ITEM 1. AND ITEM 2. Business and Properties
We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Since our founding in 1992, our core areas of focus have been offshore and onshore California. Our principal producing properties are located both onshore and offshore Southern California and onshore in California's Sacramento Basin, and are characterized by long reserve lives, predictable production profiles and substantial opportunities for further exploitation and development. We are also pursuing a major exploration and development project targeting the onshore Monterey shale formation in Southern California.
We are one of the largest independent oil and natural gas companies in California based on production volumes. According to a reserve report prepared by DeGolyer & MacNaughton, we had proved reserves of approximately 95.9 MMBOE as of December 31, 2011, based on adjusted prices of $99.62 per Bbl for oil and $4.05 per MMBtu for natural gas. As of that date, 49% of our proved reserves were oil and 51% were proved developed, and the PV-10 of those reserves was approximately $1.8 billion. Our definition of PV-10, and a reconciliation of a standardized measure of discounted future net cash flows to PV-10, is set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operation-PV-10." Our average net production in 2011 was 17,612 BOE/d.
The following table summarizes certain information concerning our production in 2011 and our reserves and inventory of drilling locations as of December 31, 2011.
(1)Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.19 per Bbl for oil and natural gas liquids and $4.12 per MMBtu for natural gas were adjusted for regional price differentials and other factors to arrive at prices of $99.62 per Bbl for oil, $68.40 per Bbl for natural gas liquids and $4.05 per MMBtu for natural gas, which were used in the calculation of proved reserves at December 31, 2011.
(2)Represents total gross drilling locations identified by management as of December 31, 2011, including 15 probable onshore Monterey shale drilling locations at the Sevier field, but excluding other potential onshore Monterey shale drilling locations. Of the total shown, 321 locations are classified as proved. Our Strengths
We believe that the following strengths provide us with significant competitive advantages:
High quality asset base with a long reserve life and growth potential. Most of our reserves are located in fields that have large volumes of hydrocarbons in place in multiple geologic horizons. One of our primary objectives is to use our engineering expertise to improve recovery rates from these fields and thereby increase our production and reserves. Our offshore Southern California fields generally have well-established production histories and exhibit relatively moderate production declines. As of December 31, 2011, our proved reserves to production ratio was 15 years based on production during the fourth quarter of 2011. In addition, because our producing properties typically have substantial
volumes of remaining hydrocarbons, they provide significant potential upside in proved reserves. We believe that we can develop additional reserves from these properties on a cost effective basis with relatively limited risk. As of December 31, 2011, we had identified 775 drilling locations on our legacy Southern California and Sacramento Basin properties and 15 probable onshore Monterey shale locations at the Sevier field. We anticipate identifying additional locations as we pursue our exploitation and development activities.
Extensive knowledge of the Monterey shale formation and substantial onshore Monterey acreage. A substantial portion of our production is from offshore wells targeting the fractured Monterey shale formation. Our technical team has extensive offshore experience with the evaluation and exploitation of this reservoir. We believe that there are significant exploration, exploitation and development opportunities relating to the Monterey shale formation onshore as well, and that our offshore expertise will help us take advantage of those opportunities. To date, our onshore Monterey shale acreage position is approximately 256,000 gross and 170,000 net acres. An additional 60,000 gross and 46,000 net acres with Monterey shale production or potential are held by production. We began drilling wells targeting the onshore Monterey shale in 2010, and have drilled over 20 wells since then, significantly advancing our knowledge of the formation. In the near term we intend to focus our efforts on the Sevier field in the San Joaquin valley where we have experienced the most success to date.
Strong position in the Sacramento Basin. We have considerable expertise in the exploration, exploitation and development of properties in the Sacramento Basin, where we have operated since 1996. We have drilled approximately 500 wells in the basin in the last five years and we are currently one of the largest operators there in terms of production and acreage. We believe that our experience, expertise and substantial presence in the basin will allow us to take advantage of attractive acquisition, exploration, exploitation and development opportunities there. In addition, we believe that the basin's proximity to northern California natural gas markets, its substantial gathering infrastructure and pipeline capacity and the relatively favorable historical differential to NYMEX prices received for natural gas produced there contribute to the value of our position.
Substantial operational flexibility. We have substantial flexibility in adapting our activities to respond to changes in commodity prices and business conditions generally. We have relatively few medium and long-term drilling commitments and are therefore capable of deferring a large portion of our capital expenditures and/or shifting those expenditures between natural gas and oil-oriented projects as commodity prices dictate. In addition, we have operating control of substantially all of our properties, which allows us to manage overhead, production and drilling costs and capital expenditures and to control the timing of exploration, exploitation and development activities.
Reputation for environmental, safety and regulatory compliance. We believe that we have established a reputation among regulators and other oil and natural gas companies as having a commitment to safe environmental practices. For example, the state of California has presented us with awards for outstanding lease maintenance at our Beverly Hills and Santa Clara Avenue fields and the onshore facility associated with our South Ellwood field. Additionally, the U.S. Bureau of Ocean Energy Management, Regulation and Enforcement presented us with the Safety Award for Excellence for our offshore operations in the Santa Clara Federal Unit, recognizing us as the top operator in the Pacific Outer Continental Shelf in 2008. We believe that our reputation is an important advantage for us when we are competing to acquire properties, particularly those in environmentally sensitive areas, because sellers are often concerned that they could be held responsible for environmental problems caused by the purchaser.
Experienced, proven management and operations team. The members of our management team have an average of over 25 years of experience in the oil and natural gas industry. Prior to founding our company in 1992, our CEO, Timothy Marquez, worked for Unocal for 13 years in both engineering and managerial positions. Our operations team has significant experience in the California oil and
natural gas industry across a broad range of disciplines, including geology, drilling and operations, and regulatory and environmental matters. Our team includes 55 engineers and geoscientists as of December 31, 2011. We believe that our experience and knowledge of the California oil and natural gas industry are important competitive advantages for us.
Our Strategy
We intend to continue to use our competitive strengths to advance our corporate strategy. The following are key elements of that strategy:
Continue to focus on the California market. Historically, we have focused primarily on properties onshore and offshore California. We believe the California market will continue to provide us with attractive growth opportunities. Many properties in California are characterized by significant hydrocarbons in place with multiple pay zones and long reserve lives-characteristics that our technical expertise makes us well-suited to exploit. We intend to continue to take advantage of development opportunities in the Sockeye, South Ellwood, West Montalvo and other California fields that have these characteristics. In addition, competition for the acquisition of properties in California is limited relative to many other markets because of the state's unique operational and regulatory environment. We believe that our technical capabilities, environmental record and experience with California regulatory requirements will allow us to grow in the California market.
Explore and develop the onshore Monterey shale formation. We plan to use the expertise we have developed with the fractured Monterey shale formation from our work in the offshore South Ellwood and Sockeye fields to facilitate our acquisition, exploration, exploitation and development of onshore properties with similar characteristics. We plan to devote approximately 39% of our $255 million capital expenditure budget for 2012, or $100 million, on activities targeting the onshore Monterey shale formation, including the drilling of 15 to 20 gross wells in the Sevier field and the acquisition of 3D seismic data in the Sevier and South Salinas fields. We intend to focus our 2012 drilling efforts on the Sevier field and expect modest production from the field in 2012. We also plan to study wells drilled in the past two years to identify zones that we may have overlooked during the initial completion of the well. We have had success completing zones at Sevier that we had not initially identified on the drilling logs. We expect that these recompletions will help us better understand our acreage relating to wells drilled during 2010 and 2011 outside of Sevier.
Maintain a flexible portfolio of development opportunities. Given current depressed natural gas prices and our robust inventory of oil projects, we intend to reduce our drilling activity in the Sacramento Basin for the near term. However, we continue to believe the basin presents significant exploration, exploitation and development opportunities from both conventional and unconventional reservoirs. As one of the largest operators in the basin, we believe that we are well positioned to identify and exploit these opportunities and that in an improved natural gas price environment we would quickly accelerate our development activities.
Maintain an efficient cost structure. We have maintained low lease operating expenses, due in part to the sale of relatively high-cost fields in Texas in 2009 and 2010 and increased efficiencies in a variety of operating areas. In 2010, we began increasing our focus on oil projects and because those projects tend to have higher operating costs than natural gas projects, we expect a slight increase in per BOE production expenses going forward. However, we will continue to focus on our operating cost structure in order to create additional production and processing efficiencies and reduce operational downtime.
Make opportunistic acquisitions of underdeveloped properties. We pursue acquisitions that we believe will add reserves and production on a cost-effective basis. Our primary focus is on operated interests in large, mature fields that are located in our core operating regions and have significant production histories, established proved reserves and potential for further exploitation and
development. We intend to continue to pursue acquisition opportunities to selectively expand our portfolio of properties.
Description of Properties
Southern California-Legacy Fields
South Ellwood Field. The South Ellwood field is located in state waters approximately two miles offshore California in the Santa Barbara channel. We conduct our operations in the field from platform Holly and own related onshore processing facilities. We acquired our interest in the field from Mobil Oil Corporation in 1997. Since that time, we have made numerous operational enhancements to the field, including redrills, sidetracks and reworks of existing wells and upgrades at the platform and the onshore treatment facility. We operate the field and have a 100% working interest.
The South Ellwood field is approximately seven miles long and is part of a regional east-west trend of similar geologic structures running along the northern flank of the Santa Barbara channel and extending to the Ventura basin. This trend encompasses several fields that, over their respective lifetimes, are each expected to produce over 100 million barrels of oil, according to the California Division of Oil, Gas, and Geothermal Resources. The Monterey shale formation is the primary oil reservoir in the field, producing sour oil with a gravity of approximately 22 degrees. As of December 31, 2011, there were 17 producing wells and five injection wells in the field.
Our processing and transportation facilities at South Ellwood include a common carrier pipeline, an onshore facility, a pier and a marine terminal. We conduct two-phase separation on the drilling platform and the oil/water emulsion is transported by pipeline to the onshore facility for further separation. After separation, the oil is transported to the refinery via a common carrier pipeline operated by our subsidiary Ellwood Pipeline, Inc. Construction of the common carrier pipeline was completed in January 2012; prior to then, the oil was transported to the marine terminal via a common carrier pipeline, and then transported to the refinery by a barge. Natural gas produced at the field is processed at the onshore facility and transported by common carrier pipeline.
Santa Clara Federal Unit. The Santa Clara Federal Unit is located approximately ten miles offshore in the Santa Barbara channel near Oxnard, California. Our operations in the unit are conducted from two platforms, platform Gail in the Sockeye field and platform Grace in the Santa Clara field. We acquired our interest in the unit and the associated facilities from Chevron in February 1999. Production is transported via pipeline to Los Angeles, California. We operate the unit and have a 100% working interest.
The Sockeye field structure is a northwest/southeast trending anticline bounded to the north and south by fault systems. The field produces from multiple stacked reservoirs ranging from the Monterey shale, at about 4,000 feet, to the Middle Sespe at approximately 7,000 feet. Other formations include the Upper Topanga, Lower Topanga and Juncal. As of December 31, 2011, there were 20 producing wells and 11 injection wells in the field. The oil produced from the Monterey shale and Upper Topanga is sour with gravities ranging from 12 to 18 degrees. The Lower Topanga and Sespe horizons produce sweet crude with gravities of 26 to 30 degrees. Chevron shut in production at platform Grace in the Santa Clara field in 1997. We primarily use the platform as a launching and receiving facility for pipeline cleaning devices and as an interconnecting pipeline to transport oil and natural gas produced from platform Gail to our onshore plant. In 2011, we returned one well to production at platform Grace.
West Montalvo Field. We acquired the West Montalvo field in Ventura County, California in May 2007. We operate the field and have a 100% working interest. The field, which includes an offshore portion that is developed from onshore locations, produces from the Sespe formation and produces sour oil with gravity of approximately 16 degrees. As of December 31, 2011, there were 29 producing
wells and two injection wells in the field. Since acquiring the field, our primary activities have consisted of returning idle wells to production, redrilling existing wells, working over and recompleting existing wells, and upgrading well lift systems and processing facilities.
Dos Cuadras Field. The Dos Cuadras field is located in federal waters approximately five miles offshore California in the Santa Barbara channel. We acquired our 25% non-operated working interest in the western two-thirds of the field from Chevron in February 1999. We have working interests ranging from approximately 17.5% to 25% in the associated onshore facility and pipelines. The field is operated by an unaffiliated third party. Production is transported via pipeline to Los Angeles, California. As of December 31, 2011, there were 87 producing wells and 17 injection wells in the field.
Beverly Hills West Field. The Beverly Hills West field is located in Beverly Hills, California. All drilling and production operations at the field are conducted from a 0.6 acre surface location adjacent to the campus of Beverly Hills high school. We acquired our interest in the field in 1995. We operate the field and have a 100% working interest. As of December 31, 2011, there were 15 producing wells and three injection wells in the field, which produce oil with gravity of approximately 23 degrees. The lease under which we operate the field expires in 2016.
Santa Clara Avenue Field. The Santa Clara Avenue field is located in Ventura County, California. We acquired our interest in this field in 1994 and 1996. We operate the field and have working interests ranging from 43% to 100%. As of December 31, 2011, there were a total of 17 producing wells in the field, which produce oil with gravity of approximately 22 degrees.
Southern California-Onshore Monterey Shale
We have developed an extensive knowledge of the Monterey shale formation through our work at the offshore South Ellwood and Sockeye (Santa Clara Unit) fields and believe the formation holds significant exploration opportunities onshore. Despite production history that dates back to the late 1880s, including in recent years some unconventional production, we believe the development of the unconventional onshore Monterey shale formation has been largely overlooked due to a number of circumstances, including California's unique competitive landscape. Industry majors have dominated the state's significant oil production and prospective undeveloped acreage for several decades with little incentive to explore new reservoirs due to highly favorable economics in their existing fields. We believe the relative scarcity of other independent operators in the area has not only slowed the development of the play, but also delayed the application of current drilling and completion technologies that have helped to advance other unconventional resource plays across the country in recent years.
In 2006 we began actively leasing onshore acreage in Southern California targeting the Monterey shale formation. Our leasing strategy has focused on areas where we believe the Monterey shale will produce light, sweet oil, where the quality and depth of the Monterey shale is expected to be advantageous, and is near existing infrastructure. As of December 31, 2011, our onshore Monterey shale acreage position totaled approximately 166,000 net acres. To date, our onshore Monterey shale acreage position is approximately 170,000 net acres. We expect to acquire additional acreage strategically in and around our existing leasehold. An additional 46,000 net acres with Monterey shale production or potential are held by production at our legacy Southern California fields.
Sevier Field. The Sevier field is located in Kern County along the western edge of the San Joaquin Valley up against California's coastal mountain range. The field is a steeply dipping, northwest-southeast trending anticline with complex geology and is located in close proximity to the Midway Sunset field. Midway Sunset is California's largest producing oil field and is expected to produce nearly 3.5 billion barrels of oil over its productive life. The gross interval of Monterey formation in the field is several thousand feet thick. To date, our acreage position at Sevier is approximately 10,000 net acres.
Sacramento Basin
In terms of historical production, the Sacramento Basin is one of California's most prolific onshore natural gas producing areas not associated with oil production. It is approximately 210 miles long and 60 miles wide and contains a variety of different geologic plays. We own 3D seismic data covering over 1,100 square miles in the basin, and 2D seismic data covering approximately 20,000 line miles. We continue to analyze this data to identify additional exploration, exploitation and development opportunities on our properties. We believe this data will also help us assess acquisition opportunities in the basin. The Forbes formation, from which the majority of our current Sacramento Basin production comes, consists of multiple, isolated, stacked reservoirs. Many of these individual zones are not revealed on drilling logs. Our technical team has been able to identify and complete many of these zones, which has contributed to a more than three-fold increase in production from the basin from 2006 to 2010.
Willows and Greater Grimes Fields. The Willows and Greater Grimes fields are located in Colusa, Glenn and Sutter counties north of Sacramento, California. Our combined lease position in these fields was approximately 164,000 net acres as of December 31, 2011. We operate substantially all of the fields and have a volume-weighted average working interest of approximately 94% (based on year end reserves of producing wells). Natural gas production in the Greater Grimes field is from the Forbes, Kione and Guinda formations and production in the Willows field is from the Forbes and Kione formations. Depths range from 2,800 feet in the Willows field to 8,900 feet in the Greater Grimes field. There were 555 producing wells in the fields as of December 31, 2011.
Other Sacramento Basin. We own interests in a number of other fields in Solano, Contra Costa, San Joaquin and Colusa counties. We operate substantially all of these fields and have a volume-weighted average working interest of approximately 68% (based on year end reserves of producing wells). As of December 31, 2011, there were a total of 38 producing wells in these fields. We believe that the fields will provide us with exploration, exploitation and development opportunities that are similar to those found in the Willows and Greater Grimes fields.
Exploration. We drill a significant number of wells on non-proved locations in the Sacramento Basin. These wells are considered "exploratory wells" as defined in SEC Regulation S-X. See "-Drilling Activity." The majority of the wells in the basin that are "exploratory wells" under SEC Regulation S-X are wells drilled on the border of existing fields in an attempt to test and expand the limits of a producing area. We generally do not distinguish between those wells and development wells from an operating perspective. We also believe there are significant exploration opportunities on our existing leasehold.
Texas
We sold our producing assets in Texas in a series of transactions that were completed in the second quarter of 2010 to multiple purchasers for aggregate net proceeds of $98.1 million (after closing adjustments and related expenses). We used the proceeds to repay $66.9 million of principal on our revolving credit facility and $30.7 million of principal on the second lien term loan then in place. We retained our 22.3% reversionary working interest in the Hastings Complex described below. The Texas properties sold comprised 7.2% of our proved reserves at December 31, 2009 or 7.1 MMBOE and contributed approximately 460 BOE/d to our average daily production during 2010.
In February 2009, we sold our interest in properties producing from the Frio formation in the Hastings Complex to Denbury Resources, Inc., or Denbury, for approximately $197.7 million, after certain post-closing adjustments, pursuant to an option agreement we entered into with Denbury in November 2006. The purchase price was in addition to the $50.0 million option payment Denbury previously made to us under the agreement. We retained certain interests in the complex not related to
the Frio formation. Substantially all of the current production from the complex is from the Frio formation.
Pursuant to the agreement, Denbury committed to a plan to pursue a CO2 enhanced recovery project at the properties it acquired. The plan calls for Denbury to make capital expenditures of at least $178.7 million by the end of 2014. As part of the plan, Denbury is responsible for providing the necessary CO2. We have the right to back in to a working interest of approximately 22.3% in the Hastings Complex after Denbury recoups (i) its operating costs relating to the project and a portion of the purchase price and (ii) 130% of its capital expenditures made on the project. If CO2 recovery operations do not meet certain development milestones by January 2013, Denbury will be required to either resell the properties to us at a discount or make additional payments to us. The agreement also establishes an area of mutual interest with respect to us and Denbury in specified areas adjacent to the properties. The success of the planned CO2 enhanced recovery project will be subject to numerous risks and uncertainties, including those relating to the geologic suitability of the properties for such a project and the availability of an economic and reliable supply of CO2. Denbury commenced injecting CO2 at the complex in December 2010 and began production in January 2012.
Other Exploration
From time to time, we pursue exploration opportunities outside of our core areas that we believe align with our corporate strengths and strategy. Amounts allocated to these types of projects in 2011 were nominal and are expected to be nominal in 2012 as well.
Oil and Natural Gas Reserves
The following table sets forth our net proved reserves as of the dates indicated. Our reserves as of December 31, 2010 and 2011 are set forth in a reserve report prepared by DeGolyer & MacNaughton. DeGolyer & MacNaughton reviews production histories and other geological, economic, ownership and engineering data related to our properties in arriving at their reserve estimates. Proved reserves as of each date indicated reflect all acquisitions and dispositions completed as of that date. A report of
DeGolyer & MacNaughton regarding its estimates of our proved reserves as of December 31, 2011 has been filed as Exhibit 99.1 to this report.
(1)Unescalated twelve month arithmetic average of the first day of the month posted prices of $79.43 per Bbl for oil and natural gas liquids and $4.38 per MMBtu for natural gas were adjusted for quality, energy content, transportation fees and regional price differentials to arrive at prices of $69.18 per Bbl for oil, $59.85 per Bbl for natural gas liquids and $4.37 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2010.
(2)Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.19 per Bbl for oil and natural gas liquids and $4.12 per MMBtu for natural gas were adjusted as described in note (1) above to arrive at prices of $99.62 per Bbl for oil, $68.40 per Bbl for natural gas liquids and $4.05 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2011.
(3)Our natural gas liquids reserves represent a minimal percentage of our total reserves (approximately 2.8% and 3.1% at December 31, 2010 and 2011, respectively), therefore natural gas liquids are not presented separately but rather are included with oil volumes.
(4)BOE is determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.
(5)Our definition of PV-10, and a reconciliation of a standardized measure of discounted future net cash flows to PV-10, is set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operation-PV-10."
Reserves Sensitivity Analysis
The following table sets forth our net proved reserves at December 31, 2011 based on alternative price scenarios as identified below in the footnotes to the table. The following price scenarios illustrate the sensitivity of our estimated reserve quantities under various price assumptions.
ARepresents reserves based on pricing prescribed by the SEC. The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for quality, energy content, transportation fees and regional price differentials to arrive at prices of $99.62 per Bbl for oil, $68.40 per Bbl for natural gas liquids and $4.05 per MMBtu for natural gas. Production costs were held constant for the life of the wells.
BPrices based on the five year NYMEX forward strip at December 31, 2011, were adjusted as described in note (A) above, resulting in prices which averaged $94.69 per Bbl for oil, $65.01 per Bbl for natural gas liquids and $4.49 per MMBtu for natural gas. Production costs were held constant with the costs as determined in the year-end unescalated SEC reserve case. (The five year NYMEX forward strip represents the futures prices for oil and natural gas as reported on the NYMEX as of December 31, 2011.)
CPrices based on a 10% reduction of the prices used in the year-end SEC case (Price Case A), resulting in prices, adjusted as described in note (A) above, of $89.92 per Bbl for oil, $61.56 per Bbl for natural gas liquids and $3.65 per MMbtu for natural gas. Production costs were held constant with the costs as determined in the year-end unescalated SEC reserve case.
DPrices based on a 10% increase of the prices used in the year-end SEC case (Price Case A), resulting in prices, adjusted as described in note (A) above, of $110.26 per Bbl for oil, $75.24 per Bbl for natural gas liquids and $4.46 per MMbtu for natural gas. Production costs were held constant with the costs as determined in the year-end unescalated SEC reserve case.
