SOURCE: Venoco, Inc.

Venoco, Inc.

May 14, 2013 07:00 ET

Venoco, Inc. Announces First Quarter 2013 Financial and Operational Results

28% Increase in Daily Oil Production Over Q1 2012; Amended Revolving Credit Facility and Repayment of Second Lien Term Loan; New South Ellwood Well Averages Over 1,500 BOE/d in March

DENVER, CO--(Marketwired - May 14, 2013) - Venoco, Inc. today reported financial and operational results for the first quarter 2013. The company reported a net loss of $4.2 million for the quarter on total revenues of $87.3 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain other items, were $4.8 million for the quarter. Adjusted EBITDA was $40.4 million in the first quarter of 2013, compared to $40.7 million in the fourth quarter of 2012. 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 957 thousand barrels of oil equivalent (MBOE) for the quarter, or 10,628 BOE per day (BOE/d); excluding volumes contributed by Sacramento Basin properties held in escrow, production for the quarter was 855 MBOE or 9,501 BOE/d.

  • Daily oil volumes in the first quarter of 2013 were up 8% over the fourth quarter 2012 and up 28% over first quarter 2012.

  • Entered into an amendment to the revolving credit agreement which increased the borrowing base of the facility. The company repaid the second lien term loan with proceeds from the amended facility.

  • Production from the first well completed at South Ellwood in 2013 averaged more than 1,500 gross BOE per day in March and has averaged approximately 1,400 gross BOE per day over the last 30 days. 

"With the amendment of our revolving credit facility, repayment of our second lien term loan and the completion of our first well of 2013 at South Ellwood during the first quarter, we have had a very eventful start to the year," said Ed O'Donnell, Venoco's CEO. "Being able to get these milestones behind us early in the year clears the path for us to execute on our capital plan and access some of the extensive value that we have in our oily Southern California assets."

Sacramento Basin Sale Update

Effective December 31, 2012, the company sold all of its producing properties in the Sacramento Basin as well as its prospective onshore Monterey acreage in the San Joaquin basin, excluding the Sevier field, to an unrelated third party for $250 million. Portions of the proceeds from the sale were held in escrow pending receipt of consents regarding the transfer of ownership of certain assets. As of May 1, all proceeds have been released from escrow and received by Venoco.

As title for the properties held in escrow did not transfer to the purchaser until the consents regarding the transfer of ownership were obtained, the company's reported production of 10,628 BOE/d for the first quarter of 2013 includes 1,127 BOE/d of production from the affected Sacramento Basin properties.

First Quarter Production

Pro forma for the sale of the Sacramento Basin assets, production in the first quarter of 2013 was 9,501 BOE/d compared to 8,718 BOE/d in the fourth quarter of 2012 and 7,455 BOE/d in the first quarter of 2012. Daily oil production in the first quarter 2013 of 9,011 Bbls/d was up 8% compared to 8,348 Bbls/d in the fourth quarter of 2012, primarily as a result of production from the 3242-4RD well at South Ellwood which was completed in late February 2013. The well contributed nearly 500 BOE/d to the first quarter net production and over the last 30 days, has produced at an average rate of about 1,400 gross BOE/d. Additionally, during the fourth quarter 2012, we performed scheduled annual maintenance at the South Ellwood field which negatively impacted fourth quarter 2012 production by an estimated 400 - 450 BOE/d. First quarter 2013 oil production of 9,011 Bbls/d was up 28% over oil production of 7,044 Bbls/d in the first quarter of 2012, primarily as a result of successful drilling at the company's South Ellwood and West Montalvo fields during 2012 and early 2013. 

"Although the 3242-4RD well came on-line later in the quarter than we had initially anticipated, the high rate of production that we are seeing from the well is very encouraging and will go a long way in helping us achieve our production guidance of 10,000 to 10,500 BOE per day for the year," commented Mr. O'Donnell. "This well was drilled to the eastern boundary of our lease, as was the 3242-12 well that was completed in June 2012, which continues to produce over 2,000 gross BOE per day. Based on the success of these wells, we believe that additional opportunities exist on the eastern portion of our lease that could provide us with similar high impact results." 

