Item 1. and 2. BUSINESS AND PROPERTIES
RESOLUTE’S BUSINESS
Resolute Energy Corporation (“Resolute” or the “Company”), a Delaware corporation incorporated on July 28, 2009, was formed to consummate a business combination with Hicks Acquisition Company I, Inc. (“HACI”), a Delaware corporation incorporated on February 26, 2007. HACI was a blank check company that was formed to acquire through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination, one or more businesses or assets. HACI’s initial public offering (the “Offering”) was consummated on October 3, 2007. HACI had not engaged in any operations or generated any operating revenue prior to the business combination with Resolute.
On September 25, 2009 (the “Acquisition Date”), HACI consummated a business combination under the terms of a Purchase and IPO Reorganization Agreement (“Acquisition Agreement”) with Resolute and Resolute Holdings Sub, LLC (“Sub”), whereby, through a series of transactions, HACI’s stockholders collectively acquired a majority of the outstanding shares of Resolute common stock (the “Resolute Transaction”). As a result of the Resolute Transaction, Resolute owned, directly or indirectly, 100% of the equity interests of Resolute Natural Resources Company, LLC (“Resources”), WYNR, LLC (“WYNR”), BWNR, LLC (“BWNR”), RNRC Holdings, Inc. (“RNRC”), and Resolute Wyoming, Inc. (“RWI”) (formerly known as Primary Natural Resources, Inc. (“PNR”)), and owned a 99.996% equity interest in Resolute Aneth, LLC (“Aneth”), (collectively “Predecessor Resolute”). The entities comprising Predecessor Resolute prior to the Resolute Transaction were wholly owned by Sub (except for Aneth, which was 99.996% owned by Sub), which in turn is a wholly-owned subsidiary of Resolute Holdings, LLC (“Holdings”). Under generally accepted accounting principles, HACI was the accounting acquirer.
Resolute is an independent oil and gas company engaged in the exploration, exploitation and development of its oil and gas properties located in Utah, Wyoming, North Dakota and, to a lesser extent, properties in Alabama and Oklahoma. Approximately 90% of Resolute’s revenue is generated from the sale of oil production. Resolute’s main focus is on increasing reserves and production from its properties located in Utah (its “Aneth Field Properties”) and from Hilight Field and related properties in Wyoming, (“Wyoming Properties”), while improving efficiency and controlling costs in its operations. Resolute believes that significantly more oil can be recovered from its Aneth Field Properties through industry standard secondary and tertiary recovery techniques. Resolute has completed a number of exploitation projects that have increased its proved developed reserve base, and it has plans for additional expansion and enhancement projects. In its Wyoming Properties, Resolute has identified 36 exploitation opportunities similar to those successfully completed by the previous operator. Resolute plans to further expand its reserve base through a focused acquisition strategy by looking to acquire properties that have upside potential through development drilling and exploitation projects and through the acquisition, exploration and exploitation of acreage that appears to contain relatively low risk and repeatable drilling opportunities. Also, Resolute seeks to reduce the effect of short-term commodity price fluctuations on its cash flow through the use of various derivative instruments.
Resolute’s largest asset, constituting 93% of its proved reserves, is its ownership of working interests in Greater Aneth Field (“Aneth Field”), a mature, long-lived oil producing field located in the Paradox Basin on the Navajo Reservation in southeast Utah. Resolute owns a majority of the working interests in, and is the operator of, three federal production units covering approximately 43,000 gross acres. These are the Aneth Unit, in which Resolute owns a 62% working interest, the McElmo Creek Unit, in which Resolute owns a 75% working interest, and the Ratherford Unit, in which Resolute owns a 59% working interest. As of December 31, 2009, Resolute had interests in, and operated 399 gross (262 net) active producing wells and 334 gross (218 net) active water and CO2 injection wells on its Aneth Field Properties. The crude oil produced from the Aneth Field Properties is generally characterized as light, sweet crude oil that is highly desired as a refinery blending feedstock.
Resolute’s Wyoming Properties are largely located in the Powder River Basin of Wyoming and constitute approximately 7% of Resolute’s net proved reserves. Hilight Field, anchoring the Wyoming production and reserves, produces oil and gas from the Muddy formation. Shallow coalbed methane (“CBM”) production also
comes from this area. Resolute also owns properties in eastern Wyoming and Oklahoma that produce oil and gas. As of December 31, 2009, the Wyoming Properties consisted of 466 gross (420 net) active wells and Resolute operates all but 6 gross (1 net) wells. In addition, Resolute holds exploration leasehold rights in Wyoming’s Big Horn Basin and Alabama’s Black Warrior Basin.
In March 2010, Resolute acquired a 45% working interest in approximately 61,000 gross (42,000 net leasehold) acres in Williams County, North Dakota. This undeveloped leasehold is located within the Bakken shale trend of the Williston Basin. Although the Middle Bakken formation will be the primary objective, secondary objectives include the Three Forks, Madison and Red River formations. Resolute expects to participate in drilling at least three horizontal wells in this area during 2010.
As of December 31, 2009, Resolute’s estimated net proved reserves were approximately 64.4 MMBoe, of which approximately 35% were proved developed producing reserves and approximately 77% were oil. The pre-tax PV-10 of Resolute’s net proved reserves at December 31, 2009, was $479.9 million and the standardized measure of its estimated net proved reserves as of December 31, 2009, was $361.0 million. For additional information about the calculation of Resolutes’s PV-10 and its standardized measure, please read “Business and Properties - Estimated Net Proved Reserves.” The following table sets forth summary information attributable to Resolute’s estimated net proved reserves that is derived from its December 31, 2009, reserve report which was developed by Resolute and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. Reserves and production information is as follows.
1)
For the year ended December 31, 2009.
2)
Determined by dividing Resolute’s estimated future operating costs as of December 31, 2009, by total estimated net proved reserves as of December 31, 2009, for each reserve category.
3)
Determined by dividing Resolute’s estimated future production taxes as of December 31, 2009, by total estimated net proved reserves as of December 31, 2009, for each reserve category.
4)
Future development costs include costs incurred in connection with the initiation, extension and expansion of CO2 flood projects, including CO2 purchases, drilling of development wells, upgrades to field infrastructure, workovers of producing wells and recompletion of existing wells into new producing zones.
5)
Determined by dividing Resolute’s estimated total future development costs related to reserves classified as proved undeveloped by total estimated net proved undeveloped reserves as of December 31, 2009.
Resolute’s Business Strategies
Bring Proved Developed Non-Producing and Proved Undeveloped Reserves into Production. At December 31, 2009, Resolute had estimated net proved reserves of approximately 42.1 MMBoe that were classified as proved developed non-producing and proved undeveloped. An estimated 40.0 MMBoe, or 95% of those reserves, are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO2 floods that are currently in operation on Resolute’s Aneth Field Properties. Predecessor Resolute and Resolute incurred approximately $21.9 million of capital expenditures related to the Aneth Field Properties during 2009, and Resolute expects to incur an additional $377.4 million of capital expenditures over the next 28 years (including purchases of CO2), in connection with bringing those incremental reserves attributable to Resolute’s CO2 flood projects into production. Resolute’s current plan anticipates approximately $162 million of these future capital expenditures will be incurred from 2010 through 2012.
Increase Production and Improve Efficiency of Operations on Resolute’s Existing Properties. Resolute’s management team has experience in managing operationally intensive oil and gas properties. As the operator of the Aneth Field Properties, Resolute has the ability to directly manage its costs, control the timing of its exploitation activities and effectively implement programs to increase production and improve the efficiency of its operations. For example, Predecessor Resolute initiated a program to actively work with vendors to reduce labor and material costs. Predecessor Resolute also conducted a proprietary 3-D seismic survey of the Aneth Unit in 2007, which is the first 3-D seismic survey covering Aneth Field. Resolute expects that the data obtained from this seismic survey will provide information to enable it to more efficiently develop and improve the recovery from its Aneth Field Properties. In addition, soon after Predecessor Resolute acquired properties from Chevron and from ExxonMobil and became the operator of the Aneth, McElmo Creek and Ratherford Units, Predecessor Resolute undertook a program of repair and maintenance of those producing assets. As a result of these efforts, Resolute has seen a reduction in the well workover costs. Also, because Resolute is the operator of three federal units in Aneth Field, it has been able to assemble a critical mass of employees and projects and allocate its resources across a broader area in a more efficient manner than was previously the case when each unit had a different operator.
Pursue Acquisitions of Properties with Development Potential. From inception, Predecessor Resolute’s goal was to grow its reserve base through a focused acquisition strategy. It completed three significant acquisitions, two in Utah and one in Wyoming. Substantially all of its Aneth Field Properties were acquired through significant purchases in November 2004 and April 2006. Predecessor Resolute then acquired its Wyoming Properties in July 2008. Resolute looks to acquire similar producing properties in the onshore United States that have upside potential through relatively low-risk development drilling and exploitation projects. It believes its knowledge of various operating areas, strong management and staff and solid industry relationships will allow it to find, capitalize on and integrate strategic acquisition opportunities in various areas.
Acquire and Explore Properties in Oil Prone Areas. Resolute recently acquired leasehold interests in the Williston Basin that are prospective for oil production in the Middle Bakken formation as well as other formations. Resolute intends to explore these properties and to acquire, explore and develop other properties in areas of the United States that are prospective for production of oil or natural gas liquids (“NGL”).
Reduce Commodity Price Risk through Hedging. Resolute seeks to reduce the effect of short-term commodity price fluctuations and achieve less volatile and more predictable cash flows through the use of various derivative instruments such as swaps, puts, calls and collars. Resolute expects to continue to use these financial arrangements to reduce its commodity price risk. As of December 31, 2009, Resolute had in place oil and gas swaps, oil and gas collars and a gas basis hedge. These included oil swaps covering approximately 75% of its anticipated 2010 oil production at a weighted average price of $67.24 per Bbl, oil collars covering approximately 4% of its anticipated 2010 oil production with a floor of $105.00 per Bbl and ceiling of $151.00 per Bbl, gas swaps covering approximately 73% of its anticipated 2010 gas production at a weighted average price of $9.69 per MMBtu, and a CIG gas basis hedge priced at $2.10 per MMBtu covering approximately 34% of its anticipated 2010 gas production. Additional instruments are also in place for future years and are summarized in the table below.
Competitive Strengths
A High Quality Base of Long-Lived Oil Producing Properties. The Aneth Field Properties have several characteristics that Resolute believes will provide a stable production platform with which to fund its development and growth activities:
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The properties are expected to have a long productive life. As of December 31, 2009, the proved developed producing reserves had a reserves-to-production ratio of approximately 10 years and the total proved reserves had a reserves-to-production ratio of 31 years.
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The light, sweet crude oil produced from its Aneth Field Properties is more attractive to refineries than the heavy or sour crude oil found in many areas, including the Permian Basin.