Changes in Proved Reserves
Our net proved reserves of 95,884 MBOE as of December 31, 2011 increased 13% from 85,098 MBOE as of December 31, 2010. Our estimated oil and natural gas reserves were principally affected by the following during 2011:
•Extensions and discoveries increased reserves by 16,298 MBOE due to (i) drilling of locations which were not previously classified as proved in the Sacramento Basin and re-evaluation and analysis of data from existing wells which enabled us to identify additional PUD locations and (ii) re-evaluation of the Sockeye field which resulted in additional PUD reserves based on performance of the field;
•Revisions of previous estimates increased reserves by 849 MBOE due to (i) the extension of the estimated life of the South Ellwood field as a result of the approval and completion of the onshore pipeline that replaced the barge operation for transportation of oil production from the field, (ii) better than anticipated drilling success and performance of certain Sacramento Basin fields, (iii) price changes that resulted in a net positive impact and (iv) addition of behind pipe reserves in the Sacramento Basin supported by positive operating results, all of which were largely offset by (i) removal of PUDs not drilled within five years and changes to the timing and focus of PUD development forecasts, and (iii) loss of reserves due to less than expected drilling results and performance, primarily at West Montalvo;
•Purchases of reserves in place increased reserves by 67 MBOE; and
•Current year production decreased reserves by 6,428 MBOE.
Our PUD reserves of 47,119 MBOE as of December 31, 2011 increased 11% from 42,340 MBOE as of December 31, 2010. Our estimated PUDs were principally affected by the following during 2011:
•Extensions, discoveries and improved recovery increased PUDs by 14,537 MBOE due to (i) drilling locations which were not previously classified as proved in the Sacramento Basin and re-evaluation and analysis of data from existing wells which enabled us to identify additional PUD locations and (ii) re-evaluation of the Sockeye field which resulted in additional PUD reserves based on the performance of the field;
•Revisions of previous estimates decreased PUDs by 7,151 MBOE due to (i) removal of PUDs not drilled within five years and changes to the timing and focus of PUD development forecasts and (ii) loss of a portion of reserves related to existing PUDs at West Montalvo due to less than expected drilling results and performance, partially offset by (i) increases in PUDs due to the extension of the estimated life of the South Ellwood field as a result of the approval and completion of the onshore pipeline that replaced the barge operation for transportation of oil production from the field; and
•2,607 MBOE of reserves classified as proved undeveloped at December 31, 2010 were drilled during the year, primarily at West Montalvo and throughout the Sacramento Basin-capital expenditures related to PUD drilling during 2011 were approximately $20.5 million.
At December 31, 2011, we have no PUDs that are scheduled for development five years or more beyond the date the reserves were initially recorded, except for two PUDs at the Sockeye field which are scheduled to be drilled in the first half of 2012. The wells will be drilled from Platform Gail, which was subject to the deep water drilling moratorium imposed by the Secretary of the U.S. Department of Interior from May 2010 through October 2010 following the Deepwater Horizon well blowout in the Gulf of Mexico. The drilling of these wells was delayed as a result of the moratorium, but were scheduled to be drilled as soon as was practicable after the relevant aspects of the moratorium were lifted. These two PUDs represent approximately 530 MBOE, or 0.6%, of our December 31, 2011 proved reserves. All PUD locations are within one spacing offset of proved locations.
Uncertainties with respect to future acquisition and development of reserves include (i) the success of our development programs, including with respect to the development of the onshore Monterey shale formation and potential changes to our drilling schedule based on ongoing operational results, (ii) our ability to obtain permits from relevant regulatory bodies to pursue development projects, (iii) changes in commodity prices, including potential changes to our drilling schedule if natural gas prices decline further, (iv) the availability of sufficient cash flow from operations or external financing to fund our capital expenditure program, (v) the effect of legislative or regulatory changes on our ability to pursue our hedging strategy, and (vi) the availability and cost of viable acquisition candidates.
As discussed in "Business and Properties-Description of Properties-Texas," Denbury commenced CO2 injection at the Hastings Complex in December 2010 and began production in January 2012. Once the field demonstrates response to the flood, we expect to record a portion of the proved reserves related to our reversionary interest in the project. Any proved reserves recorded that are attributable to our reversionary interest will be subject to a significant degree of variability until Denbury has recovered all of its costs as defined in the agreement and we are able to back in to our 22.3% working interest. The amount of reserves and resulting production necessary for Denbury to recover its costs will be determined in large part by such factors as the existing commodity prices and operating cost environment.
Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used
Our year-end reserve report is prepared by DeGolyer & MacNaughton in accordance with guidelines established by the SEC. Reserve definitions comply with the definitions provided by Regulation S-X of the SEC. DeGolyer & MacNaughton prepares the reserve report based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provide to them. This information is reviewed by knowledgeable members of our company to ensure accuracy and completeness of the data prior to submission to DeGolyer & MacNaughton. Upon analysis and evaluation of data provided, DeGolyer & MacNaughton issues a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our Reserves Manager, relevant Reservoir Engineers and Mark DePuy, our Senior Vice President, Business Development and Acquisitions, for completeness of the data presented, reasonableness of the results obtained and compliance with the reserves definitions in Regulation S-X of the SEC. Once all questions have been addressed, DeGolyer & MacNaughton issues the final appraisal report, reflecting its conclusions.
A letter which identifies the professional qualifications of the individual at DeGolyer & MacNaughton who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2011 has been filed as an addendum to Exhibit 99.1 to this report.
Internally, Mr. DePuy is responsible for overseeing our reserves process. He initially joined us in 2005 as Vice President of Northern Assets and was named our Chief Operating Officer the following year. He resigned as our COO in October 2008, but re-joined us in December 2011. Mr. DePuy has over 30 years of experience in the oil and natural gas industry and holds a B.S. in Petroleum Engineering from the Colorado School of Mines and M.B.A from the University of California, Los Angeles.
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetrics, material balance, advance production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
Production, Prices, Costs and Balance Sheet Information
The following table sets forth certain information regarding our net production volumes, average sales prices realized, and certain expenses associated with sales of oil and natural gas for the periods indicated. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included elsewhere in this report. No pro forma adjustments have been made for acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. The information set forth below is not necessarily indicative of future results.
(1)The South Ellwood field comprised more than 15% of our total proved reserves as of December 31, 2011. Production from the field was 806 MBbls and 252 MMcf in 2009, 746 MBbls and 93 MMcf in 2010 and 713 MBbls and 288 MMcf in 2011.
(2)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 for offshore properties are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on the timing of barge deliveries, oil in tank and pipeline inventories, and oil pipeline sales nominations.
(3)BOE is determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.
(4)Net of amounts capitalized. Drilling Activity
The following table sets forth information with respect to development and exploration wells we completed from January 1, 2009 through December 31, 2011. The number of gross wells is the total
number of wells we participated in, regardless of our ownership interest in the wells. Fluid injection wells for waterflood and other enhanced recovery projects are not included as gross or net wells.
(1)A productive well is not a dry well, as described below, but a well for which we have set casing. Wells classified as productive, do not always provide economic levels of production.
(2)A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
(3)We drill a significant number of wells on non-proved locations in the Sacramento Basin. These wells are considered "exploratory wells" as defined in SEC Regulation S-X and are included in the Exploration Wells Drilled category above. The majority of the wells in the basin that are "exploratory wells" under SEC Regulation S-X are wells drilled on the border of existing fields in an attempt to test and expand the limits of a producing area. We generally do not distinguish between those wells and development wells from an operating perspective. Of the gross productive exploration wells drilled in 2011, 24 were drilled in the Sacramento Basin. The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered.
Present Activities
As of December 31, 2011, we were in the process of drilling 2.0 gross (2.0 net) wells and there were 6.0 gross (6.0 net) wells waiting on completion. See "Management's Discussion and Analysis of Financial Condition and Results of Operation-Overview-Capital Expenditures" for additional discussion of our present development activities.
Oil and Natural Gas Wells
The following table details our working interests in producing wells as of December 31, 2011. A well with multiple completions in the same bore hole is considered one well. Wells are classified as oil
or natural gas wells according to the predominant production stream, except that a well with multiple completions is considered an oil well if one or more is an oil completion.
(1)Amounts shown include 16 oil wells and 4 natural gas wells with multiple completions. Acreage
The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2011. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.
(1)The percentage of undeveloped acreage held under leases due to expire in 2012, 2013 and 2014, unless extended by exploration or production activities or extension of lease terms, is approximately 5%, 18% and 13%, respectively. Risk and Insurance Program
Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including the risk of well blowouts, oil spills and other adverse events. We could be held responsible for injuries suffered by third parties, contamination, property damage or other losses resulting from these types of events. In addition, we have generally agreed to indemnify our drilling rig contractors against certain of these types of losses. Because of these risks, we maintain insurance against some, but not all, of the potential risks affecting our operations and in coverage amounts and deductible levels that we believe to be economic. Our insurance program is designed to provide us with what we believe to be an economically appropriate level of financial protection from significant unfavorable losses resulting from damages to, or the loss of, physical assets or loss of human life or liability claims of third parties, attributed to certain assets and including such occurrences as well blowouts and resulting oil spills. We regularly review our risks of loss and the cost and availability of insurance and consider the need to revise our
insurance program accordingly. Our insurance coverage includes deductibles which must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
In general, our current insurance policies covering a blowout or other insurable incident resulting in damage to one of our offshore oil and gas wells provide up to $50 million of well control, pollution cleanup and consequential damages coverage and $250 million of third party liability coverage for additional pollution cleanup and consequential damages, which also covers personal injury and death. The availability and cost of insurance has been impacted by the Gulf of Mexico Deepwater Horizon incident, which occurred in April 2010. In particular, while we have been able to secure our desired level of insurance coverage, we believe that there is less liability insurance coverage available industry-wide and that which is available is more expensive than in the past.
If a well blowout, spill or similar event occurs that is not covered by insurance or not fully protected by insured limits, it could have a material adverse impact on our financial condition, results of operations and cash flows. See "Risk Factors-Our business involves significant operating risks that could adversely affect our production and could be expensive to remedy. We do not have insurance to cover all of the risks that we may face".
Remediation Plans and Procedures
As required by regulations imposed by the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, we have updated our existing company oil-spill response plan, we continue to maintain oil spill response equipment on the platforms, including oil spill containment boom and a boat for boom deployment, and have maintained oil-spill financial assurance in connection with our offshore operations. Our oil-spill response plan details procedures for rapid response to spill events that may occur as a result of our operations. The plan calls for training personnel in spill response. Periodically, drills are conducted to measure and maintain the effectiveness of the plan. We review the plan annually and update where necessary.
Also pursuant to BOEMRE regulations, and similar regulations adopted by the California Department of Fish and Game's Office of Oil Spill Prevention and Response, we continue to be a member of Clean Seas, LLC, or Clean Seas, a cooperative entity operated with other offshore operators to effectively respond to oil spills in the offshore region in which we operate. The purpose of Clean Seas is to act as a resource to its member companies by providing an inventory of state-of-the-art oil spill response equipment, trained personnel, and expertise in the planning and execution of response techniques. Clean Seas' equipment consists primarily of oil spill response vessels, including two equipped with approximately 4,500 feet of oil spill containment boom, advanced oil recovery systems, high capacity stationary skimmers, storage tanks for recovered oil, infrared radar and advanced electronic equipment for directing and monitoring oil spill response activities. Clean Seas also recruits and trains local fishermen to assist in oil recovery and the recovery of impacted wildlife. Clean Seas' designated area of response, which encompasses all of our offshore operations, comprises the open oceans and coastline of the South Central Coast of California including Ventura, Santa Barbara, and San Luis Obispo Counties, and the Santa Barbara Channel Islands.
Title to Properties
We believe that we have satisfactory title to all of our material assets. Title to our properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry. However, we believe that none of these liens, restrictions,
easements, burdens and encumbrances materially detract from the value of our properties or from our interest in those properties or materially interfere with our use of those properties, in each case in the operation of our business as currently conducted. We believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our current business in all material respects as described in this report. As is customary in the oil and natural gas industry, we typically make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations.
Indebtedness under our revolving credit facility is secured by liens on substantially all of our oil and natural gas properties and other assets. See "Management's Discussion and Analysis of Financial Condition and Results of Operation-Liquidity and Capital Resources-Capital Resources and Requirements."
Marketing, Major Customers and Delivery Commitments
Markets for oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our production is sold to competing buyers, including large oil refining companies and independent marketers. In the year ended December 31, 2011, approximately 95% of our revenues were generated from sales to four purchasers: ConocoPhillips (66%), Enserco Energy (18%), Calpine Producer Services LP (6%), and Concord Energy LLC (5%). Prospectively, under our new oil sales contracts, a significant portion of our oil production will be sold to Tesoro Refining and Marketing Company. As a result, we expect Tesoro to a be a significant customer in 2012, with a corresponding decrease in sales to ConocoPhillips. Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors. We had no material delivery commitments as of February 14, 2012.
Competition
The oil and natural gas business is highly competitive in the search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors principally consist of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators. Our competitors include, but are not limited to, Occidental Petroleum Corporation, Plains Exploration & Production Company, Berry Petroleum Company and Breitburn Energy Partners L.P. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop our properties. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.
Offices
We currently lease approximately 47,200 net square feet of office space in Denver, Colorado, where our principal office is located. The lease for the Denver office expires in 2014. We lease an additional 51,000 net square feet of office space in Carpinteria, California from 6267 Carpinteria Avenue, LLC. The lease for the Carpinteria office will expire in 2019. 6267 Carpinteria Avenue, LLC was a wholly owned subsidiary of ours prior to March 2006, when we paid a dividend consisting of 100% of the membership interests in 6267 Carpinteria Avenue, LLC to our then-sole stockholder. The lease has remained in effect following the payment of the dividend. Additionally, we lease 7,700 net square feet of office space in Bakersfield, California, the lease for which expires in 2013. We also have leases for certain field offices which are insignificant on a quantitative basis. We believe that our office
facilities are adequate for our current needs and that additional office space can be obtained if necessary.
Employees
As of December 31, 2011, we had approximately 365 full-time employees, none of whom were party to collective bargaining arrangements.
Regulatory Environment
Our oil and natural gas exploration, production and transportation activities are subject to extensive regulation at the federal, state and local levels. These regulations relate to, among other things, environmental and land-use matters, conservation, safety, pipeline use, drilling and spacing of wells, well stimulation, transportation, and forced pooling and protection of correlative rights among interest owners. The following is a summary of some key regulations that affect our operations.
Environmental and Land Use Regulation
A wide variety of environmental and land use regulations apply to companies engaged in the production and sale of oil and natural gas. These regulations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures to remain in compliance. Failure to comply with these requirements can result in civil and/or criminal penalties and liability for non-compliance, clean-up costs and other environmental damages. It also is possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect.
California Environmental Quality Act ("CEQA"). CEQA is a California statute that requires consideration of the environmental impacts of proposed actions that may have a significant effect on the environment. CEQA requires the responsible governmental agency to prepare an environmental impact report that is made available for public comment. The responsible agency also is required to consider mitigation measures. The party requesting agency action bears the expense of the report.
We currently are in the CEQA process in connection with several exploration wells that are part of our Monterey shale project in several counties in California. We may be required to undergo the CEQA process for other lease renewals and other proposed actions by state and local governmental authorities that meet specified criteria. At a minimum, the CEQA process delays and adds expense to the process of obtaining new leases, permits and lease renewals.
Discharges to Waters. The Federal Water Pollution Control Act of 1972, as amended (the "Clean Water Act"), and comparable state statutes impose restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into regulated waters and wetlands. These controls generally have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. These laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal and offshore waters without appropriate permits. Violation of the Clean Water Act and similar state regulatory programs can result in civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. They also can impose substantial liability for the costs of removal or remediation associated with discharges of oil, hazardous substances, or other pollutants.
The Clean Water Act also regulates stormwater discharges from industrial properties and construction sites, and requires separate permits and implementation of a Stormwater Pollution Prevention Plan ("SWPPP") establishing best management practices, training, and periodic monitoring of covered activities. Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure ("SPCC") plans or facility response plans to address potential oil spills.
Certain exemptions from some Clean Water Act requirements were created or broadened pursuant to the Energy Policy Act of 2005.
Oil Spill Regulation. The Oil Pollution Act of 1990, as amended ("OPA"), amends and augments the Clean Water Act as it relates to oil spills. It imposes potentially unlimited liability on responsible parties without regard to fault for the costs of cleanup and other damages resulting from an oil spill in federal waters. Responsible parties include (i) owners and operators of onshore facilities and pipelines and (ii) lessees or permittees of offshore facilities. In addition, OPA requires parties responsible for offshore facilities to provide financial assurance in the amount of $35.0 million, which can be increased to $150.0 million in some circumstances, to cover potential OPA liabilities.
Regulations imposed by the BOEMRE also require oil-spill response plans and oil-spill financial assurance from offshore oil and natural gas operations, whether operating in state or federal offshore waters. These regulations were designed to be consistent with OPA and other similar requirements. Under BOEMRE regulations, operators must join a cooperative that makes oil-spill response equipment available to its members. The California Department of Fish and Game's Office of Oil Spill Prevention and Response ("OSPR") has adopted oil-spill prevention regulations that overlap with federal regulations. We have complied with these OPA, BOEMRE and OSPR requirements by adopting an offshore oil spill contingency plan and becoming a member of Clean Seas, LLC, a cooperative entity operated with other offshore operators to prevent and respond to oil spills in the offshore region in which we operate. See "-Remediation Plans and Procedures".
Air Emissions. Our operations are subject to local, state and federal regulations governing emissions of air pollutants. Local air-quality districts are responsible for much of the regulation of air-pollutant sources in California. California requires new and modified stationary sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally based permitting requirements. Because of the severity of ozone levels in portions of California, the state has the most severe restrictions on emissions of volatile organic compounds ("VOCs") and nitrogen oxides ("NOX") of any state. Producing wells, natural gas plants and electric generating facilities all generate VOCs and NOX. Some of our producing wells are in counties that are designated as non-attainment for ozone and, therefore, potentially are subject to restrictive emission limitations and permitting requirements. California also operates a stringent program to control hazardous (toxic) air pollutants, and this program could require the installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits generally are resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air-emission sources. Air emissions from oil and natural gas operations also are regulated by oil and natural gas permitting agencies, including BOEMRE, the California State Lands Commission ("CSLC"), and other local agencies.
Waste Disposal. We currently own or lease a number of properties that have been used for production of oil and natural gas for many years. Although we believe the prior owners and/or operators of those properties generally utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we currently own or lease. State and federal laws applicable to oil and natural gas wastes have become more stringent. Under new laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial well-plugging operations to prevent future, or mitigate existing, contamination.
We may generate wastes, including "solid" wastes and "hazardous" wastes that are subject to the federal Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes, although certain oil and natural gas exploration and production wastes currently are exempt
from regulation as hazardous wastes under RCRA. The federal Environmental Protection Agency ("EPA") has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our oil and natural gas operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and may therefore become subject to more rigorous and costly management, disposal and clean-up requirements. State and federal oil and natural gas regulations also provide guidelines for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both onshore and offshore.
Superfund. Under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, also known as CERCLA or the Superfund law, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated "hazardous substances" at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, in the course of our operations we may have generated and may generate wastes that fall within CERCLA's definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties.
Abandonment, Decommissioning and Remediation Requirements. Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production and transportation facilities and the environmental restoration of operations sites. BOEMRE regulations, coupled with applicable lease and permit requirements and each property's specific development and production plan, prescribe the requirements for decommissioning our federally leased offshore facilities. CSLC and the California Department of Conservation, Division of Oil, Gas and Geothermal Resources ("DOGGR") are the principal state agencies responsible for regulating the drilling, operation, maintenance and abandonment of all oil and natural gas wells in the state, whether onshore or offshore. BOEMRE regulations require federal leaseholders to post performance bonds. See "-Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations-Plugging and Abandonment Costs" for a discussion of our principal obligations relating to the abandonment and decommissioning of our facilities.
California Coastal Act. The California Coastal Act regulates the conservation and development of California's coastal resources. The California Coastal Commission (the "Coastal Commission") works with local governments to make permit decisions for new developments in certain coastal areas and reviews local coastal programs, such as land-use restrictions. The Coastal Commission also works with the OSPR to protect against and respond to coastal oil spills. The Coastal Commission has direct regulatory authority over offshore oil and natural gas development within the state's three mile jurisdiction and has authority, through the Federal Coastal Zone Management Act, over federally permitted projects that affect the state's coastal zone resources. We conduct activities that may be subject to the California Coastal Act and the jurisdiction of the Coastal Commission.
Marine Protected Areas ("MPAs"). In 2000, President Clinton issued Executive Order 13158, which directs federal agencies to strengthen management, protection and conservation of existing MPAs and to establish new MPAs. The executive order requires federal agencies to avoid causing harm to MPAs through federally conducted, approved, or funded activities. The order also directs EPA to propose new regulations under its Clean Water Act authority to ensure protection of the marine environment. This order and related Clean Water Act regulations have the potential to adversely affect our operations by restricting areas in which we may engage in future exploration, development, and production operations and by causing us to incur increased expenses.
Naturally Occurring Radioactive Materials ("NORM"). Our operations my generate wastes containing NORM. Certain oil and natural gas exploration and production activities can enhance the radioactivity of NORM. NORM primarily is regulated by state radiation control regulations. The Occupational Safety and Health Administration also has promulgated regulations addressing the handling and management of NORM. These regulations impose certain requirements regarding worker protection, the treatment, storage, and disposal of NORM waste, the management of NORM containers, tanks, and waste piles, and certain restrictions on the uses of land with NORM contamination.
Other Environmental Regulation. Our leases in federal waters on the Outer Continental Shelf are administered by the BOEMRE and require compliance with detailed BOEMRE regulations and orders. Under certain circumstances, BOEMRE may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.
Our offshore leases in state waters or "tidelands" (within three miles of the coastline) are administered by the state of California and require compliance with certain CSLC and DOGGR regulations. CSLC serves as the lessor of our state offshore leases and is charged with overseeing leasing, exploration, development and environmental protection of the state tidelands.
Commencing with the Cunningham Shell Act of 1955, California has enacted several pieces of legislation that withhold state tidelands from oil and natural gas leasing. The Cunningham Shell Act protects an area of tidelands offshore Santa Barbara County that stretches west from Summerland Bay to Coal Oil Point, and includes waters offshore the unincorporated area of Montecito, the City of Santa Barbara and the University of California at Santa Barbara. It also protects the state tidelands around the islands of Anacapa, Santa Cruz, Santa Rosa and San Miguel. In 1994, California enacted the California Sanctuary Act which, with three exceptions, prohibits leasing of any state tidelands for oil and natural gas development. Oil and natural gas leases in effect as of January 1, 1995 are unaffected by this legislation until such leases revert back to the state, at which time they will become part of the California Coastal Sanctuary. This legislation does not restrict our existing state offshore leases or our current or planned future operations.
Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas ("GHG") emissions that have been or may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil and natural gas we produce. EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider "cap and trade" legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. On September 27, 2006, California's governor signed into law Assembly Bill (AB) 32, known as the "California Global Warming Solutions Act of 2006," which established a statewide cap
on GHGs designed to reduce the state's GHG emissions to 1990 levels by 2020 and establishes a "cap and trade" program. The California Air Resources Board adopted regulations that went into effect on January 1, 2012. These regulations are not expected to directly impact our operations as the first phase, beginning in 2012, includes all major industrial sources and utilities, while the second phase, which starts in 2015, will address distributors of transportation fuels, natural gas, and other fuels. We will continue to monitor the implementation of these regulations through industry trade groups and other organizations in which we are a member.
