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 heavily oil-weighted and are located both onshore and offshore Southern California. These properties are characterized by long reserve lives, predictable production profiles and substantial opportunities for further exploitation and development. Additionally, we hold a 22.45% reversionary interest in certain properties in the Hastings Complex near Houston, Texas, where Denbury Resources, Inc., or Denbury, is currently performing an extensive CO2 flood.
According to a reserve report prepared by DeGolyer & MacNaughton, we had proved reserves of approximately 40.4 MMBOE as of December 31, 2014, based on Venoco's SEC adjusted weighted average prices of $86.69 per Bbl for oil and $5.21 per MMBtu for natural gas. As of that date, 95% of our proved reserves were oil and 69% were proved developed, and the PV-10 of our reserves was approximately $0.7 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 2014 was 7,406 BOE/d.
The following table summarizes certain information concerning our production in 2014.
(1)Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.99 per Bbl for oil and natural gas liquids and $4.35 per MMBtu for natural gas were adjusted for regional price differentials and other factors to arrive at prices of $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 per MMBtu for natural gas, which were used in the calculation of proved reserves at December 31, 2014.
Going Private Transaction and Subsequent Events
In January 2012, Venoco entered into a merger agreement with Timothy Marquez, currently DPC's Chief Executive Officer and Venoco's Executive Chairman, and certain affiliates of Mr. Marquez, including DPC. Mr. Marquez then beneficially owned approximately 50% of Venoco's common stock. Pursuant to the merger agreement, DPC acquired all of Venoco's common stock not beneficially owned by Mr. Marquez for $12.50 per share in cash in a transaction that was completed in October 2012. We refer to this transaction as the going private transaction. DPC is privately-held and, as a result of the going private transaction, Venoco's common stock ceased trading on the New York Stock Exchange and was deregistered under the Securities Exchange Act of 1934 (the "Exchange Act"). However, Venoco has outstanding 8.875% senior notes due 2019, and in August 2013, DPC issued $255 million principal amount of 12.25% / 13.00% senior PIK toggle notes due 2018, and the indentures governing the notes require each company to file reports with the SEC as if it was a reporting company under SEC rules. Venoco and DPC are filing this combined report to satisfy those reporting requirements. See "Explanatory Note" immediately preceding Part I of this report.
We incurred a significant amount of indebtedness in connection with the going private transaction. In order to reduce our indebtedness, we have engaged in sales of assets in recent years. In particular, we sold our West Montalvo properties for approximately $200 million in October 2014, and we sold our Sacramento Basin properties in December 2012 for approximately $250 million. In addition, in April 2015, we entered into additional financing transactions to refinance some of our outstanding indebtedness and provide liquidity. See "Management's Discussion and Analysis of Financial Condition and Results of Operation" for more information regarding the asset sales, our additional financing transactions and our current indebtedness.
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 supporting infrastructure. 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 24 degrees. As of December 31, 2014, there were 22 producing wells and four injection wells in the field. We have experienced communication issues with some wells near the field's lease boundary. Accordingly, we have reduced our activity in that area in recent periods, and we have focused our exploration and development activities primarily on the Coal Oil Point structure, which is located on the north-east side of the field.
Our processing and transportation facilities at South Ellwood include a common carrier pipeline, an onshore facility and a pier. We conduct three- phase separation on the platform and oil/water emulsion is transported by pipeline to the onshore facility for further separation. After separation, the oil is transported to a third-party refinery via pipeline, including a common carrier pipeline operated by our subsidiary Ellwood Pipeline, Inc. Natural gas produced at the field is processed at the onshore facility and transported by common carrier pipeline.
We submitted an application to adjust the lease line at the South Ellwood field, and that application was deemed complete by the California State Lands Commission (CSLC) in December 2014. If made, the adjustment could significantly increase the reserves associated with the field. Subsequent development of the adjusted lease area can be accomplished using our existing facilities and infrastructure. Our application is subject to review by the CSLC under the California Environmental Quality Act, which requires an environmental impact report. We anticipate that the review period will be approximately 18 months, but it could be longer. Our application may not be granted on the terms we request or at all.
Santa Clara Federal Unit. The Santa Clara Federal Unit is located in federal waters 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, 2014, there were 24 producing wells and 5 injection wells in the field. The oil produced from the Monterey shale and Upper Topanga is sour with gravities ranging from 12 to 17 degrees. The Lower Topanga and Sespe horizons produce sweet crude with gravities of 27 to 32 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, however, we returned one well to production at platform Grace. Both platforms are self-sufficient, with all production, processing and power generation operations conducted offshore.
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, 2014, there were 86 producing wells and 22 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, 2014, there were 13 producing wells and three injection wells in the field, which produce oil with a gravity of approximately 26 degrees. The lease under which we operate the field expires in 2016. We are currently in the process of negotiating an extension of the lease.
Southern California-Onshore Monterey Shale
We have developed considerable 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 exploration opportunities onshore. As of December 31, 2014, our onshore Monterey shale acreage position totaled approximately 18,990 net acres and is located primarily in two basins: Salinas Valley and San Joaquin. We sold approximately 109,000 net acres in San Joaquin in the Sacramento Basin asset sale in December 2012.
Texas
In February 2009, we sold certain properties in the Hastings Complex near Houston, Texas to Denbury for approximately $247.7 million (including a $50 million option payment made prior to closing), but we retained an interest in the properties relating to a CO2 enhanced recovery project to be pursued by Denbury. Pursuant to the sale agreement, Denbury committed to make capital expenditures of at least $178.7 million by the end of 2014 to develop the project. Through September 30, 2014, Denbury has incurred $334 million in capital expenditures related to the project. 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 22.45% 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. 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 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. Denbury has informed us that production from the complex averaged approximately 6,780 BOE/d for the full year 2014, and 6,720 BOE/d in the fourth quarter of 2014.
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 2014 were nominal and are expected to be nominal in 2015 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, 2013 and 2014 are set forth in reserve reports prepared by DeGolyer & MacNaughton. DeGolyer & MacNaughton reviews production histories and other geologic, 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, 2014 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 $96.78 per Bbl for oil and natural gas liquids and $3.67 per MMBtu for natural gas were adjusted for quality, energy content, transportation fees, regional price differentials and other factors to arrive at prices of $98.37 per Bbl for oil, $79.04 per Bbl for natural gas liquids and $4.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2013.
(2)Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.99 per Bbl for oil and natural gas liquids and $4.35 per MMBtu for natural gas
were adjusted as described in note (1) above to arrive at prices of $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2014.
(3)Our natural gas liquids reserves represent a minimal percentage of our total reserves (approximately 3.4% and 3.8% at December 31, 2013 and 2014, 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)Excluding production from the West Montalvo assets.
(6)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, 2014 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 $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 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, 2014 (Price Case B) were adjusted as described in note (A) above, resulting in prices which averaged $61.91 per Bbl for oil, $46.05 per Bbl for natural gas liquids and $4.63 per MMBtu for natural gas. Production costs were held constant with the costs as determined in the year-end SEC 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, 2014.
CPrices based on a 10% reduction of the prices used in the year-end SEC case (Price Case C) resulting in prices, adjusted as described in note (A) above, of $77.90 per Bbl for oil, $64.01 per Bbl for natural gas liquids and $4.69 per MMBtu for natural gas. Production costs were held constant with the costs as determined in the year-end SEC case.
DPrices based on a 10% increase of the prices used in the year-end SEC case (Price Case D) resulting in prices, adjusted as described in note (A) above, of $95.40 per Bbl for oil, $78.24 per Bbl for natural gas liquids and $5.73 per MMBtu for natural gas. Production costs were held constant with the costs as determined in the year-end SEC case.
Changes in Proved Reserves
Our net proved reserves of 40.4 MMBOE as of December 31, 2014 decreased 24% from 53.1 MMBOE as of December 31, 2013. Our estimated oil and natural gas reserves were principally affected by the following during 2014:
• Extensions and discoveries increased reserves by 0.3 MMBOE, due primarily to the drilling of the M2 infill well at Sockeye;
• The sale of West Montalvo decreased reserves by 6.9 MMBOE;
• Current year production decreased reserves by 2.7 MMBOE; and
• Revisions of previous estimates decreased reserves by 3.4 MMBOE, due primarily to the South Ellwood lease boundary well communication and an updated Hastings Complex CO2 enhanced tertiary recovery project production forecast; these were partially offset by an upward reserve revision related to Dos Cuadras field performance.
Our PUD reserves of 12.6 MMBOE as of December 31, 2014 decreased 25% from 16.8 MMBOE as of December 31, 2013. Our estimated PUDs were principally affected by the following during 2014:
• Revisions of previous estimates decreased PUD reserves by 0.2 MMBOE, due primarily to timing changes to the drilling programs offset by a new PUD location at the Sockeye field;
• The sale of West Montalvo decreased PUD reserves by 1.7 MMBOE; and
• 2.3 MMBOE of reserves classified as proved undeveloped at December 31, 2013 were drilled in the Coal Oil Point structure at South Ellwood-capital expenditures related to PUD drilling during 2014 were approximately $16.7 million.
At December 31, 2014, we have no PUDs that are scheduled for development five years or more beyond the date the reserves were initially recorded. 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 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, and (iv) the availability of sufficient cash flow from operations or external financing to fund our capital expenditure program. In addition, the proved reserves related to our reversionary interest in the Hastings Complex CO2 project 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 22.45% 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 commodity price 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 for accuracy and completeness prior to submission to DeGolyer & MacNaughton. Upon analysis and evaluation of the data, 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 Chief Executive Officer, for completeness of the data presented, reasonableness of the results obtained and compliance with the reserves definitions in Regulation S-X. 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, 2014 has been filed as an addendum to Exhibit 99.1 to this report and is incorporated by reference herein.
Internally, Ms. Gale Wright is responsible for overseeing our reserves process. Ms. Wright joined Venoco in 2006 as part of the Reserves and Acquisitions & Development group. In 2008, Ms. Wright was promoted to Reserves Manager responsible for all corporate Reserves Reporting. She assists the financial team with project forecasting, planning and modeling. Ms. Wright has over 30 years of industry experience in various operational and business development roles in the Rockies, Gulf Coast, Permian Basin and California beginning with 10 years at Chevron followed by other several large companies such as Conoco Phillips and Enron.
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 following table summarizes proved reserves and production for fields that exceed 15% of our total proved reserves as of December 31, 2014:
(a)Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.71 per Bbl for oil and natural gas liquids and $2.76 per MMBtu for natural gas were adjusted for quality, energy content, transportation fees and regional price differentials to arrive at realized prices of
$101.39 per Bbl for oil, $55.15 per Bbl for natural gas liquids and $3.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2012.
(b)Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.78 per Bbl for oil and natural gas liquids and $3.67 per MMBtu for natural gas were adjusted for regional price differentials and other factors to arrive at prices of $98.37 per Bbl for oil, $79.04 per Bbl for natural gas liquids and $4.41 per MMBtu for natural gas, which were used in the calculation of proved reserves at December 31, 2013.
(c)Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.99 per Bbl for oil and natural gas liquids and $4.35 per MMBtu for natural gas were adjusted for regional price differentials and other factors to arrive at prices of $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 per MMBtu for natural gas, which were used in the calculation of proved reserves at December 31, 2014.
(d)We do not have production related to the Hastings Complex, but we own a reversionary interest that allows us to back-in to a working interest of approximately 22.45% 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.
(e)In December 2012, we completed the sale of certain properties in the Sacramento Basin and San Joaquin Valley areas of California to an unrelated third party for $250 million, subject to certain closing adjustments.
(f)Effective July 1, 2014, we sold the Montalvo assets to an unrelated third party for $200.2 million, subject to certain closing adjustments.
(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 pipeline inventories, oil pipeline sales nominations, and prior to February 2012, the timing of barge deliveries and oil in tanks.
(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, 2012 through December 31, 2014. 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)In 2014 we drilled two wells, one of which was to a proved undeveloped location into the Coal Oil Point structure from Platform Holly; the other was drilled to an infill location into the M2 zone from Platform Gail. From an operational perspective, we view these wells as development wells, although they are within the definition of exploration wells under applicable SEC rules.
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.
Oil and Natural Gas Wells
The following table details our working interests in producing wells as of December 31, 2014. 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 14 oil wells with multiple completions.
Acreage
The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2014. 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 2015, 2016 and 2017, unless extended by exploration or production activities or extension of lease terms, is approximately 11%, 8% and 3%, respectively.
(2)Information relating to the Sacramento Basin reflects properties that were not included in the Sacramento Basin asset sale.
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 $90 million of well control, pollution cleanup and consequential damages coverage and $300 million of third party liability coverage for additional pollution cleanup and consequential damages, which also covers personal injury and death.
If a well blowout, spill or similar event occurs that is not covered by insurance, 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 Safety and Environmental Enforcement ("BSEE"), we annually update our existing company oil-spill response plan as required by regulations, 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. Drills are conducted annually to measure and maintain the effectiveness of the plan, and plan or equipment improvements are made accordingly.
Also pursuant to BSEE 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' Oil Spill Response Organization (OSRO) primarily consists of four oil spill response vessels and one oil spill response barge including all associated manpower, equipment and materials to satisfy federal, state, and local spill response requirements. 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 Venoco's revolving credit facility is secured by liens on substantially all of its 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, 2014, approximately 97% of our revenues were generated from sales to two purchasers: ConocoPhillips 66 (43%) and Tesoro Refining and Marketing Company (54%). 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 March 31, 2015.
Competition
The oil and natural gas business is highly competitive with respect to 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. 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 24,000 net square feet of office space in Denver, Colorado, where our principal office is located. The lease for the Denver office expires in 2024. 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 2023. 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, 2014, we had approximately 158 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 statutory and regulatory programs 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.
Discharges to Waters. The Federal Water Pollution Control Act of 1972, as amended (the "Clean Water Act"), and comparable state statutes impose permitting and regulatory restrictions and controls on the discharge of "pollutants," including produced waters, sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal, and offshore waters, and other 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. 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 such discharges.
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 from certain above-ground and underground storage tanks.
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, and imposes potentially unlimited liability on responsible parties without regard to fault for the removal costs resulting from an offshore facility oil spill in federal waters. However, while the OPA limits liability for certain "damages" resulting from an oil spill, the Bureau of Ocean Energy Management ("BOEM") announced in December 1014, that it was increasing that liability limit to $133.65 million from $75 million. Responsible parties under the OPA include owners and operators of onshore facilities and pipelines and lessees or permittees of offshore facilities. In addition, BOEM regulations require parties responsible for offshore facilities to provide financial assurance to cover potential OPA liabilities in the amount of $35 million, which can be increased to $150 million in some circumstances.
Regulations promulgated by the BSEE require oil-spill response plans for offshore oil and natural gas operations, whether operating in state or federal waters. These regulations were designed to be consistent with OPA and other similar requirements. Under BSEE regulations, operators must join a cooperative that makes oil-spill response equipment available to its members. The California Department of Fish and Wildlife'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, BSEE 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 BSEE, the California State Lands Commission ("CSLC"), and other local agencies.
Additionally, effective June 4, 2013, an information gathering rule adopted by the South Coast Air Quality Management District ("SCAQMD"), Rule 1148.2, requires well operators of onshore wells subject to SCAQMD's jurisdiction to notify SCAQMD before undertaking certain activities at wells, including hydraulic fracturing, and then to report information regarding chemical usage and operational data regarding those well activities. SCAQMD anticipates reviewing the information gathered under SCAQMD Rule 1148.2 and developing regulations if necessary to protect air quality. If SCAQMD develops regulations regarding well activities, including hydraulic fracturing, our operating costs could increase.
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 designated as hazardous wastes under RCRA. 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 excludes 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. BSEE 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. BOEM 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.
Well Stimulation Regulations. We have on occasion in the past engaged in activities involving the use of hydraulic fracturing and other well-stimulation methods, and could use them in the future. Hydraulic fracturing 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 to a production well. Fractures typically are created through the injection of water, chemicals, and sand or other "proppants" into the rock formation. Several federal entities, including the EPA, recently have asserted potential regulatory authority over hydraulic fracturing, and the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, the results of which are anticipated to be available for review in 2015. Moreover, the EPA also is studying the potential impact of wastewater derived from hydraulic fracturing activities, and in 2015 plans to propose standards that such wastewater must meet before being transported to a treatment plant. Other federal agencies have examined and are continuing to examine hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality.
