SOURCE: Venoco, Inc.

Venoco, Inc.

November 20, 2014 05:30 ET

Venoco, Inc. Announces 3rd Quarter 2014 Financial and Operational Results

Second Successful Well Completed at Coal Oil Point Prospect; Sale of West Montalvo Field Closed October, 2014 for $200.2 Million

DENVER, CO--(Marketwired - Nov 20, 2014) - Venoco, Inc. ("Venoco" or the "company") today reported financial and operational results for the third quarter of 2014. The company reported net income of $39.5 million for the quarter on total revenues of $57.9 million.

The Company experienced reduced income from operations for the first nine months of 2014 compared to the first nine months of 2013, due primarily to production and pricing declines. However, there was a significant increase in net income as a result of changes in the valuation of hedging positions in the third quarter of 2014 versus a loss on the extinguishment of debt recorded in the third quarter of 2013.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain other items, were $6.6 million for the quarter, up from $4.4 million in the second quarter of 2014. Adjusted EBITDA was $29.9 million in the third quarter of 2014, compared to $36.1 million in the second quarter. 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 676 thousand barrels of oil equivalent (MBOE) for the quarter, or 7,344 BOE per day (BOE/d).

  • Second successful completion of a well in the Coal Oil Point Prospect, northeast of Platform Holly in the South Ellwood field.

  • Initiated drilling efforts during the third quarter for a development infill well at Platform Gail, Sockeye Field, targeting the Monterey zone (M2), and completed the well early in the fourth quarter.

  • Sale of West Montalvo properties and acreage on October 29, 2014 for $200.2 million.

During the third quarter, Venoco successfully completed a well to a proved location in the Coal Oil Point Prospect, located to the northeast of Platform Holly in the South Ellwood field. The well successfully intersected all targeted horizons in the Monterey. The well was completed in three phases, the first of which occurred during the second quarter, where the lowest three zones tested wet. Although good hydrocarbon shows were seen while drilling the lower sections of the Monterey, commercial hydrocarbons were not found which is also consistent with this portion of the reservoir found elsewhere at South Ellwood. The well was subsequently recompleted in 2 stages successfully adding the middle and upper sections of the Monterey, during the third quarter. The well was placed back on production in late August, and after cleaning up, it was producing at an average rate of about 360 gross barrels of oil per day. The well is currently producing 450 gross barrels of oil per day.

"This well affirmed our initial analysis of the fault block following the drilling of the 3242-19 well at Coal Oil Point in 2013. We were encouraged by the positive results from last year's well which intersected only the uppermost interval of seven Monterey zones. Our team applied the information gathered over the past year toward the design of this year's 3242-20 well, which in many respects was a world-class drilling and completion program," stated Mark DePuy, Venoco's CEO. "This new well intersected and all seven zones, which was a remarkable achievement given the complex geology and significant reach to the formation from Platform Holly. "Although not all seven zones are productive, several are, and the sustained downhole pressures and rates suggest this well will be a very solid producer for years to come. We will continue to analyze the results from this well and evaluate the potential for further development in the area."

Recent Events

On October 29, 2014, the Company sold all of its producing properties in the West Montalvo field in Ventura County to an unrelated third party for $200.2 million. The proceeds were applied towards the outstanding balance on Venoco's revolving credit facility.

"The sale of West Montalvo highlights our continued focus on reducing our outstanding debt, particularly our revolving credit facility debt," Mr. DePuy said. "We purchased West Montalvo in 2007, at a time when the field was producing about 700 barrels of oil equivalent per day. As a testament to our track record of redeveloping and unlocking value in mature fields, our team was able to significantly ramp up production and build a compelling inventory of new development projects over the past few years at Montalvo. As much as we regret having to sell Montalvo we have garnered excellent economic returns on our investment and received what we consider to be excellent value for this asset," Mr. DePuy added.

On November 3, 2014, the Company engaged Opportune LLP ("Opportune") to provide various accounting advisory and consulting services to it and Denver Parent Corporation ("DPC,") following the departures of Timothy Ficker, Chief Financial Officer, and Douglas Griggs, Chief Accounting Officer. As part of that engagement, Scott Pinsonnault of Opportune was named interim Chief Financial Officer of Venoco and DPC.

Additionally on November 3, 2014, Heather Hatfield assumed the duties of principal accounting officer of the Company. Ms. Hatfield was previously serving as Venoco's Internal Audit Director.