Other environmental protection statutes that may impact our operations include the Marine Mammal Protection Act, the Marine Life Protection Act, the Marine Protection, Research, and Sanctuaries Act of 1972, the Endangered Species Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.
Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations
Significant potential costs relating to environmental and land-use regulations associated with our existing properties and operations include those relating to (i) plugging and abandonment of facilities, (ii) clean-up costs and damages due to spills or other releases, and (iii) penalties imposed for spills, releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, obligations relating to plugging and abandonment, clean-up and other environmental costs in connection with our acquisition of operating interests in fields, and these costs can be significant.
Plugging and Abandonment Costs. Our operations, and in particular our offshore platforms and related facilities, are subject to stringent abandonment and closure requirements imposed by BOEMRE and the state of California. With respect to the Santa Clara Federal Unit, Chevron retained most of the abandonment obligations relating to the platforms and facilities when it sold the fields to us in 1999. We are responsible for abandonment costs relating to the wells and to any expansions or modifications we made following our acquisition of the fields. We also agreed to assume from Chevron all abandonment obligations associated with its 25% interest in the infrastructure (but not the wells) in the Dos Cuadras field. We agreed to assume all of the abandonment costs relating to the operations, including platform Holly, in the South Ellwood field when we purchased it from Mobil Oil Corporation in 1997.
As described in note 6 to our financial statements, we have estimated the present value of our aggregate asset retirement obligations to be $92.5 million as of December 31, 2011. This figure reflects the expected future costs associated with site reclamation, facilities dismantlement and plugging and abandonment of wells. The discount rates used to calculate the present value varied depending on the estimated timing of the obligation, but typically ranged between 4% and 9%. Actual costs may differ from our estimates. Our financial statements do not reflect any liabilities relating to other environmental obligations.
Under a variety of applicable laws and regulations, including CERCLA, RCRA and BOEMRE regulations, we could in some circumstances be held responsible for abandonment and clean-up costs relating to our operations, both onshore and offshore, notwithstanding contractual arrangements that assign responsibility for those costs to other parties.
Clean-up Costs. Certain of our facilities have known environmental contamination for which we will be responsible for the associated clean-up efforts, subject to our right to be indemnified by third parties in some cases. The regulators have generally not yet determined the applicable clean-up requirements associated with the facilities. However, we expect that we will be permitted to defer remedial actions until we cease operations at the relevant facilities. As the clean-up is expected to be
performed at the end of the useful life of the relevant facilities, we have included estimates for the cost of the clean-up in our asset retirement obligations reflected in our financial statements.
Penalties for Non-Compliance. We believe that our operations are in material compliance with all applicable oil and natural gas, safety, environmental and land-use laws and regulations. However, from time to time we receive notices of noncompliance with Clean Air Act and other requirements from relevant regulatory agencies. We received a number of minor notices of violation ("NOVs") from regulatory agencies in 2011. We do not expect to incur significant penalties with respect to any outstanding NOV. See "Legal Proceedings."
Other Regulation
The pipelines we use to gather and transport our oil and natural gas are subject to regulation by the U.S. Department of Transportation ("DOT") under the Hazardous Liquids Pipeline Safety Act of 1979, as amended ("HLPSA"), and the Pipeline Safety Act of 1992, which relate to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Under the Pipeline Safety Act, the Research and Special Programs Administration of DOT is authorized to require certain pipeline modifications as well as operational and maintenance changes. We believe our pipelines are in substantial compliance with HLPSA and the Pipeline Safety Act. Nonetheless, significant expenses could be incurred if new or additional safety requirements are implemented.
The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act and the Natural Gas Policy Act. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis.
The rates, terms, and conditions applicable to the interstate and intrastate transportation of oil by pipelines is regulated by, respectively, the FERC under the Interstate Commerce Act and the California Public Utilities Commission under the California Public Resources Code.
The safety of our operations primarily is regulated by the BOEMRE, the CSLC, the Coast Guard and the Occupational Safety and Health Administration. We believe our facilities and operations are in substantial compliance with the applicable requirements of those agencies. In the event different or additional safety measures are required in the future, we could incur significant expenses to meet those requirements.
In August 2011, EPA proposed regulations specifically applicable to the oil and gas industry that would require operators to capture 95 percent VOC emissions from wells that are hydraulically fractured. The proposed regulations also would require reductions in emissions of methane and air toxics. The proposal includes four rules for the oil and natural gas industry: a new source performance standard for VOCs; a new source performance standard for sulfur dioxide; an air toxics standard for oil and natural gas production; and an air toxics standard for natural gas transmission and storage. Any laws or regulations that may be adopted to restrict or reduce these emissions would likely require us to incur increased operating costs. The final rule is expected to be issued in March or April of 2012.
Executive Officers of the Registrant
The following table sets forth certain information with respect to our executive officers as of December 31, 2011.
Timothy Marquez co-founded Venoco in September 1992 and served as our CEO from our formation until June 2002. He founded Marquez Energy in 2002 and served as its CEO until we acquired it in March 2005. Mr. Marquez returned as our Chairman, CEO and President in June 2004. Mr. Marquez has a B.S. in petroleum engineering from the Colorado School of Mines. Mr. Marquez began his career with Unocal Corporation, where he worked for 13 years managing assets offshore California and in the North Sea and performing other managerial and engineering functions.
Edward O'Donnell is our COO. Mr. O'Donnell initially joined us in 1997 as Vice President of development and was later Vice President of the Offshore Business Unit. From April 2001 to June 2002 he served as the President of our Domestic Division. From June 2002 through 2005 he provided independent business consulting to non-profit organizations and small retail businesses. In 2006 he became the CEO of Gong Zhu Enterprises, a provider of financial, accounting, and management consulting services to small retail businesses. Mr. O'Donnell also served two terms on our board of directors. He re-joined us in March 2007 as Senior Vice President and was appointed COO in January 2012. In addition, on January 18, 2012 we announced a succession plan whereby Mr. Marquez plans to step down as our CEO in the third quarter of 2012, and, at that time, Mr. O'Donnell is expected to assume the role of CEO. Mr. O'Donnell has 20 years of experience with Unocal Corporation in various engineering and management positions. He holds a B.S. degree in petroleum engineering from Montana Tech, an M.S. in petroleum engineering from the University of Southern California and an M.B.A. from Pepperdine University.
Timothy A. Ficker became our CFO in April 2007. Prior to joining us, Mr. Ficker was Vice President, CFO and Secretary of Infinity Energy Resources, Inc., a NASDAQ-listed energy company, having been appointed to those positions in May 2005. From October 2003 through April 2005, Mr. Ficker served as an audit partner in KPMG LLP's Denver office, and from June 2002 through September 2003, he served as an audit director for KPMG LLP. From September 1989 through June 2002, he worked for Arthur Andersen LLP, including as an audit partner after September 2001, where he served clients primarily in the energy industry. Mr. Ficker is a certified public accountant and received a B.B.A. in accounting from Texas A&M University.
Terry L. Anderson is our General Counsel and Secretary. Mr. Anderson joined us in March 1998 and served as General Counsel until June 2002. From July 2002 to August 2004, Mr. Anderson was in private practice in Santa Barbara, California. He returned in his current capacities in August 2004. Mr. Anderson holds a B.S. in petroleum engineering and a J.D. from the University of Southern California. Mr. Anderson was Vice President and General Counsel of Monterey Resources, Inc., a NYSE-listed company, from August 1996 to January 1998. Prior to that, he was chief transactional attorney for Santa Fe Energy Resources in Houston, Texas. Mr. Anderson is licensed to practice law in Texas and California.
Mark DePuy is our Senior Vice President, Business Development and Acquisitions. Mr. DePuy initially joined us in 2005 as Vice President of Northern Assets. The following year, he was named
COO and oversaw our assets in Northern and Southern California, as well as numerous field operations in Texas. Mr. DePuy resigned as our COO in October 2008, after which he provided consulting services for us on coastal development projects in California. From March 2010 through November 2011, he served as CEO and President of Great Western Oil and Gas, a private oil and gas company with operations focused primarily in Colorado and North Dakota. Mr. DePuy re-joined us in his current role in December 2011. He has 27 years of experience in various operational, management and business planning functions with Unocal/Chevron in both the domestic and international operations. He has an M.B.A. from the University of California, Los Angeles and a B.S. in petroleum engineering from the Colorado School of Mines.
Available Information
We maintain a link to investor relations information on our website, www.venocoinc.com, where we make available, free of charge, our filings with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, or Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also make available on our website copies of the charters of the audit, compensation and corporate governance/nominating committees of our board of directors, our code of business conduct and ethics and our corporate governance guidelines. Stockholders may request a printed copy of these governance materials or any exhibit to this report by writing to the Corporate Secretary, Venoco, Inc., 370 17th Street, Suite 3900, Denver, Colorado, 80202-1370. You may also read and copy any materials we file with the SEC at the SEC's Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Information regarding the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains the documents we file with the SEC. Our website and the information contained on or connected to our website is not incorporated by reference herein and our web address is included as an inactive textual reference only.
ITEM 1A.
ITEM 1A. Risk Factors
Oil and natural gas prices are volatile and change for reasons that are beyond our control. Decreases in the price we receive for our oil and natural gas production adversely affect our business, financial condition, results of operations and liquidity.
Declines in the prices we receive for our oil and natural gas production adversely affect many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth and the carrying value of our oil and natural gas properties, all of which depend primarily or in part upon those prices. For example, due in significant part to lower commodities prices, our revenues from oil and natural gas sales and cash flow from operations declined 52% and 44%, respectively, in 2009 compared to 2008. Declines in the prices we receive for our oil and natural gas also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations. For example, continued depressed natural gas prices have caused us to reduce our drilling activity in the Sacramento Basin from 93 wells spud in 2010 to 40 wells in 2011 and we have included five wells in our 2012 capital expenditure budget. In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and, as a result, adversely affect our quantities of proved reserves. Among other things, a reduction in our reserves can limit the capital available to us, as the maximum amount of available borrowing under our revolving credit facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantities of those reserves.
Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Prices have historically been volatile and are likely to continue to be volatile in the future. The prices of oil and natural gas are affected by a variety of factors that are beyond our control, including changes in global supply and demand for oil and natural gas, domestic and foreign governmental regulations and taxes, the level of global oil and natural gas exploration activity and inventories, the price, availability and consumer acceptance of alternative fuel sources, the availability of refining capacity, technological advances affecting energy consumption, weather conditions, speculative activity, financial and commercial market uncertainty and worldwide economic conditions.
In addition to factors affecting the price of oil and natural gas generally, the prices we receive for our oil and natural gas production is affected by factors specific to us and to the local markets where the production occurs. Pricing can be influenced by, among other things, local or regional supply and demand factors (such as refinery or pipeline capacity issues, trade restrictions and governmental regulations) and the terms of our sales contracts.
The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, our California oil typically has a lower gravity, and a portion has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil requires more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. This discount, or differential, varies over time and can be affected by factors that do not have the same impact on the price of premium grade light oil. We cannot predict how the differential applicable to our production will change in the future, and it is possible that it will increase. The difficulty involved in predicting the differential also makes it more difficult for us to effectively hedge our production. Many of our hedging arrangements are based on benchmark prices and therefore do not fully protect us from adverse changes in the differential applicable to our production.
Our planned operations will require additional capital that may not be available.
Our business is capital intensive, and requires substantial expenditures to maintain currently producing wells, to make the acquisitions and/or conduct the exploration, exploitation and development
activities necessary to replace our reserves, to pay expenses and to satisfy our other obligations. In recent years, we have chosen to pursue projects that required capital expenditures in excess of cash flow from operations. That fact has made us dependent on external financing to a greater degree than many of our competitors. Our substantial existing indebtedness increases the risk that external financing will not be available to us when needed. If we reduce our capital spending in an effort to conserve cash, this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flow from operations and income.
It may be difficult or impossible for us to finance our operations through the incurrence of additional indebtedness.
We have relied on borrowings under our revolving credit facility to finance our operations in some recent periods. Lenders may not fund borrowings under the facility when we request them to do so. In 2009, a former lender under the facility, Lehman Commercial Paper, Inc., ceased funding amounts under the facility as a result of the bankruptcy of its parent company, Lehman Brothers Holdings Inc. Existing lenders under the revolving credit facility may face similar issues. Our ability to borrow under the facility may also be limited if we are unable, or run a significant risk of becoming unable, to comply with the financial covenants that we are required to satisfy under the facility. It may be difficult to maintain compliance with the maximum debt to EBITDA (as defined in the agreement) ratio in the future if we borrow a significant portion of the available capacity under the facility and/or our EBITDA is adversely affected by operational problems, counterparties' failure to perform under hedge agreements or other factors. In addition, the borrowing base under the facility is subject to redetermination periodically and from time to time in the lenders' discretion. Borrowing base reductions may occur with respect to the revolving credit facility as a result of unfavorable changes in commodity prices, asset sales, performance issues or other events. Due in significant part to lower commodity prices, the borrowing base under the revolving credit facility was reduced in early 2009 from $200 million to $125 million. Our current borrowing base is $200 million. In addition to reducing the capital available to finance our operations, a reduction in the borrowing base could cause us to be required to repay amounts outstanding under the facility in excess of the reduced borrowing base, and the funds necessary to do so may not be available at that time.
Sources of external debt financing other than revolving credit facility borrowings may not be available when needed on acceptable terms or at all, especially during periods in which financial market conditions are unfavorable. Our ability to incur additional indebtedness will be limited under the terms of the revolving credit facility, the indenture governing our 8.875% senior notes and the indenture governing our 11.50% senior notes, which we refer to collectively as our debt agreements (see-"Liquidity and Capital Resources-Capital Resources and Requirements"). In addition, if we finance our operations through borrowings under our revolving credit facility or other additional indebtedness, the risks that we now face relating to our current debt level would intensify, and it may be more difficult to satisfy our existing financial obligations.
We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt.
We have a substantial amount of indebtedness. At February 14, 2012, we had total outstanding debt of $679.0 million, comprised of $35.0 million outstanding on our revolving credit facility, $500.0 million under our 8.875% senior notes and $144.0 million (net of discount) under our 11.50% senior notes. Interest obligations on our indebtedness are significant. Our debt bears interest at a weighted average interest rate of approximately 9.20% as of February 14, 2012. In 2011, we had interest expense of $61.1 million.
Our level of indebtedness could have important effects on our business. For example, it could:
•make it more difficult for us to satisfy our obligations under our debt agreements and increase the risk that we may default on our debt obligations;
•require us to dedicate a substantial portion of our cash flow from operations and certain types of transactions to payments on our debt, thereby reducing the amount of our cash flow available for working capital, capital expenditures, acquisition and other investment opportunities and other general business activities;
•limit our flexibility in planning for, or reacting to, changes in commodity prices, our business or the oil and gas industry;
•place us at a competitive disadvantage compared to our competitors that have lower debt service obligations and significantly greater operating and financing flexibility than we do;
•limit our financial flexibility, including our ability to borrow additional funds on favorable terms or at all;
•increase our vulnerability to general adverse economic and industry conditions; and
•result in an event of default upon a failure to comply with financial covenants contained in our debt agreements which, if not cured or waived, could have a material adverse effect on our business, financial condition or results of operations.
If our cash flow and other capital resources are insufficient to fund our obligations under our debt agreements on a current basis and at maturity, we could attempt to refinance or restructure the debt or to repay the debt with the proceeds from an equity offering or from sales of assets. The proceeds of future borrowings, equity financings or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all. In addition, our debt agreements contain provisions that would limit our flexibility in responding to a shortfall in our expected liquidity by selling assets or taking certain other actions. For example, we could be required to use some or all of the proceeds of an asset sale to reduce amounts outstanding under our debt agreements in some circumstances. Any refinancing that requires the use of cash could require us to reduce or delay planned capital expenditures. There can be no assurance that any such strategies could be implemented on satisfactory terms, if at all.
We also face a refinancing risk. Significant amounts of our indebtedness do not require current payments of principal, but are payable in full on maturity. Cash flow from operations may not be sufficient to repay the outstanding balance on our debt when it matures. Global capital markets have experienced a severe contraction in the availability of debt financing in the recent past. Financial effects of this crisis were exacerbated in the oil and natural gas industry by the effect of volatile commodity prices. The ability to pay principal and interest on our debt, and to refinance our debt upon maturity, will depend not only upon our financial and operating performance, but on the state of the global economy, credit markets and commodity prices during the period through the time of refinancing, many of which are factors over which we have no control. There can be no assurances that we will be able to make principal and interest payments on our indebtedness and to refinance our indebtedness at maturity as needed.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.
The reserve data included in this report represent estimates only. Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as
future commodity prices, production costs, severance and excise taxes and availability of capital, estimates of required capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of our reserves, the economically recoverable quantities of oil and natural gas attributable to our properties, the classifications of reserves based on risk of recovery and estimates of our future net cash flows.
Additionally, SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This recently-implemented rule has limited and may continue to limit our potential to record additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.
At December 31, 2011, 49% of our estimated proved reserves were proved undeveloped and 10% were proved developed non-producing. Estimation of proved undeveloped reserves and proved developed non-producing reserves is almost always based on analogy to existing wells as contrasted with the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Revenues from estimated proved developed non-producing reserves will not be realized until some time in the future, if at all.
You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our PV-10 estimates are based on assumed future prices and costs. Actual future prices and costs may be materially higher or lower than the assumed prices and costs. Further, the effect of derivative instruments is not reflected in these assumed prices. Also, the use of a 10% discount factor to calculate PV-10 may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
Oil and natural gas exploration, exploitation and development activities may not be successful and could result in a complete loss of a significant investment.
Exploration, exploitation and development activities are subject to many risks. For example, new wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. Similarly, previously producing wells that are returned to production after a period of being shut in may not produce at levels that justify the expenditures made to bring the wells back on line. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. In addition, the cost of exploration, exploitation and development activities is subject to numerous uncertainties, and cost factors can adversely affect the economics of a project. Further, our exploration, exploitation and development activities may be curtailed, delayed or canceled as a result of numerous factors, including:
•title problems;
•problems in delivery of our oil and natural gas to market;
•pressure or irregularities in geological formations;
•equipment failures or accidents;
•adverse weather conditions;
•reductions in oil and natural gas prices;
•compliance with environmental and other governmental requirements, including with respect to permitting issues; and
•costs of, or shortages or delays in the availability of, drilling rigs, equipment, qualified personnel and services.
Dry holes and other unsuccessful or uneconomic exploration, exploitation and development activities adversely affect our cash flow, profitability and financial condition, and can adversely affect our reserves.
Drilling results in emerging plays, such as the onshore Monterey shale, are subject to heightened risks.
Part of our strategy is to pursue acquisition, exploration and development activities in emerging plays such as our onshore Monterey shale project. Our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Because emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. In addition, part of our drilling strategy to maximize recoveries from the onshore Monterey shale formation may involve drilling and/or completion techniques that have proven to be successful in other shale formations. These drilling and completion strategies and techniques require greater amounts of capital investment than more established plays. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established. If drilling success rates or production are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations or other operational problems, the value of our position in the affected area will decline, our results of operations, financial condition and liquidity will be adversely impacted and we could incur material write-downs of unevaluated properties.
The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not control. When these facilities or systems are unavailable, our operations can be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities owned by third parties. In general, we do not control these facilities and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to deliver to market the oil and natural gas we produce and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our oil and natural gas is dependent upon coordination among third parties who own transportation and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. These are risks for which we generally do not maintain insurance.
Our hedging arrangements involve credit risk and may limit future revenues from price increases, result in financial losses or reduce our income.
To reduce our exposure to fluctuations in the prices of oil and natural gas, we enter into hedging arrangements with respect to a substantial portion of our oil and natural gas production. See
"Quantitative and Qualitative Disclosures About Market Risk" for a summary of our hedging activity. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:
•production is less than expected;
•a counterparty to a hedging contract fails to perform under the contract; or
•there is a change in the expected differential between the underlying price in the hedging contract and the actual prices received.
A significant percentage of our cash flow in some prior periods resulted from payments made to us by our hedge counterparties. If hedge counterparties are unable to make payments to us under our hedging arrangements, our results of operation, financial condition and liquidity would be adversely affected. In addition, the uncertainties associated with our hedging programs are greater than those of many of our competitors because the price of the heavy oil that we produce in California is subject to risks that are in addition to the price risk associated with premium grade light oil. Also, our working capital could be impacted if we enter into derivative arrangements that require cash collateral and commodity prices subsequently change in a manner adverse to us. The obligation to post cash or other collateral could, if imposed, adversely affect our liquidity.
Moreover, we have experienced, and may continue to experience, substantial realized and unrealized losses relating to our hedging arrangements. Realized commodity derivative gains or losses represent the difference between the strike prices set forth in hedging contracts settled during the relevant period and the ultimate settlement prices. We incur a realized commodity derivative loss when a contract is settled at a price above the strike price. Losses of this type reflect the limit our hedging arrangements impose on the benefits we would otherwise have received from an increase in the price of oil or natural gas during the period. Unrealized commodity derivative gains and losses represent the change in the fair value of our open derivative contracts from period to period. We incur an unrealized commodity derivative loss when the futures price used to estimate the fair value of a contract at the end of the period rises. Increases in oil prices have caused us to incur substantial realized and unrealized commodity derivative losses in some recent periods, and we may experience similar or greater losses of these types in future periods. We may experience more volatility in our commodity derivative gains and losses than many of our competitors because we do not designate our derivatives as cash flow hedges for accounting purposes and because we hedge a larger percentage of our production than some of our competitors.
We are subject to complex laws and regulations, including environmental laws and regulations, that can adversely affect the cost, manner and feasibility of doing business and limit our growth.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to exploration for, and the exploitation, development, production and transportation of, oil and natural gas, as well as environmental, safety and other matters. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, may harm our business, results of operations and financial condition. Laws and regulations applicable to us include those relating to:
•land use restrictions, which are particularly strict along the coast of southern California where many of our operations are located;
•drilling bonds and other financial responsibility requirements;
•spacing of wells;
•emissions into the air (including emissions from ships in the Santa Barbara channel);
•unitization and pooling of properties;
•habitat and endangered species protection, reclamation and remediation;
•the containment and disposal of hazardous substances, oil field waste and other waste materials;
•the use of underground storage tanks;
•transportation and drilling permits;
•the use of underground injection wells, which affects the disposal of water from our wells;
•safety precautions;
•the prevention of oil spills;
•the closure of production facilities;
•operational reporting; and
•taxation and royalties.
Under these laws and regulations, we could be liable for:
•personal injuries;
•property and natural resource damages;
•releases or discharges of hazardous materials;
•well reclamation costs;
•oil spill clean-up costs;
•other remediation and clean-up costs;
•plugging and abandonment costs, which may be particularly high in the case of offshore facilities;
•governmental sanctions, such as fines and penalties; and
•other environmental damages.
Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. We are a defendant in a series of lawsuits alleging, among other things, that air, soil and water contamination from the oil and natural gas facility at our Beverly Hills field caused the plaintiffs to develop cancer or other diseases or to sustain related injuries. See "Legal Proceedings-Beverly Hills Litigation." These suits and/or related indemnity claims could have a material adverse effect on our financial condition. Moreover, compliance with applicable laws and regulations could require us to delay, curtail or terminate existing or planned operations.
Some environmental laws and regulations impose strict liability. Strict liability means that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of prior operators of properties we have acquired or other third parties, including, in some circumstances, operators of properties in which we have an interest and parties that provide transportation services for us. Similarly, some environmental laws and regulations impose joint and several liability, meaning that we could be held responsible for more than our share of a particular reclamation or other obligation, and potentially the entire obligation, where other parties were involved in the activity giving rise to the liability. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Similarly, our plugging and abandonment obligations will be substantial and may be more than our estimates. Compliance costs are relatively high for us because many of our properties are located offshore California and in other environmentally sensitive areas and because California environmental laws and
regulations are generally very strict. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters, but they will be material. Environmental risks are generally not fully insurable.
Similarly, our operations could be adversely affected by environmental and other laws and regulations that require us to obtain permits before commencing drilling or other activities. For example, we recently terminated our pursuit of a proposed lease extension in the South Ellwood field due to difficulties in obtaining the necessary permits. In addition, even when permits are granted, they may be subject to conditions which impose delays on a project, increase its costs or reduce its benefits to us. Permitting and similar risks are high for us relative to many of our competitors because oil and natural gas projects are frequently the source of considerable political controversy in California, and political opposition may make it more difficult for us to obtain consents and approvals for our projects.
Changes in applicable laws and regulations could increase our costs, reduce demand for our production, impede our ability to conduct operations or have other adverse effects on our business.
Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gas ("GHG") present an endangerment to human health and the environment, which allows EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider "cap and trade" legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. On September 27, 2006, California's governor signed into law Assembly Bill (AB) 32, known as the "California Global Warming Solutions Act of 2006," which established a statewide cap on GHGs designed to reduce the state's GHG emissions to 1990 levels by 2020 and establishes a "cap and trade" program. The California Air Resources Board adopted regulations that went into effect on January 1, 2012. These regulations are not expected to directly impact our operations as the first phase, beginning in 2012, includes all major industrial sources and utilities, while the second phase, which starts in 2015, will address distributors of transportation fuels, natural gas, and other fuels. We will continue to monitor the implementation of these regulations through industry trade groups and other organizations in which we are a member. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.
Additionally, the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Reform Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through implementing regulations to be adopted by the SEC, the Commodities Futures Trading Commission and other regulators. We are currently assessing the likely impact of the Reform Act on our operations, and this assessment will continue as the regulatory process contemplated by the Reform Act progresses. If, as a result of the Reform Act or its implementing regulations, capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions, which are currently collateralized on a non-cash basis by our oil and natural gas properties and other assets, would likely make it impracticable to implement our current hedging strategy or to meet the hedging requirements contained in our revolving credit facility. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy. We are more vulnerable to the adverse consequences of changes in laws and regulations relating to derivatives than many of our competitors because we hedge a relatively large proportion of our expected production and because our hedging strategy is integral to our overall business strategy.
Following the Deepwater Horizon well blowout in the Gulf of Mexico, the Secretary of the U.S. Department of Interior imposed a drilling moratorium in May 2010, which delayed a planned redrill of an inactive well from Platform Gail. That moratorium was subsequently lifted for fixed-leg platforms like Platform Gail. However, additional moratoria, or similar rules promulgated by other governmental authorities, could have significant impacts on our operations in the future. In addition, the U.S. Department of Interior has experienced significant delays in processing permit applications for new drilling projects. Delays in the government's permitting process could have significant impacts on the industry as a whole and our future results of operations.
In addition, some of our activities involve the use of hydraulic fracturing, which is a process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water and chemicals into the rock formation. The EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act's Underground Injection Control Program and has commenced drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study anticipated to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced in October 2011 that it is also commencing a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the Fracturing Responsibility and Awareness of Chemicals Act has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. These proposals, to the extent adopted, may increase our costs and make it more difficult, or impossible, to pursue some of our exploration or development projects.
We could also be adversely affected by future changes to applicable tax laws and regulations. For example, proposals have been made to amend federal and/or California law to impose "windfall profits," severance or other taxes on oil and natural gas companies. If any of these proposals become law, our costs would increase, possibly materially. Significant financial difficulties currently facing the State of California may increase the likelihood that one or more of these proposals will become law.
President Obama's 2013 Fiscal Year Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.
Our business involves significant operating risks that could adversely affect our production and could be expensive to remedy. We do not have insurance to cover all of the risks that we may face.
Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including:
•well blowouts;
•cratering and explosions;
•pipe failures and ruptures;
•pipeline accidents and failures;
•casing collapses;
•fires;
•mechanical and operational problems that affect production;
•formations with abnormal pressures;
•uncontrollable flows of oil, natural gas, brine or well fluids; and
•releases of contaminants into the environment.
Our offshore operations are further subject to a variety of operating risks specific to the marine environment, including a dependence on a limited number of gas and water injection wells and electrical transmission lines. Moreover, because we operate in California, we are also susceptible to risks posed by natural disasters such as earthquakes, mudslides, fires and floods.
In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our operations are conducted offshore and in other environmentally sensitive areas, including areas with significant residential populations. We do not maintain insurance in amounts that cover all of the losses to which we may be subject, and the insurance we have may not continue to be available on acceptable terms. Moreover, some risks we face are not insurable. Also, we could in some circumstances have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.
A failure to complete successful acquisitions would limit our growth.
Because our oil and natural gas properties are depleting assets, our future oil and natural gas reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. Acquiring additional oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is an important component of our strategy. Our focus on the California market reduces the pool of suitable acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. Our substantial level of indebtedness will limit our ability to make future acquisitions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.
Acquisitions involve a number of risks, including the risk that we will discover unanticipated liabilities or other problems associated with the acquired business or property.
In assessing potential acquisitions, we typically rely to a significant extent on information provided by the seller. We independently review only a portion of that information. In addition, our review of the business or property to be acquired will not be comprehensive enough to uncover all existing or
potential problems that could affect us as a result of the acquisition. Accordingly, it is possible that we will discover problems with an acquired business or property that we did not anticipate at the time we completed the transaction. These problems may be material and could include, among other things, unexpected environmental problems, title defects or other liabilities. When we acquire properties on an "as-is" basis, we have limited or no remedies against the seller with respect to these types of problems.
The success of any acquisition we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales. In addition, we may face greater risks to the extent we acquire properties in areas outside of California, because we may be less familiar with operating, regulatory and other issues specific to those areas.
Our ability to achieve the benefits we expect from an acquisition will also depend on our ability to efficiently integrate the acquired operations with ours. Our management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business concerns. The challenges involved in the integration process may include retaining key employees and maintaining key employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding the acquired properties.
Competition in the oil and natural gas industry is intense and may adversely affect our results of operations.
We operate in a competitive environment for acquiring properties, marketing oil and natural gas, integrating new technologies and employing skilled personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be willing and able to pay more for oil and natural gas properties than our financial resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. Our competitors may also enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future with respect to acquiring prospective reserves, developing reserves, marketing our production, attracting and retaining qualified personnel, implementing new technologies and raising additional capital.
Enhanced recovery techniques may not be successful, which could adversely affect our financial condition or results of operations.
Certain of our properties may provide opportunities for a CO2 enhanced recovery project. Risks associated with enhanced recovery techniques include, but are not limited to, the following:
•geologic unsuitability of the properties subject to the enhanced recovery project;
•unavailability of an economic and reliable supply of CO2, or other shortages of equipment;
•lower than expected production;
•longer response times;
•higher operating and capital costs; and
•lack of technical expertise.
If any of these risks occur, it could adversely affect the results of the affected project, our financial condition and our results of operations. We may pursue other enhanced recovery activities from time to time as well, and those activities may be subject to the same or similar risks.
Our operations are subject to a variety of contractual, regulatory and other constraints that can limit our production and increase our operating costs and thereby adversely affect our results of operations.
We are subject to a variety of contractual, regulatory and other operating constraints that limit the manner in which we conduct our business. These constraints affect, among other things, the permissible uses of our facilities, the availability of pipeline capacity to transport our production and the manner in which we produce oil and natural gas. These constraints can change to our detriment without our consent. These events, many of which are beyond our control, could have a material adverse effect on our results of operations and financial condition and could reduce estimates of our proved reserves.
The loss of our key personnel could adversely affect our business.
We believe our continued success depends in part on the collective abilities and efforts of our key personnel, including our executive officers. We do not maintain key man life insurance policies. The loss of the services of key management personnel could have a material adverse effect on our results of operations. Additionally, if we are unable to find, hire and retain needed key personnel in the future, our results of operations could be materially and adversely affected.
Shortages of qualified operational personnel or field equipment and services could affect our ability to execute our plans on a timely basis, increase our costs and adversely affect our results of operations.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. From time to time, there have also been shortages of drilling rigs and other field equipment, as demand for rigs and equipment has increased with the number of wells being drilled. These factors can also result in significant increases in costs for equipment, services and personnel. For example, we have experienced an increase in drilling, completion and other costs associated with certain Monterey shale wells. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. From time to time, we have experienced some difficulty in obtaining drilling rigs, experienced crews and related services and may continue to experience these difficulties in the future. In part, these difficulties arise from the fact that the California market is not as attractive for oil field workers and equipment operators as mid-continent and Gulf Coast areas where drilling activities are more widespread. In addition, the cost of drilling rigs and related services has increased significantly over the past several years. If shortages persist or prices continue to increase, our profit margin, cash flow and operating results could be adversely affected and our ability to conduct our operations in accordance with current plans and budgets could be restricted.
Because we cannot control activities on properties we do not operate, we cannot control the timing of those projects. If we are unable to fund required capital expenditures with respect to non-operated properties, our interests in those properties may be reduced or forfeited.
Other companies operated approximately 4% of our production in the fourth quarter of 2011. Our ability to exercise influence over operations for these properties and their associated costs is limited. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to exploration, exploitation, development or acquisition activities. The success and timing of exploration, exploitation and development activities on properties operated by others depend upon a number of factors that may be outside our control, including:
•the timing and amount of capital expenditures;
•the operator's expertise and financial resources;
•approval of other participants in drilling wells; and
•selection of technology.
Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with the project. If we are not willing and able to fund required capital expenditures relating to a project when required by the majority owner or operator, our interests in the project may be reduced or forfeited. Also, we could be responsible for plugging and abandonment and other liabilities in excess of our proportionate interest in the property.
Changes in the financial condition of any of our large oil and natural gas purchasers or other significant counterparties could adversely affect our results of operations and liquidity.
For the year ended December 31, 2011, approximately 95% of our oil and natural gas revenues were generated from sales to four purchasers: ConocoPhillips, Enserco Energy, Calpine Producer Services LP and Concord Energy LLC. In 2012, we expect to sell a significant amount of our production to Tesoro Refining and Marketing Company. A material adverse change in the financial condition of any of our largest purchasers could adversely impact our future revenues and our ability to collect current accounts receivable from such purchasers. We face similar counterparty risks in connection with other contracts under which we may be entitled to receive cash payments, including insurance policies and commodity derivative agreements. Major counterparties may also seek price or other concessions from us if they perceive us to be dependent on them or to lack viable alternatives.
We were required to write down the carrying value of our properties as of December 31, 2008 and may be required to do so again in the future.
We use the full cost method of accounting for oil and natural gas exploitation, development and exploration activities. Under full cost accounting rules, we perform a "ceiling test." This test is an impairment test and generally establishes a maximum, or "ceiling," of the book value of our oil and natural gas properties that is equal to the expected after-tax present value of the future net cash flows from proved reserves, calculated using the twelve month arithmetic average of the first of the month prices. If the net book value of our properties (reduced by any related net deferred income tax liability) exceeds the ceiling, we write down the book value of the properties. At December 31, 2008, our net capitalized costs exceeded the ceiling by $641 million, net of income tax effects, and we recorded an impairment of our oil and gas properties in that amount. We could recognize further impairments in the future. To the extent our acquisition and development costs increase, we will become more susceptible to ceiling test write downs in low price environments.
All of our producing properties are located in one state and adverse developments in that state would negatively affect our financial condition and results of operations.
All of our principal properties are located in California. Our Southern California and Sacramento Basin properties represented approximately 53% and 47%, respectively, of our proved reserves as of December 31, 2011 and accounted for a combined 100% of our 2011 production. Any circumstance or event that negatively impacts the production or marketing of oil and natural gas in California generally, or in Southern California or the Sacramento Basin in particular, would adversely affect our results of operations and cash flows. Many of our competitors have operations that are more geographically dispersed than ours, and therefore may be less subject than we are to risks affecting a particular geographic area.
We are controlled by Timothy Marquez, who is able to determine the outcome of matters submitted to a vote of our stockholders. This limits the ability of other stockholders to influence our management and policies.
Timothy Marquez, our Chairman and CEO, beneficially owned approximately 50.3% of our outstanding common stock as of February 14, 2012. Through this ownership, Mr. Marquez is able to control the composition of our board of directors and direct our management and policies. Accordingly, Mr. Marquez generally has the direct or indirect power to:
•elect all of our directors and thereby control our policies and operations;
•amend our bylaws and some provisions of our certificate of incorporation;
•appoint our management;
•approve future issuances of our common stock or other securities;
•approve the payments of dividends, if any, on our common stock;
•approve the incurrence of debt by us; and
•agree to or prevent mergers, consolidations, sales of all or substantially all our assets or other extraordinary transactions.
Mr. Marquez's significant ownership interest could adversely affect investors' perceptions of our corporate governance. In addition, Mr. Marquez may have an interest in pursuing acquisitions, divestitures and other transactions that involve risks to us. For example, Mr. Marquez could cause us to make acquisitions that increase our indebtedness or to sell revenue generating assets. Mr. Marquez may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Also, we have engaged, and may continue to engage, in related party transactions involving Mr. Marquez. For example, we have entered into a non-exclusive aircraft sublease agreement with TimBer, LLC, a company owned by Mr. Marquez and his wife.
The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets or the issuance of additional shares of common stock in future acquisitions.
Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares in the public market, or the possibility of such sales, could impair our ability to raise capital through the sale of additional common or preferred stock. As of February 14, 2012, Timothy Marquez beneficially owned approximately 50.3% of our common stock, primarily through the Marquez Trust. As of December 31, 2011, we had granted options to purchase an aggregate of approximately 0.8 million shares of our common stock and 2.8 million shares of restricted stock to certain of our directors and employees. The Marquez Trust and these other holders, subject to compliance with applicable securities laws and vesting requirements, are permitted to sell shares they own or acquire upon the exercise of options in the public market. Sales of a substantial number of shares of our common stock by those holders could cause our stock price to fall.
In addition, in the future, we may issue shares of our common stock in connection with acquisitions of assets or businesses. If we use our shares for this purpose, the issuances could have a dilutive effect on the market value of shares of our common stock, depending on market conditions at the time of an acquisition, the price we pay, the value of the business or assets acquired, our success in exploiting the properties or integrating the businesses we acquire and other factors.
Our certificate of incorporation and bylaws and Delaware law contain provisions that may prevent, discourage or frustrate attempts to replace or remove our current management by our stockholders, even if such replacement or removal may be in our stockholders' best interests.
Our certificate of incorporation and bylaws and Delaware law contain provisions that could enable our management, including Mr. Marquez, to resist a takeover attempt (even if Mr. Marquez ceases to beneficially own a controlling block of our common shares). These provisions:
•restrict various types of business combinations with significant stockholders (other than the Marquez Trust, Mr. Marquez and his wife);
•provide for a classified board of directors;
•limit the right of stockholders to remove directors or change the size of the board of directors;
•limit the right of stockholders to fill vacancies on the board of directors;
•limit the right of stockholders to act by written consent or call a special meeting of stockholders;
•require a higher percentage of stockholders than would otherwise be required to amend, alter, change or repeal certain provisions of our certificate of incorporation; and
•authorize the issuance of preferred stock with any voting rights, dividend rights, conversion privileges, redemption rights and liquidation rights and other rights, preferences, privileges, powers, qualifications, limitations or restrictions as may be specified by our board of directors.
These provisions could discourage, delay or prevent a change in the control of our company or a change in our management, even if the change would be in the best interests of our stockholders, adversely affect the voting power of holders of common stock and limit the price that investors might be willing to pay in the future for shares of our common stock. Similarly, our debt agreements have provisions relating to a change of control of our company that could have a similar effect.
There can be no assurance that the transaction contemplated by the merger agreement between us and Mr. Marquez and certain of his affiliates will be completed. If the merger is not completed, the market price of our common stock may be adversely affected.
In August 2011, our board of directors received the proposal from Mr. Marquez described in "Management's Discussion and Analysis of Financial Condition and Results of Operations-Overview-Recent Events." In January 2012, we announced that we entered into a definitive merger agreement with Mr. Marquez and certain of his affiliates pursuant to which he will acquire all shares of which he is not the beneficial owner for $12.50 per share in cash. The closing trading price of our common stock was $8.98 per share on the last trading day prior to the announcement of the proposal, and it was $7.69 per share on the last trading day prior to the announcement of the merger agreement. After each announcement, the trading price of our common stock increased and traded closer to the $12.50 per share proposal price. However, the trading price of our common stock has been subject to significant volatility since the original announcement. Completion of the transaction is subject to certain closing conditions, including procurement of financing, receipt of shareholder approval (including approval by a majority of the unaffiliated shareholders) and other customary conditions. There can be no assurance that those conditions will be satisfied. If the transaction is not consummated, the stock price could fall below its current trading range. In addition, we could be required to make an expense reimbursement payment to an affiliate of Mr. Marquez if the merger agreement is terminated in certain circumstances. We could also be adversely affected by litigation that has been initiated in connection with the transaction.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 3.
ITEM 3. Legal Proceedings
In the ordinary course of our business we are named from time to time as a defendant in various legal proceedings. We maintain liability insurance and believe that our coverage is reasonable in view of the legal risks to which our business ordinarily is subject.
Beverly Hills Litigation
Between June 2003 and April 2005, six lawsuits were filed against us and certain other energy companies in Los Angeles County Superior Court by persons who attended Beverly Hills High School or who were or are citizens of Beverly Hills/Century City or visitors to that area during the time period running from the 1930s to date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which we have not been named) who claimed to be suffering from various forms of cancer or other illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs alleged that exposure to substances in the air, soil and water that originated from either oil-field or other operations in the area were the cause of the cancers and other maladies. We have owned an oil and natural gas facility adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before we acquired the facility. All cases were consolidated before one judge. Twelve "representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs' cases were stayed. In November 2006, the judge entered summary judgment in favor of all defendants in the test cases, including Venoco. The judge dismissed all claims by the test case plaintiffs on the ground that they offered no evidence of medical causation between the alleged emissions and the plaintiffs' alleged injuries. Plaintiffs appealed the ruling. A decision on the appeal is expected in 2012. We vigorously defended the actions, and will continue to do so until they are resolved. Certain defendants and related parties have made claims for indemnity which we are disputing. We cannot predict the cost of indemnity obligations at the present time.
One of our insurers currently is paying for the defense of these lawsuits under a reservation of its rights. If the insurer ceases to provide such defense and we are unsuccessful in enforcing our rights in any subsequent litigation, we may be required to bear the costs of the defense, and those costs may be material. If it ultimately is determined that the pollution exclusion or another exclusion contained in one or more of its policies applies, we will not have the protection of those policies with respect to any damages or settlement costs ultimately incurred in the lawsuits.
Based on the information known to us to date, we do not believe that it is probable that a material judgment against us will result. Therefore, no liability has been accrued. If one or more of these matters are resolved in a manner adverse to us, and if insurance coverage is determined not to be applicable, their impact on our results of operations, financial position and/or liquidity could be material.
State Lands Commission Royalty Litigation
In November 2011, the California State Lands Commission (SLC) filed suit against us in Santa Barbara County alleging that we underpaid royalties on oil and gas produced from the South Ellwood field in California for the period from August 1, 1997 through May 2011 by approximately $9.5 million. The case has since been removed to Los Angeles County, California. The principal issues in dispute are (i) the oil price on which royalties should be calculated and (ii) whether we are entitled to deduct the cost of transporting oil from the South Ellwood field to the point of sale in calculating the royalty. With respect to the oil price, we have paid royalties based on the price we actually received in
arms-length transactions. The SLC contends that we should be paying royalties based on the higher of the price actually received and the highest "posted price" for oil sold in the Midway Sunset Field, near Bakersfield, California. With respect to the deduction of transportation costs, we believe that state law allows us to adjust the sale price to reflect the cost of delivering the oil from the field to the point of sale. Based on our review of the SLC's contentions, audit records and additional historical records, we believe that we may have overpaid royalties on oil and gas production during the period in question and we may be owed a refund of such overpayments. We believe the position of the SLC is without merit and we intend to vigorously contest the suit and to enforce our right to receive a refund of royalties we may have overpaid. We do not believe that it is probable that a material judgment against us will result. Therefore, no liability has been accrued.
Delaware Litigation
On August 26, 2011, Timothy Marquez, our Chairman and CEO, submitted a nonbinding proposal to our board of directors to acquire all of the shares of Venoco he does not beneficially own for $12.50 per share in cash (the "Marquez Proposal"). As a result of that proposal, four lawsuits were filed in the Delaware Court of Chancery in 2011 against the Company and each of our directors by shareholders alleging that the Company and our directors had breached their fiduciary duties to the shareholders in connection with the Marquez Proposal. A fifth lawsuit filed in 2011, also in the Delaware Court of Chancery, named only Mr. Marquez as a defendant. On January 16, 2012, we announced we had entered into a merger agreement with Mr. Marquez and certain of his affiliates pursuant to which, at closing, each of the shareholders other than Mr. Marquez and his affiliates would receive $12.50 for each share of Company stock (the "Merger"). Following announcement of the merger agreement, three additional suits were filed in Delaware and three suits were filed in federal court in Colorado naming as defendants the Company and each of our directors. Each action seeks certification as a class action. Plaintiffs in both the Delaware and Colorado actions challenge the Merger and allege, among other things, that the consideration to be paid is inadequate. The complaints seek, among other relief, to enjoin defendants from consummating the Merger and to direct defendants to exercise their fiduciary duties to obtain a transaction that is in the best interests of the shareholders. We have reviewed the allegations contained in the complaints and believe they are without merit.
Other-In addition, we are a party from time to time to other claims and legal actions that arise in the ordinary course of business. We believe that the ultimate impact, if any, with respect to these other claims and legal actions will not have a material effect on our consolidated financial position, results of operations or liquidity.
ITEM 4.