Properties with Significant Low-Risk and Low-Cost Development Opportunities. As of December 31, 2009, approximately 42.1 MMBoe, or 65% of Resolute’s estimated net proved reserves, were classified as proved developed non-producing or proved undeveloped. An estimated 40.0 MMBoe, or 95% of those reserves, are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO2 floods that are currently in operation on Resolute’s Aneth Field Properties. Resolute’s current development plan for its Aneth Field Properties indicates that in six years the daily production rate, on a Boe basis, should be double the average production rate achieved during the twelve months ended December 31, 2009. After that, Resolute expects the production rate to remain relatively stable for approximately four years and then begin a natural decline. Resolute believes these development projects, particularly its planned CO2 flood projects, are relatively low risk compared to other conventional drilling-focused exploration and production activities, in large part because of the successful results of the McElmo Creek Unit CO2 flood program that has been in operation since 1985 and because of the observed response from the CO2 flood expansion Resolute has undertaken in the Aneth Unit. Following the initiation of the CO2 flood project in the McElmo Creek Unit in 1985, oil production from the unit increased by approximately 30% over a thirteen year period (approximately 22% as a result of the CO2 flood project and approximately 8% as a result of 24 newly drilled wells). Production then returned to a state of natural decline in 1998. Because of similar geological characteristics across Resolute’s Aneth Field Properties, Resolute expects to achieve analogous incremental reserves in Aneth Unit as were seen in McElmo Creek Unit,, but at accelerated production rates, due to the higher rate of CO2injection in Resolute’s Aneth Unit project.
Operating Control Over the Resolute Properties. Resolute is the operator of the Aneth, McElmo Creek and Ratherford Units. As a result of having a critical mass of employees and projects and operating control across the three federal units encompassing approximately 43,000 acres, it has the ability to utilize its employees on a prioritized basis. Because Resolute is the operator of all of its Aneth Field Properties, it believes it can attract contract services, materials and equipment from a broader market and negotiate more favorable terms than would otherwise be available. Resolute also has the ability to control the timing, scope and costs of development projects undertaken in its Aneth Field Properties. Resolute also operates Hilight Field and most of its other Wyoming Properties.
Experienced Management Team with Operational, Transactional and Financial Experience in the Energy Industry. With an average industry work experience of more than 25 years, the senior management team of Resolute has considerable experience in acquiring, exploring, exploiting, developing and operating oil and gas properties, particularly in operationally intensive oil and gas fields. Five members of its senior management who formed Holdings in 2004 previously worked together as part of the senior management team of HS Resources, Inc., an independent oil and gas company that was listed on the New York Stock Exchange and primarily operated in the Denver-Julesburg Basin in northeast Colorado. HS Resources conducted resource development programs, managed and enhanced a gas gathering and processing system and built a hydrocarbon physical marketing and transportation business. Its development activities included drilling new wells, deepening wells and recompleting and refracturing existing wells to add reserves and enhance production. HS Resources also had an active program of acquiring producing properties and properties with development potential. HS Resources was acquired by Kerr-McGee Corporation in 2001.
Aneth Field
Aneth Field, located in San Juan County, Utah, was discovered by Texaco in 1956 and was subsequently developed by several large integrated oil companies. It is the largest oil field in the Paradox Basin. Resolute’s Aneth Field Properties cover approximately 43,000 acres and during the twelve months ended December 31, 2009, gross production from the Aneth Field Properties averaged 9,188 barrels of oil per day.
The primary producing horizon in Aneth Field is the Pennsylvanian-age Desert Creek formation, which is a carbonate algal-mound formation with average depth of approximately 5,525 feet. While there is some reservoir heterogeneity in Aneth Field, development of the reserves generally has been accomplished with well-tested methodologies, including drilling and infilling vertical wells, horizontal drilling, waterflood activities and CO2 flooding. For administrative, organizational and operational reasons, in 1961 Aneth Field was divided into four separate federal production units to facilitate efficient development of the field and recovery of reserves. The three units that Resolute operates, the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit, which constitute Resolute’s Aneth Field Properties, possess substantially similar geologic and operating characteristics.
Predecessor Resolute acquired its Aneth Field Properties primarily through two significant acquisitions. In November 2004, it acquired a 53% operating working interest in the Aneth Unit, a 15% non-operating working interest in the McElmo Creek Unit and a 3% non-operating working interest in the Ratherford Unit (“Chevron Properties”). In the April 2006 acquisition, it acquired an additional 7.5% non-operating working interest in the Aneth Unit, a 60% operating working interest in the McElmo Creek Unit and a 56% operating working interest in the Ratherford Unit ( “ExxonMobil Properties”).
Predecessor Resolute acquired its Aneth Field Properties in connection with its strategic alliance with Navajo Nation Oil and Gas Company, Inc., (” NNOG”), an oil and gas company owned by the Navajo Nation. NNOG maintains a minority interest in each of the Chevron Properties and the ExxonMobil Properties and possesses options to purchase additional minority interests in those properties from Resolute under certain circumstances. Please read “- Relationship with the Navajo Nation.”
Aneth Unit. During the twelve months ended December 31, 2009, Aneth Unit production averaged approximately 3,115 barrels of oil per day (gross) from 162 gross (100 net) active producing wells. Resolute operated 150 gross (93 net) active injection wells in the Aneth Unit. Since the discovery of oil at the site in 1956, the Aneth Unit has produced a total of approximately 153 MMBbl of oil. The Aneth Unit was originally developed with vertical wells drilled on 80-acre spacing and was infill drilled to 40-acre spacing in the 1970s. Since unitization in 1961, the unit has been under waterflood. Between 1994 and 1998, an affiliate of Texaco operated the Aneth Unit and drilled 43 multi-lateral horizontal wells (23 producers and 20 injectors). Most of these horizontal wells were utilized to create a horizontal waterflood pattern on the eastern side of the unit. In 1998, the injectors in two square miles of the Aneth Unit were converted to a water-alternating-gas CO2 pilot project to assess the possibility of a field-wide CO2 injection flood program. The multi-lateral horizontal wells and the pilot CO2 program were successful in increasing production rate and adding reserves, however, the pilot CO2 program was never expanded into a unit-wide program. Predecessor Resolute became operator of the Aneth Unit on December 1, 2004, and has been successful in reducing the decline rate such that the average daily gross oil production from the Aneth Unit as a whole has remained relatively constant since the time of acquisition.
McElmo Creek Unit. During the twelve months ended December 31, 2009, McElmo Creek Unit production averaged approximately 3,649 barrels of oil per day (gross) from 140 gross (105 net) active producing wells. Resolute operated 107 gross (80 net) active injection wells on the McElmo Creek Unit. Since its discovery, the McElmo Creek Unit has produced a total of approximately 163 MMBbl of oil. The McElmo Creek Unit has been under waterflood since the early 1960s and prior operators commenced infill drilling to 40-acre spacing during the 1970s. A stabilized oil production decline trend was established for the waterflood over approximately seven years prior to the initiation of a CO2 flood program in 1985. Following the initiation of the CO2 flood project in the McElmo Creek Unit in 1985, oil production from the unit increased by approximately 30% over a 13 year period (approximately 22% as a result of the CO2 flood project and approximately 8% as a result of 24 newly drilled wells). Production then returned to a state of natural decline in 1998. Prior to Predecessor Resolute’s acquisition of the ExxonMobil Properties, the McElmo Creek Unit was operated by ExxonMobil. Predecessor Resolute became operator of the McElmo Creek Unit on June 1, 2006, and was successful in increasing the average daily
gross production rate. This was due to a number of factors, including its efforts to return wells to operation, improve artificial lift capacity at producing wells, improve compressor run times, increase production from new horizontal drilling, reduce freeze problems in the winter months and increase CO2 injection.
Ratherford Unit. During the twelve months ended December 31, 2009, Ratherford Unit production averaged approximately 2,424 barrels of oil per day (gross) from 97 gross (57 net) active producing wells. Resolute operated 77 gross (45 net) active injection wells on the Ratherford Unit. Since discovery, the Ratherford Unit has produced a total of approximately 102 MMBbl of oil. The core of the Ratherford Unit has been developed with horizontal wells, while the edges of the unit have been developed with vertical wells. Predecessor Resolute became operator of the Ratherford Unit on June 1, 2006, and was successful in increasing the average daily gross production rate. This increase in production resulted from a number of factors, including its efforts to improve artificial lift capacity at producing wells, increase production from new horizontal drillings, return wells to operation and increase water injection resulting from injection well cleanouts.
Wyoming Properties
Resolute’s Wyoming Properties consist of three units in Hilight Field, minor non-unitized Muddy formation production in the Hilight area, non-unitized CBM production in the Hilight area and twelve other small fields in Wyoming. Resolute also owns interests in two small fields in Oklahoma. All but one of the Wyoming Properties are operated by Resolute.
Hilight Field consists of the Jayson Unit, the Grady Unit, the Central Hilight Unit, and the South Hilight Unit. Resolute has an 82.7% working interest in Jayson, an 82.5% working interest in the Grady Unit and a 98.5% working interest in Central Hilight Unit. The Jayson, Grady and Central Hilight Units cover an area of almost 50,000 acres, and are operated by Resolute. Hilight Field was discovered by Inexco Oil Company in 1969, was developed on 160-acre spacing, unitized in 1971-1972 and underwent waterflood between 1972 and the mid-1990s. As of December 31, 2009, there were 144 active producing wells, and cumulative production through December 31, 2009, from Resolute’s three operated units was 68.3 MMBbl of oil and 150.0 Bcf of gas. Average daily gross production for the twelve months ending December 31, 2009, was 215 Bbl of oil per day and 10,258 Mcf of gas per day. Net proved reserves assigned to these properties as of December 31, 2009, were 4.4 MMBoe. Muddy formation sandstones form the main reservoir in the field. Average depth to the Muddy formation is approximately 9,100 ft. Minor production also comes from the Upper Cretaceous Niobrara, Upper Cretaceous Turner, and Pennsylvanian Minnelusa reservoirs. Recent activity includes 21 infill wells, including three horizontal laterals drilled by the prior operator in 2006 and 2007, and five Muddy re-stimulation, or refrac projects. Future activity may include the continuation of the infill and refrac programs, new drilling to extend the field boundaries, and exploration for unconventional oil from the overlying Niobrara and Mowry shales.
Resolute’s CBM production in the Hilight area comes from 263 producing wells. Average daily gross production for the twelve months ending December 31, 2009, was 2,900 Mcf per day. Although it varies from well to well, Resolute has an average of approximately 91% working interest in its Hilight area CBM properties. No net proved reserves were attributable to these wells as of December 31, 2009, The Wyodak-Anderson coals of the Paleocene Fort Union formation are the reservoir for this shallow gas reserve. Average depth to the reservoir is less than 500 feet. Recent activity by the prior operator includes seventeen wells that were drilled to extend the central portion of the field to the east. Since Predecessor Resolute took over operations, the CBM field has undergone downsizing and reconfiguration in an attempt to find the most economic balance between lease operating expenses and production.