"While recognizing the enormous contributions Tim and Doug made to the Company for many years, we are delighted to have Scott and Heather with us in these key managerial roles," said Mr. DePuy. "Scott's impressive background makes him very well suited to lead our accounting and financial groups during this transitional period. When coupled with Heather's knowledge base and our experienced accounting team in place, we are confident in the capabilities of our financial and reporting functions. Scott is quickly coming up to speed on our assets, our operations, and management systems and controls. Because our near term focus on settling recent organizational changes, ongoing review of 2015 capital budget considerations and sorting through strategic alternatives given recent volatility and changes in the commodity markets, we will not hold an operational and financial update conference call at this time. We will communicate key activities and action plans as they become more definitive."

"I am very excited at the prospect of working with the Venoco staff and senior managers during this time," Mr. Pinsonnault stated. "I am impressed with the staff Mr. Ficker and Mr. Griggs built here, and look forward to leading this group, and also helping the Company execute a variety of near-term strategic objectives." 

Additionally, on November 6, 2014 the Company engaged Blackstone Advisory Partners, L.P. ("Blackstone") to provide various advisory and consulting services. During the engagement, Jonathan Lurvey of Blackstone will lead a team of energy industry advisory professionals in a number of capacities pertaining to development and implementation of strategic alternatives including facilitation of targeted acquisition and growth opportunities, evaluation and monetization of certain non-core assets, and capital structure considerations. 

Third Quarter 2014 Production

Production in the third quarter of 2014 was 7,344 BOE/d compared to 7,907 BOE/d in the second quarter of 2014 and 9,036 BOE/d in the third quarter of 2013. Pro forma for the sale of West Montalvo, production in the third quarter of 2014 was 6,013 BOE/d compared to 6,456 BOE/d in the second quarter of 2014, and 7,468 BOE/d in the third quarter of 2013. 

Additional pro forma information for the West Montalvo sale was made available in a Form 8-K filed with the SEC on November 4, 2014.

"A variety of unforeseen events, including a prolonged third-party pipeline shutdown in the first quarter, and a couple of key electric submersible pump failures forced us to divert resources and resulted in unexpected production shortfalls in the third quarter and earlier quarters, as well as the need to alter our planned drilling schedule for the year," Mr. DePuy added. "However, our recent drilling efforts at Coal Oil Point were successful although delayed, and we are very encouraged with the progress and early indications of the Sockeye E-29 well that was in the process of being drilling during the 3rd quarter."

"Our recent drilling success on Platform Gail during the third quarter was a positive and encouraging event taking us into the fourth quarter. Over the month of November, the well produced approximately 460 gross barrels of oil per day, which was above expectations. While it is still early, we are optimistic that this well will continue to produce at a solid rate during the fourth quarter and into next year," said Mr. DePuy. 

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

         
    Quarter Ended   Nine Months Ended
Region   9/30/13   6/30/14   9/30/14   9/30/13   9/30/14
Southern California (excl. W. Montalvo)   7,468   6,456   6,013   7,803   6,259
West Montalvo   1,568   1,451   1,331   1,657   1,415
Sacramento Basin(2)   -   -   -   373   -
  Total   9,036   7,907   7,344   9,833   7,674
   
(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) Nine months ended 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 to the purchaser.
   

Third Quarter 2014 Costs

Venoco's third quarter 2014 lease operating expenses of $26.96 per BOE were up from $25.26 per BOE in the second quarter of 2014 and $21.99 per BOE in the third quarter of 2013. On an absolute basis our LOE was essentially flat with the second quarter 2014 and third quarter 2013. Pro forma for the sale of the West Montalvo field, third quarter 2014 LOE per BOE was $27.10 compared to $26.56 per BOE in the second quarter of 2014 and $22.50 per BOE in the third quarter of 2013.

Venoco's third quarter G&A costs, excluding one-time severance costs and non-cash share-based compensation, were $7.29 per BOE compared to $8.33 per BOE in the second quarter of 2014 and $9.26 per BOE in the third quarter of 2013. On an absolute basis, and excluding the costs outlined above, G&A expense was $4.9 million, down 18% from second quarter 2014 and 36% from third quarter 2013. Excluding production from the West Montalvo properties, Venoco's per barrel G&A costs, excluding the costs outlined above, were $8.91 per BOE in the third quarter of 2014 compared to $10.21 per BOE in the second quarter of 2014 and $11.20 per BOE in the third quarter of 2013. Please see the end of this release for relevant GAAP reconciliations.