ITEM 4. Mine Safety Disclosures.
Not applicable.
PART II
ITEM 5.
ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Price Range of Common Stock and Number of Holders
Our common stock is listed on the New York Stock Exchange under the symbol "VQ".
The following table sets forth the high and the low sale prices per share of our common stock for the periods indicated. The closing price of the common stock on February 14, 2012 was $11.11.
As of February 14, 2012, there were 361 record holders of our common stock.
Unregistered Sales of Equity Securities
Not applicable.
Dividend Policy
We have not declared any cash dividends on our common stock during the two most recent fiscal years and have no plans to do so in the foreseeable future. The ability of our board of directors to declare any dividend is subject to limits imposed by the terms of our debt agreements, which currently prohibit us from paying dividends on our common stock. Our ability to pay dividends is also subject to limits imposed by Delaware law. In determining whether to declare dividends, the board will consider the limits imposed by our debt agreements, our financial condition, results of operations, working capital requirements, future prospects and other factors it considers relevant.
Comparison of Cumulative Return
The following graph compares the cumulative return on a $100 investment in our common stock from November 17, 2006, the date the common stock trading began on the New York Stock Exchange, through December 31, 2011, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the S&P 1500 Oil and Gas Consumable Fuels Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. The indices are included for comparative purposes only. This graph is not "soliciting material," is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
COMPARISON OF CUMULATIVE TOTAL RETURN
AMONG VENOCO, INC., THE RUSSELL 2000 INDEX,
AND THE S&P 1500 OIL & GAS CONSUMABLE FUELS INDEX
ITEM 6.
ITEM 6. Selected Financial Data
The table below contains selected consolidated financial data. The statement of operations, cash flow, balance sheet and other financial data for each year has been derived from our consolidated financial statements. You should read this information together with "Management's Discussion and Analysis of Financial Condition and Results of Operation" and our consolidated financial statements and the related notes included elsewhere in this report. No pro forma adjustments have been made for the acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. Amounts are in thousands, except per share data.
ITEM 7.
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," and "us" 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 recent years, the exploration, exploitation and development of the onshore Monterey shale formation has taken a fundamental role in our corporate strategy, and efforts to expand our knowledge of the onshore formation have increased significantly. A substantial portion of our production is from offshore wells targeting the fractured Monterey shale formation, and we believe that there are significant opportunities relating to the Monterey shale formation onshore as well.
In the execution of our strategy, our management is principally focused on economically developing additional reserves of oil and natural gas and on maximizing production levels through exploration, exploitation and development activities in a manner consistent with preserving adequate liquidity and financial flexibility.
Recent Events
In August 2011, our board of directors received a proposal from our Chairman and CEO, Timothy Marquez, to acquire all of the outstanding shares of our common stock of which he is not the beneficial owner for $12.50 per share in cash (the "Marquez Proposal"). Mr. Marquez is currently the beneficial owner of approximately 50.3% of the common stock. The board of directors formed a special committee comprised of all independent directors to evaluate and consider this proposal as well as third party alternatives. In January 2012, we announced that we had entered into a definitive merger agreement with Mr. Marquez and certain of his affiliates pursuant to which he will acquire all shares he does not beneficially own for $12.50 per share in cash. The special committee also announced that it unanimously concluded that the transaction with Mr. Marquez was in the best interest of the Company's minority shareholders. As a result, the agreement was approved by the full board of directors, with Mr. Marquez abstaining. Completion of the transaction is subject to certain closing conditions, including procurement of financing, receipt of shareholder approval (including approval by a majority of unaffiliated shareholders) and other customary conditions. As the transaction remains subject to certain closing conditions, there can be no assurance that this transaction will be consummated. See the "Risk Factors" section of this Annual Report.
Capital Expenditures
We have developed an active capital expenditure program to take advantage of our extensive inventory of drilling prospects and other projects. Our development, exploitation and exploration capital expenditures were $255 million in 2011, up from $218 million in 2010. Approximately $185 million of the 2011 capital expenditures went to drilling and rework activities, $20 million to facilities, and the remaining $50 million to land, seismic and capitalized G&A costs. We incurred approximately $180 million or 71% of our 2011 capital expenditures in Southern California and $74 million or 29% in the Sacramento Basin with the remainder going toward exploration projects. Of the total amount spent in Southern California, approximately $113 million went to projects targeting the onshore Monterey shale formation.
Our 2012 development, exploitation and exploration capital expenditure budget is $255 million, of which approximately $223 million or 87% is expected to be deployed in Southern California and $32 million or 13% in the Sacramento Basin. Of the $223 million allocated to Southern California, approximately $100 million is expected to be deployed to onshore Monterey shale activities with the remainder going to activities at legacy Southern California fields. The aggregate levels of capital expenditures for 2012, and the allocation of those expenditures, are dependent on a variety of factors, including 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 2011 capital spending program and the outlook for 2012.
Southern California-Legacy Fields
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. The field has not been fully delineated offshore or fully developed onshore and we continue to evaluate our drilling results and refine our development program for the coming years. During 2011, we spud five wells, one onshore and four offshore. We also performed five recompletions during the year. Our 2012 capital expenditure budget includes plans to drill seven wells, one of which was spud in the fourth quarter and completed during the first quarter of 2012. We spud two additional wells in the first quarter of 2012 and plan to spud a third well later in the quarter.
In the Sockeye field, we redrilled two inactive wells that target the Monterey shale formation during 2011. Our 2012 capital expenditure budget includes plans to drill three wells at Sockeye, which are expected to be drilled in the first half of the year.
At the South Ellwood field, we have received permits to drill two undeveloped locations and continue to work on permitting two additional locations on our existing leases. We have completed the facilities work necessary to begin drilling those locations and plan to spud the first well in March. Our 2012 capital expenditure budget includes plans to drill four wells in the field during 2012.
In addition, during the third quarter of 2011 our subsidiary Ellwood Pipeline, Inc. received the approvals necessary to begin 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 during January 2012. Primarily as a result of the pipeline approval, the estimated reserve life of the South Ellwood field was extended by approximately 30 years and proved reserves in the field increased by approximately 8.1 MMBOE, based on SEC pricing as of December 31, 2011.
Southern California-Onshore Monterey Shale
In 2006, we began actively leasing onshore acreage in Southern California targeting the Monterey shale. Our leasing has 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. To date, our onshore Monterey shale acreage position totals approximately 256,000 gross and 170,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin. We also have an additional 60,000 gross and 46,000 net acres with Monterey shale production or potential which are held by production at our legacy Southern California fields.
During 2011 we spud 12 onshore wells targeting the Monterey shale, including three horizontal wells, and set casing on 13 wells (including wells spud in 2010). In total, since the beginning of 2010 when we began actively drilling wells targeting the onshore Monterey shale formation through 2011, we have spud 24 wells (17 vertical and seven horizontal), of which 20 have had casing set and two wells,
both vertical, were used as pilot holes for two horizontal wells. In addition, earlier this year, we completed the second and final phase of a 3-D seismic shoot in the San Joaquin area which covered approximately 500 square miles. We continue to analyze the data from the shoot.
We have been encouraged by the scientific information collected thus far, particularly in two of our prospect areas (the Sevier field in the San Joaquin Basin and the South Salinas field in the Salinas Valley). To date, we have not seen material levels of production or reserves from the program. We believe we will see production resulting from our delineation drilling and testing efforts which began at Sevier in 2011 and which will continue into 2012. During 2011 we spud six vertical wells (including four wells during the fourth quarter) at Sevier. Due to terrain and public lands issues, we drill from pads that are large enough to drill multiple wells. At times, however, in order to drill another new well, we need to shut in testing of other wells on the same drill pad. Because of this, and because we have several intervals to test independently in each well, we do not have longer term tests by interval or by well. However, we have been encouraged by the testing and geologic data we have obtained from each subsequent well.
Our 2012 capital expenditure budget includes plans to drill 15 to 20 wells at Sevier, where we currently have one rig operating. Additionally, we plan to study our onshore Monterey wells drilled in 2010 and 2011 for recompletion opportunities based on knowledge we have gained over the past few years. We also plan to collect 3D seismic data at Sevier and Salinas Valley during 2012.
Sacramento Basin
In the Sacramento Basin, we continue to pursue our infill drilling program in the greater Grimes and Willows fields. During 2011, we spud 40 wells and performed 237 recompletions in the basin. We continue to test and evaluate potential downspacing opportunities in the basin as well as new methods of improving productivity and reducing drilling costs. We also continue to pursue our hydraulic fracturing program in the basin with 21 wells fractured during 2011.
As of December 31, 2011, we had identified 734 drilling locations in the basin, and we anticipate identifying additional locations as we pursue further exploration, exploitation and development opportunities. We believe the Sacramento Basin presents significant exploration opportunities and in order to further our understanding of these opportunities we drill a small number of what we consider to be exploratory wells in the basin each year. In early 2011 we drilled a discovery well on an anomaly which we identified using 3D seismic data we acquired with leasehold in 2009. The discovery well's average net production in 2011 was 2.3 million cubic feet per day and it extended the boundaries of the Grimes field. We drilled additional wells in 2011 along this extension area and these wells, combined with the discovery well, exited the year at a net production rate of 8.3 million cubic feet per day. Operationally, we distinguish these exploratory wells from the numerous non-proved locations that we drill each year as part of our development drilling program but are considered "exploratory wells" as defined in SEC Regulation S-X.
We have reduced our activity levels in the basin in recent years as a result of depressed natural gas prices and our increased focus on our oil-based projects including Monterey shale activities. Our 2012 capital expenditure budget contemplates a continuation of this strategy. We plan to drill five wells and perform 180 recompletions and seven fracs. We anticipate the activity levels contemplated in our 2012 budget will result in average daily production which is lower than 2011 average daily production. We would expect to return to a focus on growth in the basin when natural gas prices improve. As of December 31, 2011, our acreage position in the basin was approximately 204,000 net acres (245,000 gross).
Acquisitions and Divestitures
Hastings Complex Sale. In February 2009, we completed the sale of our principal interests in the Hastings Complex to Denbury for approximately $197.7 million. We retained the right to back into a working interest of approximately 22.3% in the CO2 project Denbury is pursuing at the Hastings Complex after it recoups certain costs. In December 2010, Denbury commenced injecting CO2 at the Hastings Complex and has begun production at the field in January 2012.
Sale of Other Texas Assets. We sold our producing assets in Texas in a series of transactions that were completed in the second quarter of 2010 to multiple purchasers for aggregate net proceeds of $98.1 million (after closing adjustments and related expenses).
Other. We have an active acreage acquisition program and we regularly engage in acquisitions (and, to a lesser extent, dispositions) of oil and natural gas properties, primarily in and around our existing core areas of operations, including transactions in each of 2009, 2010 and 2011.
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 condition, revenues, results of operations, liquidity, rate of growth, the carrying value of our oil and natural gas properties and borrowing capacity under our revolving credit facility, all of which depend in part upon those prices. 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 February 14, 2012 we had hedge contract floors covering 8,500 barrels of oil per day and 29.5 million cubic feet of natural gas per day for 2012. We have also secured hedge contracts for portions of our 2013, 2014 and 2015 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 are based on the NYMEX WTI ("WTI") crude price index and these contracts expire at the end of the first quarter of 2012. To replace the expiring contracts, we have entered into new sales contracts based on certain Southern California crude price indexes, which traded at a premium to WTI throughout 2011 and have more closely tracked with the Inter-Continental Exchange Brent crude price index ("Brent"). We have also entered into a new sales contract related to oil produced from our South Ellwood field which is more favorable than the previous contract because, effective January 31, 2012, we are able to deliver our oil through a common carrier pipeline rather than via barge.
Expected Production. As a result of sustained depressed natural gas prices, during 2011 we emphasized our oil projects in Southern California relative to our natural gas projects in the Sacramento Basin. We plan to continue this strategy in 2012, with approximately 48% of our planned capital expenditures allocated to our legacy Southern California fields and 39% allocated to our onshore Monterey shale program. Given our expected increase in capital spending related to our oil producing legacy Southern California assets in 2012, we expect the production ratio of oil to natural gas to increase in 2012 relative to 2011. We also expect overall production in 2012 to be similar to production in 2011 on a BOE basis. Our expectations with respect to future production rates are subject to a number of uncertainties, including those associated with third party services, the availability of drilling rigs, oil and natural gas prices, events resulting in unexpected downtime, permitting issues, 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, and other factors, including those referenced in the "Risk Factors" section this Annual Report.
Lease Operating Expenses. Lease operating expenses ("LOE") of $14.64 per BOE for 2011 were higher than our 2010 results of $12.65 per BOE. We expect our 2012 LOE per BOE to be higher relative to 2011 primarily as a result of a continued shift in our focus to oil projects as compared to natural gas projects. Our expectations with respect to future expenses are subject to numerous risks and uncertainties, including those described and referenced in the preceding paragraph.
Property and Production Taxes. Property and production taxes of $0.99 per BOE for 2011 were relatively flat when compared to our 2010 results of $1.01 per BOE. We expect our 2012 property and production taxes to remain relatively flat on a per BOE basis compared to our 2011 results. As with lease operating expenses, our expectations with respect to future property and production taxes are subject to numerous risks and uncertainties.
Transportation Expenses. Transportation expenses were $9.3 million for 2011 and $9.1 million in 2010. We expect that our transportation expenses will decrease in 2012 compared to 2011 as a result of the completion of the onshore pipeline that transports the oil produced from our South Ellwood field. This pipeline will eliminate the use of the double-hulled barge that was used throughout 2011.
General and Administrative Expenses. General and administrative expenses increased slightly to $4.96 per BOE (excluding share-based compensation charges of $0.88 per BOE and costs of $0.26 per BOE related to the evaluation by the special committee of the Marquez Proposal) in 2011 compared to $4.78 per BOE for 2010 (excluding share-based compensation charges of $0.68 per BOE and one-time charges of $0.19 per BOE for severance payments resulting from the sale of our Texas producing properties). Excluding share-based compensation charges and special committee related charges, on a per BOE basis, we expect our G&A costs to increase in 2012 compared to 2011. As with our lease operating expenses and property and production taxes, our expectations with respect to G&A costs are subject to numerous risks and uncertainties.
Depreciation, Depletion and Amortization (DD&A). DD&A for 2011 of $13.35 per BOE increased from our 2010 DD&A of $11.79 per BOE. We expect our 2012 DD&A to increase on a per BOE basis compared to our full year 2011 results. As with lease operating expenses, property and production taxes and G&A expenses, our expectations with respect to DD&A expenses are subject to numerous risks and uncertainties.
Interest Expense. As a result of the refinancing of our second lien term loan in the first quarter of 2011 (see "-Capital Resources and Requirements"), we replaced $455.3 million of variable rate debt with $500.0 million of 8.875% fixed rate debt. Additionally, because our second lien term loan was subject to variable interest rates, we had entered into interest rate derivative contracts to mitigate our interest rate risk and, as a result, $500.0 million of variable rate borrowings effectively bore interest at approximately 7.8%. In conjunction with the refinancing transaction in the first quarter of 2011, we settled the interest rate derivative contracts.
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 and 2009 as well as taxable losses in each of the tax years from 2008 through 2011. These losses and expected future taxable losses were a key consideration that led us to conclude that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2010 and December 31, 2011 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; consistent, meaningful production and proved reserves from our onshore Monterey shale project; and meaningful production and proved reserves from the CO2 project at the Hastings Complex. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.
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 the comparability of the data below. The information set forth below is not necessarily indicative of future results.
(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 the timing of barge deliveries, oil in tanks and pipeline inventories, and oil pipeline sales nominations.
(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, 2011 to Year Ended December 31, 2010
Oil and Natural Gas Sales. Oil and natural gas sales increased $32.8 million (11%) to $323.4 million in 2011 from $290.6 million in 2010. The increase was due to higher realized oil prices, partially offset by a decrease in oil production and lower realized natural gas prices, as described below.
Oil sales increased by $37.2 million (20%) in 2011 to $227.2 million compared to $190.0 million in 2010. Oil production decreased by 13%, with production of 2,441 MBbl in 2011 compared to 2,792 MBbl in 2010. The production decrease was partially due to the sales of our remaining producing properties in Texas in the second quarter of 2010. Excluding production from the Texas properties, production decreased by 239 MBbls (9%) from 2,680 MBbls in 2010 to 2,441 MBbls in 2011. The decrease is primarily due to natural production decline at the Sockeye, South Ellwood and West Montalvo fields. Our average realized price for oil increased $22.14 (32%) from $68.86 per Bbl in 2010 to $91.00 per Bbl in 2011.
Natural gas sales decreased $4.4 million (4%) in 2011 to $96.2 million compared to $100.6 million in 2010. Natural gas production increased by 727 MMcf (3%), with production of 23,923 MMcf in 2011 compared to 23,196 MMcf in 2010. Excluding production from the Texas properties, natural gas production increased by 1,068 MMcf (5%) from 22,855 MMcf in 2010 to 23,923 MMcf in 2011. The increase is due in large part to successful drilling and recompletion activity in the Sacramento Basin, primarily in the Grimes field, in the latter half of 2010 and during 2011. Our average realized price for natural gas decreased $0.32 (7%) from $4.34 per Mcf for 2010 to $4.02 per Mcf for 2011.
Other Revenues. Other revenues increased by $0.7 million (15%) to $5.4 million in 2011 from $4.7 million in 2010. Effective April 2010, we entered into a contract related to the double-hulled barge that transported oil produced at our South Ellwood field (see "-Transportation Expenses"). The contract allowed us to sub-charter the barge and retain a major portion of the revenues from those activities. Per terms of the contract, there is a minimum notification period for termination; as such the contract will be terminated in May 2012 since the common carrier pipeline is now used to transport oil production from the field.
Lease Operating Expenses. Lease operating expenses ("LOE") increased $9.8 million (12%) to $94.1 million in 2011 from $84.3 million in 2010. Excluding the Texas properties, production expenses increased $12.5 million (15%) from $81.6 million in 2010 to $94.1 million in 2011. The increase in LOE is primarily due to (i) costs incurred to return Platform Grace to production, which had been shut-in since the end of 2008 and (ii) non-recurring maintenance performed at Dos Cuadras, Platform Gail and Platform Holly, primarily in the third quarter of 2011. On a per unit basis, LOE was $14.64 per BOE in 2011 and $12.65 per BOE in 2010. Excluding the Texas assets, LOE per BOE increased from $12.57 per BOE in 2010 to $14.64 per BOE in 2011.
Production and Property Taxes. Production and property taxes decreased $0.3 million (5%) to $6.4 million in 2011 from $6.7 million in 2010. The decrease was primarily due to the sale of our remaining Texas properties in the second quarter of 2010. Excluding the Texas properties, production and property taxes remained relatively flat at $6.4 million in 2011 and $6.3 million in 2010.
Transportation Expenses. Transportation expenses increased $0.2 million (2%) to $9.3 million in 2011 from $9.1 million in 2010. In April 2010, a transportation contract became effective relating to the time-charter of a double-hulled barge to transport oil produced from our South Ellwood field. Under that contract we paid a flat day rate, regardless of our usage of the barge, but had the ability to
sub-charter the vessel when it is not in use transporting production from the South Ellwood field (see "-Other Revenues"). The increase in 2011 compared to 2010 was the result of the transportation contract being in place for the full year in 2011 compared to nine months in 2010.
Depletion, Depreciation and Amortization (DD&A). DD&A expense increased $7.3 million (9%) to $85.8 million in 2011 from $78.5 million in 2010. The increase is due to a higher depletion rate primarily due to higher amortizable bases at each of the quarterly periods in 2011 compared to 2010. DD&A expense on a per unit basis increased by $1.56 (13%) from $11.79 per BOE for 2010 to $13.35 per BOE for 2011.
Accretion of Abandonment Liability. Accretion expense remained relatively constant at $6.4 million in 2011 compared to $6.2 million in 2010.
General and Administrative (G&A). The following table summarizes the components of general and administrative expense incurred during the periods indicated (in thousands):
G&A expense increased $1.6 million (4%) to $39.2 million in 2011 compared to $37.6 million in 2010. The overall increase in G&A costs was primarily due to (i) non-cash share-based compensation expense of $5.7 million (net of amount capitalized) charged to G&A in 2011 compared to $4.5 million (net of amount capitalized) in 2010, (ii) a higher annual bonus accrual for 2011 based on a higher level of achievement of specified bonus metrics in 2011, (iii) increased travel costs in 2011 and (iv) costs incurred of $1.6 million in 2011 related to the evaluation by the special committee of the board of directors of the Marquez Proposal. The increases were partially offset by (i) higher capitalization in 2011 as a result of an increased focus on onshore Monterey shale activities and other development related activity in 2011 (ii) one-time severance payments of $1.3 million in 2010 related to the sale of our Texas properties and the related closure of our Texas operations and (iii) a decrease in professional fees incurred in 2011 compared to 2010. Excluding the effect of the non-cash share-based compensation expense, special committee-related costs and one-time severance charges, G&A expense increased to $4.96 per BOE in 2011 from $4.78 per BOE in 2010.
Interest Expense, Net. Interest expense, net of interest income, increased $20.5 million (51%) to $61.1 million in 2011 from $40.6 million in 2010. The increase was primarily the result of the refinancing of our second lien term loan in February 2011 with the issuance of our 8.875% senior notes. The interest rate on our second lien term loan, which was outstanding during 2010, averaged approximately 4.4% per annum during the year.
Amortization of Deferred Loan Costs. Amortization of deferred loan costs was $2.3 million in 2011 compared to $2.4 million in 2010. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.
Interest Rate Derivative (Gains) Losses, Net. In conjunction with the retirement of our second lien term loan in February 2011, we settled our outstanding interest rate swap contracts for $38.1 million. The result of settlement of the contracts and other activity prior to settlement resulted in an unrealized interest rate derivative gain of $40.1 million and a realized interest rate derivative loss of $41.1 million. In 2010, we recognized an unrealized interest rate derivative loss of $13.7 million and a realized interest rate derivative loss of $18.1 million.
Loss on Extinguishment of Debt. We recognized a loss on extinguishment of debt in 2011 of $1.4 million resulting from the repayment of our second lien term loan. The loss related primarily to the write off of unamortized deferred financing costs associated with the second lien term loan.
Commodity Derivative (Gains) Losses, Net. The following table sets forth the components of commodity derivative (gains) losses, net in our consolidated statements of operations for the periods indicated (in thousands):
Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in both 2011 and 2010 reflect the settlement of contracts at prices below the relevant strike prices. In the fourth quarter of 2011, we settled all of our 2013 natural gas hedge contracts (except for basis swaps) which resulted in a non-recurring gain of $12.0 million, which is reflected in the 2011 realized commodity derivative (gains) losses. In the fourth quarter of 2010, we settled certain 2011 gas puts and collars which resulted in realized gains of $19.1 million and are reflected in the 2010 realized commodity derivative gains. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative contracts.
