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Form 10-K for VENOCO, INC.


15-Apr-2013

Annual Report


ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operation

The following discussion and analysis should be read in conjunction with our financial statements and related notes and the other information appearing in this report. As used in this report, unless the context otherwise indicates, references to "we," "our," "ours," "us" and the "Company" refer to Venoco, Inc. and its subsidiaries collectively.

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to have the potential to add significant reserves on a cost-effective basis and through selective acquisitions of underdeveloped properties. In the execution of our strategy, our management is principally focused on economically developing additional reserves and on maximizing production levels through exploration, exploitation and development activities in a manner consistent with preserving adequate liquidity and financial flexibility.

Recent Events

Going Private Transaction. In January 2012, we entered into a merger agreement with Timothy Marquez and certain of his affiliates pursuant to which an affiliate of Mr. Marquez agreed to acquire all of our common stock not beneficially owned by Mr. Marquez for $12.50 per share in cash. We refer to this transaction as the going private transaction. The going private transaction closed in October 2012. Following the closing, Venoco's common stock is no longer publicly traded; however, we will continue reporting as a voluntary filer with the SEC as required by the indentures governing our senior notes. In connection with the closing of the going private transaction, we entered into the fifth amended and restated credit agreement related to our revolving credit facility and a $315 million second lien term loan. Both of these agreements are discussed in further detail in "-Liquidity and Capital Resources-Capital Resources and Requirements." We subsequently entered into an amendment to the revolving credit agreement and repaid all amounts outstanding under the second lien term loan as discussed below.

Sacramento Basin Asset Sale. In December 2012, we completed the sale of certain properties in the Sacramento Basin and San Joaquin Valley areas of California to an unrelated third party for $250 million, subject to certain closing adjustments, of which $100.6 million was placed into escrow pending the receipt of consents to assign and the expiration or waiver of preferential purchase rights relating to certain of the properties. Of the $100.6 million placed into escrow, $72.8 million was received two days after closing and $17.9 million was received in February and March. The remaining $9.9 million is expected to be released by June 30, 2013. We applied proceeds from the sale to pay down $214.7 million of the principal balance outstanding on the second lien term loan facility and a $6.4 million prepayment penalty. The assets sold had proved reserves of approximately 44,900 MBOE as of December 31, 2011. Production from those assets averaged 8,939 BOE/d in 2012, 100% of which was natural gas.

Amended and Restated Revolving Credit Agreement and Second Lien Refinancing. In March 2013, we entered into an amendment to the revolving credit agreement that increased the borrowing base under the facility to $270 million. We then borrowed an additional $107 million under the facility and used those funds to repay the remaining amounts outstanding under the second lien term loan ($100 million) and a prepayment penalty of $3.0 million. The amendment also changed certain financial covenants included in the revolving credit agreement, as described in "-Liquidity and Capital Resources-Capital Resources and Requirements."


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Capital Expenditures

We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other projects. Our 2012 development, exploitation and exploration capital expenditures were $219 million, with approximately $117 million devoted to Southern California legacy projects, $76 million to onshore Monterey projects and $26 million to the Sacramento Basin. We reduced our overall capital expenditures, and increased our focus on development relative to exploration drilling, following the completion of the going private transaction. Our 2013 development, exploitation and exploration capital expenditure budget is $91 million, of which approximately $78 million is expected to be devoted to our legacy Southern California assets and approximately $13 million to onshore Monterey shale activities. The expected reduction in capital expenditures in 2013 is a result of our focus on deleveraging following the completion of the going private transaction.

The aggregate levels of capital expenditures in 2013, and the allocation of those expenditures, are dependent on a variety of factors, including changes in commodity prices, permitting issues, the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from our estimates. The following summarizes certain significant aspects of our 2012 capital spending program and the current outlook for 2013.

Southern California-Exploitation and Development

At the South Ellwood field, we drilled and completed two PUD wells during the second quarter of 2012 (the 3120-14 well and the 3242-12 well), both of which were successful. A third PUD well (the 3242-4 well) was drilled in the third quarter, which was not initially successful. Also in the third quarter, we spud a probable location (the 3242-19 well). However, drilling on this well was temporarily suspended in the fourth quarter to facilitate the redrill of the unsuccessful 3242-4 well to a different location.