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

    Quarter ended
Region   3/31/12   12/31/12   3/31/13
Southern California   7,455   8,718   9,501
Sacramento Basin(2)   9,970   8,221   1,127
  Total   17,425   16,939   10,628
  (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) First quarter 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 has been transferred to the purchaser.

First Quarter Costs

Venoco's first quarter 2013 lease operating expenses of $19.36 per BOE were up from $15.69 per BOE in the fourth quarter of 2012 and $15.42 per BOE in the first quarter of 2012. Pro forma for the sale of the Sacramento Basin and San Joaquin basin properties, the first quarter 2013 LOE was $21.05 per BOE, down from $25.75 per BOE in the fourth quarter of 2012. 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.

Venoco's first quarter G&A costs, excluding going private related costs, severance costs related to the sale of the Sacramento Basin assets and non-cash share-based compensation, was $13.14 per BOE compared to $8.47 per BOE in the fourth quarter of 2012 and $5.37 per BOE in the first quarter of 2012. Excluding production from the Sacramento Basin properties, Venoco's per barrel G&A costs, excluding the costs outlined above, were $14.71 per BOE in the first quarter of 2013 compared to $16.45 per BOE in the fourth quarter of 2012 and $12.56 in the first quarter of 2012. On a pro forma basis, G&A costs were higher in the fourth quarter of 2012 and first quarter of 2013 as a result of the conversion of restricted stock and stock option awards into cash settlement awards as a result of the going private transaction completed in October 2012.

    Quarter Ended
UNAUDITED (per BOE)   3/31/12   12/31/12   3/31/13
Lease Operating Expenses   $ 15.42   $ 15.69   $ 19.36
Production/Property Taxes     1.02     0.71     1.18
DD&A Expense     14.03     13.53     12.09
G&A Expense (1)     5.37     8.47     13.14
(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 First Quarter 2013

Venoco's first quarter capital expenditures for exploration, development and other spending were $21 million, including $13 million for drilling and rework activities, $1 million for facilities, and the remaining $7 million for land, seismic and capitalized G&A. 

In the first quarter of 2013, the company spent $18 million or 86% of its capital expenditures on its Southern California legacy fields, primarily at the South Ellwood field. During the quarter, the company completed one well (3242-4RD), which was a re-drill of a wet well originally completed in 2012. The 3242-4RD was spud in late 2012 and completed in February 2013. The well has produced at an average rate of approximately 1,400 gross BOE per day over the last 30 days. Additionally, during the first quarter, the company continued work on the 3242-19, a probable location which was originally spud in 2012 but was suspended to facilitate the re-drill of the 3242-4RD well. The company returned to drilling operations on the 3242-19 well during the first quarter; however, it has suspended drilling again as a result of a generator failure. The company is currently working to have the generator replaced or repaired. In the interim, the company has begun preparations to drill another location that would bottom near the eastern boundary of the field and expects to initiate drilling activity on this well in the near future. Once the eastern boundary well is completed, the company intends to continue with the 3242-19 later in the year.

In the first quarter of 2013, the company had relatively minimal onshore Monterey capital expenditures of $3 million or 14% of its total first quarter capital expenditures, incurred primarily for facilities.

Financing Update

In March 2013, the company entered into an amendment to the credit agreement governing its revolving credit facility, which resulted in an increase to the borrowing base to $270 million (subject to commitments of $268 million), revisions to the total debt leverage covenant ratio and the addition of a secured debt leverage covenant. On March 29, 2013, the company used proceeds from the amended revolving credit facility to repay the remaining principal outstanding on the second lien term loan.