Resolute also has working interests in twelve small fields in Wyoming and two in Oklahoma. Currently, Resolute operates wells in Campbell, Carbon, Natrona and Crook counties, Wyoming, and Dewey and Woodward counties, Oklahoma. During the twelve months ending December 31, 2009, these properties produced an average of approximately 299 barrels of oil per day from 52 gross (34 net) active producing wells. In addition, there are 5 gross (3 net) active water injection wells. Net proved reserves assigned to these properties as of December 31, 2009, were 311 MBoe.
Exploration Properties
Big Horn Basin Properties. Predecessor Resolute developed a grassroots exploration concept in early 2005 to target an unconventional oil resource in the Mowry shale of the Big Horn Basin in northwest Wyoming. Since that time, the Mowry shale has become an emerging oil play over a larger area in northern Wyoming and southern Montana. Predecessor Resolute began leasing in June 2005 and it has acquired 82,133 gross (70,811 net) acres in the play with more than 99% of its leased properties having at least five years remaining on the lease term. Predecessor Resolute entered into an area of mutual interest agreement effective November 1, 2006, with Fidelity Exploration and Production Company (“Fidelity”) covering acreage in the southeast part of the basin where 22,644 gross acres were jointly acquired on a 50-50 basis. That agreement has expired, but the acreage remains subject to a joint operating agreement for its remaining term. Resolute has not yet commenced development of this asset.
Black Warrior Basin Properties. In mid-2005, Predecessor Resolute initiated an exploration program in the Black Warrior Basin of northwest Alabama that targeted unconventional gas resources in the Devonian Chattanooga shale, the Mississippian Floyd shale, and the Pennsylvanian Pottsville coals. Approximately 39,500 net acres are currently leased. Predecessor Resolute drilled a vertical well in April 2007 that penetrated all three objectives and was cased without a completion attempt. It later entered into a participation agreement with Huber Energy LLC (“Huber”), effective June 26, 2008, under which Huber can earn an interest in the acreage by incurring all costs on specific development activities. Huber re-entered Resolute’s vertical well and completed the Chattanooga shale and recovered gas, but at uneconomic rates. The well is currently shut-in. Huber acquired proprietary 2-D seismic data in July 2009 for risk reduction on potential future operational activities targeting the Chattanooga and Floyd shales. Huber is also undertaking permitting activities for a potential CBM pilot program on the leasehold. The Pottsville formation has been producing CBM from adjacent areas since the early 1980s.
Recently Announced Activities
Williston Basin Properties. In March 2010, Resolute acquired a 45% working interest in approximately 61,000 gross (42,000 net leasehold) acres in Williams County, North Dakota. This undeveloped leasehold is located within the Bakken shale trend of the Williston Basin. Although the Middle Bakken formation will be the primary objective, secondary objectives include the Three Forks, Madison and Red River formations. For 2010, Resolute has allocated approximately $25 million for acreage acquisition, drilling and completion activities in this area, and expects to participate in drilling at least three horizontal wells during 2010.
Oil Recovery Overview
When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation. The only natural force present to move the crude oil through the reservoir rock to the wellbore is the pressure differential between the higher pressure in the rock formation and the lower pressure in the wellbore. Various types of pumps are often used to reduce pressure in the wellbore, increasing the pressure differential. At the same time, there are many factors that act to impede the flow of crude oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production, referred to as “primary recovery,” recovers only a small fraction of the crude oil originally in place in a producing formation.
Many, but not all, oil fields are amenable to assistance from a waterflood, a form of “secondary recovery,” which is used to maintain reservoir pressure and to help sweep oil to the wellbore. In a waterflood, some of the wells are used to inject water into the reservoir while other wells are used to produce the fluid. As the waterflood matures, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the oil from the water, with the oil going to pipelines or holding tanks for sale and the water being recycled to the injection facilities. Primary recovery followed by secondary recovery usually produces between 15% and 40% of the crude oil originally in place in a producing formation.
A third stage of oil recovery is called “tertiary recovery” or “enhanced oil recovery”, (“EOR”). In addition to maintaining reservoir pressure, this type of recovery seeks to alter the properties of the oil in ways that facilitate
production. The three major types of tertiary recovery are chemical flooding, thermal recovery (such as a steamflood) and miscible displacement involving CO2 or hydrocarbon injection.
In a CO2 flood, CO2 is liquefied under high pressure and injected into the reservoir. The CO2 then swells the oil in a way that increases the mobilization of bypassed oil while also reducing the oil’s viscosity. The lighter components of the oil vaporize into the CO2 while the CO2 also condenses into the oil. In this manner, the two fluids become miscible, mixing to form a homogeneous fluid that is mobile and has lower viscosity and lower interfacial tension, thus facilitating the migration of oil and gas to the producer wells.
Miscible CO2 flooding was first commercially successful with Chevron’s 1972 miscible CO2 flood in the SACROC field in Scurry County, Texas. According to the Oil & Gas Journal’s 2008 Worldwide EOR Survey, there were 105 miscible CO2 projects in the United States (with an additional sixteen miscible CO2 projects in the planning stages) that produced an estimated 249,700 barrels of oil per day during 2008. In addition to Resolute’s projects in its Aneth Field Properties, CO2 projects are located in Texas, Oklahoma, New Mexico, Colorado, Wyoming, Michigan and Mississippi. Four companies, Occidental Petroleum, Kinder Morgan, Amerada Hess and Chevron, are responsible for the majority of the estimated daily production from these CO2 projects.
Planned Operating and Development Activities
Resolute has prepared a development program for its Aneth Field Properties that includes CO2 flooding, field infrastructure enhancements, recompletions, workovers of producing and injection wells, infill drilling and waterflood enhancement. The application of each of these activities and technologies has been successfully established in various locations within the Aneth Field Properties, and the development plans have been designed to enhance or extend projects that were tested or initiated by the previous operators but were never fully completed due to such factors as lack of fieldwide operatorship and lower commodity prices. Resolute believes that its close working relationship with NNOG and the Navajo Nation will enhance its ability to advance development of its Aneth Field Properties.
CO2 Floods. A major component of planned activity over the next several years involves extensions and expansions of the CO2 floods initiated by the major oil companies, first in the McElmo Creek Unit in 1985 and then in the Aneth Unit in 1998. The McElmo Creek Unit CO2 flood is virtually unit-wide, whereas the Aneth Unit CO2 flood was limited to a pilot project covering approximately two square miles in the northeast corner of that unit.
The Aneth and McElmo Creek Units exhibit similar geologic characteristics. As a result, Resolute expects its Aneth Unit CO2 flood to achieve results analogous to those achieved in the McElmo Creek CO2 flood program, adjusted for operating and timing differences. Therefore, Resolute has modeled its estimate of increased incremental proved developed non-producing and proved undeveloped reserves based upon the results achieved in the McElmo Creek Unit CO2 flood. It also has modeled its projection of increased rate of oil production based upon the oil production response of the McElmo Creek Unit as a function of the injection of CO2. The oil production rate response is related to the rate at which CO2 is injected. The McElmo Creek CO2 project was initiated in 1985 with a relatively low rate of CO2 injection, and therefore experienced an oil production rate response that was lower than what might have been achieved had CO2 been injected at a higher rate. Resolute estimates that the rate of oil production will increase faster at the Aneth Unit than the production response experienced at the McElmo Creek Unit because of Resolute’s plan to inject CO2 volumes at a greater rate at the Aneth Unit than at the McElmo Creek Unit.
Aneth Unit. Construction activities and costs associated with phases 1, 2 and 3 of the Aneth Unit CO2 expansion project, covering the western portion of the Aneth Unit, are now substantially complete. Initial CO2 injection began in July 2007 and oil response has been observed in all three active phases. Phase 4 construction is scheduled to begin during the fourth quarter of 2010 and injection of CO2 is expected to commence in the second quarter of 2011 with significant production response estimated in 2012.
McElmo Creek Unit. Resolute plans to expand the existing CO2 flood project into a segment of the Desert Creek zone that has not yet been CO2 flooded. It performed well under waterflood and was abandoned by a prior operator after it reached a prior economic limit of water cut and before the existing CO2 flood was implemented.
This segment is expected to perform well under CO2 flood. Additional waterflood reserves will also be recovered as the waterflood will be effectively restarted in conjunction with the start of the CO2 flood.
Ratherford Unit. The geology and, except for the prevalence of horizontal wells, the overall operations of the Ratherford Unit are fundamentally the same as the other two units, including an extensive waterflood of the Desert Creek reservoir. Resolute is evaluating future plans to include a CO2 flood of this unit.
The following table sets forth, as of December 31, 2009, Resolute’s estimate of the future capital expenditures, net to its interest, for construction, well work and other costs and for purchases of CO2 required to implement its CO2 flood projects in two of the units of its Aneth Field Properties through 2038. The following table also sets forth the estimated net proved developed non-producing and proved undeveloped reserves included in Resolute’s reserve report as of December 31, 2009, which Resolute anticipates will be produced as a result of these projects. Resolute and Predecessor Resolute incurred $21.9 million of capital expenditures related to the Aneth Field Properties during 2009, and Resolute expects to incur an additional $377.4 million of capital expenditures over the next 28 years (including purchases of CO2), in connection with bringing into production those incremental proved developed non-producing and proved undeveloped reserves attributable to its CO2 flood project. Resolute has entered into two CO2 purchase contracts for a substantial portion of the CO2 it expects to use in connection with its CO2 flood projects. In order to further these CO2 flood projects, it expects to incur approximately $162 million of these future capital expenditures from 2010 through 2012.
As Resolute advances its CO2 projects, the injected CO2 will displace an increasing portion of the water currently being injected in the waterflood operation. Resolute will need to safely dispose of that water, and, to that end, has drilled a water disposal well with four horizontal laterals. Engineering studies have indicated that this initial well should be able to handle most of the incremental water production. To protect against the possibility that the first water disposal well might become incapable of handling all volumes of water to be disposed of, Resolute is presently in the process of securing permits to drill a second water disposal well to handle any excess water disposal needs. This well could be ready for water disposal by the second quarter of 2011.
The success of Resolute’s CO2 projects also depends on acquiring adequate amounts of CO2. Resolute has entered into two CO2 purchase contracts that provide a significant portion of the anticipated CO2 required through 2016 to pursue CO2 projects and to continue its existing CO2 floods. Resolute estimates that, as of December 31, 2009 and through 2016, it will need gross aggregate volumes of CO2 of approximately 177.7 Bcf, or approximately 115.6 Bcf net to its working interest. As of December 31, 2009, it had gross aggregate volumes of approximately 108.7 Bcf committed to it under the two contracts noted above.
