
Oil (Bbls/d)     8,543       7,946     -7 %     8,348       7,946     -5 %     8,033       8,712     8 %
Natural Gas (Mcf/d)     2,957       3,391     15 %     51,543       3,391     -93 %     55,820       4,723     -92 %
BOE/d     9,036       8,511     -6 %     16,939       8,511     -50 %     17,336       9,499     -45 %
Oil Price per Barrel Produced (in dollars):                                                                  
Realized price before hedging   $ 99.16     $ 90.55     -9 %   $ 94.53     $ 90.55     -4 %   $ 97.28     $ 95.79     -2 %
Realized hedging gain (loss)     (5.42 )     (5.63 )   4 %     (11.08 )     (5.63 )   -49 %     (10.32 )     (7.66 )   -26 %
Net realized price   $ 93.74     $ 84.92     -9 %   $ 83.45     $ 84.92     2 %   $ 86.96     $ 88.13     1 %
Natural Gas Price per Mcf (in dollars):                                                                  
Realized price before hedging   $ 4.19     $ 4.48     7 %   $ 3.60     $ 4.48     24 %   $ 2.88     $ 4.06     41 %
Realized hedging gain (loss)     -       -     0 %     (0.09 )     -     -100 %     0.25       -     -100 %
Net realized price   $ 4.19     $ 4.48     7 %   $ 3.51     $ 4.48     28 %   $ 3.13     $ 4.06     30 %
Expense per BOE (in dollars):                                                                  
Lease operating expenses   $ 21.99     $ 29.46     34 %   $ 15.69     $ 29.46     88 %   $ 14.48     $ 22.44     55 %
Production and property taxes   $ (0.57 )   $ 1.86     -426 %   $ 0.71     $ 1.86     162 %   $ 1.53     $ 1.02     -33 %
Transportation expenses   $ 0.06     $ 0.06     0 %   $ 0.01     $ 0.06     500 %   $ 0.81     $ 0.05     -94 %
Depreciation, depletion and amortization   $ 15.10     $ 15.72     4 %   $ 13.53     $ 15.72     16 %   $ 13.68     $ 14.09     3 %
General and administrative (2)   $ 6.45     $ 25.15     290 %   $ 13.56     $ 25.15     85 %   $ 8.70     $ 14.54     67 %
Interest expense   $ 18.86     $ 16.84     -11 %   $ 14.96     $ 16.84     13 %   $ 11.25     $ 18.78     67 %
                   
(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, oil pipeline sales nominations, and prior to February 2012, the timing of barge deliveries and oil in tanks.
 
(2) Net of amounts capitalized.       
 
 
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
    Quarter Ended     Quarter Ended     Year Ended  
UNAUDITED (In thousands)   9/30/13     12/31/13     12/31/12     12/31/13     12/31/12     12/31/13  
REVENUES:                                                
Oil and natural gas sales   $ 79,696     $ 66,269     $ 90,725     $ 66,269     $ 350,426     $ 313,373  
Other     1,249       666       1,231       666       6,090       4,129  
Total revenues     80,945       66,935       91,956       66,935       356,516       317,502  
EXPENSES:                                                
Lease operating expense     18,274       23,067       24,446       23,067       91,888       77,786  
Property and production taxes     (472 )     1,459       1,100       1,459       9,688       3,521  
Transportation expense     50       48       18       48       5,169       181  
Depletion, depreciation and amortization     12,551       12,311       21,073       12,311       86,780       48,840  
Accretion of asset retirement obligation     595       611       1,470       611       5,768       2,477  
General and administrative     5,358       19,695       21,134       19,695       55,186       50,403  
Total expenses     36,356       57,191       69,241       57,191       254,479       183,208  
Income from operations     44,589       9,744       22,715       9,744       102,037       134,294  
FINANCING COSTS AND OTHER:                                                
Interest expense     15,674       13,185       23,310       13,185       71,399       65,114  
Amortization of deferred loan costs     868       818       1,005       818       2,756       3,705  
Loss on extinguishment of debt     16,787       465       1,520       465       1,520       38,549  
Commodity derivative realized (gains) losses     4,261       4,118       13,296       4,118       (26,989 )     28,128  
Commodity derivative unrealized (gains) losses and amortization of derivative premiums     9,910       10,926       (13,278 )     10,926       99,938       (15,521 )
Total financing costs and other     47,500       29,512       25,853       29,512       148,624       119,975  
Income (loss) before taxes     (2,911 )     (19,768 )     (3,138 )     (19,768 )     (46,587 )     14,319  
Income tax provision (benefit)     -       -       -       -       -       -  
Net income (loss)   $ (2,911 )   $ (19,768 )   $ (3,138 )   $ (19,768 )   $ (46,587 )   $ 14,319  
                                                 
 
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  
                 

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)   12/31/12     9/30/13     12/31/13     12/31/12     12/31/13  
Adjusted EBITDA Reconciliation                                        
Net income   $ (3,138 )   $ (2,911 )   $ (19,768 )   $ (46,587 )   $ 14,319  
Interest expense     23,310       15,674       13,185       71,399       65,114  
DD&A     21,073       12,551       12,311       86,780       48,840  
Accretion of asset retirement obligation     1,470       595       611       5,768       2,477  
Amortization of deferred loan costs     1,005       868       818       2,756       3,705  
Loss on extinguishment of debt     1,520       16,787       465       1,520       38,549  
Non-cash share-based compensation expense     1,952       (2,335 )     8,492       6,197       9,680  
Going private related costs     5,240       -       -       9,997       -  
Sacramento Basin severance costs     1,496       -       -       1,496       -  
Amortization of derivative premiums     1,202       1,017       1,018       12,424       4,002  
Unrealized commodity derivative (gains) losses     (14,480 )     8,893       9,908       87,514       (19,523 )
Adjusted EBITDA   $ 40,650     $ 51,139     $ 27,040     $ 239,264     $ 167,163  
                                         

We also provide per BOE G&A expenses excluding costs associated with the going-private transaction, severance costs related to the sale of the Sacramento Basin assets 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  
    12/31/12     9/30/13   12/31/13     12/31/12     12/31/13  
G&A per BOE Reconciliation                                      
                                       
G&A expense   $ 21,134     $ 5,358   $ 19,695     $ 55,186     $ 50,403  
Less:                                      
Non-cash share-based compensation expense     (1,500 )     2,335     (8,492 )     (5,075 )     (9,680 )
Going private related costs     (5,240 )     -     -       (9,997 )     -  
Sacramento Basin severance costs     (1,200 )     -     -       (1,200 )     -  
G&A Expense Excluding Share-Based Comp and Going Private Costs     13,194       7,693     11,203       38,914       40,723  
MBOE     1,558       831     783       6,345       3,467  
G&A Expense per BOE Excluding Share-Based Comp and Going Private Costs   $ 8.47     $ 9.26   $ 14.31     $ 6.13     $ 11.75  
MBOE excluding Sacramento Basin production     802       -     -       3,078       3,365  
G&A Expense per BOE Excluding Non-Cash Share-Based Comp and Going Private Costs-Excluding Sacramento Basin Production   $ 16.45     $ 9.26   $ 14.31     $ 12.64     $ 12.10  
                                       

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
                   

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