On March 20, 2015 the BLM released a final rule that will regulate hydraulic fracturing on federal and Indian lands. The rule requires operators to: (i) submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM before hydraulically fracturing an existing well; (ii) design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate "usable" water; (iii) monitor cementing operations during well construction; (iv) take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful; (v) perform a successful mechanical integrity test prior to the hydraulic fracturing operation; (vi) monitor annulus pressure during a hydraulic fracturing operation; (vii) manage recovered fluids in rigid enclosed, covered or netted and screened above-ground storage tanks, with very limited exceptions that must be approved on a case-by-case basis; (viii) disclose the chemicals used to the BLM and the public, with limited exceptions for material demonstrated to be trade secrets; and (ix) provide documentation of all of the above actions to the BLM. In addition, Congress has considered, and may in the future consider, legislation that would amend the Safe Drinking Water Act to encompass hydraulic fracturing activities. Past proposed legislation would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. If such legislation is adopted in the future, it would establish an additional level of regulation and impose additional costs on our operations.
EPA also has begun a Toxic Substances Control Act ("TSCA") rulemaking, which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. In addition, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that EPA add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under EPCRA's Toxics Release Inventory (TRI) program. Concurrently, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.
EPA also finalized major new Clean Air Act standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells in August 2012 known as "Quad O." The standards require, among other things, use of reduced emission completions, or green completions, to reduce VOC emissions during hydraulically fractured natural gas well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators at gas well affected facilities. Following a legal challenge and several petitions for administrative reconsideration of the Quad O rules, EPA issued final amendments related to storage tanks, green completions, and other provisions of the rule in September 2013 and December 2014 respectively. Most key provisions in Quad O take effect in 2015. The rules associated with such standards are substantial and will likely increase future costs of our operations and will require us to make modifications to our operations or install new equipment.
On September 20, 2013, California enacted Senate Bill 4, which requires the DOGGR to promulgate regulations regulating well-stimulation operations, including hydraulic fracturing and certain acid stimulation treatments. On December 30, 2014, DOGGR released its final regulations, which go
into effect on July 1, 2015. Until then, DOGGR's interim regulations, which closely track the final regulations, will be in effect. The final regulations require operators to obtain a permit prior to conducting well-stimulation operations, notify DOGGR 72 hours prior to the start well-stimulation treatments, and disclose various types of operational data, including the chemical composition of well-stimulation fluids, which will be made available on a publicly accessible website. Operators also are required to hire an independent third party to notify every neighboring tenant and landowner within a prescribed distance at least 30 days prior to commencing well-stimulation operations and to test well water and surface water suitable for drinking if requested by neighboring landowners. The regulations also require operators to evaluate and test the casing, tubing, and cement lining of the well borehole and related equipment to ensure that the well's construction is more than adequate to withstand hydraulic fracturing operations. In addition, operators must ensure that all potentially productive zones, zones capable of over-pressurizing the surface casing annulus, or corrosive zones are isolated and sealed to prevent vertical migration of gases or fluids behind the casing. The regulations also require operators to monitor and test the well during and after hydraulic fracturing operations to verify that no well failure has occurred. Operators also are required to monitor the California Integrated Seismic Network during and after hydraulic fracturing to determine if any earthquakes of magnitude 2.7 or greater occur within a specified area around the well. If such an earthquake occurs, further hydraulic fracturing in the area is suspended until authorized by DOGGR. Our current operations do not fall within the scope of Senate Bill 4 or the interim or final regulations. However, we will continue to monitor regulatory developments in this area.
Under Senate Bill 4, the state must complete an environmental impact report (EIR) analyzing the effects of hydraulic fracturing statewide, a draft of which was released on January 14, 2015. While the draft EIR concludes that hydraulic fracturing has the potential to cause "significant and unavoidable impacts to aesthetics, air quality, biological resources, cultural resources, geology, soils and mineral resources, greenhouse gas emissions, land use planning, risk of upset/public and worker safety, and transportation and traffic," it notes that all of these risks can be mitigated or prevented. In addition, the draft EIR concludes that hydraulic fracturing is the "Environmentally Superior Alternative" because limiting or prohibiting hydraulic fracturing would require greater levels of imported oil and gas resources, which would pose social, political, and economic consequences at the state and national scales.
Also, some states have adopted, and other states are considering adopting, requirements that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, in 2011, Texas enacted HB 3328, which requires the well-by-well public disclosure of all the constituent chemicals, compounds and water volume contained in fluids used for hydraulic fracturing. Texas also requires specific construction and testing requirements for wells that will be hydraulically fractured.
Various counties and municipalities around the country have passed laws restricting or prohibiting hydraulic fracturing. Our operations currently are not impacted by such laws. However, there is a risk that our operations could be adversely impacted by such laws in the future, especially since our operations are located in California, which historically has been at the forefront of environmental regulation. We will continue to monitor developments in this area.
Greenhouse Gas Regulation. Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas ("GHG") emissions passed in response to climate change concerns, may increase our operating costs and 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, with which we are complying. In June 2014, however, the United States Supreme Court invalidated a portion of EPA's
GHG program in the case Utility Air Regulatory Group v. EPA ("UARG"). Specifically, under the Supreme Court's UARG opinion, sources subject to the federal Title V and/or the Prevention of Significant Deterioration ("PSD") programs because of emissions of non-GHG pollutants may still be subject to GHG permitting, including requirements to install Best Available Control Technology ("BACT"). Sources that would be subject to Title V or PSD because of GHG emissions only, however, are no longer subject to GHG permitting requirements, including GHG BACT requirements. Upon remand, EPA currently is considering how to implement the Court's decision.
In Spring 2014, EPA issued five "Methane White Papers" exploring methane emissions from, and possible controls for, various aspects of the oil and natural gas production process. Building on these white papers, in January 2015, EPA announced a comprehensive strategy to further reduce methane emissions from the U.S. oil and gas industry, as part of the Obama Administration's overall GHG reduction strategy. Proposed rules governing methane emission reductions are expected in 2015, with final rules expected in 2016. While it is difficult to predict the substance of such rules, they likely will include additional control, monitoring, recordkeeping, and reporting requirements focused on fugitive methane emissions for much of the oil and natural industry.
The U.S. Congress has considered and may in the future consider "cap and trade" legislation that would establish an economy-wide cap on GHG emissions 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 GHG regulations that went into effect on January 1, 2012, and the enforceable compliance obligations began on January 1, 2013. These regulations do not directly impact our operations as the first phase includes 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. Our current operations are subject to the reporting requirements of these regulations; however, our operations are not subject to current California cap and trade regulations.
Other Environmental Regulation. Our leases in federal waters on the Outer Continental Shelf are administered by BOEM and BSEE and require compliance with detailed BOEM and BSEE regulations and orders. Under certain circumstances, BOEM or BSEE 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 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.
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 various 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 BSEE 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 the notes to our financial statements, we have estimated the present value of our aggregate asset retirement obligations to be $30.9 million as of December 31, 2014. 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 BSEE 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 generally have 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 2014. 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, we could incur significant expenses 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, 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 BSEE, 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 expenditures to meet those requirements.
Executive Officers of the Registrant
The following table sets forth certain information with respect to our executive officers as of December 31, 2014.
Timothy Marquez is DPC's sole director and its CEO, having served in those roles since its formation in January 2012. He co-founded Venoco in September 1992 and served as its CEO from its 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 Venoco's Chairman, CEO and President in June 2004. He became Venoco's Executive Chairman in August 2012. 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.
Mark DePuy became Venoco's Chief Executive Officer in June of 2014. 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 rejoined us in the role of Senior Vice President, Business Development and Acquisitions in December 2011. He also has 27 years of experience in various operational, management and business planning functions with Unocal/Chevron in both the domestic and international operations. Mr. DePuy 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
Scott Pinsonnault, Interim Chief Financial Officer, serves as a Managing Director with Opportune. His duties include corporate finance and interim management responsibilities and he has been with that firm since August 2014. Previously, Mr. Pinsonnault served as Chief Financial Officer of Cubic Energy, Inc. from April 2014 through August 2014 and before that he was a Director with Deloitte Financial Advisory Services, now known as Deloitte Business Transaction Analytics, from September 2012 to March 2014. While at Deloitte, his duties included serving as a financial and restructuring advisor, expert witness, interim officer and manager, and turnaround manager. From October 2011 through August 2012, he served as Vice President of SFC Energy Partners, a $1 billion upstream oil and gas private equity fund based in Denver, Colorado. While at SFC Energy Partners, he sourced and originated upstream oil and gas investments. From February 2011 through October 2011, he served as Managing Director of Project Finance for Unicredit Bank AG, a German and Italian bank with its U.S. headquarters in New York, New York. While at Unicredit Bank, his duties included originating and managing upstream oil and gas reserve-based loan and other project finance transactions. From January 2009 through February 2011, he was a Director with Bridge Associates, LLC, a professional services firm. While there, his duties included serving as a financial and restructuring advisor, expert witness, interim officer and manager, and turnaround manager. Mr. Pinsonnault received a B.S. in Geology from St. Lawrence University, an M.S. in Geology and Geophysics from Texas A&M University, and an M.B.A in Finance and Management from Tulane University.
Brian E. Donovan became General Counsel and Secretary in October of 2014. Mr. Donovan began his tenure with Venoco as Assistant General Counsel and Assistant Secretary in December of 2007 and has served as an integral part of the management team ever since. Prior to joining Venoco, he amassed over 20 years of legal experience with various subsidiaries of Peabody Energy, Inc. including Gold Fields Mining Corporation, Arid Operations, Inc., and Peabody Natural Gas, LLC. Mr. Donovan holds a Bachelor of Science degree in petroleum engineering from the Colorado School of Mines, a Juris Doctor degree from the University of Denver, and a Master of Laws degree in taxation from the University of Denver and is licensed to practice law in Colorado.
Ian Livett is Venoco's Vice President of Southern California Operations. Mr. Livett joined Venoco in 2010 as Facilities Engineering and Construction Manager and was promoted to Vice President, Southern California Operations in 2012. Mr. Livett has more than 35 years of experience working in the oil and natural gas industry including asset management, operations, facilities and pipelines engineering and construction and project management. Prior to joining Venoco, Mr. Livett worked for BP from 1978 until 2009 in various capacities and at locations including the United Kingdom, the North Sea, Norway, France, Abu Dhabi, the Gulf of Mexico and Alaska. He received his degree in civil engineering from the University of Liverpool in England.
Available Information
We maintain a link to investor relations information on our website, www.venocoinc.com, where we make available, free of charge, Venoco and joint Venoco/DPC filings with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports, 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 our code of business conduct and ethics and certain other governance documents. You may request a printed copy of these 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
We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business and prevent us from meeting our obligations under our indebtedness. Those risks could increase if we incur more debt.
We have a substantial amount of indebtedness, in part as a result of the financing required to complete the going private transaction. At December 31, 2014, we had total outstanding debt of $840.1 million, comprised of $65.0 million outstanding on Venoco's revolving credit facility, $500.0 million of Venoco's 8.875% senior notes and $275.1 million of DPC's 12.25% / 13.00% senior PIK toggle notes. Interest obligations on our indebtedness are significant. Our debt bears interest at a weighted average interest rate of approximately 9.95% as of December 31, 2014. In 2014, we had interest expense of $87.0 million. Following the completion of our April 2015 financing transactions described in "Management's Discussion and Analysis of Financial Condition and Results of Operation-Recent Events," our total outstanding debt as of April 15 is $993 million. We are pursuing a variety of measures to reduce our indebtedness, but these efforts may not be successful. If we are unable to reduce our indebtedness, or obtain additional financing, we may not have enough cash and working capital to fund our operations beyond the near term.
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.
The increase in our indebtedness resulting from the going private transaction has made it more difficult for us to comply with certain covenants in our debt agreements, and we have been forced to seek multiple amendments to and waivers of these covenants from our lenders. 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 or if we are otherwise unable to comply with the covenants in those agreements, 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. In addition, following the completion of the going private transaction, there is no longer a market for our common stock, and this would likely make any equity financing transaction more difficult. There can be no assurance that any such strategies could be implemented on satisfactory terms, if at all. Further, if a default occurs under one debt agreement, this could cause a cross-default under other debt agreements. Venoco's revolving credit facility was terminated as part of the April 2015 financing transactions, thus eliminating one potential source of financing flexibility.
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, and may be insufficient to support any new indebtedness necessary to refinance, 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. Recent significant declines in commodity prices may have a similarly adverse effect on the availability of financing. 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. If we are unable to satisfy our obligations under our debt agreements, our creditors could elect to declare some or all of our debt to be immediately due and payable, our secured lenders could elect to commence foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation.
Commodity prices are volatile and change for reasons that are beyond our control. Decreases in the price we receive for our production adversely affect our business, financial condition, results of operations and liquidity.
Declines in the prices we receive for our production adversely affect many aspects of our business, including our financial condition, revenues, profitability, cash flows, results of operations, liquidity, rate of growth, quantity and present value of our reserves, and the carrying value of our 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 46% in the fourth quarter of 2014 compared to the same period in 2013. 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. In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and the estimated value of that production and, as a result, adversely affect our estimated proved reserves. Among other things, a reduction in our reserves can limit the capital available to us, as the availability of many sources of capital likely will be based to a significant degree on the estimated quantities and value of those reserves.
Commodity prices are subject to wide fluctuations in response to changes in supply and demand. Prices have historically been volatile and are likely to continue to be volatile in the future. During 2014, the daily Brent oil spot price ranged from a high of $115.06 per Bbl to a low of $57.33 per Bbl and the NYMEX natural gas Henry Hub spot price ranged from a high of $6.15 per MMBtu to a low of $2.89 per MMBtu. In particular, the price of oil declined significantly in the last seven months of 2014, from a high of $115.06 per Bbl in June to a low of $57.33 per Bbl in December, in each case based upon the daily Brent oil spot price. 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, geopolitical factors affecting other oil producing countries, the actions of members of the Organization of Petroleum Exporting Countries, or OPEC, 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 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 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. Our ability to incur additional indebtedness is limited under the terms of our debt agreements. In addition, DPC has caused and may continue to cause Venoco to pay dividends to it in order to allow it to pay cash interest on its senior notes. If we reduce our capital spending in an effort to conserve cash or to facilitate the payment of dividends from Venoco to DPC, this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flow from operations and income, any of which could result in a breach of our obligations under our debt agreements. We have reduced our planned capital expenditures for 2015 relative to 2014, and expect this to result in a decline in production for the year.
DPC is a holding company and is dependent on distributions from Venoco to pay its obligations on its senior notes.
DPC is a holding company with no business operations and no material assets other than the capital stock of Venoco. All of our operations are conducted through Venoco and its subsidiaries. Consequently, DPC is dependent on dividends, distributions, loans or other payments from Venoco and, indirectly, its subsidiaries, to make payments of principal and interest in cash on the DPC 12.25% / 13.00% senior PIK toggle notes. All of DPC's direct and indirect subsidiaries are separate and distinct legal entities, and they have not guaranteed DPC's obligations under its notes.
The ability of Venoco to pay dividends and make other payments to DPC will depend on the cash flows and earnings of Venoco and its subsidiaries, which, in turn, are subject to all of the risks associated with operating in the oil and natural gas industry and as discussed in this section. The ability of DPC's direct and indirect subsidiaries to pay dividends and make distributions may be restricted by,
among other things, applicable laws and regulations and by the terms of the agreements into which they enter. If DPC is unable to obtain funds from its direct and indirect subsidiaries as a result of restrictions under their debt or other agreements, applicable laws and regulations or otherwise, DPC may not be able to pay cash interest or principal on its notes when due. The terms of Venoco's debt agreements significantly restrict it from paying dividends or otherwise transferring assets to DPC. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Requirements" for a discussion of certain relevant terms of Venoco's debt agreements. We cannot assure you that the debt agreements and other agreements governing the current and future indebtedness of DPC's direct and indirect subsidiaries will permit sufficient dividends, distributions, loans or other payments necessary to provide DPC with sufficient funds to pay cash interest or principal on DPC's senior notes when due. In addition, under certain circumstances, legal restrictions may limit DPC's ability to obtain cash from its subsidiaries. Under the Delaware General Corporation Law (the "DGCL"), DPC's Delaware-incorporated subsidiaries may only make dividends (i) out of their "surplus" as defined in the DGCL or (ii) if there is no such surplus, out of their net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. Under fraudulent transfer laws, DPC's subsidiaries may not pay dividends if the relevant entity is insolvent or is rendered insolvent as a result of the dividend. The measures of insolvency for purposes of these fraudulent transfer laws vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. There can be no assurance that Venoco will not become insolvent and that it will be permitted to make distributions in the future in compliance with these restrictions in amounts needed to service DPC's indebtedness. Venoco has no plans to pay cash dividends to DPC for the foreseeable future.
