SOURCE: Venoco, Inc.

Venoco, Inc.

February 07, 2011 06:30 ET

Venoco, Inc. Announces Reserves and Operations Update

DENVER, CO--(Marketwire - February 7, 2011) -

  • Venoco Reports Year-End 2010 Reserves of 85.1 Million BOE

  • Full-Year 2010 Production of 6.7 Million BOE or 18,241 BOE/d

  • Company to Expand Monterey Drilling in 2011

Venoco, Inc. (NYSE: VQ) announced today that its total proved oil and gas reserves as of December 31, 2010 were 85.1 million barrels of oil equivalent (MMBOE) at SEC benchmark pricing of $79.43 per barrel of oil and $4.38 per thousand cubic feet (MCF) of natural gas. The company's production in 2010 was approximately 6.7 MMBOE or 18,241 BOE per day.

The company added 4.6 million BOE of reserves this year through extensions and discoveries, at its Sacramento Basin assets. However, the company also lost 2.7 million BOE due the SEC's 5-year rule for developing proved undeveloped (PUD) locations.

"When allocating our 2010 and 2011 capital expenditure budgets we made the strategic decision based on commodity prices to shift our focus away from natural gas projects toward oil projects," commented Tim Marquez, Chairman and CEO. "We realized decreasing our drilling activity from 100+ wells per year to fewer than 50 contemplated in the 2011 budget would result in some PUDs coming off our books at year-end but we can't ignore the disparity in commodity prices and we feel fortunate that we have the ability to shift our focus within our existing portfolio," added Mr. Marquez.

Net of production and asset sales, the company added 2.7 MMBOE of proved reserves in its Sacramento Basin assets and lost 1.5 MMBOE of proved reserves at its Southern California assets due to certain performance related revisions. In total, year-end 2010 reserves increased 0.9 MMBOE compared to year-end 2009 reserves, net of production and pro forma for the sale of assets during the year. 

"In recent years, the exploration, exploitation and development of the onshore Monterey shale formation has played a fundamental role in our corporate strategy, and investments made to expand our knowledge of the onshore formation have increased substantially. As was our expectation, we do not have reserves booked for the onshore Monterey shale formation as of year-end and as a result our finding and development costs for 2010 are out of line with our historical metrics," said Mr. Marquez. "Clearly we believe the opportunity for future reserve bookings and production growth from the oil projects we're pursuing are significant," added Mr. Marquez.

The company's preliminary estimates of 2010 costs incurred and rollforward of proved reserves are as follows:

2010 Capitalized Costs Incurred   ($000)
Property acquisition and leasehold costs:      
  Unevaluated property   $ 22,673
  Proved property   $ 1,048
Exploration costs   $ 88,966
Development costs   $ 102,283
  Total costs incurred   $ 214,970
         
2010 Reserve Rollforward   MBOE  
Beginning of the year reserves   98,313  
Revisions of previous estimates   (3,799 )
Extensions and discoveries   4,625  
Purchases of reserves in place   53  
Production   (6,658 )
Sales of reserves in place   (7,436 )
End of year reserves   85,098  
       
Proved developed reserves:      
Beginning of year   50,421  
End of year   42,758  

Adjusting for capital related to the Monterey Shale play and the Hastings field, the company estimates its 3-year and 5-year F&D costs will be approximately $22.67 and $19.43 per BOE respectively. (The company invested heavily in the Hastings field in order to maximize the field's PV-10 since it was a critical parameter used to determine the field's sales price under the agreement with Denbury Resources.)

The pre-tax PV-10 value of the company's reserves using SEC benchmark pricing of $79.43 per barrel of oil and $4.38 per MMBTU for gas is $1.1 billion. Using the December 31, 2010 NYMEX 5-year strip pricing, the company's estimate of reserves is 86.1 MMBOE and the pre-tax PV-10 value is $1.6 billion. See the end of this release for a reconciliation of PV-10 to a standardized measure.

"One of our hidden assets is the 22.3% reversionary interest that we retained when we sold the Hastings field to Denbury in 2009," said Mr. Marquez. "We were happy to see that the Green Line, which brings CO2 from Denbury's Jackson Dome field to Hastings, was completed and CO2 injection commenced in December. We have approximately 18 million BOE of probable reserves associated with the reversionary interest -- a portion of which we expect to be converted to proved once the field responds to the flood."

The following table details the company's reserve categories for the last three years and PV-10 for 2010 (see the end of this release for a reconciliation of PV-10 to a standardized measure):

Net Proved Reserves (end of period)   2008PF(1)   2009PF(1)   2010
Oil (MBbls)            
  Developed   23,657   25,750   22,270
  Undeveloped   22,561   21,758   20,301
    Total   46,218   47,508   42,571
             
Natural Gas (MMcf)            
  Developed   100,124   120,052   122,928
  Undeveloped   116,783   142,314   132,235
    Total   216,907   262,366   255,163
             
Total Proved Reserves (MBoe)   82,369   91,236   85,098
             
PV-10 ($000)            
  Developed           575,152
  Undeveloped           553,544
    Total         $ 1,128,696
 
(1)Pro forma for the February 2009 sale of the company's Hastings field and the 2Q-2010 sale of other Texas assets.

Operations Update

"Our focus in 2010 was on building our Monterey Shale acreage position, staffing our Unconventional Resource Team and beginning the science to unlock the oil in the Monterey while maintaining production at our legacy assets," said Mr. Marquez. "Although we slightly underperformed full-year production guidance by approximately 2%, as we shifted capital to enhancing our Monterey Shale position and knowledge, our operational team did an exceptional job of driving down costs and improving our profitability on legacy assets."