We successfully completed the 3242-4 redrill (the 3242-4RD well) to an in-fill location at the South Ellwood field in the first quarter of 2013. Over the last 20 days of March, the 3242-4RD well produced about 1,500 gross BOE per day and the more successful of the earlier PUD wells drilled in the second quarter of 2012 (the 3242-12 well) produced about 2,100 gross BOE per day, for a total of 3,600 gross, or 3,000 net BOE per day for the two wells. Approximately 98% of the production from the two wells is oil. In 2013, we plan to complete drilling of the suspended 3242-19 probable well, drill one to two additional wells and replace the existing de-rated power cable to Platform Holly. The new power cable will provide us with the ability to place up to three additional gross wells on electric submersible pumps (in lieu of gas lift), which is expected to improve our recovery capabilities.

Our subsidiary Ellwood Pipeline, Inc. completed construction of a common carrier pipeline that allows us to transport our oil from the field to refiners without the use of a barge or the marine terminal we previously used. The pipeline commenced operations in January 2012.

In the West Montalvo field, we have pursued an active workover, recompletion and return to production program that has resulted in significant production gains since we acquired the field in May 2007. Beginning in 2011, we began an active drilling program in the field and we continue to evaluate our drilling results and refine our development program for the coming years. In 2012, we spud five wells and completed six wells in the field, including one well that was spud in 2011. The field has not been fully delineated offshore or fully developed onshore. We plan to drill four proved undeveloped locations and one probable location at the field in 2013.

In the Sockeye field, we drilled three wells and performed one recompletion during 2012. For 2013, there are no significant development projects planned at Sockeye.


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Southern California-Onshore Monterey Shale

In 2006, we began actively leasing onshore acreage in Southern California targeting the Monterey shale. Our leasing focused on areas where we believe the Monterey shale will produce light, sweet oil, and where the quality and depth of the Monterey shale is expected to be advantageous. Our onshore Monterey shale acreage position currently totals approximately 70,000 gross and 57,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin. These totals do not include 169,000 gross (109,000 net) acres in San Joaquin included in the Sacramento Basin asset sale.

Since 2010, we have pursued an active drilling program targeting the onshore Monterey shale formation. From that time through December 31, 2012, we have spud 29 wells and have set casing on 26 of those wells. During 2012, we spud five wells at the Sevier field in the San Joaquin Valley and completed six, including one that was spud during the fourth quarter of 2011. We incurred approximately $76 million in capital expenditures related to onshore Monterey development in 2012. To date, we have not seen material levels of production or reserves from the program and have, following the completion of the going private transaction, reduced our capital expenditures related to the project. Based on the data we have gathered and the results we have seen to date at the Sevier field, however, we believe that our testing efforts and delineation drilling in the area will ultimately result in commercial levels of production from the field.

Sacramento Basin

We reduced our activity levels in the Sacramento Basin in recent years as a result of depressed natural gas prices and our increased focus on our oil-based projects. During 2012, we drilled four wells and performed approximately 250 recompletions in the basin. Our reduced capital spending resulted in lower average daily production from the basin in 2012 relative to 2011.

Other Acquisitions and Divestitures

Sale of Sacramento Basin and San Joaquin Valley Assets. On December 31, 2012, we sold certain properties in the Sacramento Basin and San Joaquin Valley areas (not including any acreage in the Sevier field) to an unrelated third party for $250 million. See "-Recent Events-Sacramento Basin Asset Sale."

Sale of Santa Clara Avenue Field. In May 2012, we sold our interests in the Santa Clara Avenue field for $23.4 million (after closing adjustments).

Sale of Other Texas Assets. In April 2010, we signed certain purchase and sale agreements to divest our producing properties in Texas ("Texas Sales") for $98.1 million (after closing adjustments and related expenses). The transactions included interests in the Manvel field, our overriding royalty interest in the Hastings Complex and our other oil and natural gas producing properties in the Texas Gulf Coast. We used the proceeds from the sales to repay $66.9 million of the principal balance on the revolving credit facility and $30.7 million of the principal balance on the second lien term loan then in place.