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 rule has limited and may continue to limit our ability 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, 2014, 31% of our estimated proved reserves were proved undeveloped and 3% 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 undeveloped reserves and proved developed non-producing reserves will not be realized until sometime 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 actual prices we receive for our production, 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. Because market prices for oil at the end of 2014 were significantly lower than the assumed future prices for the year determined under SEC rules, the estimated quantity and present values of our reserves presented in this report are higher than they would be if we had used year-end oil prices instead. Moreover, the lower year-end prices may be more reflective of future economic conditions. 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. Moreover, even commercial wells may be less productive or more expensive than we expect and production from those wells may decline faster than we project. Even when properly used, 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.
Our drilling results in emerging areas are more uncertain than drilling results in areas that are developed and producing. Because emerging plays have limited or no production history, our ability to use past drilling results in those areas to help predict our future drilling results is limited. 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 may require greater amounts of capital investment than those used in 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. To date, we have established commercial production from the onshore Monterey shale formation only on a very limited basis, in part due to differences in the geology of the onshore Monterey relative to some other shale formations. 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, processing facilities and related infrastructure and services owned by third parties. In general, we do not control these assets or services and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these assets or services 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 or provide facilities or services 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 commodity price fluctuations, we enter into hedging arrangements with respect to a substantial portion of our 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 produced by many of
our competitors. 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. 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, which 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;
• unitization and pooling of properties;
• habitat and endangered species protection;
• the management 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;
• hydraulic fracturing (including limitations on the use of this technology);
• 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 were, until recently, 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. Similar suits and/or related indemnity claims in the future 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 and without negligence on our part 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 generally are 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 generally are not fully insurable.
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. In particular, zoning changes related to the processing facility for the South Ellwood field could prohibit continued use of the facility.
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. Examples of changes in laws and regulations that may affect us adversely include the following:
Zoning. Venoco's Ellwood Onshore Facility ("EOF") is located in the City of Goleta, Santa Barbara County, California. The EOF removes water and gas from crude oil produced from Venoco's platform Holly before it is transported by pipeline to market. The EOF is zoned as a legal non-conforming use because, in 1991, after the EOF was constructed, the County of Santa Barbara rezoned the property for recreational uses. In January 2015, the Goleta City Council passed an ordinance establishing procedures and guidelines for the termination of nonconforming uses. Under the ordinance, the Goleta City Council could hold a hearing and, after considering certain factors specified in the ordinance, order the termination of the nonconforming use within five years. We expect that the EOF would be the subject of such a hearing. If so, and if a termination order were entered, Venoco could then apply for a modification of the order to extend the date by which the nonconforming use for the EOF must cease up to an additional 15 years. However, there can be no assurance that such a modification would be granted, or that any legal challenge Venoco might bring regarding the ordinance or its implementation would be successful. If the EOF is terminated, Venoco would have to find an economical alternative to processing crude oil at the EOF or stop producing crude oil from platform Holly. Any alternative processing arrangement would likely entail increased costs, and these costs could be material. Venoco and the City of Goleta have entered into a tolling agreement to give the parties time to gather information and determine whether a negotiated settlement of the dispute is feasible. If Venoco is prevented from using the EOF, this could have a material adverse effect on our production, reserves, cash flows and liquidity.
Greenhouse Gases. The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to human health and the environment, which allows EPA to begin regulating GHG emissions under existing provisions of the federal Clean Air Act. EPA has begun to implement GHG-related reporting and permitting rules, with which we are complying. 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 cap and trade regulations that went into effect on January 1, 2012. 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.
In Spring 2014, EPA issued five "Methane White Papers" exploring methane emissions from, and possible controls for, various aspects of the oil and natural gas production process. Building on these white papers, in January 2015, EPA announced a comprehensive strategy to further reduce methane emissions from the U.S. oil and gas industry, as part of the Obama Administration's overall GHG reduction strategy. Proposed rules governing methane emission reductions are expected in 2015, with final rules expected in 2016. The California Air Resources Board also is working on a rulemaking to reduce methane emissions from oil and gas production, processing, storage, and well stimulation (including hydraulic fracturing). While it is difficult to predict the substance of such rules, they likely
will include additional control, monitoring, recordkeeping, and reporting requirements focused on fugitive methane emissions for much of the oil and natural gas industry.
Hydraulic Fracturing. We have on occasion in the past engaged in activities involving the use of hydraulic fracturing, and could use hydraulic fracturing in the future. Hydraulic fracturing 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 to a production well. Fractures typically are created through the injection of water and chemicals into the rock formation. Several federal entities, including the EPA, have recently asserted potential regulatory authority over hydraulic fracturing, and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with the results of the study anticipated to be available for review in 2015. Moreover, the EPA also is studying the potential impact of wastewater derived from hydraulic fracturing activities, and in early 2015 plans to propose standards that such wastewater must meet before being transported to a treatment plant. Other federal agencies have examined and are continuing to examine hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality.
On March 20, 2015 the BLM released a final rule that will regulate hydraulic fracturing on federal and Indian lands. The rule requires operators to: (i) submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM before hydraulically fracturing an existing well; (ii) design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate "usable" water; (iii) monitor cementing operations during well construction; (iv) take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful; (v) perform a successful mechanical integrity test prior to the hydraulic fracturing operation; (vi) monitor annulus pressure during a hydraulic fracturing operation; (vii) manage recovered fluids in rigid enclosed, covered or netted and screened above-ground storage tanks, with very limited exceptions that must be approved on a case-by-case basis; (viii) disclose the chemicals used to the BLM and the public, with limited exceptions for material demonstrated to be trade secrets; and (ix) provide documentation of all of the above actions to the BLM. In addition, Congress has considered, and may in the future consider, legislation that would amend the Safe Drinking Water Act to encompass hydraulic fracturing activities. Past proposed legislation would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. If such legislation is adopted in the future, it would establish an additional level of regulation and impose additional costs on our operations.
Also, some states have adopted, and other states are considering adopting, requirements that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, in 2011, Texas enacted HB 3328, which requires the well-by-well public disclosure of all the constituent chemicals, compounds and water volume contained in fluids used for hydraulic fracturing.
On September 20, 2013, California enacted Senate Bill 4, which requires the California Department of Conservation, Division of Oil, Gas and Geothermal Resources ("DOGGR") to promulgate regulations regulating well stimulation operations, including hydraulic fracturing and certain acid stimulation treatments. On December 30, 2014, DOGGR released its final regulations, which go into effect on July 1, 2015. Until then, DOGGR's interim regulations, which closely track the final regulations, will be in effect. The final regulations require operators to obtain a permit prior to conducting well-stimulation operations, notify DOGGR prior to the start of well stimulation treatments, and disclose various types of operational data, including the chemical composition of well-stimulation fluids, which will be made available on a publicly accessible website. Operators also are required to
notify every neighboring tenant and landowner within a prescribed distance at least 30 days prior to commencing well-stimulation operations and to test well water and surface water suitable for drinking if requested by neighboring landowners. The regulations also require operators to evaluate and test the casing, tubing, certain equipment, and cement lining of the well borehole to ensure that the well's construction can withstand hydraulic fracturing operations. In addition, operators must ensure that all potentially productive zones, zones capable of over-pressurizing the surface casing annulus, or corrosive zones are isolated and sealed to prevent vertical migration of gases or fluids behind the casing. The regulations also require operators to monitor and test the well during and after hydraulic fracturing operations to verify that no well failure has occurred. Operators also are required to monitor the California Integrated Seismic Network during and after hydraulic fracturing to determine if any earthquakes of magnitude 2.7 or greater occur within a specified area around the well. If such an earthquake occurs, further hydraulic fracturing in the area is suspended until authorized by DOGGR. Our current operations do not fall within the scope of Senate Bill 4 or the interim or final regulations. However, we will continue to monitor regulatory developments in this area.
Various counties and municipalities around the country have passed laws restricting or prohibiting hydraulic fracturing. Our operations currently are not impacted by such laws. However, there is a risk that our operations could be adversely impacted by such laws in the future, especially since our operations are located in California, which historically has been at the forefront of environmental regulation. We will continue to monitor developments in this area.
As of June 4, 2013, an information gathering rule adopted by the South Coast Air Quality Management District ("SCAQMD"), Rule 1148.2, requires well operators of onshore wells in SCAQMD's jurisdiction to notify SCAQMD before undertaking certain activities at wells, including hydraulic fracturing, and then to report information regarding chemical usage and operational data regarding those well activities. SCAQMD anticipates reviewing the information gathered under Rule 1148.2 and developing regulations if necessary to protect air quality. If SCAQMD develops regulations regarding well activities, including hydraulic fracturing, our operating costs could increase.
Permitting. We are obligated to obtain various governmental permits and approvals to pursue our projects, and the relevant permitting and approval processes may change in ways that make them more burdensome, time-consuming and/or unpredictable. For example, following the Deepwater Horizon well blowout in the Gulf of Mexico, the Secretary of the U.S. Department of the 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 the 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.
Derivatives. 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 is in the process of being determined in significant part through implementing regulations adopted by the SEC, the Commodities Futures Trading Commission and other regulators. 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 would likely make it impracticable to implement our current hedging strategy. In addition, capital, margin and business conduct requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy, in part because there may be fewer counterparties participating in the market and increased counterparty costs that are passed on to us.
We are more vulnerable to the adverse consequences of changes in laws and regulations relating to derivatives than many of our competitors because we typically hedge a relatively large proportion of our expected production and because our hedging strategy is integral to our overall business strategy.
Tax. 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 has made 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.
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, and such a project is currently being pursued at the Hastings Complex by Denbury. 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 than expected 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. In addition, as discussed in "Legal Proceedings," we have been involved in a dispute with Denbury regarding certain aspects of the agreement governing the Hastings Complex project. Any further disputes or disagreements could increase the risks associated with the project or reduce its benefits to us.
A failure to complete successful acquisitions would limit our growth.
Because our oil and natural gas properties are depleting assets, our future 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. Also, our substantial level of indebtedness and the lack of any market for our common stock will limit our ability to make future acquisitions. 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. 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. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges.
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.
Significant portions of our estimated proved reserves and production are attributable to a small number of wells, and adverse events with respect to one or more of these wells could have a material adverse effect on our business, financial condition and results of operations.
More than 27% of our estimated proved reserves as of December 31, 2014 were concentrated in our five largest wells, and more than 10% of our estimated proved reserves were attributable to a single well in the South Ellwood field. As a result of this concentration of reserves, any significant adverse events with respect to one or more of these wells, including those discussed elsewhere in this section, could materially and adversely affect our reserves, production, financial condition and results of operations.
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. 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. If there is a shortage of qualified operational personnel or field equipment and services, 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 properties representing 31% of our proved reserves as of December 31, 2014. 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, 2014, approximately 97% of our oil and natural gas revenues were generated from sales to two purchasers: Phillips 66 and Tesoro Refining and Marketing Company. A material adverse change in the financial condition of either 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 have been required to write down the carrying value of our properties in the past 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 additional 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.
Our properties are located primarily in California. Any circumstance or event that negatively impacts the production or marketing of oil and natural gas in California generally, or in Southern California 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 stockholder vote.
Timothy Marquez, DPC's sole director and CEO and Venoco's Executive Chairman, beneficially owns over 90% of DPC's outstanding common stock, and DPC owns all of the outstanding common stock of Venoco. Through his beneficial ownership, Mr. Marquez is able to control the composition of the DPC and Venoco board of directors and direct both companies' management and policies. Accordingly, Mr. Marquez generally has the direct or indirect power to:
• elect all directors of DPC and Venoco and thereby control our policies and operations;
• amend the bylaws and certificate of incorporation of DPC and Venoco;
• appoint management of DPC and Venoco;
• approve future issuances of securities by DPC or Venoco;
• approve the payments of dividends, if any, on common stock of DPC or Venoco;
• approve the incurrence of debt by DPC or Venoco;
• agree to or prevent mergers, consolidations, sales of all or substantially all assets or other extraordinary transactions involving DPC or Venoco.
Mr. Marquez's 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, in July 2011 we entered into a non-exclusive aircraft sublease agreement with TimBer, LLC, a company owned by Mr. Marquez and his wife.
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 is subject.
Beverly Hills Litigation-As previously disclosed, in July 2012, all matters relating to the Beverly Hills litigation were settled other than certain indemnity claims made against Venoco and others relating to the cost of defense of the suit. Also as previously disclosed, certain of those indemnity claims were settled in September 2014. The Company has concluded that the legal risk associated with the remaining indemnity claims is de minimis.
Delaware Litigation-In August 2011 Timothy Marquez, the then-Chairman and CEO of Venoco, submitted a nonbinding proposal to the board of directors of Venoco to acquire all of the shares of Venoco he did not beneficially own for $12.50 per share in cash (the "Marquez Proposal"). As a result of that proposal, five lawsuits were filed in the Delaware Court of Chancery in 2011 against Venoco and each of its directors by shareholders alleging that Venoco and its directors had breached their fiduciary duties to the shareholders in connection with the Marquez Proposal. On January 16, 2012, Venoco entered into a Merger Agreement with Mr. Marquez and certain of his affiliates pursuant to which Venoco, Mr. Marquez and his affiliates would effect the going private transaction. Following announcement of the Merger Agreement, five additional suits were filed in Delaware and three suits were filed in federal court in Colorado naming as defendants Venoco and each of its directors. In March 2013 the plaintiffs in Delaware filed a consolidated amended class action complaint in which they requested that the court determine among other things that (i) the merger consideration is inadequate and the Merger Agreement was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable and (ii) the merger should be rescinded or in the alternative, the class should be awarded damages to compensate them for the loss as a result of the breach of fiduciary duties by the defendants. The Colorado actions have been administratively closed pending resolution of the Delaware case. Venoco has reviewed the allegations contained in the amended complaint and believes they are without merit. Trial is expected to occur in 2015.
Denbury Arbitration-In January 2013 Venoco and its wholly owned subsidiary, TexCal Energy South Texas, L.P. ("TexCal"), notified Denbury Resources, Inc. through its subsidiary Denbury Onshore, LLC ("Denbury") that it was invoking the arbitration provisions contained in contracts between TexCal and Denbury pursuant to which TexCal conveyed its interest in the Hastings Complex to Denbury and retained a reversionary interest. Denbury is obligated to convey the reversionary interest to TexCal at "payout" as defined in the contracts. The dispute involves the calculation of the
cost of CO2 delivered to the Hastings Complex which is used in Denbury's enhanced oil recovery operations. The Company believes that Denbury has materially overcharged the payout account for the cost of CO2 and the cost of transporting it to the Hastings Complex. In December 2013, the three judge arbitration panel unanimously agreed with Venoco's position. In January 2014 Denbury requested that the arbitration panel modify its decision in a way that could increase the cost of CO2. In March 2014 the Arbitration Panel modified its original award consistent with the Company's position and awarded the Company approximately $1.8 million in attorneys' fees and costs incurred in the arbitration. In late March 2014 Denbury appealed the arbitration ruling to the District Court for Harris County, Texas asking the court to vacate the arbitration award. On February 11, 2015 the District Court granted Venoco's motion to confirm the arbitration award. On March 12 2015, Denbury filed a motion for a new trial with the District Court.
Other-In addition, Venoco is a party from time to time to other claims and legal actions that arise in the ordinary course of business. Venoco believes that the ultimate impact, if any, of these other claims and legal actions will not have a material effect on its 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
Market for Common Stock
There is no market for the common stock of Venoco or DPC. As of March 31, 2015, DPC owns all of the outstanding stock of Venoco, and two affiliates of Mr. Marquez own 94% of the outstanding stock of DPC.
Unregistered Sales of Equity Securities
None.
Repurchases of Common Stock
Not applicable.
Dividend Policy
Venoco paid DPC cash dividends of $2.7 million in the fourth quarter of 2012, $15.8 million in the third quarter of 2013 and $3.9 million in the first quarter of 2014. As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operation-Liquidity and Capital Resources-Capital Resources and Requirements," Venoco's ability to pay dividends to DPC is subject to various legal and contractual limitations. See also the notes to the financial statements included herein.