Venoco's third quarter property and production tax expense was $2.1 million compared to $2.3 million in the second quarter of 2014 and $(0.5) million in the third quarter of 2013. Pro forma for the sale of the West Montalvo field, third quarter 2014 property and production tax expense was $1.8 million compared to $1.7 million in the second quarter of 2014 and $(0.6) million in the third quarter of 2013.

The following table details the company's operating costs on a per BOE basis (BOE/d):

         
    Quarter Ended   Nine Months Ended
UNAUDITED (per BOE)   9/30/13     6/30/14   9/30/14   9/30/13   9/30/14
Lease Operating Expenses   $ 21.99     $ 25.26   $ 26.96   $ 20.39   $ 26.67
Property and Production Taxes     (0.57 )     3.15     3.14     0.77     2.93
DD&A Expense     15.10       16.38     17.39     13.61     16.58
G&A Expense (1)     9.26       8.33     7.29     11.00     9.02
                                 
(1) Net of amounts capitalized and excluding non-cash share-based compensation costs and one-time severance costs.See the end of this release for a reconciliation of G&A per BOE.
   

Third Quarter 2014 Capital Investment

Venoco's third quarter 2014 capital expenditures for exploration, development and other spending were $17 million, including $16 million for drilling and rework activities, and the remaining $1 million for facilities, land, seismic, and capitalized G&A. Excluding the capital expenditures associated with West Montalvo, third quarter 2014 capital expenditures for exploration, development and other spending were $12 million, including $11 million for drilling and rework activities, and the remaining $1 million for facilities, land, seismic, and capitalized G&A.

In the third quarter, the Company spent $16.5 million or 97% of its capital expenditures on its Southern California legacy fields, a significant amount of which was incurred at the South Ellwood field. During the quarter, the company continued with completion and testing activities on the 3242-20 well in the South Ellwood field, which was drilled into the Coal Oil Point Prospect.

Additionally during the quarter, the Company spud the E-29 well at the Sockeye field, into the Monterey 2 (M2) zone off Platform Gail. The Company spent approximately $7 million on the drilling of the well during the quarter. The well began producing on October 15, 2014 and initially produced approximately 610 gross barrels of oil per day.

In the third quarter of 2014, the company had relatively minimal onshore Monterey capital expenditures of $0.5 million or 3% of its total third quarter capital expenditures.

DPC Financial Statements

The indentures governing the senior PIK / toggle notes issued by DPC require DPC to file periodic reports with the SEC beginning with the quarter ended September 30, 2013. DPC and Venoco have filed a combined report on Form 10-Q for the quarter that includes information for both companies.

Information Regarding Earnings Conference Call

In light of the recent significant events outlined above, Venoco will not host a conference call in connection with its third quarter 2014 results. 

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, 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 production and well performance and drilling and development opportunities. 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 and/or to obtain waivers to or amendments of Venoco's revolving credit facility as needed. 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.

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. Initial and test results from a well may not be indicative of the well's longer-term performance.