One of these contracts is with ExxonMobil Gas & Power Marketing Company (“EMGP”). The price per Mcf of CO2 under this contract is 1.4% of the price of West Texas Intermediate crude oil. The volume Resolute is allowed to take and that EMGP is required to deliver is 20,000 Mcf per day, or approximately 3.6 Bcf over the six months remaining on the contract from January 1, 2010. Resolute is obligated to take or if not taken, pay for 80% of this volume on a monthly basis, with limited make-up rights for volumes not taken. Resolute also has the right to resell any CO2 it is obligated to take under this contract but that it is not able to use. Resolute has the right to take delivery into either the McElmo Creek Pipeline (which would be for its own use) or into Kinder Morgan’s Cortez Pipeline (which would occur if it were reselling the CO2). The contract term runs until June 30, 2010, and it will not be renewed. As of December 31, 2009, Resolute had made payments of $0.3 million under this contract for 0.4 MMcf of CO2 for which it had not yet taken delivery.
The second contract for the purchase of CO2 is with Kinder Morgan CO2 Company, L.P (“Kinder Morgan”). This gas is also delivered from the McElmo Dome field. The price per Mcf of CO2 under this contract is 1.75% of the price of West Texas Intermediate crude oil, and the contract runs through December 31, 2016. This contract has a variable schedule of committed contract quantities intended to make available the expected requirements of Phases 1, 2, 3 and 4 of Resolute’s Aneth Unit CO2 project as well as the requirements of its expansion project in the McElmo Creek Unit, less the volumes expected to be provided under its EMGP contract. The Kinder Morgan contract maximum daily quantities range from a high of approximately 41,000 Mcf per day in 2010, declining to approximately 6,000 Mcf per day during 2016, the last year of the contract. The aggregate total contract quantity over the term of the contract for these projects is approximately 63.6 Bcf. Resolute has the option to increase the total contract volume by approximately 41.5 Bcf between 2011 and 2016. Following the termination of the EMGP contract in June 2010, all of Resolute’s supply of CO2 is expected to be under the Kinder Morgan contract.
Resolute is required to take, or pay for if not taken, 75% of the total of the maximum daily quantities for each month during the term of the Kinder Morgan contract. There are make-up provisions allowing any take-or-pay payments it makes to be applied against future purchases for specified periods of time. Resolute has a one time right to reduce committed volumes under the contract by an amount between 10.0 and 25.3 Bcf for 25% of the contract price at the time the volumes are released. It does not have the right to resell CO2 required to be purchased under the Kinder Morgan contract. As of December 31, 2009, Resolute had made payments of $1.4 million under this contract for 1.3 MMcf of CO2 for which it had not yet taken delivery.
The CO2 that Resolute purchases for its use will be delivered to it through the McElmo Creek Pipeline. This pipeline is approximately 25 miles in length and runs directly from the McElmo Dome Field to Resolute’s McElmo Creek Unit. Pipelines within the Aneth Field Properties are used to distribute the CO2 to the Aneth Unit. Resolute owns a 75% interest in, and is the operator of, the McElmo Creek Pipeline. Resolute recently added a pump to the pipeline to increase capacity to 70,000 Mcf per day. Additional pumps are planned to further increase capacity to more than 130,000 Mcf per day.
Wyoming Properties. Resolute has prepared a multi-year development plan for the Wyoming Properties. At Hilight Field, the previous operator was successful in adding new reserves by stimulating the Muddy formation. Resolute plans to continue this program with 38 refracs scheduled to be completed between 2010 and 2012. The repair and maintenance program will continue and certain water discharge facilities are scheduled to be reconfigured in 2010. At the Hilight area CBM property, any new operational activities will be planned after the results of the field reconfiguration, which was implemented on a trial basis beginning in April 2009, are fully analyzed. At the other fourteen properties acquired in June 2008, two proved undeveloped reserve locations are scheduled to be drilled in 2011, and the repair and maintenance program will continue.
Other Planned Activities
Aneth Field - Gas Processing. Currently there are two types of gas production in Aneth Field, saleable gas and contaminated gas. The saleable gas stream has low levels of CO2and is sold. The contaminated gas stream has high levels of CO2 which prevents it from being sold. This contaminated gas stream currently is compressed and re-injected into the reservoir. As Resolute continues its CO2 injection and expansion plans, the volume of contaminated gas will significantly increase. This contaminated stream is rich in NGL, which represents a valuable product. Resolute plans to install new facilities and gas plant equipment to process and treat this contaminated stream. This project will recover condensate and also strip the majority of the CO2 from the contaminated stream. The condensate will be sold and the CO2 will be compressed and re-injected. The residue gas stream will be marketed through third party facilities.
Black Warrior Basin Properties. Activities on Resolute’s Black Warrior Basin exploration acreage in Alabama are expected to occur in 2010 and 2011. Under a participation agreement with Huber, Huber has the option to perform specified activities which would earn it an interest in Resolute’s Black Warrior acreage. Huber may drill, complete, and test a five-well CBM pilot in 2010 to earn into the CBM leasehold interests. Permitting for such a pilot is ongoing. In addition, Huber has the option to further develop the deeper Floyd and/or Chattanooga shale-gas plays to earn additional interest in the acreage. Potential earning activities include completing the Floyd formation from Resolute’s existing vertical well, or drilling, completing, and testing the Chattanooga formation in a
horizontal lateral from Resolute’s existing vertical well, or drilling, completing, and testing the Chattanooga formation from a new well.
Big Horn Basin Properties. Resolute has 82,133 gross (70,811 net) acres in the Big Horn Basin. In 2006, Predecessor Resolute entered into an area of mutual interest agreement with Fidelity covering certain acreage in the southeast portion of the basin, under which approximately 22,644 gross acres were jointly acquired on a 50-50 basis. That agreement has expired, but the acreage remains subject to a joint operating agreement for its remaining term. In addition, both Resolute and Fidelity independently control additional leaseholds in the immediate area. The emerging Mowry shale oil resource play is the primary reservoir target and the Frontier and Phosphoria are secondary reservoir targets. A well to test the Mowry is tentatively planned for 2011.
Williston Basin Properties. In March 2010, Resolute acquired a 45% working interest in approximately 61,000 gross (42,000 net) leasehold acres in Williams County, North Dakota. This undeveloped leasehold is located within the Bakken shale trend of the Williston Basin. Although the Middle Bakken formation will be the primary objective, secondary objectives include the Three Forks, Madison and Red River formations. For 2010, Resolute has allocated approximately $25 million for acreage acquisition, drilling and completion activities in this area and expects to participate in drilling at least three horizontal wells.
Estimated Net Proved Reserves
Reserve estimates as of December 31, 2009, were prepared by Resolute and audited by NSAI, Resolute’s independent petroleum engineers. Please read “Risk Factors - Risks Related to Resolute’s Business, Operations and Industry” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute” in evaluating the material presented below.
Resolute’s reserve report was prepared under the direct supervision of Resolute’s Reservoir Engineering Manager, who is a qualified reserve estimator and auditor. The report was 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. The reserve estimates were reviewed internally by senior management. An audit of the reserve estimates was performed by NSAI.
The professional qualifications of Resolute’s Reservoir Engineering Manager meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines, 1982; registered professional engineer with the State of Colorado since 1987; member of Society of Petroleum Engineers since 1980; more than 27 years of practical petroleum engineering experience; more than 27 years of practical experience in estimating and evaluating reserves information with at least five of these years being in charge of estimating and evaluating reserves.
The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader in petroleum property analysis for industry, financial organizations and government agencies. NSAI was founded in 1961 and is registered to perform consulting petroleum engineering services by the Texas Board of Professional Engineers Registration. Within NSAI, the technical person primarily responsible for the NSAI audit is David Miller. Mr. Miller has been practicing consulting petroleum engineering at NSAI since 1997. He is a Registered Professional Engineer in the State of Texas and has more than 28 years of practical experience in petroleum engineering, with more than 12 years experience in the estimation and evaluation of reserves. He graduated from the University of Kentucky in 1981 with a Bachelor of Science degree in Civil Engineering and from Southern Methodist University in 1994 with a Master of Business Administration degree. Mr. Miller meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
A report of NSAI regarding its audit of the estimates of proved reserves at December 31, 2009, has been filed as Exhibit 99.1 to this report and is incorporated herein,
The following table presents Resolute’s estimated net proved oil, gas and NGL reserves and the present value of its estimated net proved reserves as of December 31, 2009, all according to standards set by the Securities and Exchange Commission (“SEC”). The standardized measure shown in the table below is not intended to represent the current market value of Resolute’s estimated oil and gas reserves. Resolute’s estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC.
1)
In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, Resolute’s estimated net proved reserves and standardized measure at December 31, 2009, were determined utilizing prices equal to the twelve-month unweighted arithmetic average of first day of the month prices, resulting in an average NYMEX oil price of $61.18 per Bbl of oil and an average Henry Hub spot market gas price of $3.87 per MMBtu, such prices deemed to be “current” by the SEC and FASB.
2)
Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC and FASB, less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Calculation of standardized measure does not give effect to derivatives transactions. For a description of Resolute’s derivatives transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute - Quantitative and Qualitative Disclosures About Market Risk.”
3)
PV-10 is a non-GAAP measure and incorporates all elements of the standardized measure, but excludes the effect of income taxes. 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.
Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled within five years to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.
The data in the above table represent estimates only. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological
interpretation and judgment. Accordingly, reserves estimates may vary, perhaps significantly, from the quantities of oil and gas that are ultimately recovered. Please read “Risk Factors - Risks Related to Resolute’s Business, Operations and Industry.”
Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by SEC and FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Therefore, without reserve additions in excess of production through successful exploitation and development activities or acquisitions, Resolute’s reserves and production will ultimately decline over time. Please read “Risk Factors - Risks Related to Resolute’s Business, Operations and Industry” and “Note 15 - Supplemental Oil and Gas Information (unaudited)” to the audited consolidated financial statements of Resolute for a discussion of the risks inherent in oil and gas estimates and for certain additional information concerning Resolute’s estimated proved reserves.
At December 31, 2009, no proved undeveloped reserves have remained undeveloped for more than five years.
Proved reserves reported by Resolute of 64.4 MMBoe at December 31, 2009, represent a 31% increase over the 49.3 MBoe reported by Predecessor Resolute at December 31, 2008. Production (including that of Predecessor Resolute) during 2009 reduced proved reserves by 2.7 MMBoe, while revisions of previous estimates increased proved reserves by 17.8 MMBoe. Commodity pricing was the principal factor leading to the revisions in proved reserves. In accordance with the varying SEC requirements in effect at each year end, the reserves at December 31, 2009, utilized prices of $61.18 per barrel of oil and $3.87 per MMBtu, as compared to prices of $44.60 per barrel of oil and $5.24 per MMBtu of gas at December 31, 2008.