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. As a result of the going private transaction on October 3, 2012, DPC and Venoco are entities under the common control of Mr. Marquez and his affiliates. The consolidated financial
data for DPC prior to 2012 is identical to Venoco. 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 acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. Amounts are in thousands.
ITEM 7.
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operation
This Annual Report on Form 10-K is a combined report being filed by DPC and Venoco, a direct 100% owned subsidiary of DPC. DPC is a holding company formed to acquire all of the common stock of Venoco in a going private transaction that was completed in October 2012. Unless otherwise indicated or the context otherwise requires, (i) references to "DPC" refer only to DPC, (ii) references to the "company," "we," "our" and "us" refer, for periods following the going private transaction, to DPC and its subsidiaries, including Venoco and its subsidiaries, and for periods prior to the going private transaction, to Venoco and its subsidiaries and (iii) references to "Venoco" refer to Venoco and its subsidiaries. See "Explanatory Note" immediately preceding Part I of this report. Venoco and DPC are filing this combined report to satisfy reporting requirements under the indentures governing their respective senior notes. 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.
Overview
We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our strategy is to grow through exploration, exploitation and development projects we believe to have the potential to add significant reserves on a cost-effective basis and through selective acquisitions of underdeveloped properties. In the execution of our strategy, our management is principally focused on economically developing additional reserves and on maximizing production levels through exploration, exploitation and development activities in a manner consistent with preserving adequate liquidity and financial flexibility. We currently conduct our operations in one reportable geographical segment-the United States.
Although our current asset base is primarily located along the southern California coast, we have extensive experience working and operating in other areas such as central California and eastern Texas onshore. Our core competencies and capabilities translate to many other geographic areas as well. We have been recognized by various regulatory agencies which govern our operations and assets, past and present, for our operational excellence and exemplary health, safety and environmental performance. In addition, we take our corporate and social responsibilities in the areas in which we operate seriously and with a strong level of commitment. In 2014, we received a resolution from Santa Barbara County recognizing our numerous contributions to the county and the state.
Recent Developments
As discussed in "Business and Properties-Going Private Transaction and Subsequent Events," we completed the going private transaction in October 2012 and incurred a substantial amount of additional debt in order to do so. We have undertaken a variety of measures to reduce our indebtedness, including in particular the asset sales described in "-Acquisitions and Divestitures." However, our deleveraging efforts have been impacted by various operational issues, including an extended shutdown of the pipeline that transports our South Ellwood field production in 2014 and apparent communication affecting production from some of our wells in the same field. More recently, our deleveraging efforts have also been affected by the dramatic decline in the price of oil that occurred over the second half of 2014. We have been required to obtain numerous amendments to and waivers from the lenders under Venoco's revolving credit facility as a result of these factors, and we have significantly curtailed our planned capital expenditures for 2015 relative to prior years.
We recently completed a series of financing transactions in response to our indebtedness and liquidity situation. On April 2, 2015, Venoco entered into agreements relating to three new debt instruments: (i) first lien senior secured notes with an aggregate principal amount of $175 million (the "first lien secured notes"), (ii) second lien senior secured notes with an aggregate principal amount of $150 million (the "second lien secured notes") and (iii) a $75 million cash collateralized senior secured
credit facility (the "term loan facility"). Approximately $72 million of proceeds from the issuance of the first lien secured notes and the term loan facility were used to repay all amounts outstanding under Venoco's revolving credit facility, which was then terminated. The second lien secured notes were issued in exchange for $194 million aggregate principal amount of, and accrued interest on, Venoco's outstanding 8.875% senior notes due 2019. We expect to incur a gain on extinguishment of indebtedness in the second quarter in connection with this exchange. The terms of the new debt instruments are summarized in "-Liquidity and Capital Resources-Capital Resources and Requirements." These transactions increased our indebtedness overall, but reduced our near-term cash interest expense and provided us with flexibility and additional liquidity that we intend to use to advance longer term projects.
Capital Expenditures
Our 2014 development, exploitation and exploration capital expenditures were $77 million, with approximately $73 million incurred for Southern California legacy projects and $4 million for onshore Monterey projects. Our 2015 development, exploitation and exploration capital expenditure budget is $18 million, of which approximately $16.5 million is expected to be devoted to our legacy Southern California assets and approximately $1.5 million to onshore Monterey shale activities. We do not currently plan to drill any new wells in 2015; instead, our capital expenditures will be devoted primarily to operational improvements, regulatory, health, safety and environmental compliance and progressing other long lead-time projects. However, we will continually evaluate market and economic conditions and may determine it is appropriate to proceed with drilling activities.
The aggregate levels of capital expenditures in 2015, and the allocation of those expenditures, are dependent on a variety of factors, including changes in commodity prices, permitting matters, 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 2014 capital spending program and the current outlook for 2015.
Southern California-Legacy Fields
In 2014, Venoco drilled one well at the Coal Oil Point structure in the South Ellwood field, which is located on the north east side of the field. The well was drilled near the successful 3242-19 RD5 well (which was drilled in 2013) to further develop and optimize production from the proved reserves in the Coal Oil Point structure. The lowest zone of the 2014 well tested wet, but in August, we completed a higher zone of the well, which proved to be hydrocarbon bearing and was placed on initial production on August 20, 2014. As of December 31, 2014 this zone was producing approximately 440 Bbls/d.
Because of communication issues we have experienced with respect to certain wells near the field's lease boundary, we have concentrated our recent exploration and development efforts on the Coal Oil Point area. Production from the South Ellwood field in 2014 was adversely affected by a prolonged shutdown of the third party pipeline that delivers oil from the field. We do not currently expect a comparable shutdown in 2015.
In the West Montalvo field, we drilled and completed two new well locations and concluded drilling and completion of two wells that were spud in 2013.
In the Sockeye field, we performed one recompletion and drilled one development well in the M-2 zone from Platform Gail. The well began producing on October 15, 2014 and initially produced approximately 610 Bbls/d.
Southern California-Onshore Monterey Shale
In 2006, we began leasing onshore acreage in Southern California targeting the Monterey shale. Our onshore Monterey shale acreage position currently totals approximately 27,000 gross and 24,000 net acres and is located primarily in three basins: Santa Maria, Salinas Valley and San Joaquin.
Between 2010 and 2013, we spud 29 wells and have set casing on 26 of those wells. To date, we have not seen material levels of production or reserves from the program and have, following the completion of the going private transaction, reduced our capital expenditures related to the project.
Acquisitions and Divestitures
We have a demonstrated track record in adding value through our development (and re-development) programs with our assets as well as building and realizing additional upside potential. Strategically, we feel the timing and value received in the asset sales described below were favorable, especially given the dramatic change in market conditions and commodity prices we have experienced. Tactically, these transactions allowed us to deleverage and improve our balance sheet.
West Montalvo Asset Sale. In October 2014, Venoco completed the sale of its West Montalvo properties to an unrelated third party for $200.2 million in cash, subject to certain closing adjustments. Venoco applied 100% of the net proceeds to reduce the principal balance outstanding on its revolving credit facility. The assets included in the sale had proved reserves of approximately 7,302 MBOE as of December 31, 2013. Production from those assets averaged 1,614 BOE/d in 2013 and 1,415 BOE/d in the first nine months of 2014.
Sacramento Basin Asset Sale. In December 2012, Venoco completed the sale of certain properties in the Sacramento Basin and San Joaquin Valley areas of California to an unrelated third party for $250 million, some of which was received in 2013. Venoco applied proceeds from the sale to pay down $214.7 million of the principal balance outstanding on its then-outstanding second lien term loan facility and a $6.4 million prepayment penalty. The assets sold had proved reserves of approximately 44,900 MBOE as of December 31, 2011. Production from those assets averaged 8,939 BOE/d in 2012, 100% of which was natural gas.
Other. We have an acreage acquisition program and we regularly engage in acquisitions and dispositions of oil and natural gas properties, primarily in and around our existing core areas of operations.
Trends Affecting our Results of Operations
Oil and Natural Gas Prices. Historically, prices received for our oil and natural gas production have been volatile and unpredictable, and that volatility is expected to continue. Changes in the market prices for oil directly impact many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth, carrying value of our properties and value of our proved reserves, all of which depend in part upon those prices. The assets included in the Sacramento Basin asset sale included substantially all of our properties that produce predominately natural gas. We therefore expect to have minimal exposure to changes in natural gas prices for the foreseeable future.
We employ a hedging strategy designed to reduce the variability in cash flows resulting from changes in commodity prices. As of March 31, 2015, we had hedge contract floors covering 4,595 barrels of oil per day for 2015. We have also secured hedge contracts for portions of our 2016 production. See "Quantitative and Qualitative Disclosures About Market Risk-Commodity Derivative Transactions" for further details concerning our hedging activities.
Production. Our 2015 capital spending has been allocated approximately 92% to our legacy Southern California fields and 8% to our onshore Monterey shale program. In light of current
commodity prices and our need to preserve liquidity, we have substantially reduced our capital expenditure budget for 2015. This capital program is focused on operational improvements, meeting regulatory and EHS requirements, and progressing long lead-time projects. None of the current budgeted capital is directed towards incremental production-adding development projects. As a result, we expect production to decline year over year from 2014.
Lease Operating Expenses. Lease operating expenses ("LOE") of $26.77 per BOE for 2014 were higher than our 2013 results of $22.44 per BOE. Offshore production activities are typically higher cost than onshore activities, and offshore production comprised a larger percentage of our total production for 2014 due to the sale of West Montalvo. In addition, our LOE per BOE was affected by lower year over year production. We expect that our LOE per BOE will be generally consistent in 2015 relative to 2014.
Property and Production Taxes. Property and production taxes of $2.82 per BOE for 2014 were higher than our 2013 results of $1.02 per BOE. We expect our total 2015 property and production taxes to be lower than they were in 2014, but to be higher on a per BOE basis due to lower production. Our ad valorem tax expense is highly sensitive to drilling results and the estimated present value of future net cash flows from new wells, and may be volatile in the future.
General and Administrative Expenses. General and administrative expenses were $8.39 per BOE (excluding non-cash share-based compensation decreases of $1.01 per BOE) for 2014 compared to $11.75 per BOE for 2013 (excluding non-cash share-based compensation charges of $2.79 per BOE). During 2014 we implemented a reduction in work force program to reduce our overhead to be more reflective of the asset base we have following the Sacramento Basin and West Montalvo asset sales. Excluding share-based compensation charges and certain one-time charges, we expect our 2015 G&A costs to be less than they were in 2014, but, on a per BOE basis, to increase in 2015 compared to 2014 due to our lower expected production in 2015.
Depreciation, Depletion and Amortization (DD&A). DD&A for 2014 was $16.31 per BOE compared to $14.09 per BOE for 2013. We expect our 2015 DD&A to be similar on a per BOE basis compared to our 2014 results.
Interest Expense. Interest expense was $32.21 per BOE in 2014 compared to $24.99 per BOE for 2013. This is largely due to our reduced production. We expect our overall interest expense to increase in 2015. However, because a portion of the interest payments will be paid in kind, we expect the cash portion of our interest expense to decline.
Commodity Derivative Gains and Losses. We do not account for commodity derivative contracts as cash flow hedges. Commodity derivative gains and losses include settlements of commodity derivative contracts, changes in fair value of open commodity derivative contracts and amortization of derivative premiums. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. Cash settlement of derivative instruments represents the difference between the strike prices in contracts settled during the period and the ultimate settlement prices. Payments actually due to or from counterparties on these derivatives will typically be offset by corresponding changes in prices ultimately received from the sale of our production. We have incurred significant commodity derivative gains and losses in recent periods and may continue to incur these types of gains and losses in the future.
Income Tax Provision (Benefit). We incurred losses before income taxes in 2008, 2009, and 2012, as well as taxable losses in each of the tax years from 2008 through 2013. These losses and expected future taxable losses were key considerations that led us to conclude that we should maintain a full
valuation allowance against our net deferred tax assets at December 31, 2013 and December 31, 2014 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 or for state income taxes. Future events or new evidence which may lead us to conclude that it is more likely than not that our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; meaningful incremental oil production and proved reserves from development efforts at our Southern California legacy properties; meaningful production and proved reserves from the CO2 project at the Hastings Complex; and taxable events resulting from one or more deleveraging transactions. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.
Our expectations with respect to future production rates, expenses and the other matters discussed above are subject to a number of uncertainties, including those discussed and referenced in "Risk Factors." For example, with respect to future production rates, uncertainties include those associated with third party services, limitations on capital expenditures resulting from the terms of our debt agreements, the availability of drilling rigs, oil prices, events resulting in unexpected downtime, permitting issues and drilling success rates.
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 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. Except for the items identified below as being specific to consolidated Venoco or consolidated DPC, all information is shown for both companies.
(1)Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on pipeline inventories, oil pipeline sales nominations, and prior to February 2012, the timing of barge deliveries and oil in tanks.
(2)BOE is determined using the ratio of one barrel of oil or natural gas liquids to six Mcf of natural gas.
(3)Net of amounts capitalized.
Comparison of Year Ended December 31, 2014 to Year Ended December 31, 2013
Oil and Natural Gas Sales. Oil and natural gas sales decreased $91.3 million (29%) to $222.1 million in 2014 from $313.4 million in 2013. The decrease was due to lower oil production and prices as described below.
Oil sales decreased by $89.0 million (29%) in 2014 to $217.4 million compared to $306.4 million in 2013. Oil production decreased by 20%, with production of 2,555 MBbl in 2014 compared to 3,180 MBbl in 2013. The decrease is due to a prolonged shutdown of the pipeline that transports production from our South Ellwood field, the sale of West Montalvo and production declines from existing wells at a variety of fields. Our average realized price for oil decreased $10.11 (11%) from $95.79 per Bbl in 2013 to $85.68 per Bbl in 2014.
Natural gas sales decreased $2.3 million (33%) in 2014 to $4.7 million compared to $7.0 million in 2013. Natural gas production decreased by 841 MMcf (49%), with production of 1,724 MMcf in 2013 compared to 883 MMcf in 2014. The decrease is primarily due to the sale of our Sacramento Basin assets. Our average realized price for natural gas increased $1.23 (30%) from $4.06 per Mcf for 2013 to $5.29 per Mcf for 2014.
Other Revenues. Other revenues decreased by $1.9 million (48%) to $2.2 million in 2014 from $4.1 million in 2013, primarily due to lower pipeline volumes and revenue.
Lease Operating Expenses. Lease operating expenses ("LOE") decreased by $5.5 million (7%) to $72.3 million in 2014 from $77.8 million in 2013. On a per unit basis, LOE increased by $4.33 per BOE from $22.44 in 2013 to $26.77 in 2014 due to lower production.
Production and Property Taxes. Production and property taxes increased $4.1 million (116%) to $7.6 million in 2014 from $3.5 million in 2013. The increase is primarily due to revised year-to-date supplemental property tax estimates that were recorded in the third quarter of 2013. On a per BOE basis, property and production taxes increased $1.80 per BOE to $2.82 per BOE in 2014 from $1.02 per BOE in 2013.
Transportation Expenses. Transportation expenses remained consistent at $0.2 million in 2014 from $0.2 million in 2013.
Depletion, Depreciation and Amortization (DD&A). DD&A expense decreased $4.7 million (10%) to $44.1 million in 2014 from $48.8 million in 2013. The decrease was primarily due to lower production. DD&A expense on a per unit basis increased $2.22 per BOE to $16.31 per BOE for 2013 compared to $14.09 per BOE for 2013.
Accretion of Abandonment Liability. Accretion expense remained consistent at $2.5 million in 2014 compared to $2.5 million in 2013.
General and Administrative (G&A). The following table summarizes the components of Venoco's general and administrative expense incurred during the periods indicated (in thousands):
Venoco G&A expenses decreased $30.5 million (60%) to $19.9 million in 2014 compared to $50.4 million in 2013. The decrease is due to lower employee related G&A costs and lower share-based compensation of $(4.9) million (net of amount capitalized) charged to G&A in 2014 compared to $19.3 million (net of amount capitalized) in 2013. The lower employee related G&A costs and share based compensation expenses are due to decreases in personnel and the reduction of related share-based compensation expense previously recognized due to the lower estimated value of DPC stock.
Excluding the effect of the non-cash share-based compensation expense and non-recurring costs relating to the reduction in force, G&A expense decreased to $8.39 per BOE in 2014 from $11.75 per BOE in 2013.
DPC incurred nominal G&A expenses in 2014 of $0.4 million.