Other. We have an active acreage acquisition program and we regularly engage in acquisitions and dispositions of oil and natural gas properties, primarily in and around our existing core areas of operations.

Trends Affecting our Results of Operations

Oil and Natural Gas Prices. Historically, prices received for our oil and natural gas production have been volatile and unpredictable, and that volatility is expected to continue. Changes in the market prices for oil and natural gas directly impact many aspects of our business, including our financial


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condition, revenues, results of operations, liquidity, rate of growth, carrying value of our oil and natural gas properties, value of our proved reserves and borrowing capacity under our revolving credit facility, all of which depend in part upon those prices. The assets included in the Sacramento Basin asset sale included substantially all of our properties that produce predominately natural gas. We therefore expect to have limited exposure to changes in natural gas prices for the foreseeable future.

We employ a hedging strategy to reduce the variability of the prices we receive for our production and provide a minimum revenue stream. As of March 29, 2013, we had hedge contract floors covering 6,700 barrels of oil per day for 2013. We settled all of our natural gas contracts in January 2013 as a result of the Sacramento Basin asset sale. We have also secured hedge contracts for portions of our 2014, 2015 and 2016 production. See "Quantitative and Qualitative Disclosures About Market Risk-Commodity Derivative Transactions" for further details concerning our hedging activities.

Additionally, the sales contracts under which we have historically sold a significant portion of our oil were based on the NYMEX WTI ("WTI") crude price index and these contracts expired at the end of the first quarter of 2012. To replace the expiring contracts, we entered into new sales contracts based on certain Southern California crude price indexes, which traded at a premium to WTI throughout 2011 and 2012 and have more closely tracked with the Inter-Continental Exchange Brent crude price index ("Brent"). Additionally, effective February 2012, we entered into a new sales contract related to oil produced from our South Ellwood field with terms more favorable than the previous contract because, as of January 31, 2012, we were able to deliver our oil through a common carrier pipeline rather than via barge. As a result of these contracts, our average realized price for oil in the period from April through December 2012 was approximately $6.91 per barrel higher than the average WTI price and approximately $11.23 per barrel below the average Brent price for the same period. We entered into a new sales contract effective May 1, 2013 with terms similar to the previous sales contract.

Expected Production. Our 2013 capital spending has been allocated approximately 86% to our legacy Southern California fields and 14% to our onshore Monterey shale program. As a result of the increase in capital spending related to our oil producing Southern California assets in 2012, the planned increase for 2013 and the success of two of our recently drilled South Ellwood wells, we expect production from those assets to increase in 2013. Overall, we expect production to be significantly lower in 2013 than it was in 2012 due primarily to the Sacramento Basin asset sale. On a pro forma basis, excluding production from properties included in the asset sale, we expect production to increase in 2013 compared to 2012.

Lease Operating Expenses. Lease operating expenses ("LOE") of $14.48 per BOE for 2012 were slightly lower than our 2011 results of $14.64 per BOE. We expect that the continuing shift in our focus to oil development will result in an increase in our LOE per BOE in 2013 relative to 2012.

Property and Production Taxes. Property and production taxes of $1.53 per BOE for 2012 were higher than our 2011 results of $0.99 per BOE due to successful oil wells drilled in 2012. We expect our 2013 property and production taxes to be higher on a per BOE basis than they were in 2012. Our ad valorem tax expense is highly sensitive to drilling results and the estimated present value of future net cash flows from new wells, and may be volatile in the future.

Transportation Expenses. Transportation expenses were $5.2 million in 2012 and $9.3 million in 2011. The decrease was due to the elimination, in mid-May 2012, of the South Ellwood barge operation as a result of the completion of the onshore pipeline during the first quarter of 2012. We expect that our transportation expenses will decrease slightly in 2013 compared to 2012 as a result of the use of the onshore pipeline for the full year.