Costs incurred of $23 million (including that incurred by Predecessor Resolute) to develop Resolute’s proved undeveloped reserves in 2009 declined from the $52.3 million incurred by Predecessor Resolute in 2008, primarily due to a lower average cost of CO2 purchased and lower activity levels in response to lower commodity prices in the first half of 2009.
The following table sets forth Resolute’s net proved reserves at December 31, 2009, based on alternative price scenarios as identified below in the footnotes to the table. The price scenarios illustrate the sensitivity of our estimated reserve quantities under various price and cost assumptions.
1)
Represents reserves utilizing the SEC guidelines which were in effect at December 31, 2009. The SEC Case utilized prices equal to the twelve-month unweighted arithmetic average of first day of the month prices, resulting in an average NYMEX oil price of $61.18 per Bbl of oil and an average Henry Hub spot market gas price of $3.87 per MMBtu of gas.
2)
Represents reserves utilizing the SEC guidelines which were in effect at December 31, 2008. The Flat Case was based on prices in effect at December 31, 2009, which were a NYMEX oil price of $79.36 per Bbl of oil and a Henry Hub spot market gas price of $5.79 per MMBtu of gas.
3)
Represents reserves utilizing future strip prices at December 31, 2009. The Strip Case utilized prices which included NYMEX front-month oil prices of $82.30, $86.13, $87.99, and $89.53 per barrel for each of the years from 2010 through 2013. Prices were held constant thereafter at $91.30 per barrel for 2014 and beyond. Similarly, gas prices used were $5.77, $6.31, $6.48, and $6.62 per MMBtu for the four year period, and $6.80 per MMBtu for 2014 and thereafter. Capital and operating costs were escalated by 3% per year through 2014 and held constant thereafter. Aneth field operating costs were allocated on a per-well and per-barrel cost model rather than the per-well and per-producing unit cost model used in the SEC and Flat cases.
Production and Price History
Set forth in the table below are Resolute and Predecessor Resolute’s operating data for 2009, 2008 and 2007.
Productive Wells
The following table sets forth information as of December 31, 2009, relating to the productive wells in which Resolute owns a working interest. Productive wells consist of producing wells and wells capable of producing, including wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which Resolute has a working interest, and net wells are the sum of Resolute’s fractional working interests owned in gross wells. In addition to the wells set forth below, as of December 31, 2009, Resolute had interests in and operated 334 gross (218 net) active water and CO2 injection wells on the Aneth Field Properties, and 5 gross (3 net) active water injection wells associated with the Wyoming Properties.
Acreage
All of Resolute’s leasehold acreage is categorized as developed or undeveloped. The following table sets forth information as of December 31, 2009, relating to the Company’s leasehold acreage:
Approximately 22,000 net acres of undeveloped acreage expires in 2010 and approximately 2,000 and 1,300 net acres expire in 2011 and 2012, respectively. The majority of the expirations (approximately 19,000 net acres) in 2010 through 2012 relate to acreage in the Black Warrior Basin in Alabama.
1)
Developed acreage is acreage attributable to wells producing oil or gas.
2)
The number of gross acres is the total number of acres in which Resolute owns a working interest and/or unitized interest.
3)
Net acres are calculated as the sum of Resolute’s working interests in gross acres.
4)
The net revenue interest is the percentage of total production to which Resolute is entitled after reductions for burdens on production such as royalties and overriding royalties.
5)
Undeveloped acreage includes leases either within their primary term or held by production.
Drilling Results
Subsequent to the acquisition in September 2009, Resolute did not engage in drilling exploratory or developmental wells. Predecessor Resolute did not engage in drilling in 2009 and 2008, but in 2007 drilled 15 gross (14.6 net) wells.
Relationship with the Navajo Nation
The purchase of Resolute’s Aneth Field Properties was facilitated by Predecessor Resolute’s strategic alliance with NNOG and, through NNOG, the Navajo Nation. The Navajo Nation formed NNOG, a wholly-owned corporate entity, under Section 17 of the Indian Reorganization Act. Resolute supplies NNOG with acquisition, operational and financial expertise and NNOG helps Resolute communicate and interact with the Navajo Nation agencies.
Resolute’s strategic alliance with NNOG is embodied in a Cooperative Agreement that Predecessor Resolute entered into with NNOG in 2004 to facilitate Resolute and NNOG’s joint acquisition of the Chevron Properties. The agreement was amended subsequently to facilitate the joint acquisition of the ExxonMobil Properties. Among other things, this agreement provides that:
•
Resolute and NNOG will cooperate on the acquisition and subsequent development of their respective properties in Aneth Field.
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NNOG will assist Resolute in dealing with the Navajo Nation and its various agencies, and Resolute will assist NNOG in expanding its financial expertise and its operating capabilities. Since Predecessor Resolute and NNOG acquired the Aneth Field Properties, NNOG has helped facilitate interaction between Resolute and the Navajo Nation Minerals Department and other agencies of the Navajo Nation.
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NNOG has a right of first negotiation in the event of a proposed sale or change of control of Resolute or a sale by Resolute of all or substantially all of its Chevron Properties or ExxonMobil Properties. This right is separate from and in addition to the statutory preferential purchase right held by the Navajo Nation.
In addition to the above provisions, Predecessor Resolute granted NNOG three separate but substantially similar purchase options. Each purchase option entitles NNOG to purchase from Resolute up to 10% of the undivided working interests that Resolute acquired from Chevron or ExxonMobil, as applicable, as to each unit in the Aneth Field Properties. Each purchase option entitles NNOG to purchase at fair market value, for a limited
period of time, the applicable portion of the undivided working interest Resolute acquired. The fair market value is to be determined without giving effect to the existence of the Navajo Nation statutory preferential purchase right or the fact that the properties are located on the Navajo Reservation. Each option becomes exercisable based upon Resolute’s achieving payout multiples of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout includes the effect of Resolute’s hedging program. The multiples of payout that trigger the exercisability of the purchase options with respect to each of the Chevron Properties and the ExxonMobil Properties are 100%, 150% and 200%. The options are not exercisable prior to four years from the relevant acquisition except in the case of a sale of such assets by, or a change of control of, Resolute. In that case, the first option for 10% would be accelerated and the other options would terminate.
As of December 31, 2009, the payout balance on the Chevron Properties was approximately $51.6 million and the payout balance on the ExxonMobil Properties was approximately $108.3 million. Assuming the purchase options are not accelerated due to a change of control of Resolute, and assuming Resolute continues to develop its Aneth Field Properties in accordance with its plans, Resolute expects that the initial payout associated with the purchase options would not occur for a number of years.
The following table demonstrates the maximum net undivided working interest in each of the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit that NNOG could acquire from Resolute upon exercising each of its purchase options under the Cooperative Agreement. The exercise by NNOG of its purchase options in full would not give it the right to remove Resolute as operator of any of Resolute’s Aneth Field Properties.
Marketing and Customers
Aneth Field. Resolute currently sells all of its crude from its Aneth Field Properties to a single customer, Western Refining Southwest, Inc. (“Western”), a subsidiary of Western Refining, Inc. under a contract that terminates August 31, 2010. This contract which was effective September 1, 2009, provides for a fixed differential to the NYMEX price for crude oil of $6.25 per Bbl. This contract continues month-to-month after August 31, 2010, with either party having the right to terminate after the initial term, upon ninety days’ notice. The contract may also be terminated by Western after December 30, 2009, upon sixty days notice, if Western is not able to renew its right-of-way agreements with the Navajo Nation or if such rights-of-way are declared invalid and either Western is prevented from using such rights-of way or the Navajo Nation declares Western to be in trespass with respect to such rights-of-way.
Western has two refineries in the Four Corners area, the 16,800 barrel per day Bloomfield refinery in Farmington, New Mexico, and the 26,000 barrel per day Gallup refinery in Gallup, New Mexico. In November 2009 Western announced that it intended to discontinue refining operations at the Bloomfield refinery. Western now refines Resolute’s crude oil at the Gallup refinery. Resolute’s production is transported to the refinery via the Running Horse crude oil pipeline owned by NNOG to a terminal known as Bisti, approximately 20 miles south of Farmington, New Mexico, that serves the refinery. The Resolute and NNOG oil has been jointly marketed to Western. The combined Resolute and NNOG volumes are approximately 7,000 barrels of oil per day.
Resolute’s Aneth Field crude oil is a sweet, light crude oil that is particularly well suited to be refined in Western’s refinery. Although Resolute has sold all of its crude oil production to Western since Predecessor Resolute acquired the Chevron Properties in November 2004, and despite the value of Resolute’s crude oil production to Western, Resolute cannot be certain that the commercial relationship with Western will continue for the indefinite future, and Resolute cannot be certain that the refinery will not suffer significant down-time or be closed. If for any reason Western is unable or unwilling to purchase Resolute’s crude oil production, Resolute has other alternatives for marketing its crude oil production. Resolute has been working with NNOG to establish alternative transportation and markets for Resolute’s crude oil. A joint venture comprised of affiliates of NNOG and Resolute has completed construction of a high volume truck loading facility located at the terminal end of NNOG’s Running Horse Pipeline that will be operative and capable of loading all of Resolute and NNOG’s production. Crude oil can be trucked a relatively short distance from the loading facility to rail loading sites near and south of Gallup, New Mexico, or longer distances to refineries or oil pipelines in southern New Mexico and west Texas. Resolute can also transport its crude oil by various combinations of truck, pipeline and rail from its Aneth Field Properties to markets north in Utah, Colorado and Wyoming. The cost of selling Resolute’s crude oil to alternative markets in the short term would result in a greater differential to the NYMEX price for crude oil than Resolute currently receives. If Resolute chooses or is forced to sell to these alternative markets for a longer period of time, these costs could be lowered significantly. Under long term arrangements, which may require the investment of capital, Resolute believes it would realize a NYMEX differential substantially equivalent to the current differential realized in the price received from Western.
Resolute’s gas production is minimally processed in the field and then sent via pipeline to the San Juan River Gas Plant for further processing. Resolute sells its gas at daily market prices to numerous purchasers at the tailgate of the plant, and it receives a contractually specified percentage of the proceeds from the sale of NGL and plant products.
Wyoming. Resolute sells the majority of its crude oil in Wyoming to TEPPCO Crude Oil, LLC and minor amounts to other purchasers in a competitive market. The price it receives relative to the NYMEX price varies depending on supply and demand differentials in the relevant geographic areas in which Resolute’s wells are located and the quality of Resolute’s crude oil. Resolute’s conventional gas in Wyoming comes from Hilight Field and is sold to the Anadarko Petroleum Corporation Fort Union Gas Plant. Resolute receives a percentage of proceeds for the liquids sold by the plant, and Resolute can either take its residue gas in kind or market it through Anadarko. Currently, Resolute is selling its gas through Anadarko. Resolute’s CBM gas also comes from the Hilight areas and is minimally conditioned at the Fort Union Gas Plant and is sold through Anadarko. Resolute receives the Colorado Interstate Gas Company index price for all the gas it sells.