Interest Expense, Net. For Venoco, interest expense decreased $12.5 million (19%) to $52.6 million in 2014 compared to $65.1 million in 2013. The decrease was the result of the repayment of Venoco's 11.50% $150 million senior notes in the third quarter of 2013 and the paydown of $200 million on the revolving credit facility. For DPC, interest expense increased $0.4 million to $87.0 million in 2014 compared to $86.6 million in 2013. The incremental increase of $34.4 million from Venoco's total interest was due to interest on DPC's 12.25% / 13.00% senior PIK toggle notes.
Amortization of Deferred Loan Costs. For Venoco, amortization of deferred loan costs decreased $0.4 million (11%) to $3.3 million in 2014 compared to $3.7 million in 2013. For DPC, amortization of deferred loan costs decreased $0.5 million (20%) to $4.3 million in 2014 compared to $4.8 million in 2013. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.
Loss on Extinguishment of Debt. For Venoco, the loss on extinguishment of debt of $2.3 million in 2014 resulted from a write-off of unamortized deferred loan costs for repayment of Venoco's revolving credit facility.
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. Unrealized commodity derivative (gains) losses represent the change in the fair value of our open derivative contracts from period to period.
Income Tax Provision (Benefit). Due to our valuation allowance, there was no income tax expense (benefit) recorded for 2014 or 2013. 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.
Net Income (Loss). For Venoco, net income for 2014 was $120.4 million compared to net income of $14.3 million for 2013. For DPC, net income for 2014 was $84.6 million compared to a net loss of $28.4 million for 2013. The changes between periods are the result of the items discussed above.
Comparison of Year Ended December 31, 2013 to Year Ended December 31, 2012
Oil and Natural Gas Sales. Oil and natural gas sales decreased $37.0 million (11%) to $313.4 million in 2013 from $350.4 million in 2012. The decrease was due to lower natural gas production, partially offset by higher oil production, as described below.
Oil sales increased by $14.9 million (5%) in 2013 to $306.4 million compared to $291.5 million in 2012. Oil production increased by 8%, with production of 3,180 MBbl in 2013 compared to 2,940 MBbl in 2012. The increase is primarily due to higher production at our South Ellwood field, resulting from successful drilling activity. Our average realized price for oil decreased $1.49 (2%) from $97.28 per Bbl in 2012 to $95.79 per Bbl in 2013.
Natural gas sales decreased $51.9 million (88%) in 2013 to $7.0 million compared to $58.9 million in 2012. Natural gas production decreased by 18,706 MMcf (92%), with production of 1,724 MMcf in 2013 compared to 20,430 MMcf in 2012. The decrease is primarily due to the sale of Sacramento Basin assets. Our average realized price for natural gas increased $1.18 (41%) from $2.88 per Mcf for 2012 to $4.06 per Mcf for 2013.
Other Revenues. Other revenues decreased by $2.0 million (32%) to $4.1 million in 2013 from $6.1 million in 2012. During part of 2012 we received revenues related to sub-charter activity of the barge previously used to transport oil production from our South Ellwood field. Our contract related to the barge was terminated effective in mid-May 2012; therefore, we did not realize any sub-charter revenue in 2013.
Lease Operating Expenses. Lease operating expenses ("LOE") decreased by $14.1 million (15%) to $77.8 million in 2013 from $91.9 million in 2012. The decrease was primarily due to the sale of Sacramento Basin assets. Excluding the Sacramento Basin assets sold, LOE remained relatively consistent at $77.3 million in 2013 and $76.4 million in 2012. On a per unit basis, LOE increased by $7.96 per BOE from $14.48 in 2012 to $22.44 in 2013. Excluding Sacramento Basin assets sold, on a per unit basis, LOE decreased by $2.07 per BOE from $24.85 in 2012 to $22.95 in 2013.
Production and Property Taxes. Production and property taxes decreased $6.2 million (64%) to $3.5 million in 2013 from $9.7 million in 2012. The decrease is primarily the result of revised estimates for supplemental property taxes at our South Ellwood and West Montalvo fields. On a per BOE basis, property and production taxes decreased $0.51 per BOE to $1.02 per BOE in 2013 from $1.53 per BOE in 2012.
Transportation Expenses. Transportation expenses decreased $5.0 million (96%) to $0.2 million in 2013 from $5.2 million in 2012. The decrease was due to elimination, in mid-May 2012, of the South Ellwood barge operation, which was replaced by an onshore pipeline.
Depletion, Depreciation and Amortization (DD&A). DD&A expense decreased $38.0 million (44%) to $48.8 million in 2013 from $86.8 million in 2012. The decrease was primarily due to the sale of the Sacramento Basin assets. Excluding the Sacramento Basin assets sold, DD&A remained relatively constant at $45.5 million in 2013 compared to $45.9 million in 2012. DD&A expense on a per unit basis increased $0.41 per BOE to $14.09 per BOE for 2013 compared to $13.68 per BOE for 2012.
Accretion of Abandonment Liability. Accretion expense decreased $3.3 million (57%) to $2.5 million in 2013 compared to $5.8 million in 2012. The decrease is primarily the result of the Sacramento Basin asset sale.
General and Administrative (G&A). The following table summarizes the components of Venoco's general and administrative expense incurred during the periods indicated (in thousands):
Venoco G&A expenses decreased $4.8 million (9%) to $50.4 million in 2013 compared to $55.2 million in 2012. The decrease is primarily due to lower employee related G&A costs in 2013 due to the Sacramento Basin asset sale, offset by higher legal fees and higher share-based compensation expense of $19.3 million (net of amount capitalized) charged to G&A in 2013 compared to $10.0 million (net of amount capitalized) in 2012. In connection with the going private transaction, our equity based awards were converted into cash settlement (or liability) awards. As a result of these changes, we expect that our share-based compensation expense will likely fluctuate more than when these awards were equity based. Excluding the effect of the non-cash share-based compensation expense and going private related costs, G&A expense increased to $11.75 per BOE in 2013 from $6.13 per BOE in 2012.
DPC incurred nominal G&A expenses in 2013 of $0.3 million.
Interest Expense, Net. For Venoco, interest expense decreased $6.3 million (9%) to $65.1 million in 2013 compared to $71.4 million in 2012. The decrease was primarily the result of the repayment of the second lien term loan and 11.50% senior notes, partially offset by higher interest expense resulting from the additional revolver borrowings incurred to repay the second lien term loan. For DPC, interest expense increased $12.6 million (17%) to $86.6 million in 2013 compared to $74.1 million in 2012. The incremental increase of $21.5 million from Venoco's total interest was due to interest on DPC's 12.25% / 13.00% senior PIK toggle notes and, prior to their redemption, DPC's senior secured notes.
Amortization of Deferred Loan Costs. For Venoco, amortization of deferred loan costs increased $0.9 million (34%) to $3.7 million in 2013 compared to $2.8 million in 2012. For DPC, amortization of deferred loan costs increased $1.8 million (59%) to $4.8 million in 2013 compared to $3.0 million in 2012. The costs incurred relate to our loan agreements and are amortized over the estimated lives of the agreements.
Loss on Extinguishment of Debt. For Venoco, the loss on extinguishment of debt of $38.5 million in 2013 resulted from a write-off of unamortized deferred loan costs, unamortized original issue discount and a premium paid for early repayment of Venoco's second lien term loan and 11.50% senior notes. For DPC, loss on extinguishment of debt was $58.5 million in 2013, which includes Venoco's $38.5 million loss on extinguishment of debt and an incremental $20.0 million loss on extinguishment of debt due to a write-off of unamortized deferred loan costs and a premium paid for early repayment of DPC's secured notes in August.
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 losses in 2013 reflect the settlement of contracts at prices above the relevant strike prices. In 2013 we unwound all outstanding natural gas derivative contracts at a cost of $3.8 million as a result of the Sacramento Basin asset sale, and unwound all of our oil basis swaps at a cost of $5.7 million, realizing total losses of $9.5 million. Additionally, we unwound certain oil and natural gas contracts in 2012 and realized a gain of $52.2 million which is reflected in realized commodity derivative (gains) losses. We recognized derivative premium amortization expense of $7.6 million related to the contracts that were unwound during 2012. There was no premium associated with the contracts that were unwound in 2013. 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 Provision (Benefit). Due to our valuation allowance, there was no income tax expense (benefit) recorded for 2013 or 2012. 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.
Net Income (Loss). For Venoco, net income for 2013 was $14.3 million compared to the net loss of $46.6 million for 2012. For DPC, the net loss for 2013 was $28.4 million compared to the net loss of $49.5 million for 2012. The change between periods is the result of the items discussed above.
Liquidity and Capital Resources
Venoco's primary sources of liquidity are cash generated from our operations and proceeds from debt transactions. In addition, Venoco has commodity derivative positions with a net asset value of $78.1 million as of December 31, 2014. If unwound, these positions could provide an additional source of liquidity subject to the commodity price environment at the relevant time. DPC's primary sources of liquidity are distributions from Venoco and the issuance of debt securities.
Cash Flows
Net cash provided by operating activities for Venoco was $51.2 million in 2014 compared with $89.5 million in 2013 and $163.8 million in 2012. The decrease in 2014 relative to 2013 resulted primarily from lower production and lower prices. The decrease in 2013 relative to 2012 resulted primarily from lower production as a result of the Sacramento Basin asset sale and cash outflows of $28.1 million for realized commodity derivative losses.
Net cash provided by operating activities for DPC was $31.2 million compared with $84.8 million in 2013 and $161.1 million in 2012. The difference in the amounts between Venoco and DPC relates to additional DPC interest expense.
Net cash provided by investing activities for Venoco and DPC was $108.2 million compared with $3.5 million used in 2013 and $56.6 million used in 2012. The primary investing activities in 2014 were net sales proceeds of $196.5 million received as a result of the Montalvo asset sale. The primary investing activities in 2013 were $102.0 million in capital expenditures on oil properties, partially offset by net sales proceeds of $101.1 million received as a result of the Sacramento Basin asset sale. The primary investing activities in 2012 were $223.8 million in capital expenditures on oil and natural gas properties related to our capital expenditure program, partially offset by net sales proceeds of $171.6 million received as a result of the Sacramento Basin and Santa Clara Avenue field asset sales.
Net cash used in financing activities for Venoco was $144.8 million in 2014 compared to $139.1 million in 2013 and $61.5 million in 2012. Venoco's primary financing activities in 2014 were draws on the revolver of $182 million and repayments $322 million including 100% of the proceeds from the sale of West Montalvo. Venoco's primary financing activities in 2013 were (i) repayment of $315 million on Venoco's second lien term loan with a combination of Sacramento Basin asset sale proceeds of $208 million and borrowings on its revolving credit facility of $107 million, (ii) repayment of its 11.50% senior notes funded by a capital contribution from DPC to Venoco of $158 million, (iii) net additional borrowings of $98 million on its revolving credit facility, (iv) prepayment premiums of $20.4 million incurred for the repayment of the second lien term loan and the 11.50% senior notes, and (v) a dividend of $15.8 million paid to DPC for payment of interest expense by DPC. Venoco's primary financing activities in 2012 were (i) net proceeds of $308.7 million, net of the $6.3 million original issue discount, from entering into its second lien term loan, (ii) net repayments of $43.0 million on its revolving credit facility, and (iii) the repurchase of common shares for $308.3 million in the going private transaction.
Net cash used in financing activities for DPC was $141.1 million in 2014 compared to $118.4 million in 2013 and $58.4 million in 2012. DPC's incremental financing activity in 2014 of $3.9 million was the receipt of dividends from Venoco.
Capital Resources and Requirements
Our 2015 capital expenditure budget is $18 million. This amount is substantially less than it has been in past years and is reflective of current market and economic conditions. We expect our 2015 capital expenditures to be devoted primarily to operational improvements, regulatory, health, safety and environmental compliance and progressing other long lead-time projects. The aggregate levels of capital expenditures in 2015, and the allocation of those expenditures, are dependent on a variety of factors, including changes in commodity prices, permitting matters, 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. Our other principal anticipated uses of cash are ongoing operating expenses and interest payments on our indebtedness. Historically, we have used funds from operations and borrowings under our revolving credit facility as our primary sources of liquidity. We project that cash flow from operations and cash on hand resulting from our recent financing transactions will be sufficient to fund our planned capital expenditures and ongoing operations for 2015.
We are currently pursuing a number of actions to improve our balance sheet including minimizing our capital expenditures by suspending drilling operations for 2015, effectively managing our working capital and improving our cash flows from operations. We cannot assure you that these initiatives will be successful. 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, and the possibility of an unexpected interruption in production.
In addition, Venoco is subject to various legal and contractual limitations on its ability to pay dividends or otherwise make distributions to DPC, and DPC will be able to pay interest on its 12.25% / 13.00% senior PIK toggle notes in cash only if it receives cash dividends or distributions from Venoco. The agreements permit Venoco to pay dividends to DPC in certain circumstances. We do not expect these criteria to be met in 2015. The February 2015 interest payment on DPC's notes was made 100% in kind, and we expect to continue making interest payments 100% in kind for the foreseeable future.
The following is a summary of the terms of our significant debt agreements as of December 31, 2014 and as of the date of this report. As discussed in "-Recent Events," Venoco entered into financing transactions in April 2015 pursuant to which it (i) issued the first lien secured notes and the second lien secured notes, (ii) entered into the term loan facility, (iii) repaid all amounts outstanding under its revolving credit facility and terminated the facility and (iv) repurchased $194 million aggregate principal amount of, and accrued interest on, its 8.875% senior notes due 2019.
Revolving Credit Facility ($65 million outstanding as of December 31, 2014; terminated as of the date of this report). In October 2012, Venoco entered into a fifth amended and restated credit agreement governing its revolving credit facility, and entered into several subsequent amendments to the agreement. The facility had a maturity date of March 31, 2016. The agreement contained customary representations, warranties, events of default, indemnities and covenants, including covenants that restricted Venoco's ability to incur indebtedness and required it to meet specified financial tests. As of December 31, 2014, all covenants under the facility were satisfied or waived.
Loans under the revolving credit facility designated as "Base Rate Loans" bore interest at a floating rate equal to (i) the greater of (x) the administrative agent's announced base rate, (y) the federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 1.25% to 2.00%, based upon utilization. Loans designated as "LIBO Rate Loans" under the revolving credit facility bore interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.25% to 3.00%, based upon utilization. The applicable margin for both Base Rate Loans and LIBO Rate Loans was increased by 0.50% when Venoco's debt to EBITDA ratio exceeded 3.75 to 1.00 on the
last day of each of the two fiscal quarters most recently ended. A commitment fee of 0.50% per annum was payable with respect to unused borrowing availability under the facility. The revolving credit facility was secured by a first priority lien on substantially all of Venoco's assets.
The revolving credit facility had a total capacity of $500.0 million, but was limited by the lesser of commitments from participating lenders and the borrowing base, both of which were $88.5 million as of December 31, 2014. The borrowing base was subject to redetermination twice each year, was subject to redetermination at other times at our request or at the request of the lenders. Lending commitments under the facility were allocated at various percentages to a syndicate of eleven banks. As of December 31, 2014, we had approximately $65 million outstanding under the facility at an average interest rate of 3.7% and $19.9 million in available borrowing capacity, net of the outstanding balance and $3.6 million of outstanding letters of credit.
Venoco 8.875% Senior Notes ($500 million outstanding as of December 31, 2014; $308 million outstanding as of the date of this report). In February 2011, Venoco 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, Venoco repaid in full the outstanding principal balance of $455.3 million on its second lien term loan then in place. The 8.875% senior notes pay interest semi-annually in arrears on February 15 and August 15 of each year. Venoco may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, Venoco 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 Venoco's ability to make investments, incur additional indebtedness or create liens on its assets.
DPC 12.25% / 13.00% Senior PIK Toggle Notes ($275.1 million outstanding as of December 31, 2014; $285 million outstanding as of the date of this report). In August 2013, DPC issued $255 million principal amount of 12.25% / 13.00% senior PIK toggle notes due 2018 at 97.304% of par. Interest on the notes is payable on February 15 and August 15 of each year, commencing February 15, 2014. The initial interest payment on the notes was required to be paid in cash. For each interest period thereafter (other than for the final interest period ending at the stated maturity, which will be paid in cash), DPC will, in certain circumstances, be permitted to pay interest on the notes by increasing the principal amount of the notes or issuing new notes (collectively, "PIK interest"). Cash interest on the notes accrues at the rate of 12.25% per annum. PIK interest on the notes accrues at the rate of 13.00% per annum until the next payment of cash interest. The notes are not currently guaranteed by any of DPC's subsidiaries. DPC may redeem the notes, in whole or in part, at any time prior to August 15, 2015, at a "make-whole" redemption price described in the indenture. DPC may also redeem all or any part of the notes on and after August 15, 2015 at a redemption price of 106.125% of the principal amount and declining to 100% by August 15, 2017. The notes are senior unsecured obligations and contain operational covenants that, among other things, limit our ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase stock, create liens or sell assets.