Income Tax Expense (Benefit). We incurred losses before income taxes in 2008 and 2009 as well as taxable losses in each of the tax years from 2008 through 2011. These losses and expected future taxable losses were a key consideration that led us to conclude that we should maintain a full valuation allowance against our net deferred tax assets at December 31, 2010 and December 31, 2011 since we could not conclude that it is more likely than not that the net deferred tax assets will be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during periods in which those temporary differences become deductible. 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. However, we continue to evaluate the existing evidence to determine the point at which we can conclude that it is more likely than not that we will be able to realize our net deferred tax assets and, as a result, reverse all or a portion of the valuation allowance. The income tax benefit for 2010 primarily relates to an increase in the estimated net operating loss carryback claims for the 2003 through 2005 tax years and a reduction in the amount owed for prior year state income taxes. Additionally, we amended prior year returns in 2010 for certain share based compensation matters, which will result in additional income tax refunds. Due to our valuation allowance, there was no income tax expense (benefit) recorded for the year ended December 31, 2011.
Net Income (Loss). Net income for 2011 was $62.3 million compared to net income of $67.5 million for 2010. The change between years is the result of the items discussed above.
Comparison of Year Ended December 31, 2010 to Year Ended December 31, 2009
Oil and Natural Gas Sales. Oil and natural gas sales increased $23.4 million (9%) to $290.6 million in 2010 from $267.2 million in 2009. The increase was due to increases in realized oil and natural gas prices, partially offset by a decrease in production as described below.
Oil sales increased by $17.9 million (10%) in 2010 to $190.0 million compared to $172.1 million in 2009. Oil production decreased by 18%, with production of 2,792 MBbl in 2010 compared to 3,402 MBbl in 2009. The production decrease was due in large part to the sale of the Hastings Complex in early February 2009 and the sales of our remaining producing properties in Texas in the second quarter of 2010. Excluding production from the Texas properties, production decreased by 285 MBbls (10%) from 2,965 MBbls in 2009 to 2,680 MBbls in 2010. This decrease is primarily due to (i) the natural decline of production at the Sockeye and South Ellwood fields and (ii) reduced production at the Dos Cuadras field as a result of certain wells being taken offline due to temporary operational difficulties. Our average realized price for oil increased $18.26 (36%) from $50.60 per Bbl in 2009 to $68.86 per Bbl in 2010.
Natural gas sales increased $5.5 million (6%) in 2010 to $100.6 million compared to $95.1 million in 2009. Natural gas production decreased 6%, with production of 23,196 MMcf in 2010 compared to 24,748 MMcf in 2009. The decrease was due in large part to the sales of our producing properties in Texas during the second quarter of 2010. Excluding production from the Texas properties, natural gas production decreased by 428 MMcf (2%) from 23,283 MMcf in 2009 to 22,855 MMcf in 2010. The slight decrease in production is primarily due to the natural decline of production from wells in the Sacramento Basin, the majority of which has been offset by production from newly drilled and recompleted wells. Our average realized price for natural gas increased $0.50 (13%) from $3.84 per Mcf in 2009 to $4.34 per Mcf for 2010.
Other Revenues. Other revenues increased by $1.4 million (42%) to $4.7 million in 2010 from $3.3 million in 2009. The increase is primarily due to a contract that became effective in April 2010, related to the double-hulled barge that transported oil produced at our South Ellwood field (see "-Transportation Expenses"). The contract allowed us to sub-charter the barge and retain the revenues from those activities. The increase in other revenues is the result of sub-charter activities in 2010.
Lease Operating Expenses. Lease operating expenses ("LOE") decreased $10.9 million (12%) to $84.3 million in 2010 from $95.2 million in 2009. The decrease was primarily due to the sale of the Hastings Complex in early February 2009 and the sale of our remaining Texas properties in the second quarter of 2010. Excluding the Texas properties, production expenses decreased $1.8 million (2%) from $83.4 million in 2009 to $81.6 million in 2010. The decrease was primarily due to lower non-recurring maintenance costs incurred at our South Ellwood field in 2010 compared to 2009. On a per unit basis, LOE was $12.65 per BOE in both 2009 and 2010. Excluding the Texas assets, LOE per BOE increased from $12.18 per BOE in 2009 to $12.57 per BOE in 2010. The increase on a per BOE basis is the result of lower production levels in 2010 compared to 2009.
Production and Property Taxes. Production and property taxes decreased $3.4 million (34%) to $6.7 million in 2010 from $10.1 million in 2009. The decrease was partially due to the sale of the Hastings Complex in early February 2009 and the sale of our remaining Texas properties in the second quarter of 2010. Excluding the Texas properties, production and property taxes decreased $1.9 million (23%) from $8.1 million in 2009 to $6.2 million in 2010. The decrease was primarily due to lower supplemental property taxes incurred in 2010 as compared to 2009 resulting from lower gas prices and lower assessed mineral rights valuations for drilling and recompletion activities.
Transportation Expenses. Transportation expenses increased $5.9 million (188%) to $9.1 million in 2010 from $3.2 million in 2009. On a per BOE basis, transportation expenses increased $0.95 per BOE, from $0.42 per BOE in 2009 to $1.37 per BOE in 2010. The increase is primarily due to the contract
described in "-Other Revenues", related to the time-charter of a double-hulled barge to transport oil produced from our South Ellwood field. Under that contract we paid a flat day rate, regardless of our usage of the barge, but had the ability to sub-charter the vessel when it is not in use transporting production from the South Ellwood field (see "-Other Revenues"). We also incurred additional transportation costs from the use of a single-hulled barge during the transition period to the double-hulled barge, which was completed late in the fourth quarter of 2010.
Depletion, Depreciation and Amortization (DD&A). DD&A expense decreased $7.7 million (9%) to $78.5 million in 2010 from $86.2 million in 2009. The decrease is related to (i) a lower amortizable base in 2010 resulting from the application of the net proceeds from the sales of our Texas producing properties and (ii) lower production in 2010 compared to 2009. DD&A expense on a per unit basis increased by $0.33 (3%) from $11.46 per BOE for 2009 to $11.79 per BOE for 2010.
Accretion of Abandonment Liability. Accretion expense increased $0.4 million (8%) to $6.2 million in 2010 from $5.8 million in 2009. The increase is primarily due to accretion from new wells drilled and completed in 2009 and 2010.
General and Administrative (G&A). The following table summarizes the components of general and administrative expense incurred during the periods indicated (in thousands):
G&A expense increased $0.7 million (2%) to $37.6 million in 2010 from $36.9 million in 2009. The overall increase in G&A costs was primarily due to increases resulting from: (i) lower capitalized G&A costs in 2010 compared to the amount capitalized in 2009 due to lower levels of drilling activity in the first quarter of 2010, (ii) one-time severance payments of $1.3 million in 2010 related to the sale of our Texas properties and the related closure of our Texas operations and (iii) non-cash share-based compensation expense of $4.5 million (net of amount capitalized) charged to G&A in 2010 compared to $2.1 million (net of amount capitalized) in 2009. We issued annual restricted stock awards in the first quarter of both 2010 and 2009. The fair value of the awards issued in the 2010 period was significantly greater than the grants in the 2009 period due to the increase in our stock price between the periods, which contributed to the increase in non-cash share-based compensation expense. These increases were partially offset by lower other general and administrative costs resulting from the closing of our Texas office and other G&A decreases. Excluding the effect of the non-cash share- based compensation expense and one-time severance charges, G&A expense increased to $4.78 per BOE in 2010 from $4.63 per BOE in 2009. The increase on a per unit basis is primarily the result of lower production levels in 2010 compared with 2009.
Interest Expense, Net. Interest expense, net of interest income, remained relatively constant at $40.6 million in 2010 compared to $41.0 million in 2009.
Amortization of Deferred Loan Costs. Amortization of deferred loan costs was $2.4 million in 2010 compared to $2.9 million in 2009. The costs incurred relate to our loan agreements, which are amortized over the estimated lives of the agreements.
Interest Rate Derivative (Gains) Losses, Net. Changes in the fair value of our interest rate swap derivative instruments resulted in unrealized losses of $13.7 million in 2010 and unrealized gains of $1.8 million in 2009. Unrealized interest rate (gains) losses represent the change in the fair value of our interest rate derivative contracts from period to period based on estimated future interest rates at the end of the reporting period. Realized interest rate swap losses were $18.1 million in 2010 and $18.4 million in 2009.
Loss on Extinguishment of Debt. We recognized losses on extinguishment of debt in 2009 of $8.5 million related to repayment of the financed derivative premiums balance in May 2009 and the refinancing of our $150 million senior notes in October 2009.
Commodity Derivative (Gains) Losses, Net. The following table sets forth the components of commodity derivative (gains) losses, net in our consolidated statements of operations for the periods indicated (in thousands):
Realized commodity derivative gains or losses represent the difference between the strike prices in the contracts settled during the period and the ultimate settlement prices. The realized commodity derivative gains in both 2010 and 2009 reflect the settlement of contracts at prices below the relevant strike prices. In the first quarter of 2009, we unwound certain 2009 oil collars and certain 2009 gas puts which resulted in non-recurring gains of $7.7 million which are reflected in the 2009 realized commodity derivative gains. In the fourth quarter of 2010, we settled certain 2011 gas puts and collars which resulted in realized gains of $19.1 million which are reflected in the 2010 realized commodity derivative gains. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period. Derivative premiums are amortized over the term of the underlying derivative contracts.
Income Tax Expense (Benefit). We incurred losses before income taxes in 2008 and 2009 as well as taxable losses in each of the tax years from 2008 through 2010. These losses were a key consideration that led us to provide a valuation allowance against our net deferred tax assets at December 31, 2009 and December 31, 2010 since we could not conclude that it is more likely than not that the net deferred tax assets will be fully realized on future tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. 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. The current tax benefit for 2009 of $14.4 million reflects a reduction of prior year current tax expense (a $6.0 million benefit) and, due to the temporary five-year carryback period that became available in 2009, a carryback of net operating losses (a $8.4 million benefit). The income tax benefit we recorded for 2010 primarily relates to an increase in the estimated net operating loss carryback claims for the 2003 through 2005 tax years and a reduction in the amount owed for prior year state income taxes. Additionally, we amended prior year returns in 2010 for certain share based compensation matters, which will result in additional income tax refunds.
Net Income (Loss). Net income for 2010 was $67.5 million compared to net loss of $47.3 million for 2009. The change between years is the result of the items discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from our operations and amounts available under our revolving credit facility.
Cash Flows
Net cash provided by operating activities was $125.5 million in 2011 compared with $160.7 million in 2010 and $118.7 million in 2009. Cash flows from operating activities in 2011 as compared to 2010 were unfavorably impacted by the settlement of our interest rate derivative contracts in the first quarter of 2011 for $38.1 million (see "-Capital Resources and Requirements"), partially offset by higher realized oil prices during 2011. Cash flows from operating activities in 2010 as compared to 2009 were favorably impacted by increases in commodity prices, partially offset by decreased production.
Net cash used in investing activities was $246.5 million in 2011 compared with net cash used of $108.3 million in 2010 and net cash used of $2.0 million in 2009. The primary investing activities in 2011 were $244.6 million in capital expenditures on oil and natural gas properties related to our capital expenditure program. The primary investing activities in 2010 were $208.4 million in capital expenditures on oil and natural gas properties related to our capital expenditure program, partially offset by the receipt of $107.4 million in net cash proceeds from the sales of our Texas producing properties in the second quarter of 2010 and the sale of our Cat Canyon field in the fourth quarter of 2010. The primary investing activities in 2009 were $174.8 million in capital expenditures for our oil and gas exploration and development programs together with $21.3 million paid to acquire certain Sacramento Basin assets. These total expenditures of $196.1 million were offset by the receipt of $197.7 million in cash proceeds from the sale of our Hastings Complex in Texas.
Net cash provided by financing activities was $124.1 million in 2011 compared to net cash used of $47.8 million in 2010 and net cash used of $116.5 million in 2009. The primary financing activities in 2011 were the two capital raising transactions we completed as described below in "-Capital Resources and Requirements". In conjunction with the capital raising transactions, we repaid (i) the outstanding principal of $455.3 million related to our second lien term loan and (ii) the outstanding balance of $45.0 million on our revolving credit facility. Additionally, subsequent to the completion of those transactions, we incurred net borrowings on our revolving credit facility of $43.0 million. The primary financing activities in 2010 were $22.9 million in net payments made on our revolving credit facility and $39.2 million of principal repayments on the second lien term loan, both of which were primarily funded by proceeds from the sales of our producing properties in Texas and our Cat Canyon field. The primary financing activities in 2009 were as follows: (i) we made net repayments of $77.2 million on our revolving credit facility and $5.5 million of principal payments on the second lien term loan, both of which were primarily funded with proceeds from the Hastings sale, (ii) we paid approximately $15.3 million in May 2009 to settle financed derivative premiums, (iii) in October 2009, we refinanced our 8.50% senior notes with the issuance of our 11.50% senior notes, which resulted in a principal repayment of $150 million and a premium payment of $3.3 million. We received cash of $142.5 million, net of the $7.5 million original issue discount, from the issuance of the 11.50% senior
notes. We incurred $2.9 million in debt issuance costs related to the senior notes refinancing. Additionally, we incurred $1.9 million of debt issuance costs related to the third amendment and restatement of the agreement governing the revolving credit facility, which we entered into in December 2009.
Capital Resources and Requirements
In the first quarter of 2011, we completed two capital raising transactions which provided us with additional liquidity. First, we issued 4.6 million shares of common stock at a price to the public of $18.75 per share. We received net proceeds of approximately $82.2 million from the equity offering after deducting offering-related expenses. Second, we issued $500 million of 8.875% senior unsecured notes which are due in February 2019. We received net proceeds of approximately $490.3 million from the notes offering, after deducting offering-related expenses. The proceeds from the two transactions were used to repay the outstanding principal of $455.3 million and accrued interest of $1.6 million related to our second lien term loan, settle the related interest rate swap contracts for $38.1 million and repay the outstanding balance of $45.0 million on our revolving credit facility.
We plan to make substantial capital expenditures in the future for the acquisition, exploration, exploitation and development of oil and natural gas properties. We expect that our exploration, exploitation and development capital expenditures, which were $255 million in 2011, will be approximately $255 million in 2012. We expect to fund our 2012 capital expenditures budget primarily with cash flow from operations, supplemented with borrowings under our revolving credit facility. Additionally, we continue to pursue joint venture transactions related to our onshore Monterey shale acreage and potential sales of non-core assets. We have significant flexibility to reduce capital expenditures if warranted by business conditions or limits on our capital resources. Uncertainties relating to our capital resources and requirements include the possibility that one or more of the counterparties to our hedging arrangements may fail to perform under the contracts, the effects of changes in commodity prices and differentials, results from our onshore Monterey shale program, which could lead us to accelerate or decelerate activities depending on the extent of our success in developing the program, and the possibility that we will pursue one or more significant acquisitions that would require additional debt or equity financing.
Amended Revolving Credit Facility. In April 2011, we entered into a fourth amended and restated credit agreement governing our revolving credit facility, which has a maturity date of March 31, 2016. The agreement contains customary representations, warranties, events of default, indemnities and covenants, including covenants that restrict our ability to incur indebtedness and require us to maintain specified ratios of current assets to current liabilities and debt to EBITDA. The minimum ratio of current assets to current liabilities (as those terms are defined in the agreement) is one to one; the maximum ratio of debt to EBITDA (as defined in the agreement) is four to one. While we do not expect to be in violation of any of our debt covenants during 2012, we believe that it will be important to monitor the debt to EBITDA ratio requirement, especially if our EBITDA is less than we expect due to operational problems or other factors, or if our borrowing needs are greater than we expect. The agreement requires us to reduce amounts outstanding under the facility with the proceeds of certain transactions or events, including sales of assets, in certain circumstances. The revolving credit facility is secured by a first priority lien on substantially all of our assets.
Loans under the revolving credit facility designated as "Base Rate Loans" bear interest at a floating rate equal to (i) the greater of (x) Bank of Montreal's announced base rate, (y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 0.75% to 1.75%, based upon utilization. Loans designated as "LIBO Rate Loans" under the revolving credit facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 1.75% to 2.75%, based upon utilization. A commitment fee of 0.5% per annum is payable with respect to unused borrowing availability under the facility.
The revolving credit facility has a total capacity of $500.0 million, but is limited by a borrowing base, which is currently established at $200.0 million. The borrowing base is subject to redetermination twice each year, and may be redetermined at other times at our request or at the request of the lenders. Lending commitments under the facility have been allocated at various percentages to a syndicate of 11 banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit markets. A failure of any members of the syndicate to fund under the facility, or a reduction in the borrowing base, would adversely affect our liquidity. As of February 14, 2012, we have $35.0 million outstanding under the facility and $161.2 million in available borrowing capacity, net of the outstanding balance and $3.8 million of outstanding letters of credit.
Second Lien Term Loan and 8.875% Senior Notes. We entered into a $500.0 million senior secured second lien term loan agreement in May 2007. Prior to repayment as described below, the term loan facility was secured by a second priority lien on substantially all of our assets and was due to mature on May 8, 2014. Loans under the second lien term loan facility designated as "Base Rate Loans" bore interest at a floating rate equal to (i) the greater of the overnight federal funds rate plus 0.50% and the administrative agent's announced base rate, plus (ii) 3.00%. Loans designated as "LIBO Rate Loans" bore interest at LIBOR plus 4.00%.
In February 2011, we issued $500 million in 8.875% senior unsecured notes due in February 2019 at par. Concurrently with the sale of the 8.875% senior notes, we repaid in full the outstanding principal balance of $455.3 million on the second lien term loan, plus accrued interest of $1.6 million.
The 8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. We may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, we may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational covenants that, among other things, limit our ability to make investments, incur additional indebtedness or create liens on our assets.
11.50% Senior Notes. In October 2009, we issued $150.0 million of 11.50% senior unsecured notes due in October 2017 at a price of 95.03% of par. The senior notes pay interest semi-annually in arrears on April 1 and October 1 of each year. We may redeem the senior notes prior to October 1, 2013 at a "make-whole price" defined in the indenture. Beginning October 1, 2013, we may redeem the notes at a redemption price equal to 105.75% of the principal amount and declining to 100% by October 1, 2016. The indenture governing the notes contains operational covenants that, among other things, limit our ability to make investments, incur additional indebtedness or create liens on our assets.
Because we must dedicate a substantial portion of our cash flow from operations to the payment of amounts due under our debt agreements, that portion of our cash flow is not available for other purposes. Our ability to make scheduled interest payments on our indebtedness and pursue our capital expenditure plan will depend to a significant extent on our financial and operating performance, which is subject to prevailing economic conditions, commodity prices and a variety of other factors. If our cash flow and other capital resources are insufficient to fund our debt service obligations and our capital expenditure budget, we may be forced to reduce or delay scheduled capital projects, sell material assets or operations and/or seek additional capital. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness and certain other means is limited by covenants in our debt agreements. In addition, pursuant to mandatory prepayment provisions in our revolving credit facility, our ability to respond to a shortfall in our expected liquidity by selling assets or incurring additional indebtedness would be limited by provisions in the facility that require us to use some or all of the proceeds of such transactions to reduce amounts outstanding under the facility in some circumstances. If we are unable to obtain funds when needed and on acceptable terms, we may not be able to complete acquisitions that may be favorable to us, meet our debt obligations or finance the capital expenditures necessary to replace our reserves.
Commitments and Contingencies
As of December 31, 2011, the aggregate amounts of contractually obligated payment commitments for the next five years were as follows (in thousands):
(1)Total contractually obligated payment commitments do not include the anticipated settlement of derivative contracts, obligations to taxing authorities or amounts relating to our asset retirement obligations, which include plugging and abandonment obligations, due to the uncertainty surrounding the ultimate settlement amounts and timing of these obligations. Our total asset retirement obligations were $92.5 million at December 31, 2011.
(2)Amounts related to interest expense on our revolving credit facility is not included in the table above because the interest rate is variable. See "Capital Resources and Requirements" for a discussion of the terms related to the revolving credit facility. During the years ended December 31, 2009, 2010 and 2011, we incurred interest expense on the revolving credit facility of $1.4 million, $1.3 million and $0.5 million, respectively. Off-Balance Sheet Arrangements
At December 31, 2011, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon financial statements that have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain accounting policies as being of particular importance to the presentation of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and natural gas revenues, oil and natural gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies and estimates affect our more significant judgments and estimates used in the preparation of our financial statements.
Reserve Estimates
Our estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as in the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available
data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance, ad valorem and excise taxes, development costs and workover and remedial costs, all of which may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on the likelihood of recovery and estimates of the future net cash flows expected from them may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value and the rate of depletion of the oil and natural gas properties. For example, oil and natural gas price changes affect the estimated economic lives of oil and natural gas properties and therefore cause reserve revisions. Our December 31, 2011 estimate of net proved oil and natural gas reserves totaled 95.9 MMBOE. Had oil and natural gas prices been 10% lower as of the date of the estimate, our total oil and natural gas reserves would have been approximately 1% lower. In addition, our proved reserves are concentrated in a relatively small number of wells. At December 31, 2011, 35% of our proved reserves were concentrated in our 20 largest wells. As a result, any changes in proved reserves attributable to such individual wells could have a significant effect on our total reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Oil and Natural Gas Properties, Depletion and Full Cost Ceiling Test
We follow the full cost method of accounting for oil and natural gas properties. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and exploitation and development of oil and natural gas reserves are capitalized. Such capitalized costs include costs associated with lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and natural gas wells, and salaries, benefits and other internal salary related costs directly attributable to these activities. Proceeds from the disposition of oil and natural gas properties are generally accounted for as a reduction in capitalized costs, with no gain or loss recognized. Depletion of the capitalized costs of oil and natural gas properties, including estimated future development and capitalized asset retirement costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves on a quarterly basis. The capitalized costs are amortized over the life of the reserves associated with the assets, with the amortization being expensed as depletion in the period that the reserves are produced. This depletion expense is calculated by dividing the period's production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the sum of the capitalized investment and estimated future development costs associated with the investment. Changes in our reserve estimates will therefore result in changes in our depletion expense per unit. For example, a 10% reduction in our estimated reserves as of December 31, 2011 would have resulted in an increase of approximately $1.38 per BOE in our average 2011 depletion expense rate. Costs associated with production and general corporate activities are expensed in the period incurred. Unproved property costs not subject to amortization consist primarily of leasehold and seismic costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as undeveloped areas are tested. Unproved oil and natural gas properties are not amortized, but are assessed, at least annually, for impairment either individually or on an aggregated basis to determine whether we are still actively pursuing the project and whether the project has been proven, either to have economic quantities of reserves or that economic quantities of reserves do not exist.
Under full cost accounting rules, capitalized costs of oil and natural gas properties, excluding costs associated with unproved properties, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated twelve month arithmetic average of the prices in effect on the first day of each month of the relevant period and requires a write down for accounting purposes if the ceiling is exceeded.
Although we did not have ceiling test write downs during 2009, 2010 or 2011, we could be required to recognize impairments of oil and gas properties in future periods if market prices of oil and natural gas decline.