 
OIL AND NATURAL GAS PRODUCTION AND PRICES 
   
    Quarter Ended     Quarter Ended     Nine Months Ended  
UNAUDITED   6/30/14     9/30/14     % Change     9/30/13     9/30/14     % Change     9/30/13     9/30/14     % Change  
Production Volume:                                                                  
Oil (MBbls) (1)     681       642     -6 %     786       642     -18 %     2,449       1,978     -19 %
Natural Gas (MMcf)     231       202     -13 %     272       202     -26 %     1,412       702     -50 %
MBOE     720       676     -6 %     831       676     -19 %     2,684       2,095     -22 %
Daily Average Production Volume:                                                                  
Oil (Bbls/d)     7,484       6,978     -7 %     8,543       6,978     -18 %     8,971       7,245     -19 %
Natural Gas (Mcf/d)     2,538       2,196     -13 %     2,957       2,196     -26 %     5,172       2,571     -50 %
BOE/d     7,907       7,344     -7 %     9,036       7,344     -19 %     9,833       7,674     -22 %
Oil Price per Barrel Produced (in dollars):                                                                  
Realized price before hedging   $ 95.63     $ 87.84     -8 %   $ 99.16     $ 87.84     -11 %   $ 97.36     $ 92.74     -5 %
Realized hedging gain (loss)     (6.65 )     (2.14 )   -68 %     (5.42 )     (2.14 )   -61 %     (5.93 )     (4.77 )   -20 %
Net realized price   $ 88.98     $ 85.70     -4 %   $ 93.74     $ 85.70     -9 %   $ 91.43     $ 87.97     -4 %
Natural Gas Price per Mcf (in dollars):                                                                  
Realized price before hedging   $ 5.35     $ 4.98     -7 %   $ 4.19     $ 4.98     19 %   $ 3.97     $ 5.51     39 %
Realized hedging gain (loss)     -       0.11     100 %     -       0.11     100 %     -       0.03     100 %
Net realized price   $ 5.35     $ 5.09     -5 %   $ 4.19     $ 5.09     21 %   $ 3.97     $ 5.54     40 %
Expense per BOE (in dollars):                                                                  
Lease operating expenses   $ 25.26     $ 26.96     7 %   $ 21.99     $ 26.96     23 %   $ 20.39     $ 26.67     31 %
Production and property taxes   $ 3.15     $ 3.14     0 %   $ (0.57 )   $ 3.14     -651 %   $ 0.77     $ 2.93     281 %
Transportation expenses   $ 0.07     $ 0.08     14 %   $ 0.06     $ 0.08     33 %   $ 0.05     $ 0.07     40 %
Depreciation, depletion and amortization   $ 16.38     $ 17.39     6 %   $ 15.10     $ 17.39     15 %   $ 13.61     $ 16.58     22 %
General and administrative (2)   $ 12.49     $ 2.00     -84 %   $ 6.45     $ 2.00     -69 %   $ 11.44     $ 9.07     -21 %
Interest expense   $ 18.54     $ 20.17     9 %   $ 18.86     $ 20.17     7 %   $ 19.35     $ 19.06     -1 %
 
(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     Nine Months Ended  
UNAUDITED (In thousands)   6/30/14     9/30/14     9/30/13     9/30/14     9/30/13     9/30/14  
REVENUES:                                                
Oil and natural gas sales   $ 66,563     $ 57,242     $ 79,696     $ 57,242     $ 247,104     $ 186,343  
Other     476       609       1,249       609       3,463       1,544  
Total revenues     67,039       57,851       80,945       57,851       250,567       187,887  
EXPENSES:                                                
Lease operating expense     18,185       18,225       18,274       18,225       54,719       55,878  
Property and production taxes     2,270       2,124       (472 )     2,124       2,062       6,130  
Transportation expense     49       51       50       51       133       157  
Depletion, depreciation and amortization     11,794       11,759       12,551       11,759       36,529       34,729  
Impairment     817       -       -       -       -       817  
Accretion of asset retirement obligation     556       629       595       629       1,866       1,852  
General and administrative     8,990       1,352       5,358       1,352       30,708       19,004  
Total expenses     42,661       34,140       36,356       34,140       126,017       118,567  
Income from operations     24,378       23,711       44,589       23,711       124,550       69,320  
FINANCING COSTS AND OTHER:                                                
Interest expense     13,351       13,635       15,674       13,635       51,929       39,926  
Amortization of deferred loan costs     863       887       868       887       2,887       2,583  
Loss on extinguishment of debt     -       -       16,787       -       38,084       -  
Commodity derivative realized (gains) losses     4,530       1,355       4,261       1,355       24,010       9,410  
Commodity derivative unrealized (gains) losses and amortization of derivative premiums     14,380       (31,691 )     9,910       (31,691 )     (26,447 )     (22,931 )
Total financing costs and other     33,124       (15,814 )     47,500       (15,814 )     90,463       28,988  
Income (loss) before taxes     (8,746 )     39,525       (2,911 )     39,525       34,087       40,332  
Income tax provision (benefit)     -       -       -       -       -       -  
Net income (loss)   $ (8,746 )   $ 39,525     $ (2,911 )   $ 39,525     $ 34,087     $ 40,332  
                                                 