General and Administrative Expenses. General and administrative expenses increased slightly to $6.13 per BOE (excluding share-based compensation charges of $1.58 per BOE and costs of $1.76 per


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BOE related to the going private transaction) in 2012 compared to $4.96 per BOE for 2011 (excluding share-based compensation charges of $0.88 per BOE and costs of $0.26 per BOE related to the going private transaction). Excluding share-based compensation charges and going private-related charges we expect our 2013 G&A costs to be slightly less than 2012, and, on a per BOE basis, to increase in 2013 compared to 2012 due to our lower expected production in 2013.

Depreciation, Depletion and Amortization (DD&A). DD&A for 2012 of $13.68 per BOE increased slightly from our 2011 DD&A of $13.35 per BOE. We expect our 2013 DD&A to decrease on a per BOE basis compared to our 2012 results.

Unrealized Derivative Gains and Losses. Unrealized gains and losses result from mark-to-market valuations of derivative positions that are not accounted for as cash flow hedges and are reflected as unrealized commodity derivative gains or losses in our income statement. Payments actually due to or from counterparties in the future on these derivatives will typically be offset by corresponding changes in prices ultimately received from the sale of our production. We have incurred significant unrealized gains and losses in recent periods and may continue to incur these types of gains and losses in the future.

Income Tax Expense (Benefit). We incurred losses before income taxes in 2008, 2009 and 2012 as well as taxable losses in each of the tax years from 2007 through 2012. These losses and expected future taxable losses were key considerations that led us to conclude that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2011 and December 31, 2012 since we could not conclude that it is more likely than not that the net deferred tax assets will be fully realized. As long as we continue to conclude that we have a need for a full valuation allowance against our net deferred tax assets, we likely will not have any income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes. Future events or new evidence which may lead us to conclude that it is more likely than not that our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; meaningful incremental oil production and proved reserves from development efforts at our Southern California legacy properties; consistent, meaningful production and proved reserves from our onshore Monterey shale project; meaningful production and proved reserves from the CO2 project at the Hastings Complex; and taxable events resulting from one or more deleveraging transactions. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.

Our expectations with respect to future production rates, expenses and the other matters discussed above are subject to a number of uncertainties, including those discussed in "Risk Factors." For example, with respect to future production rates, uncertainties include those associated with third party services, limitations on capital expenditures resulting from the terms of our debt agreements, the availability of drilling rigs, oil prices, events resulting in unexpected downtime, permitting issues and drilling success rates, including our ability to identify productive intervals and the drilling and completion techniques necessary to achieve commercial production in the onshore Monterey shale on a broader scale.

Results of Operations

The following table reflects the components of our oil and natural gas production and sales prices, and our operating revenues, costs and expenses, for the periods indicated. No pro forma adjustments have been made for the acquisitions and divestitures of oil and natural gas properties, which will affect


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the comparability of the data below. The information set forth below is not necessarily indicative of future results.

                                                         Years Ended December 31,
                                                        2010        2011       2012
   Production Volume(1):
   Oil (MBbls)                                            2,792      2,441      2,940
   Natural gas (MMcf)                                    23,196     23,923     20,430
   MBOE(2)                                                6,658      6,428      6,345
   Daily Average Production Volume:
   Oil (Bbls/d)                                           7,649      6,688      8,033
   Natural gas (Mcf/d)                                   63,551     65,542     55,820
   BOE/d(2)                                              18,241     17,612     17,336
   Oil Price per Bbl Produced (in dollars):
   Realized price                                      $  68.86   $  91.00   $  97.28
   Realized commodity derivative gain (loss)              (1.77 )    (2.48 )   (10.32 )

   Net realized price                                  $  67.09   $  88.52   $  86.96

   Natural Gas Price per Mcf Produced (in dollars):
   Realized price                                      $   4.34   $   4.02   $   2.88
   Realized commodity derivative gain (loss)               1.70       1.03       0.25

   Net realized price                                  $   6.04   $   5.05   $   3.13

   Expense per BOE:
   Lease operating expenses                            $  12.65   $  14.64   $  14.48
   Production and property taxes                       $   1.01   $   0.99   $   1.53
   Transportation expenses                             $   1.37   $   1.45   $   0.81
   Depletion, depreciation and amortization            $  11.79   $  13.35   $  13.68
   General and administrative expense, net(3)          $   5.64   $   6.10   $   8.70
   Interest expense                                    $   6.10   $   9.51   $  11.25


--------------------------------------------------------------------------------
    (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)
BOE is determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.