Hedging. Resolute enters into hedging transactions from time to time with unaffiliated third parties for portions of its crude oil and gas production to achieve more predictable cash flows and to reduce exposure to short-term fluctuations in oil and gas prices. For more a detailed discussion, please read “Pursue Acquisitions of Properties with Low-Risk Development Potential, Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute - Overview” and “- Quantitative and Qualitative Disclosures About Market Risk.”
Other Factors. The market for Resolute’s production depends on factors beyond its control, including domestic and foreign political conditions, the overall level of supply of and demand for oil and gas, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of transportation facilities and overall economic conditions. The oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Aneth Gas Processing Plant
Resolute has an interest in gas gathering and compression facilities located within and adjacent to its Aneth Field Properties. Collectively called the Aneth Gas Processing Plant, the facility comprises: a) an active gas compression operation currently operated by Resolute and b) a larger complex of inactive, decommissioned and partially dismantled gas processing plant facilities for which Chevron remains the operator of record. In 2006, Chevron began the process of demolishing the inactive portions of the Aneth Gas Processing Plant. It continues to manage the project, and it retains a 39% interest in all demolition and environmental clean-up expenses. Resolute acquired ExxonMobil’s 25% interest in the decommissioned plant and is responsible for that portion of
decommissioning and cleanup costs. Activities performed to date include removal of asbestos-containing building and insulation materials, partial dismantling of inactive gas plant buildings and facilities, and limited remediation of hydrocarbon-affected soil.
As of December 31, 2009, Resolute estimates the total cost to fully decommission the inactive portion of the Aneth Gas Processing Plant site to be $28.0 million, of which approximately $17.1 million had already been incurred and paid for. The remaining demolition liability net to Resolute’s interest is $1.4 million (on a GAAP basis that includes an inflation factor and a discount rate). Demolition activities are scheduled to be concluded in 2012. These costs do not include any costs for clean-up or remediation of the subsurface. The Aneth Gas Processing Plant site was previously evaluated by the Environmental Protection Agency (“EPA”) for possible listing on the National Priorities List (“NPL”), of sites contaminated with hazardous substances with the highest priority for clean-up under the Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”). Based on its investigation, the EPA concluded no further investigation was warranted and that the site was not required to be listed on the NPL. The Navajo Environmental Protection Agency now has primary jurisdiction over the Aneth Gas Processing Plant site. Resolute cannot predict whether it will require further investigation and possible clean-up, and the ultimate clean-up liability may be affected by the Navajo Nation’s recent enactment of a Navajo CERCLA. The Navajo CERCLA, in some cases, imposes broader obligations and liabilities than the federal CERCLA. Resolute has been advised by Chevron that a significant portion of the subsurface clean-up or remediation costs, if any, would be covered by an indemnity from the prior owner of the plant, and Chevron has provided Resolute with a copy of the pertinent purchase agreement that appears to support its position. Resolute cannot predict, however, whether any subsurface remediation will be required or what the cost of this clean-up or remediation could be. Additionally, it cannot be certain whether any of such costs will be reimbursable to it pursuant to the indemnity of the prior owner. Please read also “- Environmental, Health and Safety Matters and Regulation - Waste Handling.”
Title to Properties
In connection with Predecessor Resolute’s acquisition of the Chevron Properties and the ExxonMobil Properties, it obtained attorneys’ title opinions showing good and defensible title in the seller to at least 80% of the proved reserves of the acquired properties as shown in the relevant reserve reports presented by the sellers. Predecessor Resolute also reviewed land files and public and private records on substantially all of the acquired properties containing proved reserves. It performed similar title and land file reviews prior to acquiring the Wyoming Properties; however, the prior title opinions available for it to review and update constituted 62% of the proved reserves of the acquired properties and only the public records for these properties were reviewed. Resolute believes it has satisfactory title to all of its material proved properties in accordance with standards generally accepted in the industry. Prior to completing an acquisition of proved hydrocarbon leases in the future, it intends to perform title reviews on the most significant leases, and, depending on the materiality of properties, it may obtain a new title opinion or review previously obtained title opinions.
The Aneth Field Properties are subject to a statutory preferential purchase right for the benefit of the Navajo Nation to purchase at the offered price any Navajo Nation oil and gas lease or working interest in such a lease at the time a proposal is made to transfer the lease or interest. This could make it more difficult to sell Resolute’s oil and gas leases and, therefore, could reduce the value of the Aneth Field leases if it were to attempt to sell them.
Resolute’s properties are also subject to certain other encumbrances, 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 for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and gas industry. It believes that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from its interest in these properties or will materially interfere with the intended operation of its business.
Competition
Competition is intense in all areas of the oil and gas industry. Major and independent oil and gas companies actively bid for desirable properties, as well as for the equipment and labor required to operate and develop such properties. Many of Resolute’s competitors have financial and personnel resources that are substantially greater
than its own, and such companies may be able to pay more for productive properties and to define, evaluate, bid for and purchase a greater number of properties than Resolute’s financial or human resources permit. Resolute’s ability to acquire additional properties and to discover reserves in the future will depend on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Seasonality
Resolute’s operations have not historically been subject to seasonality in any material respect.
Environmental, Health and Safety Matters and Regulation
General. Resolute is subject to various stringent and complex federal, tribal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment, and protection of human health and safety. These laws and regulations may, among other things:
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require the acquisition of various permits before drilling commences or other operations are undertaken;
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require the installation of expensive pollution control equipment;
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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production, transportation and processing activities;
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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas;
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require remedial measures to mitigate pollution from historical and ongoing operations, such as the closure of pits and plugging of abandoned wells and remediation of releases of crude oil or other substances; and
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require preparation of an Environmental Assessment and/or an Environmental Impact Statement.
These laws and regulations may also restrict the rate of oil and gas production to a level below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.
Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunctive action, as well as administrative, civil and criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on Resolute’s business, financial condition and results of operations.
Resolute believes its operations are in substantial compliance with all existing environmental, health and safety laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its financial condition and results of operations. Spills or releases may occur, however, in the course of its operations. There can be no assurance that Resolute will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property, persons and the environment, nor can there be any assurance that the passage of more stringent laws or regulations in the future will not have a negative effect on Resolute’s business, financial condition, or results of operations.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which oil and gas business operations are generally subject and with which compliance may have a material adverse effect on Resolute’s capital expenditures, earnings or competitive position, as well as a discussion of certain matters that specifically affect its operations.
Comprehensive Environmental Response, Compensation, and Liability Act. CERCLA, also known as the “Superfund law,” and comparable tribal and state laws may impose strict, joint and several liability, without regard to fault, on classes of persons who are considered to be responsible for the release of CERCLA hazardous substances into the environment. These persons include the owner or operator of the site where a release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for
the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Such claims may be filed under CERCLA, as well as state common law theories or state laws that are modeled after CERCLA. In the course of its operations, Resolute generates waste that may fall within the definition of hazardous substances under CERCLA, as well as under the recently adopted Navajo Nation CERCLA which, unlike the federal CERCLA, defines hazardous substances to include crude oil and other hydrocarbons, thereby subjecting Resolute to potential liability under CERCLA, tribal and state law equivalents to CERCLA and common law. Therefore, governmental agencies or third parties could seek to hold Resolute responsible for all or part of the costs to clean up a site at which such hazardous substances may have been released or deposited, or other damages resulting from a release.
Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable tribal and state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and many of the other wastes associated with the exploration, development and production of crude oil or gas are currently exempt under federal law from regulation as hazardous wastes and instead are regulated under RCRA’s non-hazardous waste provisions. It is possible, however, that oil and gas exploration and production wastes now classified federally as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in Resolute’s operating expenses, which could have a material adverse effect on the results of operations and financial position. Also, in the course of operations, Resolute generates some amounts of industrial solid wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes under RCRA, tribal and state laws and regulations.
Resolute has an interest in the Aneth Gas Processing Plant located in the Aneth Unit. This gas plant consists of a non-operational portion of the plant that is in the process of being decommissioned and removed by Chevron and an operational portion dedicated to compression. Resolute is responsible for a portion of the costs of decommissioning and removal and clean-up of the non-operational portion of the plant and any restoration and other costs related to the operational processing facilities. For additional information related to Resolute’s obligations related to this plant, please read “- Aneth Gas Processing Plant.”
Air Emissions. The federal Clean Air Act and comparable tribal and state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. These regulatory programs may require Resolute to install expensive emissions control equipment, modify its operational practices and obtain permits for existing operations, and before commencing construction on a new or modified source of air emissions such laws may require Resolute to reduce its emissions at existing facilities. As a result, Resolute may be required to incur increased capital and operating costs. Federal, tribal and state regulatory agencies can impose administrative, civil and criminal penalties for non- compliance with air permits or other requirements of the federal Clean Air Act and associated tribal and state laws and regulations.
In June 2005, the EPA and ExxonMobil entered into a consent decree settling various alleged violations of the federal Clean Air Act associated with ExxonMobil’s prior operation of the McElmo Creek Unit. In response, ExxonMobil submitted amended Title V and Prevention of Significant Deterioration (“PSD”) permit applications for the McElmo Creek Unit main flare and other sources, and also paid a civil penalty and costs associated with a Supplemental Environmental Project, or “SEP.” Pursuant to the consent decree, upgrades to the main flare were completed in May 2006 by ExxonMobil, and all of the remaining material compliance measures of the consent decree have been met by Resolute. The EPA is processing the Title V and PSD permit applications. Resolute remains subject to the consent decree, including stipulated penalties for violations of emissions limits and compliance measures set forth in the consent decree.
Actual air emissions reported for these facilities are in material compliance with emission limits contained in the draft permits and the consent decree when emissions associated with qualified equipment malfunctions are taken into account.
Water Discharges. The federal Water Pollution Control Act, or the Clean Water Act, and analogous tribal and state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and
leaks of oil and other substances, into waters of the United States, including wetlands. The discharge of pollutants into regulated waters is prohibited by the Clean Water Act, except in accordance with the terms of a permit issued by the EPA or an authorized tribal or state agency. Federal, tribal and state regulatory agencies can impose administrative, civil and criminal penalties for unauthorized discharges or non- compliance with discharge permits or other requirements of the Clean Water Act and analogous tribal and state laws and regulations.
In addition, the Oil Pollution Act of 1990, or OPA, augments the Clean Water Act and imposes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, operators of oil and gas facilities must develop, implement, and maintain facility response plans, conduct annual spill training for employees and provide varying degrees of financial assurance to cover costs that could be incurred in responding to oil spills. In addition, owners and operators of oil and gas facilities may be subject to liability for cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.