   
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION  
   
UNAUDITED ($ in thousands)   12/31/13     9/30/14  
ASSETS                
  Cash and cash equivalents   $ 828     $ 14,786  
  Accounts receivable     23,737       18,868  
  Inventories     5,166       3,849  
  Other current assets     4,587       4,376  
  Commodity derivatives     340       2,164  
    Total current assets     34,658       44,043  
    Net property, plant and equipment     662,629       698,674  
    Total other assets     17,569       13,812  
TOTAL ASSETS   $ 714,856     $ 756,529  
LIABILITIES AND STOCKHOLDERS' EQUITY                
  Current Portion of long-term debt   $ -     $ 765,000  
  Accounts payable and accrued liabilities     32,966       30,561  
  Interest payable     17,408       6,162  
  Commodity derivatives     13,464       2,161  
  Share based compensation     20,723       3,048  
    Total current liabilities     84,561       806,932  
LONG-TERM DEBT     705,000       -  
COMMODITY DERIVATIVES     10,601       968  
ASSET RETIREMENT OBLIGATIONS     35,982       38,562  
SHARE BASED COMPENSATION     16,721       10,048  
    Total liabilities     852,865       856,510  
    Total stockholders' equity     (138,009 )     (99,981 )
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY   $ 714,856     $ 756,529  
                 

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. Adjusted Earnings should not be considered a substitute for net income (loss) as reported in accordance with GAAP.

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     Nine Months Ended  
UNAUDITED ($ in thousands)   9/30/13     6/30/14     9/30/14     9/30/13     9/30/14  
Adjusted Earnings Reconciliation                                        
Net Income   $ (2,911 )   $ (8,746 )   $ 39,525     $ 34,087     $ 40,332  
Plus:                                        
Unrealized commodity (gains) losses     8,893       13,176       (32,895 )     (29,431 )     (26,543 )
Loss on extinguishment of debt     16,787       -       -       38,084       -  
Tax effects     -       -       -       -       -  
Adjusted Earnings   $ 22,769     $ 4,430     $ 6,630     $ 42,740     $ 13,789  
                                         
             
    Quarter Ended     Nine Months Ended  
UNAUDITED ($ in thousands)   9/30/13     6/30/14     9/30/14     9/30/13     9/30/14  
Adjusted EBITDA Reconciliation                                        
Net income   $ (2,911 )   $ (8,746 )   $ 39,525     $ 34,087     $ 40,332  
Interest expense     15,674       13,351       13,635       51,929       39,926  
DD&A     12,551       11,794       11,759       36,529       34,729  
Impairment     -       817       -       -       817  
Accretion of asset retirement obligation     595       556       629       1,866       1,852  
Amortization of deferred loan costs     868       863       887       2,887       2,583  
Loss on extinguishment of debt     16,787       -       -       38,084       -  
Non-cash share-based compensation expense     (2,335 )     16       (4,801 )     1,188       (3,891 )
One-time general and administrative     -       3,024       -       -       3,024  
Amortization of derivative premiums     1,017       1,204       1,204       2,984       3,612  
Unrealized commodity derivative (gains) losses     8,893       13,176       (32,895 )     (29,431 )     (26,543 )
Adjusted EBITDA   $ 51,139     $ 36,055     $ 29,943     $ 140,123     $ 96,441  
                                         

We also provide per BOE G&A expenses excluding costs associated with one-time severance charges 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   Nine Months Ended  
    9/30/13   6/30/14     9/30/14   9/30/13     9/30/14  
G&A per BOE Reconciliation                                    
                                     
G&A expense   $ 5,358   $ 8,990     $ 1,352   $ 30,708     $ 19,004  
Less:                                    
Non-cash share-based compensation expense     2,335     35       3,574     (1,188 )     2,924  
One-time general and administrative     -     (3,024 )     -     -       (3,024 )
G&A Expense Excluding Share-Based Comp, and one-time severance charges     7,693     6,001       4,926     29,520       18,904  
MBOE     831     720       676     2,684       2,095  
G&A Expense per BOE Excluding Share-Based Comp and one-time severance charges   $ 9.26   $ 8.33     $ 7.29   $ 11.00     $ 9.02  
MBOE excluding Sacramento Basin production     -     -       -     2,583       -  
G&A Expense per BOE Excluding Non-Cash Share-Based Comp and one-time severance charges-Excluding Sacramento Basin Production   $ 9.26   $ 8.33     $ 7.29   $ 11.43     $ 9.02  
                                     

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