First lien secured notes (zero outstanding as of December 31, 2014; $175 million outstanding as of the date of this report). The first lien secured notes bear interest at 12% per annum and mature in February 2019. The indenture governing the first lien secured notes includes covenants customary for instruments of this type, including restrictions on Venoco's ability to incur additional indebtedness, create liens on its properties, pay dividends and make investments, in each case subject to exceptions. The covenants regarding the incurrence of additional indebtedness contain exceptions for, among other things, (i) up to $25 million of additional secured or unsecured indebtedness that may be issued or incurred in connection with certain projects approved by the holders of the notes, (ii) up to $50 million of additional second lien secured notes that may be issued in exchange for Venoco's outstanding
8.875% senior notes and (iii) up to $150 million of additional third lien or unsecured indebtedness that may be issued or incurred in exchange for the 8.875% senior notes due 2019 or to fund acquisitions. The indenture also includes restrictions on capital expenditures and an operational covenant pursuant to which Venoco is generally required to maintain a specified level of production for each quarterly period until maturity. Other covenants are generally similar to those contained in the indenture governing the existing 8.875% senior notes. Venoco's obligations under the first lien secured notes are guaranteed by all of its subsidiaries other than Ellwood Pipeline, Inc. and are secured by a first priority lien on substantially all of the assets of Venoco and the guarantors other than the cash collateral under the term loan facility. Venoco may redeem the first lien secured notes at a redemption price of 109% of the principal amount beginning on January 1, 2016 and declining to 100% by January 1, 2019.
Second lien secured notes (zero outstanding as of December 31, 2014; $150 million outstanding as of the date of this report). The second lien secured notes bear interest at 8.875% if paid in cash or 12% if paid in kind. Interest may be paid in cash or in kind, at Venoco's option, for semiannual interest periods commencing within 24 months following issuance, but may become payable entirely in cash earlier upon the occurrence of certain events. The second lien secured notes mature in February 2019. The indenture governing the second lien secured notes includes covenants, and exceptions thereto, substantially similar to those set forth in the indenture governing the first lien secured notes. Venoco's obligations under the notes are guaranteed by Venoco's subsidiaries that guarantee the first lien secured notes and are secured by a second priority lien on the same assets securing its obligations under the first lien secured notes. Venoco may redeem the second lien secured notes on the same terms as the existing 8.875% senior notes due 2019.
Term loan facility (zero outstanding as of December 31, 2014; $75 million outstanding as of the date of this report). The term loan facility, which was fully drawn at closing, matures in October 2015. Amounts borrowed under the facility will bear interest at 4.0% per annum for the first thirty days and at 12% thereafter. The facility contains representations, warranties and covenants typical for instruments of this type. Venoco's obligations under the term loan facility are secured by a first priority lien on cash collateral, which collateral may be released upon the occurrence of certain events. We expect to refinance this facility prior to its maturity with a substantially similar, but longer-term, instrument.
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, maintain compliance with the covenants in our debt agreements 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 while also allowing us to maintain compliance with our debt agreements, we may be forced to reduce or delay scheduled capital projects, sell material assets or operations, seek to restructure our indebtedness, 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 debt agreements, 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 agreements that require us to use some or all of the proceeds of such transactions to reduce amounts outstanding under the agreements 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.
The additional indebtedness we incurred in connection with the going private transaction and, more recently significant decreases in the price of oil, have increased the debt-related risks we face,
including the risks that we may default on our obligations under our debt agreements, that our ability to replace our reserves and maintain our production may be adversely affected by capital constraints and the financial covenants under our debt agreements and that we may be more vulnerable to further adverse changes in commodity prices and other economic conditions. Prior to the termination of Venoco's revolving credit facility, we were required to obtain numerous amendments to and waivers from the lenders under the facility as a result of anticipated or actual breaches of the covenants in the facility. We may be forced to seek similar amendments or waivers from current or future lenders, and there is no assurance that we will be able to obtain them in a timely manner or at all. We are currently exploring additional deleveraging efforts and have significantly curtailed our planned capital expenditures for 2015 relative to prior years. There can be no assurance that our deleveraging efforts will be successful.
Commitments and Contingencies
As of December 31, 2014, 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. The estimated present value of our total asset retirement obligations was $30.9 million at December 31, 2014.
(2)Amounts related to interest expense on our revolving credit facility are not included in the table above because the interest rate is variable. See "Liquidity and Capital Resources and Requirements" for a discussion of the terms of the revolving credit facility. During the years ended December 31, 2012, 2013 and 2014, we incurred interest expense on the revolving credit facility of $1.8 million, $6.1 million and $7.9 million, respectively.
(3)Amounts related to interest expense on our DPC 12.25%/13.00% PIK toggle notes were calculated in the above table at the 13.00% interest rate. In August 2014 and February 2015, we opted to PIK 100% of the interest.
Off-Balance Sheet Arrangements
At December 31, 2014, 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.
Adjusted Consolidated Net Tangible Assets
As of December 31, 2014, DPC's "Adjusted Consolidated Net Tangible Assets," as that term is defined in the indenture governing its 12.25% / 13.00% senior PIK toggle notes, was $0.93 billion. Adjusted Consolidated Net Tangible Assets is a non-GAAP financial measure generally defined as the discounted estimated future net revenues from reserves before income taxes (PV-10), adjusted to reflect commodity hedging obligations and for other minor items. See "-PV-10" for a reconciliation of PV-10 to standardized measure of discounted net cash flows.
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, and timing for when reversionary interests achieve payout, 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, 2014 estimate of net proved oil and natural gas reserves totaled 40.4 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 0.7% lower. In addition, our proved reserves are concentrated in a relatively small number of wells. At December 31, 2014, 41% 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, 2014 would have resulted in an increase of approximately $1.62 per BOE in our average 2014 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% net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. 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 2012, 2013 or 2014, we could be required to recognize impairments of oil and gas properties in future periods if, among other things, market prices of oil and natural gas decline. In 2014, we recognized an impairment of $0.8 million upon concluding an evaluation of certain South American projects.
Asset Retirement Obligations
The accounting standards 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.
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 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.
Share-Based Compensation
For equity based awards, we measure share-based compensation at the estimated grant date fair value of an award and recognize its compensation cost over the requisite service period (usually the vesting period). We estimate forfeitures in calculating the cost related to share-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. We then adjust compensation expense based on the actual number of awards for which the requisite service period is rendered. We do not consider a market condition to be a vesting condition with respect to compensation expense. Therefore, we do not deem an award to be forfeited solely because a market condition is not satisfied.
We measure liability awards based on the award's fair value, remeasured at each reporting date until the date of settlement. Compensation cost for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). Changes in the fair value of a liability that occur after the end of the requisite service period are considered compensation cost of the period in which the changes occur. Any difference between the amount for which a liability award is settled and its fair value at the settlement date is an adjustment of compensation cost in the period of settlement.
Our share-based compensation liability includes a liability for restricted share unit awards (RSUs), rights to receive (RTRs), employee stock ownership plan units (ESOP) and stock appreciation rights (SARs). The fair value of DPC common stock is a significant input for determining the share-based compensation amounts and the liability amounts for cash settled awards. DPC is a privately held entity for which there is no available market price or principal market for DPC common shares. There are inputs for determining the fair market value of this instrument that are unobservable. We utilize various valuation methods for determining the fair market value of DPC shares including a net asset value approach, a comparable company approach, a discounted cash flow approach and a transaction approach. Our estimate of the value of DPC shares is highly dependent on commodity prices, cost assumptions, discount rates, oil and natural gas proved reserves, overall market conditions and the identification of companies and transactions that are comparable to our operations and reserve
characteristics. While some inputs to our calculation of fair value of the DPC shares are from published sources, others, such as the discount rate and the expected future cash flows, are derived from our own calculations and estimates. There are numerous inputs and significant judgments that are utilized in determining the fair value of DPC common stock. Significant changes in the unobservable inputs, summarized above, could result in a significantly different fair value estimate.
We estimate the fair value of each SAR using the Black-Scholes valuation model. The fair market value of DPC common shares is a significant input into the Black-Scholes valuation model. Valuation models require the input of highly subjective assumptions, including the expected volatility of the price of the underlying stock. DPC shares have characteristics significantly different from those of traded shares, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is our opinion that the valuations afforded by existing models are different from the value that the shares would realize if traded in the market.
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 our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; meaningful incremental oil production and proved reserves from development efforts at our Southern California legacy properties; consistent, meaningful production and proved reserves from our onshore Monterey shale project; meaningful production and proved reserves from the CO2 project at the Hastings Complex; and taxable events resulting from one or more deleveraging transactions. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.
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 $94.71 per Bbl for oil and natural gas liquids and $2.76 per MMBtu for natural gas were adjusted for regional price differentials and other factors to arrive at realized prices of $101.39 per Bbl for oil, $55.15 per Bbl for natural gas liquids and $3.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2012.
(2)Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.78 per Bbl for oil and natural gas liquids and $3.67 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $98.37 per Bbl for oil, $79.04 per Bbl for natural gas liquids and $4.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2013.
(3)Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.99 per Bbl for oil and natural gas liquids and $4.35 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2014.
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 in cash flows resulting from changes in commodity prices. 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 cash flows than we would have if we were unhedged in times of higher oil and natural gas prices, management believes that reducing volatility associated with commodity prices 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
As of December 31, 2014, we had entered into various swap and collar agreements related to our oil 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 fixed price established in the agreement and a benchmark price, typically either Inter-Continental Exchange Brent ("Brent") or NYMEX WTI for oil or Henry Hub for natural gas.
Portfolio of Derivative Transactions
Our portfolio of commodity derivative transactions as of December 31, 2014 is summarized below:
Oil
We enter into derivative contracts, primarily collars, swaps and option contracts, in an effort 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.
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.
We have elected not to apply cash flow hedge accounting to any of our derivative transactions and we therefore 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, 2014, the fair value of our commodity derivatives was a net asset of $78.1 million.
Interest Rate Risk
We are subject to interest rate risk with respect to amounts borrowed from time to time under Venoco's revolving credit facility because those amounts bear interest at variable rates. The interest rates associated with the Venoco and DPC 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 $0.7 million on our variable rate borrowings of $65 million as of December 31, 2014. As of April 2, 2015 we no longer have any variable rate borrowings.
See notes to our consolidated financial statements for a discussion of our long-term debt as of December 31, 2014.
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 the CEO and CFO of Venoco and DPC 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.
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) at Venoco and DPC as of December 31, 2014. This evaluation was conducted under the supervision and with the participation of management, including the CEO and CFO of each company. Based on this evaluation, each company's CEO and CFO have concluded that, as of December 31, 2014, each company's disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by it 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 the Venoco and DPC 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 management, including the 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) for each of Venoco and DPC to provide reasonable assurance regarding the reliability of its 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 the CEO and CFO of each of Venoco and DPC, we assessed its internal control over financial reporting as of December 31, 2014, the end of its fiscal year. This assessment was based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that the internal control over financial reporting of each company was effective as of December 31, 2014.
Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. As previously disclosed, Tim Ficker and Doug Griggs, previously the Chief Financial Officer and Chief Accounting Officer, respectively, of Venoco and DPC resigned their positions in October 2014 and Scott Pinsonnault and Heather Hatfield assumed the duties of principal financial officer and principal accounting officer, respectively, of both companies in November 2014. This change in personnel is not expected to materially change either company's internal control structure except that the controls will be overseen by the new personnel.
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 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 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 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 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 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.
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.
Signature
Title
Date
/s/ TIMOTHY M. MARQUEZ
Timothy M. Marquez
Chief Executive Officer and Director (Principal Executive Officer)
April 15, 2015
/s/ SCOTT M. PINSONNAULT
Scott M. Pinsonnault
Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
April 15, 2015
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Venoco, Inc. and Denver Parent Corporation:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2013 and 2014
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2013 and 2014
Consolidated Statements of Changes in Stockholders' Equity for the Years Ended December 31, 2012, 2013 and
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2013 and 2014
Notes to Consolidated Financial Statements
Report of Independent
Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Denver Parent Corporation and subsidiaries
We have audited the accompanying consolidated balance sheets of Denver Parent Corporation and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and 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 Denver Parent Corporation and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with U.S. generally accepted accounting principles.
/s/ ERNST & YOUNG LLP
Denver, Colorado
April 15, 2015
Report of Independent
Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Venoco, Inc. and subsidiaries
We have audited the accompanying consolidated balance sheets of Venoco, Inc. and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and 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, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with U.S. generally accepted accounting principles.
/s/ ERNST & YOUNG LLP
Denver, Colorado
April 15, 2015
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands)
VENOCO, INC. AND SUBSIDIARIES
See notes to consolidated financial statements.
DENVER PARENT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(In thousands)
DENVER PARENT CORPORATION AND SUBSIDIARIES
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See notes to consolidated financial statements.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations Denver Parent Corporation, a Delaware corporation ("DPC"), was formed in January 2012 for the purpose of acquiring all of the outstanding common stock of Venoco, Inc., a Delaware corporation ("Venoco"), in a transaction referred to as the "going private transaction". The going private transaction was completed in October 2012. DPC has no operations and no material assets other than 100% of the common stock of Venoco. Venoco 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.
Basis of Presentation In 2011, Venoco's board of directors received a proposal from its then-chairman and chief executive officer, Timothy Marquez, to acquire all of the outstanding shares of common stock of Venoco of which he was not the beneficial owner for $12.50 per share in cash. On October 3, 2012, Mr. Marquez and certain of his affiliates, including DPC, completed the going private transaction and acquired all of the outstanding stock of Venoco. As a result, Venoco's common stock is no longer publicly traded and Venoco is a wholly owned subsidiary of DPC. DPC is majority-owned and controlled by Mr. Marquez and his affiliates.
The consolidated financial statements for Venoco and its consolidated subsidiaries are presented on a separate, stand-alone company basis. DPC has engaged in no transactions other than the going private transaction and certain debt transactions, and has incurred no expenses other than interest expenses, deferred loan costs and nominal general and administrative expenses. There are no intercompany sales or expenses between DPC and Venoco.
This Annual Report on Form 10-K is a combined report being filed by DPC and Venoco. Unless otherwise indicated or the context otherwise requires, (i) references to "DPC" refer only to DPC, (ii) references to the "Company," "we," "our" and "us" refer, for periods following the going private transaction, to DPC and its subsidiaries, including Venoco and its subsidiaries, and for periods prior to the going private transaction, to Venoco and its subsidiaries and (iii) references to "Venoco" refer to Venoco and its subsidiaries. Each registrant included herein is filing on its own behalf all of the information contained in this report that pertains to such registrant. When appropriate, disclosures specific to DPC and Venoco are identified as such. Each registrant included herein is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information. Where the information provided is substantially the same for both companies, such information has been combined. Where information is not substantially the same for both companies, we have provided separate information. In addition, separate financial statements for each company are included in this report.
Liquidity The additional indebtedness that the Company incurred in connection with the going private transaction and the associated financial covenants in Venoco's revolving credit facility have increased debt-related risks. We have undertaken a variety of measures to reduce our indebtedness, including in particular sales of our Sacramento Basin and West Montalvo properties for an aggregate price of approximately $450 million. However, our deleveraging efforts have been impacted by various operational issues, including an extended shutdown of the pipeline that transports our South Ellwood field production in 2014 and apparent communication issues affecting production from some of our wells in the same field. More recently, our deleveraging efforts have also been affected by the dramatic
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
decline in the price of oil that occurred over the second half of 2014. Prior to the termination of Venoco's revolving credit facility in April 2015, we were required to obtain numerous amendments to and waivers from the lenders under the facility as a result of these factors. We may be forced to seek further amendments or waivers from current or future lenders, and there is no assurance that we will be able to obtain them in a timely manner or at all. We are currently exploring additional deleveraging efforts and have significantly curtailed our planned capital expenditures for 2015 relative to prior years. See Note 16 for a discussion of our recent financing transactions.