2013 Guidance

The following summarizes the company's 2013 guidance:

  • Production: 10,000 - 10,500 BOE/d
  • Capital Budget: $90 - $100 million
  • Lease Operating Expenses: $20.50 - $21.50 per BOE
  • General & Administrative Expenses (excluding non-cash charges related to share-based compensation): $11.00 - $11.50 per BOE
  • Production & Property Taxes: $1.80 - $2.20 per BOE
  • DD&A: $12.50 - $13.50 per BOE

Earnings Conference Call

Venoco will host a conference call to discuss results Tuesday, May 14, 2013 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 Those wanting to participate in the Q & A portion can call (866) 202-3048 and use conference code 66593886. International participants can call (617) 213-8843 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 42870486. 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, final proceeds from its recent asset sale, 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.

    Quarter Ended     Quarter Ended  
UNAUDITED   12/31/12     3/31/13     % Change     3/31/12     3/31/13     % Change  
Production Volume:                                            
Oil (MBbls) (1)     768       811     6 %     641       811     27 %
Natural Gas (MMcf)     4,742       873     -82 %     5,668       873     -85 %
MBOE     1,558       957     -39 %     1,586       957     -40 %
Daily Average Production Volume:                                            
Oil (Bbls/d)     8,348       9,011     8 %     7,044       9,011     28 %
Natural Gas (Mcf/d)     51,543       9,700     -81 %     62,286       9,700     -84 %
BOE/d     16,939       10,628     -37 %     17,425       10,628     -39 %
Oil Price per Barrel Produced (in dollars):                                            
Realized price before hedging   $ 94.53     $ 99.71     5 %   $ 98.66     $ 99.71     1 %
Realized hedging gain (loss)     (15.91 )     (10.79 )   -32 %     (5.75 )     (10.79 )   88 %
Net realized price   $ 78.62     $ 88.92     13 %   $ 92.91     $ 88.92     -4 %
Natural Gas Price per Mcf (in dollars):                                            
Realized price before hedging   $ 3.60     $ 3.71     3 %   $ 2.76     $ 3.71     34 %
Realized hedging gain (loss)     (0.23 )     -     - %     0.63       -     - %
Net realized price   $ 3.37     $ 3.71     10 %   $ 3.39     $ 3.71     9 %
Expense per BOE (in dollars):                                            
Lease operating expenses   $ 15.69     $ 19.36     23 %   $ 15.42     $ 19.36     26 %
Production and property taxes   $ 0.71     $ 1.18     66 %   $ 1.02     $ 1.18     16 %
Transportation expenses   $ 0.01     $ 0.04     300 %   $ 2.78     $ 0.04     -99 %
Depreciation, depletion and amortization   $ 13.53     $ 12.09     -11 %   $ 14.03     $ 12.09     -14 %
General and administrative (2)   $ 5.28     $ 15.65     196 %   $ 5.37     $ 15.65     191 %
Interest expense   $ 14.96     $ 19.70     32 %   $ 9.91     $ 19.70     99 %
(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.  
    Quarter Ended  
UNAUDITED (In thousands)   3/31/12     12/31/12     3/31/13  
Oil and natural gas sales   $ 83,388     $ 90,725     $ 85,959  
Other     1,975       1,231       1,304  
Total revenues     85,363       91,956       87,263  
Lease operating expense     24,450       24,446       18,531  
Property and production taxes     1,615       1,100       1,127  
Transportation expense     4,412       18       38  
Depletion, depreciation and amortization     22,254       21,073       11,572  
Accretion of asset retirement obligation     1,391       1,470       656  
General and administrative     12,361       21,134       14,975  
Total expenses     66,483       69,241       46,899  
Income from operations     18,880       22,715       40,364  
FINANCING COSTS AND OTHER:                        
Interest expense     15,711       23,310       18,854  
Amortization of deferred loan costs     569       1,005       1,113  
Loss on extinguishment of debt     -       1,520       21,297  
Commodity derivative realized (gains) losses     (41,096 )     13,296       14,617  
Commodity derivative unrealized (gains) losses and amortization of derivative premiums     71,634       (13,278 )     (11,274 )
Total financing costs and other     46,818       25,853       44,607  
Income (loss) before taxes     (27,938 )     (3,138 )     (4,243 )
Income tax provision (benefit)     -       -       -  
Net income (loss)   $ (27,938 )   $ (3,138 )   $ (4,243 )
UNAUDITED ($ in thousands)   12/31/12     3/31/13  
  Cash and cash equivalents   $ 53,818     $ 643  
  Accounts receivable     108,356       32,031  
  Inventories     5,101       5,396  
  Other current assets     4,448       3,771  
  Commodity derivatives     153       349  
    Total current assets     171,876       42,190  
    Net property, plant and equipment     648,602       640,647  
    Total other assets     25,603       21,465  
TOTAL ASSETS   $ 846,081     $ 704,302  
  Accounts payable and accrued liabilities   $ 57,315     $ 40,532  
  Interest payable     27,862       14,145  
  Current portion of long-term debt     104,494       -  
  Commodity derivatives     20,607       13,696  
  Share-based compensation     10,424       14,349  
    Total current liabilities     220,702       82,722  
LONG-TERM DEBT     849,190       862,931  
COMMODITY DERIVATIVES     20,287       15,186  
ASSET RETIREMENT OBLIGATIONS     41,119       37,609  
SHARE-BASED COMPENSATION     10,441       5,764  
  Total liabilities     1,141,739       1,004,212  
  Total stockholders' equity     (295,658 )     (299,910 )