In August 2004, the EPA and ExxonMobil entered into a consent decree settling alleged violations of the federal Clean Water Act related to past spills of produced water and crude oil from the McElmo Creek and Ratherford Units and failure to prepare and implement Spill Prevention, Control and Countermeasure Plans. ExxonMobil paid a civil penalty and costs to implement a SEP, and made improvements to the production and injection systems. Resolute expects the consent decree to be terminated during 2010 following confirmation by the EPA of completion of the SEP. Until the consent decree is terminated by the EPA, Resolute remains subject to various monitoring, recordkeeping, and reporting requirements outlined in the consent decree, as well as stipulated penalties for spills of produced water and crude oil at the McElmo Creek and Ratherford Units.
In November 2001, the EPA issued an administrative order to ExxonMobil for removal and remediation of crude oil released as a result of a shallow casing leak at the McElmo Creek P-20 well in January 2001. In response, ExxonMobil performed various site assessment activities and began recovering crude oil from the ground water. Resolute is obligated to complete the ground water monitoring and remedial activities required under the administrative order, at an estimated cost of approximately $100,000 per year, with anticipated closure to occur in the fourth quarter of 2010 or early 2011.
Underground Injection Control. Resolute’s underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous tribal and state laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for tribal and state programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Federal, tribal and state regulations require Resolute to obtain a permit from applicable regulatory agencies to operate its underground injection wells. Resolute believes it has obtained the necessary permits from these agencies for its underground injection wells and that it is in substantial compliance with permit conditions and applicable federal, tribal and state rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of the underground injection wells is likely to result in pollution of freshwater, the substantial violation of permit conditions or applicable rules, or leaks to the environment. Although Resolute monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries.
Pipeline Integrity, Safety, and Maintenance. Resolute’s ownership interest in the McElmo Creek Pipeline has caused it to be subject to regulation by the federal Department of Transportation, or the DOT, under the Hazardous Liquid Pipeline Safety Act and comparable state statutes, which relate to the design, installation, testing, construction, operation, replacement and management of hazardous liquid pipeline facilities. Any entity that owns or operates such pipeline facilities must comply with such regulations, permit access to and copying of records, and file reports and provide required information. The DOT may assess fines and penalties for violations of these and other requirements imposed by its regulations. Resolute believes it is in material compliance with all
regulations imposed by the DOT pursuant to the Hazardous Liquid Pipeline Safety Act. Pursuant to the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, the DOT was required to issue new regulations by December 31, 2007, setting forth specific integrity management program requirements applicable to low stress hazardous liquid pipelines. Resolute believes that these new regulations, which have yet to be issued, will not have a material adverse effect on its financial condition or results of operations.
Environmental Impact Assessments. Significant federal decisions, such as the issuance of federal permits or authorizations for many oil and gas exploration and production activities are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of Resolute’s current exploration and production activities, as well as proposed exploration and development plans on federal lands, require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay any oil and gas development projects.
Other Laws and Regulations
Climate Change. Recent scientific studies have suggested that emissions of gases commonly referred to as “greenhouse gases” or “GHG”, including CO2, nitrogen dioxide and methane, may be contributing to warming of the Earth’s atmosphere. Other nations have already agreed to regulate emissions of GHG pursuant to the United Nations Framework Convention on Climate Change, (“UNFCCC”) and the Kyoto Protocol, an international treaty (not including the United States) pursuant to which many UNFCCC member countries have agreed to reduce their emissions of GHG to below 1990 levels by 2012. In response to such studies and international action, the U.S. Congress is now considering legislation to reduce emissions of GHG, and the EPA has promulgated a mandatory GHG reporting rule that took effect January 1, 2010. As finalized, the mandatory reporting rule (MRR) does not require reporting by Resolute for its operations in Aneth Field. However, on March 23, 2010, EPA proposed several amendments to the MRR that would trigger reporting requirements for the Company. Among the proposed amendments are provisions that would apply to operators that inject CO2 for enhanced oil recovery and geologic sequestration, regardless of the magnitude of associated CO2 emissions, and also to operators of oil and natural gas systems that emit more than 25,000 metric tons of CO2-equivalent GHGs across an entire producing basin, based on the aggregated GHG emissions of all facilities in a basin under common control of an operator. On June 26, 2009, the House of Representatives passed H.R. 2454, the Waxman-Markey “American Clean Energy and Security Act of 2009,” which would require 17% reduction in GHG emission by “covered entities” by 2020, relative to 2005 GHG emission levels, and create an elaborate system of allocated and tradable emission allowances and offsets to achieve mandated reductions of up to 80% by the year 2050. Companion legislation is being considered in the Senate, and a consensus bill could be developed later in 2010. Prior to this legislative action on climate change by the U.S. Congress, a number of states chose not to wait for Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or regional cap and trade programs. For example, on August 22, 2007, the Western Climate Initiative, which is comprised of a number of Western states and Canadian provinces, including the State of Utah, issued a GHG reduction goal statement seeking to collectively reduce regional GHG emissions to 15% below 2005 levels by 2020. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA may be required to regulate GHG emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of GHG. The Court’s holding in Massachusetts v. EPA that GHG fall under the federal Clean Air Act’s definition of “air pollutant” also may result in future regulation of GHG emissions from stationary sources under Clean Air Act programs, due to EPA’s recent “endangerment finding” that links global warming to man-caused emissions of GHGs and concludes there is an endangerment to public health and the environment that requires regulatory action. The passage or adoption of new legislation or regulations that restrict emissions of GHG or require reporting of such emissions in areas where Resolute conducts business could adversely affect its operations.
Department of Homeland Security. The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (“DHS”), to issue regulations establishing risk-based performance standards for the security at chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS is in the process of adopting regulations that will determine whether some of Resolute’s facilities or operations will be subject to additional DHS-mandated security requirements. Presently, it is not possible to accurately estimate the costs Resolute could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Occupational Safety and Health Act. Resolute is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes that strictly govern protection of the health and safety of workers. The Occupational Safety and Health Administration’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act, and similar state statutes require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and the public. Resolute believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Laws and Regulations Pertaining to Oil and Gas Operations on Navajo Nation Lands
General. Laws and regulations pertaining to oil and gas operations on Navajo Nation lands derive from both Navajo law and federal law, including federal statutes, regulations and court decisions, generally referred to as federal Indian law.
The Federal Trust Responsibility. The federal government has a general trust responsibility to Indian tribes regarding lands and resources that are held in trust for such tribes. The trust responsibility may be a consideration in courts’ resolution of disputes regarding Indian trust lands and development of oil and gas resources on Indian reservations. Courts may consider the compliance of the Secretary of the U.S. Department of the Interior, or the Interior Secretary, with trust duties in determining whether leases, rights-of-way, or contracts relative to tribal land are valid and enforceable.
Tribal Sovereignty and Dependent Status. The United States Constitution vests in Congress the power to regulate the affairs of Indian tribes. Indian tribes hold a sovereign status that allows them to manage their internal affairs, subject to the ultimate legislative power of Congress. Tribes are therefore often described as domestic dependent nations, retaining all attributes of sovereignty that have not been taken away by Congress. Retained sovereignty includes the authority and power to enact laws and safeguard the health and welfare of the tribe and its members and the ability to regulate commerce on the reservation. In many instances, tribes have the inherent power to levy taxes and have been delegated authority by the United States to administer certain federal health, welfare and environmental programs.
Because of their sovereign status, Indian tribes also enjoy sovereign immunity from suit and may not be sued in their own courts or in any other court absent Congressional abrogation or a valid tribal waiver of such immunity. The United States Supreme Court has ruled that for an Indian tribe to waive its sovereign immunity from suit, such waiver must be clear, explicit and unambiguous.
NNOG is a federally chartered corporation incorporated under Section 17 of the Indian Reorganization Act and is wholly owned by the Navajo Nation. Section 17 corporations generally have broad powers to sue and be sued. Courts will review and construe the charter of a Section 17 corporation to determine whether the tribe has either universally waived the corporation’s sovereign immunity, or has delegated that power to the Section 17 corporation.
The NNOG federal charter of incorporation provides that NNOG shares in the immunities of the Navajo Nation, but empowers NNOG to waive such immunities in accordance with processes identified in the charter. NNOG has contractually waived its sovereign immunity, and certain other immunities and rights it may have regarding disputes with Resolute relating to certain of the Aneth Field Properties, in the manner specified in its charter. Although the NNOG waivers are similar to waivers that courts have upheld, if challenged, only a court of competent jurisdiction may make that determination based on the facts and circumstances of a case in controversy.
Tribal sovereignty also means that in some cases a tribal court is the only court that has jurisdiction to adjudicate a dispute involving a tribe, tribal lands or resources or business conducted on tribal lands or with tribes. Although language similar to that used in Resolute’s agreements with NNOG that provide for alternative dispute resolution and federal or state court jurisdiction has been upheld in other cases, there is no guarantee that a court would enforce these dispute resolution provisions in a future case.
Federal Approvals of Certain Transactions Regarding Tribal Lands. Under current federal law, the Interior Secretary (or the Interior Secretary’s appropriate designee) must approve any contract with an Indian tribe that encumbers, or could encumber, for a period of seven years or more, (1) lands owned in trust by the United States for the benefit of an Indian tribe or (2) tribal lands that are subject to a federal restriction against alienation, or collectively Tribal Lands. Failure to obtain such approval, when required, renders the contract void.
Except for Resolute’s oil and gas leases, rights-of-way and operating agreements with the Navajo Nation, Resolute’s agreements do not by their terms specifically encumber Tribal Lands, and it believes that no Interior Secretarial approval was required to enter into those agreements. With respect to its oil and gas leases and unit operating agreements, these and all assignments to Resolute have been approved by the Interior Secretary. In the case of rights-of-way and assignments of these to Resolute, some of these have been approved by the Interior Secretary and others are in various stages of applications for renewal and approval. It is common for these approvals to take an extended period of time, but such approvals are routine and Resolute believes that all required approvals will be obtained in due course.
Federal Management and Oversight. Reflecting the federal trust relationship with tribes, the Bureau of Indian Affairs, or the BIA, exercises oversight of matters on the Navajo Nation reservation pertaining to health, welfare and trust assets of the Navajo Nation. Of relevance to Resolute, the BIA must approve all leases, rights-of-way, applications for permits to drill, seismic permits, CO2 pipeline permits and other permits and agreements relating to development of oil and gas resources held in trust for the Navajo Nation. While NNOG has been successful in facilitating timely approvals from the BIA, such timeliness is not guaranteed and obtaining such approvals may cause delays in developing the Aneth Field Properties.