(3)
Net of amounts capitalized.

Comparison of Year Ended December 31, 2012 to Year Ended December 31, 2011

Oil and Natural Gas Sales. Oil and natural gas sales increased $27.0 million (8%) to $350.4 million in 2012 from $323.4 million in 2011. The increase was due to higher realized oil prices and production, partially offset by lower realized natural gas prices and production, as described below.

Oil sales increased by $64.3 million (28%) in 2012 to $291.5 million compared to $227.2 million in 2011. Oil production increased by 20%, with production of 2,940 MBbl in 2012 compared to 2,441 MBbl in 2011. The increase is primarily due to higher production at our South Ellwood and West Montalvo fields, resulting from successful drilling activity. Our average realized price for oil increased $6.28 (7%) from $91.00 per Bbl in 2011 to $97.28 per Bbl in 2012. Our new sales contracts, which are


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tied to Southern California indices and became effective April 1, 2012, contributed to the higher average sales prices.

Natural gas sales decreased $37.3 million (39%) in 2012 to $58.9 million compared to $96.2 million in 2011. Natural gas production decreased by 3,493 MMcf (15%), with production of 20,430 MMcf in 2012 compared to 23,923 MMcf in 2011. The production decrease is primarily the result of (i) the natural production decline of wells in the Sacramento Basin and (ii) the limited number of new wells drilled during the latter part of 2011 and 2012 resulting from our reduced focus on natural gas projects due to the depressed natural gas price environment. Our average realized price for natural gas decreased $1.14 (28%) from $4.02 per Mcf for 2011 to $2.88 per Mcf for 2012.

Other Revenues. Other revenues increased by $0.7 million (14%) to $6.1 million in 2012 from $5.4 million in 2011. The increase in other revenues is primarily due to tariff revenue received from third party usage of our onshore pipelines in 2012. Our contract related to the barge that formerly transported oil produced from the South Ellwood field was terminated effective in mid-May 2012; therefore, we did not realize any sub-charter revenue after May 2012.

Lease Operating Expenses. Lease operating expenses ("LOE") was relatively consistent between periods at $91.9 million in 2012 and $94.1 million in 2011. LOE on a per unit basis also remained relatively consistent at $14.48 per BOE in 2012 and $14.64 per BOE in 2011.

Production and Property Taxes. Production and property taxes increased $3.3 million (52%) to $9.7 million in 2012 from $6.4 million in 2011. The increase is primarily due to supplemental ad valorem taxes related to successful oil wells drilled during the second quarter of 2012. On a per BOE basis, property and production taxes increased $0.54 per BOE to $1.53 per BOE in 2012 from $0.99 per BOE in 2011.

Transportation Expenses. Transportation expenses decreased $4.1 million (45%) to $5.2 million in 2012 from $9.3 million in 2011. The decrease was due to elimination, in mid-May 2012, of the South Ellwood barge operation as a result of the completion of the onshore pipeline during the first quarter of 2012.

Depletion, Depreciation and Amortization (DD&A). DD&A expense was relatively consistent at $86.8 million in 2012 compared to $85.8 million in 2011. DD&A expense on a per unit basis also remained relatively consistent at $13.35 per BOE for 2011 and $13.68 per BOE for 2012.

Accretion of Abandonment Liability. Accretion expense remained relatively constant at $5.8 million in 2012 compared to $6.4 million in 2011.

General and Administrative (G&A). The following table summarizes the components of general and administrative expense incurred during the periods indicated (in thousands):

                                                                Years Ended
                                                               December 31,
                                                             2011        2012
     General and administrative costs                      $  54,852   $  57,310
     Share-based compensation costs                            9,720      14,199
     Going-private related costs                               1,642       9,997
     Sacramento Basin asset sale exit and disposal costs           -       1,200
     General and administrative costs capitalized            (27,028 )   (27,520 )

     General and administrative expense                    $  39,186   $  55,186

G&A expense increased $16.0 million (41%) to $55.2 million in 2012 compared . . .

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