Asset Retirement Obligations
The accounting standards set forth by the FASB with respect to accounting for asset retirement obligations provide that, if the fair value for asset retirement obligations can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and natural gas producing companies incur this liability upon acquiring or drilling a well. Under this method, the retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with the offsetting charge to property cost. Periodic accretion of discount of the estimated liability is recorded in the income statement. Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our properties at the end of their productive lives, in accordance with applicable laws. We have determined our asset retirement obligation by calculating the present value of estimated cash flows related to each liability. The discount rates used to calculate the present value varied depending on the estimated timing of the relevant obligation, but typically ranged between 4% and 9%. We periodically review the estimate of costs to plug, abandon and remediate our properties at the end of their productive lives. This includes a review of both the estimated costs and the expected timing to incur such costs. We believe most of these costs can be estimated with reasonable certainty based upon existing laws and regulatory requirements and based upon wells and facilities currently in place. Any changes in regulatory requirements, which changes cannot be predicted with reasonable certainty, could result in material changes in such costs. Changes in reserve estimates and the economic life of oil and natural gas properties could affect the timing of such costs and accordingly the present value of such costs.
Income Tax Expense
Income taxes reflect the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying current tax rates to the differences between financial statement and income tax reporting. We have recognized a valuation allowance against our net deferred taxes because we cannot conclude that it is more likely than not that the net deferred tax assets will be realized as a result of estimates of our future operating income based on current oil and natural gas commodity pricing. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, we consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead us to conclude that it is more likely than not that its 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; consistent, meaningful production and proved reserves from our onshore Monterey shale project; and meaningful production and proved reserves from the CO2 project at the Hastings Complex. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.
Derivative Instruments
We reflect the fair market value of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes, as well as utilizing a Black-Scholes option valuation model that is based upon underlying forward price curve data, risk-free interest rates, credit adjusted discount rates and estimated volatility factors. Changes in commodity prices will result in substantially similar changes in the fair value of our commodity derivative agreements, and in substantially similar changes in the fair value of our commodity collars to the extent the changes are outside the floor or cap of our collars. We do not apply hedge accounting to any of our derivative contracts, therefore we recognize mark-to-market gains and losses in earnings currently.
PV-10
The pre-tax present value of future net cash flows, or PV-10, is a non-GAAP measure because it excludes income tax effects. Management believes that pre-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 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 twelve-month arithmetic average of the first of the month prices without giving effect to hedging activities or future escalation, 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 as of the dates shown (in thousands):
(1)Unescalated twelve month arithmetic average of the first day of the month posted prices of $61.04 per Bbl for oil and natural gas liquids and $3.87 per MMBtu for natural gas were adjusted as described in note (1) above to arrive at realized prices of $51.15 per Bbl for oil, $37.98 per Bbl for natural gas liquids and $3.80 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2009.
(2)Unescalated twelve month arithmetic average of the first day of the month posted prices of $79.43 per Bbl for oil and natural gas liquids and $4.38 per MMBtu for natural gas were adjusted in note (1) above to arrive at realized prices of $69.18 per Bbl for oil, $59.85 per Bbl for natural gas liquids and $4.37 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2010.
(3)Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.19 per Bbl for oil and natural gas liquids and $4.12 per MMBtu for natural gas were adjusted in note (1) above to arrive at realized prices of $99.62 per Bbl for oil, $68.40 per Bbl for natural gas liquids and $4.05 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2011.
ITEM 7A.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
This section provides information about derivative financial instruments we use to manage commodity price volatility. Due to the historical volatility of crude oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of the prices we receive for our production and providing a minimum revenue stream. Currently, we purchase puts and enter into other derivative transactions such as collars and fixed price swaps in order to hedge our exposure to changes in commodity prices. All contracts are settled with cash and do not require the delivery of a physical quantity to satisfy settlement. While this hedging strategy may result in us having lower revenues than we would have if we were unhedged in times of higher oil and natural gas prices, management believes that the stabilization of prices and protection afforded us by providing a revenue floor on a portion of our production is beneficial. We may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of our existing positions. We may use the proceeds from such transactions to secure additional contracts for periods in which we believe there is additional unmitigated commodity price risk or for other corporate purposes.
This section also provides information about our interest rate risk. See "-Interest Rate Risk."
Commodity Derivative Transactions
Commodity Derivative Agreements. As of December 31, 2011, we had entered into various swap, collar and option agreements related to our oil and natural gas production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to our properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX WTI (oil) or NYMEX Henry Hub (natural gas) price.
(1)Reflects the impact of call spreads and purchased calls, which are transactions we entered into for the purpose of modifying or eliminating the ceiling (or call) portion of certain collar arrangements. We have also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the NYMEX WTI crude price index and the Brent crude price index. Historically the two price indexes have demonstrated a close correlation with each other and with the Southern California indexes on which we sell a significant percentage of our oil. Recently, however, the relationship between WTI and Brent has diverged, favoring Brent crude. The Southern California indexes most relevant to us have tracked more closely with Brent prices than with WTI. The oil basis swaps we have entered into attempt to fix the current premium Southern California indexes are realizing relative to WTI. The natural gas basis swaps fix the differential between the Henry Hub price
and the PG&E Citygate price, the index on which the majority of our natural gas is sold. Our oil and natural gas basis swaps as of December 31, 2011 are presented below:
Portfolio of Derivative Transactions
Our portfolio of commodity derivative transactions as of December 31, 2011 is summarized below:
Oil
Natural Gas
Subsequent to December 31, 2011, we settled all of the natural gas derivative contracts that were outstanding at December 31, 2011 and realized a gain of $41.2 million. Additionally, we entered into the following commodity derivative contracts subsequent to December 31, 2011.
Natural Gas
Oil
We enter into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. The objective of our hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. Our hedging activities seek to mitigate our exposure to price declines and allow us more flexibility to continue to execute our capital expenditure plan even if market prices decline. Our collar and swap contracts, however, prevent us from receiving the full advantage of increases in oil or natural gas prices above the maximum fixed amount specified in the hedge agreement. We do not enter into hedge positions for amounts greater than our expected production levels; however, if actual production is less than the amount we have hedged and the price of oil or natural gas exceeds a fixed price in a hedge contract, we will be required to make payments against which there are no offsetting sales of production. This could impact our liquidity and our ability to fund future capital expenditures. If we were unable to satisfy such a payment obligation, that default could result in a cross-default under our revolving credit agreement. In addition, we have incurred, and may incur in the future, substantial unrealized commodity derivative losses in connection with our hedging activities, although we do not expect such losses to have a material effect on our liquidity or our ability to fund expected capital expenditures.
In addition, the use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We generally have netting arrangements with our counterparties that provide for the offset of payables against receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. All of the counterparties to our derivative contracts are also lenders, or affiliates of lenders, under our revolving credit facility. Collateral under the revolving credit facility supports our collateral obligations under our derivative contracts. Therefore, we are not required to post additional collateral when we are in a derivative liability position. Our revolving credit facility and our derivative contracts contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.
We have elected not to apply hedge accounting to any of our derivative transactions and consequently, we recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.
All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statement of operations. As of December 31, 2011, the fair value of our commodity derivatives was a net asset of $48.2 million.
Interest Rate Risk
We are subject to interest rate risk with respect to amounts borrowed from time to time under our revolving credit facility because those amounts bear interest at variable rates. The interest rates associated with our senior notes are fixed for the term of the notes. A 1.0% increase in interest rates would have resulted in additional annualized interest expense of $0.4 million on our variable rate borrowings of $43.0 million related to our revolving credit facility as of December 31, 2011.
See notes to our consolidated financial statements for a discussion of our long-term debt as of December 31, 2011.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data
See "Index to Financial Statements" on page of this report.
ITEM 9.
ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
ITEM 9A.
ITEM 9A. Controls and Procedures
Attached as exhibits to this report are certifications of our CEO and CFO required pursuant to Rule 13a-14 under the Exchange Act. This section includes information concerning the controls and procedures evaluation referred to in the certifications. Included in this report is the report of Ernst & Young LLP, our independent registered public accounting firm, regarding its audit of our internal control over financial reporting. This section should be read in conjunction with the certifications and the Ernst & Young LLP report for a more complete understanding of the topics presented.
Evaluation of Disclosure Controls and Procedures. We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of December 31, 2011. This evaluation was conducted under the supervision and with the participation of management, including our CEO and CFO. Based on this evaluation, our CEO and CFO have concluded that, as of December 31, 2011, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC. We also concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisions regarding required disclosure.
Management's Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of assets of the company,
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.
Under the supervision and with the participation of our management, including our CEO and CFO, we assessed our internal control over financial reporting as of December 31, 2011, the end of our fiscal year. This assessment was based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2011.
The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by Ernst & Young LLP, our independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Inherent Limitations on Effectiveness of Controls. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
ITEM 9B.
ITEM 9B. Other Information
None.
PART III
ITEM 10.
ITEM 10. Directors, Executive Officers and Corporate Governance
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2012 annual stockholders' meeting and is incorporated by reference in this report. Certain information concerning our executive officers is set forth in "Business and Properties-Executive Officers of the Registrant."
ITEM 11.
ITEM 11. Executive Compensation
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2012 annual stockholders' meeting and is incorporated by reference in this report.
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2012 annual stockholders' meeting and is incorporated by reference in this report.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2012 annual stockholders' meeting and is incorporated by reference in this report.
ITEM 14.
ITEM 14. Principal Accounting Fees and Services
Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2012 annual stockholders' meeting and is incorporated by reference in this report.
ITEM 15.
ITEM 15. Exhibits and Financial Statement Schedules
Financial Statements and Financial Statement Schedules
See "Index to Consolidated Financial Statements" on page.
Exhibits
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Venoco, Inc.:
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2010 and 2011
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2010 and
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2009, 2010 and 2011
Consolidated Statements of Changes in Stockholders' Equity for the Years Ended December 31, 2009, 2010 and 2011
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2010 and 2011
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Venoco, Inc. and subsidiaries
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Venoco, Inc. and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Venoco, Inc. and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, effective December 31, 2009 the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Venoco, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 15, 2012 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Denver, Colorado
February 15, 2012
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Venoco, Inc. and subsidiaries
Denver, Colorado
We have audited Venoco, Inc. and subsidiaries' (the "Company") internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Venoco, Inc. and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Venoco, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Venoco, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 15, 2012 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Denver, Colorado
February 15, 2012
VENOCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except shares amounts)
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(1)Net of income tax expense (benefit) of $899, $0 and $0 for the years ended December 31, 2009, 2010 and 2011, respectively.
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands)
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations Venoco, Inc. ("Venoco" or the "Company"), a Delaware corporation, is engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties offshore and onshore in California.
Principles of Consolidation The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. All intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest derivative instruments; (8) accrued liabilities; (9) valuation of share-based payments and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements.
Business Segment Information The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company's operations and assets are located in the United States, and all of its revenues are attributable to United States customers.
Revenue Recognition and Gas Imbalances Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. This generally occurs when a barge completes delivery, oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession.
The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under-deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over- and under- deliveries or by cash settlement, as required by applicable contracts. The Company's production imbalances were not material at December 31, 2010 and 2011.
Other revenues primarily include pipeline revenues, barge sub-charter revenues and other miscellaneous revenues.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Cash and Cash Equivalents Cash and cash equivalents consist of cash and liquid investments with an original maturity of three months or less.
Accounts Receivable The components of accounts receivable include the following (in thousands):
The Company's accounts receivable result primarily from (i) oil and natural gas sales to oil and intrastate gas pipeline companies and (ii) billings to joint working interest partners in properties operated by the Company. The Company's trade and accrued production receivables are dispersed among various customers and purchasers and most of the Company's significant purchasers are large companies with solid credit ratings. If customers are considered a credit risk, letters of credit are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues. As of December 31, 2011, 63%, 18% and 3% of the total accounts receivable balance was receivable from the Company's three major customers.
The following table provides the percentage of revenue derived from oil and natural gas sales to customers who comprise 10% or more of the Company's annual revenue (the customers in each year are not necessarily the same from year to year):
Inventories Included in inventories are oil field materials and supplies, stated at the lower of cost or market, cost being determined by the first-in, first-out method.
Accounting Pronouncements Regarding Oil and Natural Gas Resources In December 2008, the SEC published revised rules regarding oil and gas reserves reporting requirements. Key elements of the revised rules include a change in the pricing used to estimate reserves at period end, optional disclosure of probable and possible reserves and additional disclosure requirements. The rules also revised the prices used for reserves in determining depletion and the full cost ceiling test from a period end price to a twelve month average of the first day of the month prices.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In January 2010, the Financial Accounting Standards Board ("FASB") issued an Accounting Standards Update ("ASU") which amended existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules discussed above. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The revised SEC rules and the ASU amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance resulted in changes to the prices used to determine proved reserves at December 31, 2009 compared to prior periods, which did not result in significant changes to our oil and natural gas reserves.
Oil and Natural Gas Properties The Company's oil and natural gas producing activities are accounted for using the full cost method of accounting. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition of oil and natural gas properties and with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Depletion of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Depletion expense for the years ended December 31, 2009, 2010 and 2011 was $81.3 million, $74.1 million, and $81.6 million, respectively ($10.80, $11.13 and $12.69, respectively, per equivalent barrel of oil).
Unproved property costs not subject to amortization consist primarily of leasehold costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. The Company will continue to evaluate these properties and costs which will be transferred into the amortization base as the undeveloped areas are tested. The Company transferred $9.7 million, $13.7 million, and $10.4 million of unproved costs into the amortization base in 2009, 2010 and 2011, respectively, due to impairment, development of acreage or placement of assets into service. No interest costs were capitalized in 2009, 2010 or 2011 because the Company did not have any unusually significant investments in unproved properties that qualify for interest capitalization.
In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are subject to a ceiling based upon the related estimated future net revenues, discounted at 10 percent, net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. The Company did not record an impairment of oil and natural gas properties in 2009, 2010 or 2011, however, the Company could be required to recognize impairments of oil and natural gas properties in future periods if market prices of oil and natural gas decline.
General and Administrative Expenses Under the full cost method of accounting, the Company capitalizes a portion of general and administrative expenses that are directly identified with acquisition, exploration and development activities. These capitalized costs include salaries, employee benefits, costs
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities. The Company capitalized general and administrative costs of $25.1 million, $22.7 million and $27.0 million directly related to its acquisition, exploration and development activities during 2009, 2010 and 2011, respectively.
Other Property and Equipment Other property and equipment, which includes buildings, drilling equipment, leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight-line method over the estimated useful lives of the related assets, ranging from 3 to 25 years. Depreciation and amortization expense for the years ended December 31, 2009, 2010 and 2011 was $4.9 million, $4.4 million and $4.2 million, respectively.
Derivative Financial Instruments The Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. All of the Company's derivative counterparties are commercial banks that are parties to its revolving credit facility. The Company has elected not to apply hedge accounting to any of its derivative transactions and consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.
Deferred Loan Costs Deferred loan costs, included in Other Assets, are amortized over the estimated lives of the related obligations using the effective interest method.
Asset Retirement Obligations The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time the well is spud or acquired.
Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company believes that it is in material compliance with existing laws and regulations.
Income Taxes Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company's policy is to recognize interest and/or penalties related to uncertain tax positions in interest expense.
Earnings Per Share Basic earnings (loss) per share is calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period (unvested restricted stock is excluded from the weighted average shares outstanding used in the basic earnings per share calculation). Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares (unvested restricted stock and unexercised stock options). In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.
Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company's unvested restricted stock awards contain nonforfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, the two class method will not have an effect on the Company's basic earnings per share.
The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands):
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
The following table sets forth the calculation of basic and diluted earnings per share (in thousands except per share amounts):
Stock-Based Compensation Stock-based compensation is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. A market condition is not considered to be a vesting condition with respect to compensation expense. Therefore, an award is not deemed to be forfeited solely because a market condition is not satisfied.
Recently Issued Accounting Standards In May 2011, the FASB issued Accounting Standards Update No. 2011-04-Fair Value Measurement-Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, which amends current U.S. GAAP fair value measurement and disclosure guidance, to converge U.S. GAAP and IFRS requirements for measuring amounts at fair value as well as disclosures about these measurements. The authoritative guidance is effective for interim and annual periods beginning after December 15, 2011. The ASU is not expected to have a significant impact on the Company's financial statements, other than additional disclosures.
Recent Events-On August 26, 2011, the Company's board of directors received a proposal from its chairman and chief executive officer, Timothy Marquez, to acquire all of the outstanding shares of common stock of Venoco of which he is not the beneficial owner for $12.50 per share in cash. Mr. Marquez is the beneficial owner of approximately 50.3% of Venoco's common stock. The Company's board of directors formed a special committee comprised of all independent directors to evaluate and consider this proposal as well as third party alternatives. On January 16, 2012, the Company announced that it had entered into a definitive merger agreement with Mr. Marquez pursuant to which he will acquire all shares of which he is not the beneficial owner for $12.50 per share in cash. Completion of the transaction is subject to certain closing conditions, including procurement of financing, receipt of shareholder approval (including approval by a majority of the unaffiliated shareholders) and other customary conditions. As the transaction remains subject to certain closing conditions, there can be no assurance that it will be consummated.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
2. ACQUISITIONS AND SALES OF PROPERTIES
Sales of Texas Assets. In April 2010, the Company signed certain Purchase and Sale Agreements ("PSAs") to divest its producing properties in Texas ("Texas Sales") for $98.1 million (after closing adjustments and related expenses). The PSAs covered the Company's interests in the Manvel field, the Company's overriding royalty interest in the Hastings Complex and its other oil and natural gas producing properties in the Texas Gulf Coast. The sales closed in a series of transactions in the second quarter of 2010 and involved multiple purchasers, including Denbury Resources, Inc. ("Denbury"), which purchased the overriding royalty interest in the Hastings Complex. The Company 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. The Company did not recognize a gain or loss for financial reporting purposes on the sale in accordance with the full cost method of accounting, but recorded the proceeds from the Texas Sales as a reduction to the capitalized cost of its oil and natural gas properties. As a result of the Texas Sales, the Company no longer has any interests in producing oil and natural gas properties in Texas. The Company did, however, retain its 22.3% reversionary working interest in the Hastings Complex as described below.
Hastings Complex Sale. In February 2009, the Company completed the sale of its principal interests in the Hastings Complex to Denbury for approximately $197.7 million. As a result of the sale, the Company repaid all amounts then outstanding under the revolving credit facility and $5.5 million of the outstanding principal balance on the second lien term loan facility then in place. The proceeds from the Hastings Complex sale were applied as a reduction of capitalized costs of oil and natural gas properties.
As a result of the sale, Denbury committed to a development plan related to a CO2 enhanced recovery project that requires it to make minimum capital expenditures in the amount of $178.7 million by the end of 2014. The Company retained an overriding royalty interest of 2.0% in the production from the properties, which, as described above, was subsequently sold to Denbury in the second quarter of 2010. In addition, the Company has the right to back-in to a working interest of approximately 22.3% in the Hastings Complex after Denbury recoups certain costs related to the CO2 project.
3. LONG-TERM DEBT
As of the dates indicated, the Company's long-term debt consisted of the following (in thousands):
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
3. LONG-TERM DEBT (Continued)
Revolving credit facility. In April 2011, the Company entered into a fourth amended and restated credit agreement which increased the size of its revolving credit facility from $300 million to $500 million. The facility has a maturity date of March 31, 2016. The borrowing base (currently established at $200 million) is subject to redetermination twice each year, and may be redetermined at other times at the Company's request or at the request of the lenders. The facility is secured by a first priority lien on substantially all of the Company's oil and natural gas properties and other assets, including the equity interests in all of the Company's subsidiaries, and is unconditionally guaranteed by each of the Company's subsidiaries other than Ellwood Pipeline, Inc. The collateral also secures the Company's obligations to hedging counterparties that are also lenders, or affiliates of lenders, under the facility. Loans made under the revolving credit facility are designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans under the facility bear interest at a floating rate equal to (i) the greater of (x) the Bank of Montreal's announced base rate, (y) the overnight federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 0.75% to 1.75%, based on utilization. Loans designated as LIBO Rate Loans under the facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 1.75% to 2.75%, based upon utilization. A commitment fee of 0.50% per annum is payable with respect to unused borrowing availability under the facility. The agreement governing the facility contains customary representations, warranties, events of default, indemnities and covenants, including operational covenants that restrict the Company's ability to incur indebtedness and financial covenants that require the Company to maintain specified ratios of current assets to current liabilities and debt to adjusted EBITDA.
The borrowing base under the revolving credit facility has been allocated at various percentages to a syndicate of 11 banks. Certain of the institutions included in the syndicate have received support from governmental agencies in connection with events in the credit markets.
As of February 14, 2012, the Company had $35.0 million outstanding on the facility and had available borrowing capacity of $161.2 million under the facility, net of the outstanding balance and $3.8 million in outstanding letters of credit.
Second lien term loan facility and 8.875% senior notes. In May 2007, the Company entered into a $500.0 million senior secured second lien term loan facility (the "second lien term loan facility"), which was due to mature on May 8, 2014. Prior to repayment of the second lien term loan facility in February 2011 (see below), loans made under the second lien term loan facility were designated, at the Company's option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans bore interest at a floating rate equal to (i) the greater of the overnight federal funds rate plus 0.50% and a market base rate, plus (ii) 3.00%. Loans designated as LIBO Rate Loans bore interest at LIBOR plus 4.00%.
In February 2011, the Company issued $500 million in 8.875% senior notes due in February 2019 at par. Concurrently with the sale of the 8.875% senior notes, the Company repaid in full the outstanding principal balance of $455.3 million on the second lien term loan, plus accrued interest of $1.6 million. The 8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. The Company may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, the Company may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
3. LONG-TERM DEBT (Continued)
February 15, 2017. The 8.875% senior notes are senior unsecured obligations and contain operational covenants that, among other things, limit the Company's ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.
The Company recorded a loss on extinguishment of debt of $1.4 million in connection with the repayment of the second lien term loan.
11.50% senior notes. In October 2009, the Company issued $150.0 million of 11.50% senior notes due October 2017 at a price of 95.03% of par. The senior notes pay interest semi-annually in arrears on April 1 and October 1 of each year. The Company may redeem the senior notes prior to October 1, 2013 at a "make-whole price" defined in the indenture. Beginning October 1, 2013, the Company may redeem the notes at a redemption price equal to 105.75% of the principal amount and declining to 100% by October 1, 2016. The 11.50% notes are senior unsecured obligations and contain covenants that, among other things, limit the Company's ability to make investments, incur additional debt, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.
The Company was in compliance with all debt covenants at December 31, 2011.