Principles of Consolidation The consolidated financial statements for DPC include the accounts of DPC and its subsidiaries, all of which are wholly owned. The consolidated financial statements for Venoco include the accounts of Venoco and its subsidiaries, all of which are wholly owned. All intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates In the course of preparing the condensed consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in ceiling tests of oil and natural gas properties; (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 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 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
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
settlement, as required by applicable contracts. The Company's production imbalances were not material at December 31, 2013 and 2014.
Other revenues primarily include pipeline revenues and other miscellaneous revenues.
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 spread among a limited number of 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, 2014, 97% of the oil and natural gas sales related accounts receivable balance was receivable from the Company's two 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):
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
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, 2012, 2013 and 2014 was $82.6 million, $46.0 million and $42.0 million, respectively.
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. 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 $44.6 million of unproved costs out of the amortization base in 2012 due to the sale of Sacramento Basin and San Joaquin properties. The Company transferred $4.0 million of unproved costs into the amortization base in 2013 due to impairment, development of acreage or placement of assets into service. No interest costs were capitalized in 2012, 2013 or 2014 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 2012 or 2013. In 2014, the Company recorded $0.8 million impairment of the Argentina prospect. The Company could be required to recognize impairments of oil and natural gas properties in future periods if, among other things, market prices of oil and natural gas decline.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Accounts Payable and Accrued Liabilities The components of accounts payable and accrued liabilities include the following.
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 exploration, exploitation and development activities. These capitalized costs include salaries, employee benefits, costs 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 $27.5 million, $23.0 million and $8.7 million directly related to its exploration, exploitation and development activities during 2012, 2013 and 2014, 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, 2012, 2013 and 2014 was $4.2 million, $2.8 million and $2.1 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 Venoco's 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.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
Other Employee Benefit Plans The Company sponsors a 401(k) tax deferred savings plan (the Plan) and makes it available to employees. The Plan is a defined contribution plan, and the Company may make discretionary matching contributions of up to 90% of their annual compensation, not to exceed contribution limits established by the IRC. The Company makes matching contributions of 100% of participant contributions on the first 5% of compensation and 50% of participant contributions thereafter. The contributions made by the Company totaled approximately $1.7 million, $2.0 million and $2.4 million during the years ended December 31, 2014, 2013 and 2012, respectively.
Share-Based Compensation Share-based compensation for equity awards 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 share-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.
The Company measures its liability awards based on the award's fair value remeasured at each reporting date until the date of settlement. Compensation cost for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). Changes in the fair value of a liability that occur after the end of the requisite service period are compensation cost of the period in which the changes occur. Any difference between the amount for which a liability award is settled and its fair value at the settlement date is an adjustment of compensation cost in the period of settlement.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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 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.
Consolidated Statements of Comprehensive Income (Loss) No statement is presented because the Company had no comprehensive income or loss activity during the years ended December 31, 2012, 2013, or 2014.
Reclassifications Certain amounts in prior years have been reclassified to 2014 presentation. Reclassified amounts were not material to the financials.
Recently Issued Accounting Standards In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue. This authoritative accounting guidance is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period, and is to be applied using one of two acceptable methods. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's consolidated financial statements and disclosures.
In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern, which requires management to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related footnote disclosures. The guidance is effective for annual and interim reporting periods beginning on or after December 15, 2016. Early adoption is permitted for financial statements that have not been previously issued. The standard allows for either a full retrospective or modified retrospective transition method. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company's consolidated financials.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
2. SALES OF PROPERTIES
Sale of Montalvo Assets. Effective July 1, 2014, the Company sold the Montalvo field to Vintage Petroleum, LLC for $200.2 million. The Company applied 100% of the net proceeds to reduce the principal balance outstanding on its revolving credit facility. No gain or loss was recognized on the sale as the Company recorded the net proceeds as a reduction to the capitalized costs of its oil and natural gas properties.
3. DEBT
As of the dates indicated, the Company's debt consisted of the following (in thousands):
The following summarizes the terms of the agreements governing the Company's debt outstanding as of December 31, 2014.
Venoco Revolving Credit Facility. Prior to its refinancing and termination in April 2015, Venoco was party to a fifth amended and restated credit agreement which governed its revolving credit facility. The credit facility had a maximum size of $500 million and a maturity date of March 31, 2016. The borrowing base, which was subject to redetermination twice each year, and was subject to redetermination at other times at Venoco's request or at the request of the lenders, was $88 million as of December 31, 2014. The credit facility was secured by a first priority lien on substantially all of Venoco's oil and natural gas properties and other assets, including the equity interests in all of its subsidiaries, and was unconditionally guaranteed by each of those subsidiaries other than Ellwood Pipeline, Inc. The collateral also secured Venoco's obligations to hedging counterparties that were also lenders, or affiliates of lenders, under the facility. Loans made under the revolving credit facility were designated, at our option, as either "Base Rate Loans" or "LIBO Rate Loans." Loans designated as Base Rate Loans under the facility bore interest at a floating rate equal to (i) the greater of (x) the administrative agent's announced prime rate, (y) the federal funds rate plus 0.50% and (z) the one-month LIBOR plus 1.0%, plus (ii) an applicable margin ranging from 1.25% to 2.00%, based on utilization. Loans designated as LIBO Rate Loans under the facility bore interest at (i) LIBOR plus (ii) an applicable margin ranging from 2.25% to 3.00%, based upon utilization. The applicable margin for both Base Rate Loans and LIBO Rate Loans was increased by 0.50% when Venoco's debt to
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
3. DEBT (Continued)
adjusted EBITDA ratio exceeded 3.75 to 1.00 on the last day of each of the two fiscal quarters most recently ended. A commitment fee of 0.50% per annum was payable with respect to unused borrowing availability under the facility. The agreement governing the facility contained customary representations, warranties, events of default, indemnities and covenants, including operational covenants that restricted Venoco's ability to incur indebtedness and certain financial covenants.
The borrowing base under the revolving credit facility was allocated at various percentages to a syndicate of banks. As of December 31, 2014, Venoco had approximately $65 million outstanding on the facility and had available borrowing capacity of $19.9 million under the facility, net of the outstanding balance and $3.6 million in outstanding letters of credit.
The revolving credit facility generally permitted Venoco, subject to certain conditions, to pay cash dividends to DPC up to a maximum amount of $35 million in a four-quarter period on a rolling basis. Venoco paid cash dividends of $15.8 million and $3.9 million to DPC in September 2013 and February 2014, respectively.
Venoco 8.875% Senior Notes. In February 2011, Venoco issued $500 million in 8.875% senior notes due in February 2019 at par. The notes pay interest semi-annually in arrears on February 15 and August 15 of each year. Venoco may redeem the notes prior to February 15, 2015 at a "make whole premium" defined in the indenture. Beginning February 15, 2015, Venoco may redeem the notes at a redemption price of 104.438% of the principal amount and declining to 100% by February 15, 2017. The notes are senior unsecured obligations and contain operational covenants that, among other things, limit Venoco's ability to make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase its stock, create liens or sell assets.
DPC 12.25% / 13.00% Senior PIK Toggle Notes. In August 2013, DPC issued $255 million principal amount of 12.25% / 13.00% senior PIK toggle notes due August 2018 at 97.304% of par. Interest on the notes is payable on February 15 and August 15 of each year, commencing February 15, 2014. The initial interest payment on the notes was required to be paid in cash. For each interest period after the initial interest period (other than for the final interest period ending at the stated maturity, which will be paid in cash), DPC will, in certain circumstances, be permitted to pay interest on the notes by increasing the principal amount of the notes or issuing new notes (collectively, "PIK interest"). Cash interest on the notes accrues at the rate of 12.25% per annum. PIK interest on the notes accrues at the rate of 13.00% per annum until the next payment of cash interest. The August 2014 interest payment was paid 25% in cash and 75% PIK interest, and the February 2015 interest payment was paid entirely as PIK interest. DPC is a holding company that owns no material assets other than stock of Venoco; accordingly, it will be able to pay cash interest on its notes only to the extent that it receives cash dividends or distributions from Venoco. The notes are not currently guaranteed by any of DPC's subsidiaries. DPC may redeem the notes, in whole or in part, at any time prior to August 15, 2015, at a "make-whole" redemption price described in the indenture. DPC may also redeem all or any part of the notes on and after August 15, 2015 at a redemption price of 106.125% of the principal amount and declining to 100% by August 15, 2017. The notes are senior unsecured obligations and contain operational covenants that, among other things, limit our ability to
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
3. DEBT (Continued)
make investments, incur additional indebtedness, issue preferred stock, pay dividends, repurchase stock, create liens or sell assets.
Scheduled annual maturities of long-term debt outstanding as of December 31, 2014 were as follows (in thousands):
See Note 16 for a discussion of our recent financing transactions.
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Derivative Agreements. The Company utilizes swap and collar agreements and option contracts in an effort to hedge the effect of commodity price changes on its cash flows. 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 cash flows 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.
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 Venoco's revolving credit facility. Collateral under the revolving credit facility supports Venoco's collateral obligations under the derivative contracts. Therefore, the Company is not required to post additional collateral when the Company is in a derivative liability position. Venoco'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.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
The components of commodity derivative losses (gains) in the consolidated statements of operations are as follows (in thousands):
As of December 31, 2014, the Company had entered into certain swap, collar and put agreements related to its oil 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 differential between the agreement price and the price per the applicable index, Inter-Continental Exchange Brent ("Brent").
Fair Value of Derivative Instruments. The estimated fair values of derivatives included in the consolidated balance sheets at December 31, 2013 and 2014 are summarized below. The net fair value of the Company's derivatives changed by $101.8 million from a net liability of $23.7 million at December 31, 2013 to a net asset of $78.1 million at December 31, 2014, primarily due to (i) changes in the futures prices for oil, which are used in the calculation of the fair value of commodity derivatives, (ii) settlement of commodity derivative positions during the current period and (iii) changes to the Company's commodity derivative portfolio in 2014. 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 Company has not designated any of its derivative contracts as cash-flow hedging
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
4. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
instruments for accounting purposes. The main headings represent the balance sheet captions for the contracts presented (in thousands).
5. 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.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
5. ASSET RETIREMENT OBLIGATIONS (Continued)
The following table summarizes the activities for the Company's asset retirement obligations for the years ended December 31, 2013 and 2014 (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 liabilities settled or disposed of $7.6 million for 2013 and $9.4 million for 2014 primarily relate to the Montalvo asset sale.
6. CAPITAL STOCK
The going private transaction was completed in October 2012. As a result of the transaction, Venoco's common stock is no longer publicly traded and Venoco is wholly owned by DPC, an entity controlled by Timothy Marquez and his affiliates. At closing, all then-outstanding shares of Venoco common stock, other than shares beneficially owned by Mr. Marquez, were converted into the right to receive cash of $12.50 per share pursuant to the terms of the merger agreement.
During the second quarter of 2014, DPC issued 146,526 shares to its Employee Stock Ownership Plan ("ESOP"). As of December 31, 2014, there were 30,297,459 shares of common stock of DPC and 29,936,378 shares of common stock of Venoco outstanding.
7. SHARE-BASED PAYMENTS
In connection with the going private transaction, all of the Company's equity awards, which consisted of restricted share awards and stock option awards, were converted into cash settlement awards as follows:
• All unvested restricted share awards were converted into rights-to-receive awards (RTR) at $12.50 per share, subject to original service conditions. The original restricted share grants generally vested over a four year period, with 25% vesting on each subsequent anniversary of the grant date. This conversion is considered a modification of the original grant date terms and compensation expense is being recognized over the requisite service period for the greater of the original grant date fair value or $12.50 per share.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
7. SHARE-BASED PAYMENTS (Continued)
• All previously granted stock option awards, which had a maximum life of ten years, were fully vested at December 31, 2011. Holders of in-the-money options were paid the difference between $12.50 per share and the original exercise price and replacement share appreciation rights (SARs) were granted to these holders with an exercise price of $12.50 per share. Holders of options with an original exercise price greater than $12.50 were cancelled and replacement SARs were granted at the original exercise price. These SAR awards are 100% vested on the grant date and retain the original option award termination date.
After the going private transaction, the Company granted the following cash settlement or liability awards to officers, directors and certain employees of the Company:
• Restricted share unit awards (RSUs) that generally vest over a four year service period beginning April 1, 2013. At each vesting date, holders of the RSUs are paid the fair value of DPC common stock. The estimated fair value of the award is recognized as expense over the requisite service period and fair values are remeasured for unvested awards at each reporting date until the date of settlement. Certain grants of RSUs to officers and directors vest based on achievement of performance measurements used to determine the Company's annual cash bonus payout and related expense is recognized using graded vesting resulting in more accelerated expense recognition than expense recognized using straight line vesting over the service period.
• SAR awards with an exercise price of $12.50 per share for each unvested RTR award, subject to the original service conditions of the RTR. Compensation expense is recognized based on the grant date fair values over the remaining requisite service period of the RTR and these awards have a ten year life from the date of grant.
• SAR awards for each Venoco common share held at the date of the going private transaction (except for the Company's Executive Chairman) with an exercise price of $12.50 per unit. All such SAR awards are 100% vested on the grant date and have a ten year life from the date of grant.
The Company adopted an ESOP effective December 31, 2012 for eligible employees who are actively employed on the last day of the plan year. For each plan year, beginning in 2013, the Company will make discretionary contributions of restricted share units in DPC common stock to the ESOP based on a portion of the participant's eligible compensation, subject to certain Internal Revenue Code limitations. The number of ESOP restricted share units in DPC common stock granted to each participant is based on the total amount of the discretionary contribution to the participant each year, divided by the fair market value of DPC common stock on the valuation date as determined by an independent appraiser. ESOP restricted share units generally vest over a four year period beginning with the participant's hire date or the date of the adoption of the ESOP, whichever is later. The value of participants' accounts is determined based on an appraisal, performed at least annually, of the fair market value of DPC common stock. Participants may begin making withdrawals from the vested portion of their accounts upon separation from the Company or upon reaching normal retirement age as determined by the Internal Revenue Code.
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
7. SHARE-BASED PAYMENTS (Continued)
The following summarizes the Company's stock option activity for the year ended December 31, 2012:
The following summarizes the Company's cash settlement awards activity during the year ended December 31, 2014:
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
7. SHARE-BASED PAYMENTS (Continued)
Additional information related to SARs outstanding at December 31, 2014 is as follows:
The grant date fair value of each SAR is estimated using the Black-Scholes valuation model. Valuation models require the input of highly subjective assumptions, including the expected volatility of the price of the underlying stock. The Company's units have characteristics significantly different from those of traded units, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the valuations afforded by existing models are different from the value that the units would realize if traded in the market.
The following assumptions were used to compute the grant date fair value of SARs at:
The Company calculated the expected life of units granted using the "simplified method" set forth in Staff Accounting Bulletin 107 (average of vesting period and term of the option). For deep out-of-the-money SARs where the derived service period is materially longer than the explicit service period, the requisite service period is based on the derived service period. The risk free interest rate was based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility was based on the historical volatility of public companies with characteristics similar to the Company for the past seven years.
The Company measures its liability awards based on the award's fair value remeasured at each reporting date until the date of settlement. Compensation cost for each period until settlement is based on the change (or a portion of the change, depending on the percentage of the requisite service that has been rendered at the reporting date). Changes in the fair value of a liability that occur after the end of the requisite service period are compensation cost of the period in which the changes occur. Any difference between the amount for which a liability award is settled and its fair value at the settlement date is an adjustment of compensation cost in the period of settlement.
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
7. SHARE-BASED PAYMENTS (Continued)
The following table summarizes Company's share-based compensation liability at (in thousands):
The following summarizes the composition of the share-based compensation liability at (in thousands):
The Company recognized total share-based compensation costs as follows (in thousands):
As of December 31, 2014, there was $1.3 million of total unrecognized compensation cost, which is expected to be recognized over a period of 3.0 years.
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
8. 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.
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 of 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, 2014 (in thousands).
The Company's commodity derivative instruments consist primarily of swaps and collars 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
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
8. FAIR VALUE MEASUREMENTS (Continued)
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.