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  
UNAUDITED ($ in thousands)   3/31/12     12/31/12     3/31/13  
Adjusted Earnings Reconciliation                        
  Net Income   $ (27,938 )   $ (3,138 )   $ (4,243 )
  Unrealized commodity (gains) losses     63,839       (14,480 )     (12,223 )
  Going private related costs     2,628       5,240       -  
  Severance costs     -       1,496       -  
  Loss on extinguishment of debt     -       1,520       21,297  
  Tax effects     -       -       -  
Adjusted Earnings   $ 38,529     $ (9,362 )   $ 4,831  
    Quarter Ended  
UNAUDITED ($ in thousands)   3/31/12     12/31/12     3/31/13  
Adjusted EBITDA Reconciliation                        
Net income   $ (27,938 )   $ (3,138 )   $ (4,243 )
Interest expense     15,711       23,310       18,854  
DD&A     22,254       21,073       11,572  
Accretion of asset retirement obligation     1,391       1,470       656  
Amortization of deferred loan costs     569       1,005       1,113  
Loss on extinguishment of debt     -       1,520       21,297  
Non-cash share-based compensation expense     1,540       1,952       2,401  
Going private related costs     2,628       5,240       -  
Sacramento Basin severance costs     -       1,496       -  
Amortization of derivative premiums     7,795       1,202       949  
Unrealized commodity derivative (gains) losses     63,839       (14,480 )     (12,223 )
Adjusted EBITDA   $ 87,789     $ 40,650     $ 40,376  

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
    3/31/12   12/31/12   3/31/13
G&A per BOE Reconciliation                  
  G&A expense   $ 12,361   $ 21,134   $ 14,975
  Non-cash share-based compensation expense     (1,220)     (1,500)     (2,401)
  Going private related costs     (2,628)     (5,240)     -
  Sacramento Basin severance costs     -     (1,200)     -
  G&A Expense Excluding Non-Cash Share-Based Comp, Going Private Costs and Severance     8,513     13,194     12,574
  MBOE     1,586     1,558     957
G&A Expense per BOE Excluding Non-Cash Share-Based Comp, Going Private Costs and Severance   $ 5.37   $ 8.47   $ 13.14
  MBOE excluding Sacramento Basin production     678     802     855
G&A Expense per BOE Excluding Non-Cash Share-Based Comp, Going Private Costs and Severance-Excluding Sacramento Basin Production   $ 12.56   $ 16.45   $ 14.71


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, 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)   12/31/2010   12/31/2011   12/31/2012
Standardized measure of discounted future net cash flows   $ 902,901   $ 1,364,146   $ 1,157,452
Add: Present value of future income tax discounted at 10%     225,795     442,355     352,281
PV-10 at year end SEC prices   $ 1,128,696   $ 1,806,501   $ 1,509,733

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