Scheduled annual maturities of long-term debt outstanding as of December 31, 2011 were as follows (in thousands):
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Derivative Agreements. The Company utilizes swap and collar agreements and option contracts to hedge the effect of price changes on a portion of its future oil and natural gas production. The objective of the Company's hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements. The Company may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of the Company's existing positions. The Company may use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional unmitigated commodity price risk or for other corporate purposes.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty. The Company generally has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. All of the counterparties to the Company's derivative contracts are also lenders, or affiliates of lenders, under its revolving credit facility. Collateral under the revolving credit facility supports the Company's collateral obligations under the Company's derivative contracts. Therefore, the Company is not required to post additional collateral when the Company is in a derivative liability position. The Company's revolving credit facility and derivative contracts contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.
The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.
The Company has paid premiums related to certain of its outstanding derivative contracts. These premiums are amortized into commodity derivative (gains) losses over the period for which the contracts are effective. At December 31, 2011, the balance of unamortized net derivative premiums paid was $12.4 million, of which $11.4 million and $1.0 million will be amortized in 2012 and 2013, respectively.
The components of commodity derivative losses (gains) in the consolidated statements of operations are as follows (in thousands):
During the fourth quarter of 2011, the Company unwound its existing 2013 natural gas collars and puts and received $12.0 million. The gain recognized is included in realized commodity derivative losses (gains).
As of December 31, 2011, the Company had entered into swap, collar and option agreements related to its oil and natural gas production. The aggregate economic effects of those agreements are summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements provide for monthly settlement based on the
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
differential between the agreement price and the actual NYMEX WTI ("WTI") (oil) or NYMEX Henry Hub (natural gas) price.
(1)Reflects the impact of call spreads and purchased calls, which are transactions we entered into for the purpose of modifying or eliminating the ceiling (or call) portion of certain collar arrangements. The Company has also entered into certain oil and natural gas basis swaps. The oil basis swaps fix the differential between the WTI crude price index and the Inter-Continental Exchange Brent crude price index ("Brent"). Historically the two price indexes have demonstrated a close correlation with each other and with the Southern California indexes on which the Company sells a significant percentage of its oil. Recently, however, the relationship between WTI and Brent has diverged, favoring Brent crude. The Southern California indexes most relevant to the Company have tracked more closely with Brent prices than to WTI. The oil basis swaps the Company has entered into attempt to fix the current premium Southern California indexes are realizing relative with WTI. The natural gas basis swaps fix the differential between the Henry Hub price and the PG&E Citygate price, the index on which the majority of the Company's natural gas is sold. The Company's oil and natural gas basis swaps as of December 31, 2011 are presented below:
Subsequent to December 31, 2011, the Company unwound all of its 2012 natural gas collars and puts and its 2012 and 2013 natural gas basis swaps, for which it received $41.2 million. The Company also entered into the following commodity derivative contracts subsequent to December 31, 2011:
•Natural gas swaps at $3.00 (NYMEX) on 29,500 MMBtu per day, effective April 1 through December 31, 2012
•Natural gas collar at $3.50/$3.96 (NYMEX) on 24,000 MMBtu per day, effective calendar 2013
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
•Natural gas collar at $3.75/$4.42 (NYMEX) on 18,600 MMBtu per day, effective calendar 2014
•Natural gas collar at $3.75/$5.00 (NYMEX) on 15,000 MMBtu per day, effective calendar 2015
•Oil collar at $90.00/$122.70 (Brent) on 700 Bbls per day, effective calendar 2013
Interest Rate Swap. The Company previously entered into interest rate swap transactions to lock in its interest cost on $500.0 million of variable rate borrowings through May 2014. Under the swap arrangements, the Company paid a fixed interest rate of 3.840% and received a floating interest rate based on the one-month LIBO rate, with settlements made monthly. As a result of the interest rate swap agreement, $500 million of the Company's variable rate debt effectively bore interest at a fixed rate of approximately 7.8%. The Company did not designate the interest rate swap as a hedge.
In February 2011, the Company repaid the principal balance outstanding on the second lien term loan from proceeds received from the issuance of the 8.875% senior notes (see note 3), which reduced the Company's debt subject to variable rate interest to any amounts which may be outstanding under the Company's revolving credit facility. As a result, the Company settled the interest rate swaps for $38.1 million in February 2011.
The components of interest rate derivative losses (gains) in the consolidated statements of operations are as follows (in thousands):
Fair Value of Derivative Instruments. The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2010 and 2011 are summarized below. The net fair value of the Company's derivatives changed by $57.2 million from a net liability of $9.0 million at December 31, 2010 to a net asset of $48.2 million at December 31, 2011, primarily due (i) settlement of the interest rate swaps in February 2011, (ii) changes in the futures prices for oil and natural gas, which are used in the calculation of the fair value of commodity derivatives, (iii) settlement of commodity derivative positions during the current period and (iv) changes to the Company's commodity derivative portfolio during 2011. The Company does not offset asset and liability positions with the same counterparties within the financial statements, rather, all contracts are presented at their gross estimated fair value. As of the dates indicated, the Company's derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
Company has not designated any of its derivative contracts as hedging instruments. The main headings represent the balance sheet captions for the contracts presented.
5. FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).
The three levels of the fair value hierarchy are as follows:
Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
5. FAIR VALUE MEASUREMENTS (Continued)
Level 2-Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.
Level 3-Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of December 31, 2011 (in thousands).
The Company's commodity derivative instruments consist primarily of swaps, collars and option contracts for oil and natural gas. The Company values the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as level 2 within the fair value hierarchy. The discount rates used in the assumptions include a component of non-performance risk. The Company utilizes the relevant counterparty valuations to assess the reasonableness of the calculated fair values.
Fair Value of Financial Instruments. The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives (discussed above) and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company's revolving credit facility approximated fair value because the interest rate of the facility is variable. The fair value of the second lien term loan facility and the senior notes listed in the tables below were derived from available market data. This disclosure does not impact our financial position, results of operations or cash flows (in thousands).
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
5. FAIR VALUE MEASUREMENTS (Continued)
6. ASSET RETIREMENT OBLIGATIONS
The Company's asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in properties (including removal of certain onshore and offshore facilities) at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations when incurred by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company's credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.
The following table summarizes the activities for the Company's asset retirement obligations for the years ended December 31, 2010 and 2011 (in thousands):
Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 9%. The revisions of $13.4 million for 2011 primarily relate to updated estimated useful lives of certain of the Company's offshore platforms and support facilities. In particular, reserve lives for the South Ellwood field were extended in connection with the approval of the common carrier pipeline that transports oil from the field to refiners and replaced the use of a barge. The 2010 revisions primarily relate to updated estimates for expected cash outflows and changes in the timing of obligations.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
7. INCOME TAXES
The Company accounts for income taxes under the asset and liability approach, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company's consolidated financial statements or tax returns.
The Company's income tax provision (benefit) is composed of the following (in thousands):
A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35% to the Company's income tax provision (benefit) is as follows (in thousands):
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
7. INCOME TAXES (Continued)
The components of deferred tax assets and (liabilities) are as follows (in thousands):
The Company has net operating loss carryovers as of December 31, 2011 of $295.7 million for federal income tax purposes and $265.0 million for financial reporting purposes. The difference of $30.7 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. The net operating losses may be used to offset taxable income through 2031.
The Company incurred losses before income taxes in 2008 and 2009 as well as taxable losses in each of the tax years from 2008 through 2011. These losses and expected future taxable losses were a key consideration that led the Company to provide a valuation allowance against its net deferred tax assets of $114.4 million as of December 31, 2011, since it cannot conclude that it is more likely than not that $114.4 million of the net deferred tax assets will be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its 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; consistent, meaningful production and proved
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
7. INCOME TAXES (Continued)
reserves from the Company's onshore Monterey shale project; and meaningful production and proved reserves from the CO2 project at the Hastings Complex. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.
As long as the Company concludes that it will continue to have a need for a full valuation allowance against its net deferred tax assets, the Company 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.
The Company's federal income tax returns for the 2003 through 2008 tax years have been examined by the U.S. Internal Revenue Service ("IRS") with minimal disallowed deductions resulting from the examinations. As part of that process with the IRS, the Company carried back net operating losses ("NOL") to tax years 2003 through 2005, which resulted in federal tax refunds of $8.6 million. The 2009 through 2011 tax years remain open to examination by the IRS.
During the third quarter of 2010, the California Franchise Tax Board ("FTB") completed an examination of the Company's 2003 and 2004 California income tax returns. No adjustments resulted from this examination other than adjustments related to the finalization of the federal examinations discussed above, which the Company had previously provided for in its liability for uncertain state tax positions. The 2007 through 2011 tax years remain open to examination by the various state jurisdictions.
Due to the finalization of the 2003 through 2008 IRS examinations, the NOL carryback claims filed with the IRS and the finalization of the 2003 and 2004 FTB examinations, the Company believes that it has no liability for uncertain tax positions.
8. CAPITAL STOCK
The Company had 65.6 million shares of common stock issued or reserved for issuance at December 31, 2011. At December 31, 2011, the Company had 61.6 million common shares issued and outstanding, of which 2.8 million shares are restricted stock granted under the Company's 2005 stock incentive plan. At December 31, 2011, the Company had approximately 0.8 million options outstanding and 2.8 million shares available to be issued pursuant to awards under its stock incentive plans, including the 2008 Employee Stock Purchase Plan.
During the first quarter of 2011, the Company sold 4.6 million shares of common stock in a public offering at $18.75 per share and received approximately $82.2 million in net proceeds, after underwriting discounts and estimated expenses.
9. SHARE-BASED PAYMENTS
The Company has granted options to directors, certain employees and officers of the Company other than its CEO, under its 2000 and 2005 Stock Plans (the "Stock Plans"). As of December 31, 2011, there are a total of 846,055 options outstanding with a weighted average exercise price of $13.53 ($6.00 to $20.00), all of which have vested. The options typically have a maximum life of 10 years.
As of December 31, 2011, there were a total of 2,815,244 shares of restricted stock outstanding under the Company's 2005 stock incentive plan, including 1,070,495 shares granted to its CEO. Restricted shares subject to service conditions only generally vest over a four year period, with 25% vesting on each subsequent anniversary of the grant date. The grant date fair value of restricted stock subject to service conditions only is determined by the Company's closing stock price on the day prior
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
9. SHARE-BASED PAYMENTS (Continued)
to the date of grant. The vesting of 1,845,147 shares is also subject to market conditions based on the Company's total shareholder return in comparison to peer group companies and/or an industry index for each calendar year. Shares of restricted stock subject to market conditions granted prior to 2011 have a four year period over which vesting may occur. For grants issued in 2011, this period was expanded by three years in which a portion of the available shares could vest. The weighted-average fair value of the restricted shares subject to market conditions was derived using a Monte Carlo technique. The weighted average fair value of 496,846 awards with market conditions granted in February 2011 was estimated to be $17.83 per share. The estimated grant date fair values of restricted share awards are recognized as expense over the requisite service periods. The Company's total shareholder return for the measurement period of December 31, 2010 through December 31, 2011 was below the minimum threshold, therefore, none of the market based restricted shares will vest for this measurement period.
As of December 31, 2011, there was $16.8 million of total unrecognized compensation cost related to restricted stock, which is expected to be amortized over a weighted average period of 2.6 years. All compensation cost related to stock options has been recognized.
The Company recognized total share-based compensation costs as follows (in thousands):
The following summarizes the Company's stock option activity for the years ended December 31, 2009, 2010 and 2011:
(1)The intrinsic value is the amount by which the market value of the underlying stock, as of the date outstanding, exceeds the exercise price of in-the-money options.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
9. SHARE-BASED PAYMENTS (Continued)
Additional information related to options outstanding at December 31, 2011 is as follows:
The aggregate intrinsic value of options exercised in 2009, 2010 and 2011 was $0.2 million, $23.3 million and $2.2 million, respectively.
The Company had 48,500 unvested option awards outstanding on January 1, 2011 with a weighted average grant date fair value of $7.48 per award, all of which vested during the year.
The following summarizes the Company's unvested restricted stock award activity for the years ended December 31, 2009, 2010 and 2011.
The Company also provides a non-compensatory Employee Stock Purchase Plan (the "ESPP"), for which 1.4 million authorized shares of common stock remain available for issuance. Participation in the ESPP is open to all employees, other than executive officers, who meet limited qualifications. Under the terms of the ESPP, employees are able to purchase Company stock at a 5% discount as determined by the fair market value of the Company's stock on the last trading day of each purchase period. Individual employees are limited to $25,000 of common stock purchased in any calendar year.
10. RELATED PARTY TRANSACTIONS
In 2006, the Company paid a dividend consisting of 100% of its membership interest in 6267 Carpinteria Avenue, LLC ("6267 Carpinteria") to its then sole stockholder, a trust controlled by the Company's Chief Executive Officer. 6267 Carpinteria owns the office building and related land used by the Company in Carpinteria, California. The Company makes lease payments to 6267 Carpinteria under a lease for the office building entered into prior to the dividend. The lease provides for minimum lease payments of approximately $1.2 million per year through 2019.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
10. RELATED PARTY TRANSACTIONS (Continued)
The Company has entered into a non-exclusive aircraft sublease agreement with TimBer, LLC, a company owned by the Company's Chief Executive Officer, Timothy Marquez, and his wife. Through December 31, 2011, the Company has incurred approximately $1.2 million of costs related to the agreement, of which $1.1 million remains in accounts payable and accrued liabilities on the Company's balance sheet at December 31, 2011.
11. COMMITMENTS
Leases-The Company has entered into lease agreements for office space, an office building, and a parcel of land adjacent to Ellwood pier used for pier access. As of December 31, 2011, future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are $2.7 million in 2012, $2.9 million in 2013, $2.1 million in 2014, $1.9 million in 2015, $2.0 million in 2016 and $6.4 million thereafter. Net rent expense incurred for office space and the office building was $3.8 million, $2.5 million and $2.3 million in 2009, 2010 and 2011, respectively.
12. CONTINGENCIES
Beverly Hills Litigation
Between June 2003 and April 2005, six lawsuits were filed against the Company and certain other energy companies in Los Angeles County Superior Court by persons who attended Beverly Hills High School or who were or are citizens of Beverly Hills/Century City or visitors to that area during the time period running from the 1930s to date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which the Company have not been named) who claimed to be suffering from various forms of cancer or other illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs alleged that exposure to substances in the air, soil and water that originated from either oil-field or other operations in the area were the cause of the cancers and other maladies. The Company has owned an oil and natural gas facility adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before the Company acquired the facility. All cases were consolidated before one judge. Twelve "representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs' cases were stayed. In November 2006, the judge entered summary judgment in favor of all defendants in the test cases, including the Company. The judge dismissed all claims by the test case plaintiffs on the ground that they offered no evidence of medical causation between the alleged emissions and the plaintiffs' alleged injuries. Plaintiffs appealed the ruling. A decision on the appeal is expected in 2012. The Company vigorously defended the actions, and will continue to do so until they are resolved. Certain defendants and related parties have made claims for indemnity which the Company is disputing. The Company cannot predict the cost of indemnity obligations at the present time.
One of the Company's insurers currently is paying for the defense of these lawsuits under a reservation of its rights. If the insurer ceases to provide such defense and the Company is unsuccessful in enforcing its rights in any subsequent litigation, the Company may be required to bear the costs of the defense, and those costs may be material. If it ultimately is determined that the pollution exclusion or another exclusion contained in one or more of its policies applies, the Company will not have the protection of those policies with respect to any damages or settlement costs ultimately incurred in the lawsuits.
Based on the information known to the Company to date, the Company does not believe that it is probable that a material judgment against the Company will result. Therefore, no liability has been accrued. If one or more of these matters are resolved in a manner adverse to the Company, and if insurance coverage is determined not to be applicable, their impact on the Company's results of operations, financial position and/or liquidity could be material.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
12. CONTINGENCIES (Continued)
State Lands Commission Royalty Litigation
In November 2011, the California State Lands Commission (SLC) filed suit against the Company in Santa Barbara County alleging that the Company underpaid royalties on oil and gas produced from the South Ellwood field in California for the period from August 1, 1997 through May 2011 by approximately $9.5 million. The case has since been removed to Los Angeles County, California. The principal issues in dispute are (i) the oil price on which royalties should be calculated and (ii) whether the Company is entitled to deduct the cost of transporting oil from the South Ellwood Field to the point of sale in calculating the royalty. With respect to the oil price, the Company has paid royalties based on the price the Company actually received in arms-length transactions. The SLC contends that the Company should be paying royalties based on the higher of the price actually received and the highest "posted price" for oil sold in the Midway Sunset field, near Bakersfield, California. With respect to the deduction of transportation costs, the Company believes that state law allows the Company to adjust the sale price to reflect the cost of delivering the oil from the field to the point of sale. Based on its review of the SLC's contentions, audit records and additional historical records, the Company believes that it may have overpaid royalties on oil and gas production during the period in question and may be owed a refund of such overpayments. The Company believes the position of the SLC is without merit and the Company intends to vigorously contest the suit and to enforce its right to receive a refund of royalties it may have overpaid. The Company does not believe that it is probable that a material judgment against the Company will result. Therefore, no liability has been accrued.
Delaware Litigation
On August 26, 2011, Timothy Marquez, the Chairman and CEO of the Company, submitted a nonbinding proposal to the board of directors of the Company to acquire all of the shares of the Company he does not beneficially own for $12.50 per share in cash (the "Marquez Proposal"). As a result of that proposal, four lawsuits were filed in the Delaware Court of Chancery in 2011 against the Company and each of its directors by shareholders alleging that the Company and its directors had breached their fiduciary duties to the shareholders in connection with the Marquez Proposal. A fifth lawsuit filed in 2011, also in the Delaware Court of Chancery, named only Mr. Marquez as a defendant. On January 16, 2012, the Company announced it had entered into a merger agreement with Mr. Marquez and certain of his affiliates pursuant to which, at closing, each of the shareholders other than Mr. Marquez and his affiliates would receive $12.50 for each share of Company stock (the "Merger"). Following announcement of the merger agreement, three additional suits were filed in Delaware and three suits were filed in federal court in Colorado naming as defendants the Company and each of its directors. Each action seeks certification as a class action. Plaintiffs in both the Delaware and Colorado actions challenge the Merger and allege, among other things, that the consideration to be paid is inadequate. The complaints seek, among other relief, to enjoin defendants from consummating the Merger and to direct defendants to exercise their fiduciary duties to obtain a transaction that is in the best interests of the shareholders. The Company has reviewed the allegations contained in the complaints and believes they are without merit.
Other-In addition, the Company is a party from time to time to other claims and legal actions that arise in the ordinary course of business. The Company believes that the ultimate impact, if any, with respect to these other claims and legal actions will not have a material effect on its consolidated financial position, results of operations or liquidity.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2010 and 2011 (in thousands, except per share data):
14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following information concerning the Company's natural gas and oil operations has been provided pursuant to the FASB guidance regarding Oil and Gas Reserve Estimation and Disclosures. At December 31, 2011, the Company's oil and natural gas producing activities were conducted onshore within the continental United States and offshore in federal and state waters off the coast of California. The evaluations of the oil and natural gas reserves at December 31, 2009, 2010 and 2011 were prepared by DeGolyer and MacNaughton, independent petroleum reserve engineers.
Capitalized Costs of Oil and Natural Gas Properties
(1)Unevaluated costs represent amounts the Company excludes from the amortization base until proved reserves are established or impairment is determined. The Company estimates that the remaining costs will be evaluated within three years.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Continued)
Capitalized Costs Incurred
Costs incurred for oil and natural gas exploration, development and acquisition are summarized below. Costs incurred during the years ended December 31, 2009, 2010 and 2011 include capitalized general and administrative costs related to acquisition, exploration and development of natural gas and oil properties of $25.1 million, $22.7 million and $27.0 million, respectively. Costs incurred also include asset retirement costs of $6.6 million, $(5.0) million and $(7.8) million during the years ended December 31, 2009, 2010 and 2011, respectively.
Estimated Net Quantities of Natural Gas and Oil Reserves
In January 2010, the FASB issued an ASU to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules regarding oil and gas reserve reporting requirements. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies were not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2009 compared to prior periods, which did not result in a significant change to the Company's proved oil and natural gas reserves.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Continued)
The following table sets forth the Company's net proved reserves, including changes, proved developed reserves and proved undeveloped reserves (all within the United States) at the end of each of the three years in the periods ended December 31, 2009, 2010 and 2011.
(1)Unescalated twelve month arithmetic average of the first day of the month posted prices of $61.04 per Bbl for oil and natural gas liquids and $3.87 per MMBtu for natural gas were adjusted as described in note (1) above to arrive at prices of $51.15 per Bbl for oil, $37.98 per Bbl for natural gas liquids and $3.80 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2009.
(2)Unescalated twelve month arithmetic average of the first day of the month posted prices of $79.43 per Bbl for oil and natural gas liquids and $4.38 per MMBtu for natural gas were adjusted in note (1) above to arrive at prices of $69.18 per Bbl for oil, $59.85 per Bbl for natural gas liquids and $4.37 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2010.
(3)Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.19 per Bbl for oil and natural gas liquids and $4.12 per MMBtu for natural gas were adjusted in note (1) above to arrive at prices of $99.62 per Bbl for oil, $68.40 per Bbl for natural gas liquids and $4.05 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2011.
(4)Extensions for the years ended December 31, 2009, 2010 and 2011 include 32,001 MMcf, 27,749 MMcf and 89,031 MMcf, respectively, resulting from the Company's infill program in the Sacramento Basin. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by the Oil and Gas Reserve Estimation and Disclosure guidance issued by the FASB, is an attempt to present the information in a manner comparable with industry peers.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Continued)
The information is based on estimates of proved reserves attributable to the Company's interest in oil and natural gas properties as of December 31 of the years presented. These estimates were prepared by independent petroleum reserve engineers. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:
(1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.
(2) The estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company's proved reserves to the year-end quantities of those reserves for reserves as of December 31, 2009, 2010 and 2011.
(3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.
(4) Future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company's proved oil and natural gas reserves.
(5) Future net cash flows are discounted to present value by applying a discount rate of 10%.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows and does not include cash flows associated with hedges outstanding at each of the respective reporting dates.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Continued)
The following table summarizes changes in the standardized measure of discounted future net cash flows.
15. GUARANTOR FINANCIAL INFORMATION
All subsidiaries of the Company other than Ellwood Pipeline Inc. ("Guarantors") have fully and unconditionally guaranteed, on a joint and several basis, the Company's obligations under its 11.50% and 8.875% senior notes. Ellwood Pipeline, Inc. is not a Guarantor (the "Non-Guarantor Subsidiary"). The condensed consolidating financial information for prior periods has been revised to reflect the guarantor and non-guarantor status of the Company's subsidiaries as of December 31, 2011. All Guarantors are 100% owned by the Company. Presented below are the Company's condensed consolidating balance sheets, statements of operations and statements of cash flows as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934.
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
AT DECEMBER 31, 2010
(in thousands)
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
AT DECEMBER 31, 2011
(in thousands)
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2009
(in thousands)
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2010
(in thousands)
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2011
(in thousands)
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2009
(in thousands)
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2010
(in thousands)
VENOCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2009, 2010 AND 2011
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2011
(in thousands)