Share-based compensation. The Company's current share-based compensation liability includes a liability for restricted share unit awards (RSUs), share appreciation rights (SARs) and employee stock ownership plan unit awards (ESOP). The fair value of DPC common stock is a significant input for determining the share-based compensation amounts and the liability amounts for these cash settled awards. DPC is a privately held entity for which there is no available market price or principal market for DPC common shares. Inputs for determining the fair market value of this instrument are unobservable and are therefore classified as Level 3 inputs. The Company utilizes various valuation methods for determining the fair market value of this instrument including a net asset value approach, a comparable company approach, a discounted cash flow approach and a transaction approach. The Company's estimate of the value of DPC shares is highly dependent on commodity prices, cost assumptions, discount rates, oil and natural gas proved reserves, overall market conditions and the identification of companies and transactions that are comparable to the Company's operations and reserve characteristics. While some inputs to the Company's calculation of fair value of DPC shares are from published sources, others, such as reserve values, the discount rate and expected future cash flows, are derived from the Company's own calculations and estimates. Significant changes in the unobservable inputs, summarized above, could result in a significantly different fair value estimate.
The grant date fair value of each SAR is estimated using the Black-Scholes valuation model. The fair market value of DPC common shares is a significant input into the Black-Scholes valuation model. Valuation models require the input of highly subjective assumptions, including the expected volatility of the price of the underlying stock. DPC shares have characteristics significantly different from those of traded shares, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the valuations afforded by existing models are different from the value that the shares would realize if traded in the market.
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
8. FAIR VALUE MEASUREMENTS (Continued)
The following table summarizes the changes in fair value of financial assets (liabilities), which represent primarily share-based compensation liabilities, designated as Level 3 in the valuation hierarchy (in thousands):
(1)The transfers into Level 3 liability during 2013 and 2014 relate to RSU, SAR and ESOP grants made by the Company to officers, directors and certain employees, and requisite service period expense.
(2)The transfers out of Level 3 liability during 2014 relate to cash settlements of RSU grants, and forfeitures of RSU, SAR and ESOP grants as a result of employee terminations.
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 Venoco's revolving credit facility approximated fair value because the interest rate of the facility is variable. The fair value of the Venoco senior notes listed in the table below was derived from available market data (Level 1). We used available market data and valuation techniques (Level 2) to estimate the fair value of the DPC PIK toggle notes. This disclosure does not impact our financial position, results of operations or cash flows (in thousands).
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
8. FAIR VALUE MEASUREMENTS (Continued)
Assets and Liabilities Measured on a Non-recurring Basis. The Company uses fair value to determine the value of its asset retirement obligations ("ARO"). The inputs used to determine such fair value under the expected present value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and gas properties and would be classified Level 3 inputs.
9. 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. Beginning with the 2012 calendar year, DPC files consolidated federal and state income tax returns including the operating results of Venoco. The income tax provisions for DPC and Venoco have been prepared on a separate return basis. DPC and Venoco did not have current or deferred income tax expense or benefit in each of the years presented since each has a full valuation allowance against its net deferred tax assets in 2012, 2013 and 2014.
As of December 31, 2014, DPC has net operating loss carryovers ("NOLs") of $499 million for federal income tax purposes and $459 million for financial reporting purposes, and Venoco has net NOLs as of December 31, 2014 of $418 million for federal income tax purposes and $377 million for financial reporting purposes. The difference between the federal income tax NOLs and the financial reporting NOLs of $40 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 2034.
Venoco has incurred losses before income taxes in 2008, 2009, and 2012 as well as taxable losses in each of the tax years from 2008 through 2013. DPC has incurred losses before income taxes in 2008, 2009, 2012, 2013 and 2014 as well as taxable losses in each of the tax years from 2008 through 2014. These losses and expected future taxable losses were a key consideration that led Venoco and DPC to provide a full valuation allowance against its net deferred tax assets as of December 31, 2014, since it cannot conclude that it is more likely than not that its 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; meaningful incremental oil production and proved reserves from the Company's development efforts at its Southern California legacy properties; consistent, meaningful production and proved reserves from the Company's onshore Monterey shale
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
9. INCOME TAXES (Continued)
project; meaningful production and proved reserves from the CO2 project at the Hastings Complex; and taxable events resulting from one or more deleveraging transactions. 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.
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):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
9. INCOME TAXES (Continued)
The components of deferred tax assets and (liabilities) are as follows (in thousands):
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 NOLs to tax years 2003 through 2005, which resulted in federal tax refunds of $8.6 million. The 2009 through 2013 tax years remain open to examination by the IRS.
During 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 2013 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.
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
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 Timothy Marquez, the Company's then-Chairman and CEO. 6267 Carpinteria owns the office building and related land used by the Company in Carpinteria, California. The Company made lease payments to 6267 Carpinteria under a lease for the office building entered into prior to the dividend. In March 2013, the building was sold to an independent third party, and the lease terms were modified at closing under similar terms through 2023. The Company made minimum lease payments of approximately $1.2 million and $0.2 million to 6267 Carpinteria in 2012 and 2013, respectively.
The Company has entered into a non-exclusive aircraft sublease agreement with TimBer, LLC, a company owned by Mr. Marquez and his wife. The Company incurred costs related to the agreement of $0.7 million, $0.7 million and $0.7 million in 2012, 2013 and 2014, respectively.
11. COMMITMENTS
Leases-The Company has entered into lease agreements for office space, an office building, and a parcel of land adjacent to the Ellwood pier used for pier access. As of December 31, 2014, future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are $2.1 million in 2015, $2.2 million in 2016, $2.3 million in 2017, $2.5 million in 2018, $2.5 million in 2019 and $7.5 million thereafter. Net rent expense incurred for office space and the office building was $2.3 million, $2.0 million and $1.7 million in 2012, 2013 and 2014, respectively.
12. CONTINGENCIES
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 is subject.
Beverly Hills Litigation-As previously disclosed, in July 2012, all matters relating to the Beverly Hills litigation were settled other than certain indemnity claims made against Venoco and others relating to the cost of defense of the suit. Also as previously disclosed, certain of those indemnity claims were settled in September 2014. The Company has concluded that the legal risk associated with the remaining indemnity claims is de minimis.
Delaware Litigation-In August 2011 Timothy Marquez, the then-Chairman and CEO of Venoco, submitted a nonbinding proposal to the board of directors of Venoco to acquire all of the shares of Venoco he did not beneficially own for $12.50 per share in cash (the "Marquez Proposal"). As a result of that proposal, five lawsuits were filed in the Delaware Court of Chancery in 2011 against Venoco and each of its directors by shareholders alleging that Venoco and its directors had breached their fiduciary duties to the shareholders in connection with the Marquez Proposal. On January 16, 2012, Venoco entered into a Merger Agreement with Mr. Marquez and certain of his affiliates pursuant to which Venoco, Mr. Marquez and his affiliates would effect the going private transaction. Following announcement of the Merger Agreement, five additional suits were filed in Delaware and three suits were filed in federal court in Colorado naming as defendants Venoco and each of its directors. In March 2013 the plaintiffs in Delaware filed a consolidated amended class action complaint in which
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
12. CONTINGENCIES (Continued)
they requested that the court determine among other things that (i) the merger consideration is inadequate and the Merger Agreement was entered into in breach of the fiduciary duties of the defendants and is therefore unlawful and unenforceable and (ii) the merger should be rescinded or in the alternative, the class should be awarded damages to compensate them for the loss as a result of the breach of fiduciary duties by the defendants. The Colorado actions have been administratively closed pending resolution of the Delaware case. Venoco has reviewed the allegations contained in the amended complaint and believes they are without merit. Trial is expected to occur in 2015.
Denbury Arbitration-In January 2013 Venoco and its wholly owned subsidiary, TexCal Energy South Texas, L.P. ("TexCal"), notified Denbury Resources, Inc. through its subsidiary Denbury Onshore, LLC ("Denbury") that it was invoking the arbitration provisions contained in contracts between TexCal and Denbury pursuant to which TexCal conveyed its interest in the Hastings Complex to Denbury and retained a reversionary interest. Denbury is obligated to convey the reversionary interest to TexCal at "payout" as defined in the contracts. The dispute involves the calculation of the cost of CO2 delivered to the Hastings Complex which is used in Denbury's enhanced oil recovery operations. The Company believes that Denbury has materially overcharged the payout account for the cost of CO2 and the cost of transporting it to the Hastings Complex. In December 2013, the three judge arbitration panel unanimously agreed with Venoco's position. In January 2014 Denbury requested that the arbitration panel modify its decision in a way that could increase the cost of CO2. In March 2014 the Arbitration Panel modified its original award consistent with the Company's position and awarded the Company approximately $1.8 million in attorneys' fees and costs incurred in the arbitration. In late March 2014 Denbury appealed the arbitration ruling to the District Court for Harris County, Texas asking the court to vacate the arbitration award. On February 11, 2015 the District Court granted Venoco's motion to confirm the arbitration award. On March 12, 2015 Denbury filed a motion for a new trial with the District Court.
Other-In addition, Venoco is a party from time to time to other claims and legal actions that arise in the ordinary course of business. Venoco believes that the ultimate impact, if any, of these other claims and legal actions will not have a material effect on its consolidated financial position, results of operations or liquidity.
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2013 and 2014 (in thousands):
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
13. QUARTERLY FINANCIAL DATA (UNAUDITED) (Continued)
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, 2014, 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, 2012, 2013 and 2014 were prepared by DeGolyer and MacNaughton, independent petroleum reserve engineers.
Capitalized Costs of Oil and Natural Gas Properties
(1)Unevaluated costs represent leasehold and seismic costs which 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.
(2)Depletion expense for the years ended December 31, 2012, 2013 and 2014 was $82.6 million, $46.0 million and $42.0 million, respectively ($13.02, $13.27 and $15.84, respectively, per equivalent barrel of oil).
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, 2012, 2013 and 2014 include capitalized
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Continued)
general and administrative costs related to acquisition, exploration and development of natural gas and oil properties of $27.5 million, $23.0 million and $8.7 million, respectively. Costs incurred also include asset retirement costs of $1.1 million, $0.5 million and $4.6 million recorded during the years ended December 31, 2012, 2013 and 2014, respectively.
Estimated Net Quantities of Natural Gas and Oil Reserves
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, 2012, 2013 and 2014.
(1)Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.71 per Bbl for oil and natural gas liquids and $2.76 per MMBtu for natural gas were adjusted for quality, energy content, transportation fees and regional price differentials to arrive at realized
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Continued)
prices of $101.39 per Bbl for oil, $55.15 per Bbl for natural gas liquids and $3.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2012.
(2)Unescalated twelve month arithmetic average of the first day of the month posted prices of $96.78 per Bbl for oil and natural gas liquids and $3.67 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $98.37 per Bbl for oil, $79.04 per Bbl for natural gas liquids and $4.41 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2013.
(3)Unescalated twelve month arithmetic average of the first day of the month posted prices of $94.99 per Bbl for oil and natural gas liquids and $4.35 per MMBtu for natural gas were adjusted as in note (1) above to arrive at realized prices of $86.69 per Bbl for oil, $71.12 per Bbl for natural gas liquids and $5.21 per MMBtu for natural gas, which were used in the determination of proved reserves at December 31, 2014.
(4)Natural gas liquids reserves represent a minimal percentage of our total reserves (approximately 2.3%, 3.4% and 3.8% at December 31, 2012, 2013 and 2014, respectively), therefore natural gas liquids are not presented separately but rather are included with oil volumes.
(5)Extensions for the year ended December 31, 2012 represent results from the Hastings Complex's response to the CO2 project. Extensions for the year ended December 31, 2013 represent results from the drilling at the South Ellwood field of the Coal Oil Point well and the addition of reserves for two additional undeveloped locations. Extensions for the year ended December 31, 2014 represent results from the drilling of a M2 infill well at Sockeye.
Uncertainties with respect to future acquisition and development of reserves include (i) the success of development programs, including potential changes to the Company's drilling schedule based on ongoing operational results, (ii) the ability to obtain permits from relevant regulatory bodies to pursue development projects, (iii) changes in commodity prices, and (iv) the availability of sufficient cash flow from operations or external financing to fund the capital expenditure program. In addition, the Company has 9.9 million barrels of oil equivalent of proved reserves related to its reversionary interest in the Hastings Complex CO2 project, which will be subject to a significant degree of variability until Denbury has recovered all of its costs as defined in the agreement and the Company is able to back in to its 22.45% 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 price and operating cost environment.
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.
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YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
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 as of December 31, 2012, 2013 and 2014.
(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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
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 Venoco other than Ellwood Pipeline Inc. ("Guarantors") have fully and unconditionally guaranteed, on a joint and several basis, Venoco's obligations under its 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, 2014. 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. There are currently no guarantors of DPC's 12.25% / 13.00% senior PIK toggle notes.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
AT DECEMBER 31, 2013
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
AT DECEMBER 31, 2014
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2012
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2013
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2014
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2012
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2013
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
15. GUARANTOR FINANCIAL INFORMATION (Continued)
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2014
(in thousands)
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
16. SUBSEQUENT EVENTS
On April 2, 2015, Venoco entered into agreements relating to three new debt instruments: (i) first lien senior secured notes with an aggregate principal amount of $175 million (the "first lien secured notes"), (ii) second lien senior secured notes with an aggregate principal amount of $150 million (the "second lien secured notes") and (iii) a $75 million cash collateralized senior secured credit facility (the "term loan facility"). Approximately $72 million of proceeds from the issuance of the first lien secured notes and the term loan facility were used to repay all amounts outstanding under Venoco's revolving credit facility, which was then terminated. The second lien secured notes were issued in exchange for $194 million aggregate principal amount of and accrued interest on Venoco's outstanding 8.875% senior notes due 2019.
First lien secured notes. The first lien secured notes bear interest at 12% per annum and mature in February 2019. The indenture governing the first lien secured notes includes covenants customary for instruments of this type, including restrictions on Venoco's ability to incur additional indebtedness, create liens on its properties, pay dividends and make investments, in each case subject to exceptions. The covenants regarding the incurrence of additional indebtedness contain exceptions for, among other things, (i) up to $25 million of additional secured or unsecured indebtedness that may be issued or incurred inconnection with certain projects approved by the holders of the notes, (ii) up to $50 million of additional second lien secured notes that may be issued in exchange for the Venoco's outstanding 8.875% senior notes due 2019 and (iii) up to $150 million of additional third lien or unsecured indebtedness that may be issued or incurred in exchange for the Venoco's outstanding 8.875% senior notes due 2019 or to fund acquisitions. The indenture also includes restrictions on capital expenditures and an operational covenant pursuant to which Venoco is generally required to maintain a specified level of production for each quarterly period until maturity. Other covenants are generally similar to those contained in the indenture governing the existing 8.875% senior notes. Venoco's obligations under the first lien secured notes are guaranteed by all of its subsidiaries other than Ellwood Pipeline, Inc. and secured by a first priority lien on substantially all of the assets of Venoco and the guarantors other than the cash collateral under the term loan facility. Venoco may redeem the first lien secured notes at a redemption price of 109% of the principal amount beginning on January 1, 2016 and declining to 100% by January 1, 2019.
Second lien secured notes. The second lien secured notes bear interest at 8.875% if paid in cash or 12% if paid in kind. Interest may be paid in cash or in kind, at Venoco's option, for semiannual interest periods commencing within 24 months following issuance, but may become payable entirely in cash earlier upon the occurrence of certain events. The second lien secured notes mature in February 2019. The indenture governing the second lien secured notes includes covenants, and exceptions thereto, substantially similar to those set forth in the indenture governing the first lien secured notes. Venoco's obligations under the notes are guaranteed by Venoco's subsidiaries that guarantee the first lien secured notes and are secured by a second priority lien on the same assets securing its obligations under the first lien secured notes. Venoco may redeem the second lien secured notes on the same terms as the existing 8.875% senior notes due 2019. The first lien secured notes were issued under an indenture dated as of April 2, 2015 among Venoco, the guarantors and U.S. Bank National Association, as trustee and collateral agent.
VENOCO, INC. AND SUBSIDIARIES AND DENVER PARENT CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
YEARS ENDED DECEMBER 31, 2012, 2013 AND 2014
16. SUBSEQUENT EVENTS (Continued)
Term loan facility. The term loan facility, which was fully drawn at closing, matures in October 2015. Amounts borrowed under the facility will bear interest at 4.0% per annum for the first thirty days and at 12% thereafter. Venoco may repay or refinance the term facility at any time. The facility contains representations, warranties and covenants typical for instruments of this type. Venoco's obligations under the term loan facility are secured by a first priority lien on cash collateral, which collateral may be released upon the occurrence of certain events, and are guaranteed by Venoco's subsidiaries that guarantee the first lien secured notes and second lien secured notes. The term facility was incurred under a term loan and security agreement dated as of April 2, 2015 among Venoco, the guarantors and the lenders party thereto.