The company announced that production in the fourth quarter of 2010 was 17,328 BOE/d, down from third quarter production of 18,087 BOE/d as well as down from the fourth quarter 2009 production, pro forma for sale of Texas assets, of 18,575 BOE/d. As previously discussed, the company lost about 130 BOE/d in gas and liquids sales at South Ellwood due to a lengthy mechanical repair at its onshore facility. Other production shortfalls at its West Montalvo and Sockeye fields were attributable to delays resulting from a combination of mechanical failures and heavy rains in the fourth quarter.

For full-year 2010, production was 18,241 BOE/d, down from full-year 2009 production of 20,622 BOE/d. Full-year 2010 and full-year 2009 production, pro forma for the sale of the Texas assets, were 17,779 and 18,756 BOE/d, respectively. 

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

              Full Year
Region 4Q 2009   3Q 2010   4Q 2010   2009   2010
Sacramento Basin 10,227   10,284   10,163   10,230   10,033
Southern California 8,354   7,803   7,165   8,523   7,745
Texas (and other) 1,498   -   -   1,869   463
  Total 20,079   18,087   17,328   20,622   18,241

Production from the Sacramento Basin was steady quarter over quarter. The company will be reducing its drilling rigs in the Basin from three in the third and fourth quarters of 2010 down to two rigs by March 1st. Under the 2011 capital expenditure plan, daily production in the Basin is expected to remain flat compared to 2010.

"Despite the continued low natural gas prices, we are still generating positive cash flow in the Sac Basin thanks in part to our strong natural gas hedges in place in 2010 and 2011," said Mr. Marquez. "In addition, we have identified several anomalies from 3D seismic data on lands we acquired in 2009. We're very pleased with the results from a successful discovery well we drilled in December on one of these anomalies -- it is an extension of the Grimes field and tested at a rate of about 2 million cubic feet per day. We have two additional locations on this anomaly that we plan to drill later this year. We recently TD'd a well on a second anomaly that appears to be another good well, and plan to drill a well on a third anomaly this spring."

In Southern California, production was down 638 BOE/d quarter over quarter due to downtime at various wells at the company's three largest fields. The company expects production from legacy Southern California assets in 2011 to be similar to 2010.

The company spud seven vertical wells designed as Monterey Shale science wells which involved logging and coring to be used to correlate the company's petrophysical model. Completion techniques including acidizing and fracture stimulations have been used. Production test rates on the vertical wells have been 20 to more than 150 barrels of oil per day. The wells have all tested light oil (23 to 39 degree API), except for the first well in the Salinas Valley that tested heavy oil. One vertical well was used to kick-off a horizontal well. 

The company spud four horizontal wells in 2010 targeting the Monterey Shale. The first of these, drilled in the San Joaquin Basin, was uneconomic as previously reported. The second and third wells were drilled in the Santa Maria Basin and are awaiting final completion and testing. Drilling on the fourth horizontal is expected to be completed soon.

"We only planned on drilling five vertical 'science' wells when we established our original 2010 budget," Mr. Marquez explained. "With the sale of the Texas assets we were able to double the Monterey Shale budget and not only drill additional vertical wells, but also drill our first horizontal wells in the play. We are very early in the process of applying new drilling, coring, logging, completion and petrophysics to the Monterey. Before 2010, we'd invested five years to identify the resource, to build a solid lease position and to hire key personnel to pursue this play. We have made very good progress in 2010 by getting the bit into the ground."

"We are very encouraged by the early information in this highly prospective play. We continued to add to our acreage positions during 4Q-2010 and 2011 YTD and have built our acreage position to 183,000 net acres, and we have tens of thousands of additional acres in process. We plan to add a third drilling rig by the end of February and a fourth by the end of the second quarter. While we will keep our expectations modest for 2011, we remain excited about our efforts to exploit this opportunity," Mr. Marquez said.

2011 Capital Budget

As the company has previously announced, its capital expenditures budget for 2011 is $200 million. Approximately $100 million (50%) is budgeted for the Monterey Shale, $60 million (30%) for the Sacramento Basin, and $40 million (20%) for Southern California.

"Although we targeted drilling 24 net Monterey wells in 2011, we are seeing an increase in drilling and completion costs, a modest increase in service costs and a delay in the availability of completion crews which, in combination, will likely either require additional capital or a reduction in the number of wells we drill in 2011 to stay within our current capital budget," explained Mr. Marquez. 

2011 Forecasts

The following table summarizes the company's 2011 guidance:

  • Production: 19,500 BOE/d
  • Lease Operating Expenses: $14.25 per BOE
  • G&A Expenses (excluding stock-based compensation): $4.75 per BOE
  • DD&A: $13.00 per BOE

Expectations with respect to future production rates, reserves and capital projects are subject to a number of uncertainties, including those referenced below in "Forward-looking Statements."

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, operates three onshore properties in Southern California, and has extensive operations in Northern California's Sacramento Basin. Estimates of unproved reserves, which may potentially be recoverable, are, by their nature, more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, expenses, reserves and future capital projects and expenditures, and all other statements except statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 and exploration 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.

UNAUDITED ($ in thousands)   12/31/2010
       
Standardized measure of discounted future net cash flows   $ 902,901
Add: Present value of future income tax discounted at 10%     225,795
PV-10 at year end SEC prices     1,128,696
Add: Effect of five year NYMEX strip at December 31, 2010     440,514
PV-10 at five year NYMEX strip at December 31, 2010   $ 1,569,210

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