Resources Committee of the Navajo Nation Council. The Resources Committee is a standing committee of the Navajo Nation Tribal Council, and has oversight and regulatory authority over all lands and resources of the Navajo Nation. The Resources Committee reviews, negotiates and recommends to the Navajo Nation Tribal Council actions involving the approval of energy development agreements and mineral agreements; gives final approvals of rights of way, surface easements, geophysical permits, geological prospecting permits, and other surface rights for infrastructure; oversees and regulates all activities within the Navajo Nation involving natural resources and surface disturbance; sets policy for natural resource development and oversees the enforcement of federal and Navajo law in the development and utilization of resources, including issuing cease and desist orders and assessing fines for violation of its regulations and orders. The Resources Committee also has oversight authority over, among other agencies and matters, the Navajo Nation Environmental Protection Agency and Navajo Nation environmental laws, the Navajo Nation Minerals Department and Navajo Nation oil and gas laws and the Navajo Nation Land Department and Navajo Nation land use laws. While NNOG has been successful thus far in facilitating timely approvals from the Resources Committee for Resolute’s operations, such timeliness is not guaranteed and obtaining future approvals may cause delays in developing the Aneth Field Properties.
Navajo Nation Minerals Department of the Division of Natural Resources. The day-to-day operation of the Navajo Nation minerals program, including the initial negotiation of agreements, applications for approval of assignments, exercise of tribal preferential rights and most other permits and licenses relating to oil and gas development, is managed by the professional staff of the Navajo Nation Minerals Department, located within the Division of Natural Resources and subject to the oversight of the Resources Committee. The Resources Committee and the Navajo Nation Council typically defer to the Minerals Department in decisions to approve all leases and other agreements relating to oil and gas resources held in trust for the Navajo Nation. While NNOG has been successful thus far in facilitating timely action and favorable recommendations from the Minerals Department for Resolute’s operations, such timeliness is not guaranteed and obtaining future approvals may cause delays in developing the Aneth Field Properties.
Taxation Within the Navajo Nation. In certain instances, federal, state and tribal taxes may be applicable to the same event or transaction, such as severance taxes. State taxes are rarely applicable within the Navajo Nation Reservation except as authorized by Congress or when the application of such taxes does not adversely affect the interests of the Navajo Nation. Federal taxes of general application are applicable within the Navajo Nation, unless specifically exempted by federal law. Resolute currently pays the following taxes to the Navajo Nation:
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Oil and Gas Severance Tax. Resolute pays severance tax to the Navajo Nation. The severance tax is payable monthly and is 4% of its gross proceeds from the sale of oil and gas. Approximately 84% of the Aneth Unit is subject to the Navajo Nation severance tax. The other 16% of the Aneth Unit is exempt because it is either located off of the reservation or it is incremental enhanced oil recovery production, which is not subject to the severance tax. Presently all of the McElmo Creek and Ratherford Units are subject to the severance tax.
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Possessory Interest Tax. Resolute pays a possessory interest tax to the Navajo Nation. The possessory interest tax applies to all property rights under a lease within the Navajo Nation boundaries, including natural resources.
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Sales Tax. Resolute pays the Navajo Nation a 4% sales tax in lieu of the Navajo Business Activity Tax. All goods and services purchased for use on the Navajo Nation reservation are subject to the sales tax. The sale of oil and gas is exempt from the sales tax.
Royalties from Production on Navajo Nation Lands. Under Resolute’s agreements and leases with the Navajo Nation, it pays royalties to the Navajo Nation. The Navajo Nation is entitled to take its royalties in kind, which it currently does for its oil royalties but not its gas royalties. The Minerals Management Service of the United States Department of the Interior has the responsibility for managing and overseeing royalty payments to the Navajo Nation as well as the right to audit royalty payments.
Navajo Preference in Employment Act. The Navajo Nation has enacted the Navajo Preference in Employment Act, or the Employment Act, requiring preferential hiring of Navajos by non-governmental employers operating within the boundaries of the Navajo Nation. The Employment Act requires that any Navajo candidate meeting job description requirements receives a preference in hiring. The Employment Act also provides that Navajo employees can only be terminated, penalized, or disciplined for “just cause,” requires a written affirmative action plan that must be filed with the Navajo Nation, establishes the Navajo Labor Commission as a forum to resolve employment disputes and provides authority for the Navajo Labor Commission to establish wage rates on construction projects. The restrictions imposed by the Employment Act and its recent broad interpretations by the Navajo Supreme Court may limit Resolute’s pool of qualified candidates for employment.
Navajo Business Opportunity Act. Navajo Nation law requires companies doing business in the Navajo Nation to provide preference priorities to certified Navajo-owned businesses by giving them a first opportunity and contracting preference for all contracts within the Navajo Nation. While this law does not apply to the granting of mineral leases, subleases, permits, licenses and transactions governed by other applicable Navajo and federal law, Resolute treats this law as applicable to its material non-mineral contracts and procurement relating to its general business activities within the Navajo Nation.
Navajo Environmental Laws. The Navajo Nation has enacted various environmental laws that may be applicable to Resolute’s Aneth Field Properties. As a practical matter, these laws are patterned after similar federal laws, and the EPA currently enforces these laws in conjunction with the Navajo EPA. The current practice does not preclude the Navajo Nation from taking a more active role in enforcement or from changing direction in the future. Some of the Navajo Nation environmental laws not only provide for civil, criminal and administrative penalties, but also provide for third-party suits brought by Navajo Nation tribal members directly against an alleged violator, with specified jurisdiction in the Navajo Nation District Court in Window Rock. A recent example of this relates to the March 2008 adoption by the Navajo Nation of the Navajo Comprehensive Environmental Response, Compensation, and Liability Act (“Navajo CERCLA”), which gives the Navajo EPA broad authority over environmental assessment and remediation of facilities contaminated with hazardous substances. Navajo CERCLA is patterned after federal CERCLA with the important exception that, unlike federal CERCLA, Navajo CERCLA considers crude oil and other hydrocarbons to be hazardous substances subject to CERCLA response actions and damages. Navajo CERCLA also imposes a tariff on the transportation of hazardous substances,
including petroleum and petroleum products, across Navajo lands. Resolute is negotiating with representatives of the Navajo Nation Council, Navajo Department of Justice, Navajo Environmental Protection Agency, NNOG, an industry group headed by the New Mexico Oil and Gas Association and Colorado Oil and Gas Association, (“the NMOGA Group”), and others, to mitigate Navajo CERCLA’s potential impact on oilfield operations on Navajo lands. The NMOGA Group in particular has challenged the validity of the law and has entered into a tolling agreement with Navajo EPA that should forestall material implementation of Navajo CERCLA at oil and gas facilities while appropriate rules and guidelines are developed with input from the oil and gas sector. The tolling agreement was renewed in August 2009, and negotiations among Navajo EPA, Resolute and the NMOGA Group remain ongoing.
Thirty-Two Point Agreement. An explosion at an ExxonMobil facility in Aneth Field in December 1997 prompted protests by local tribal members. The protesters asserted concerns about environmental degradation, health problems, employment opportunities and renegotiating leases. The protest was settled among the local residents, ExxonMobil and the Navajo Nation by the Thirty-Two Point Agreement that provided, among other things, for ExxonMobil to pay partial salaries for two Navajo public liaison specialists, follow Navajo hiring practices, and settle further issues addressed in the Thirty-Two Point Agreement in the Navajo Nation’s “peacemaker” courts, which follow a community-level conflict resolution format. After the Thirty-Two Point Agreement was executed, Aneth Field resumed normal operations. While Resolute did not assume the obligations of ExxonMobil under the Thirty-Two Point Agreement when it acquired the ExxonMobil Properties in 2006, it has been its policy to voluntarily comply with this agreement.
Moratorium on Future Oil and Gas Development Agreements and Exploration. In February 1994, the Navajo Nation issued a moratorium on future oil and gas development agreements and exploration on lands situated within the Aneth Chapter on the Navajo Reservation. All of the Aneth Unit and a significant portion of the McElmo Creek Unit are located within the Aneth Chapter. The Navajo Nation has recently taken the position that the term of the moratorium is indefinite. Given that Resolute’s operations within the Aneth Chapter are based on existing agreements and that Resolute currently does not contemplate new exploration in this mature field, the moratorium has had and is expected to continue to have minor impact to Resolute operations.
Other Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state and Native American tribes, are authorized by statute to issue rules and regulations binding on the oil and gas industry and individual companies, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases Resolute’s cost of doing business and, consequently, affects profitability, these burdens generally do not affect Resolute any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Drilling and Production. Resolute’s operations are subject to various types of regulation at federal, state, local and Navajo Nation levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities, the Navajo Nation and other Native American tribes also regulate one or more of the following:
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the location of wells;
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the method of drilling and casing wells;
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the rates of production or “allowables”;
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the surface use and restoration of properties upon which wells are drilled;
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the plugging and abandoning of wells; and
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notice to surface owners and other third-parties.
On state, federal and Indian lands, the Bureau of Land Management laws and regulations regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third-parties and may reduce Resolute’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit or limit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas that Resolute can produce from its wells or limit the number of wells or the locations where it can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and gas within its jurisdiction.
Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of gas and the manner in which Resolute’s production is marketed. Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce by gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic gas sold in “first sales,” which include all of Resolute sales of its own production.
FERC also regulates interstate gas transportation rates and service conditions, which affects the marketing of gas that Resolute produces, as well as the revenue Resolute receives for sales of its gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the gas industry historically has been very heavily regulated; therefore, Resolute cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can it determine what effect, if any, future regulatory changes might have on gas related activities.
Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on-shore and instate waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase Resolute’s costs of getting gas to point-of-sale locations.
Employees
As of December 31, 2009, Resolute had 132 full-time employees and 3 part-time employees, including 26 geologists, geophysicists, petroleum engineers and land and regulatory professionals. Approximately 40 of Resolute’s field level employees are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, or USW labor union, and are covered by a collective bargaining agreement. Resolute believes that it has a satisfactory relationship with its employees.
Offices
Resolute currently leases approximately 22,725 square feet of office space in Denver, Colorado at 1675 Broadway, Suite 1950, Denver, Colorado 80202, where its principal offices are located. In February 2010, Resolute entered into an amended lease agreement which increased the office space to 28,800 square feet and extended the lease term through July 2013. In addition, Resolute owns and maintains field offices in Cortez, Colorado and Montezuma Creek, Utah, and leases other, less significant, office space in locations where staff are located. Resolute believes that its office facilities are adequate for its current needs and that additional office space can be obtained if necessary.
Available Information
The Company maintains a link to investor relations information on its website, www.resoluteenergy.com, where it makes available, free of charge, the Company’s filings with the SEC, including its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, (“Exchange Act”), as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the SEC. The Company also makes available on its website copies of the charters of the audit, compensation and corporate governance/nominating committees of the Company’s Board of Directors, its code of business conduct and ethics, audit committee whistleblower policy, stockholder and interested parties communication policy and corporate governance guidelines. Stockholders may request a printed copy of these governance materials or any exhibit to this report by writing to the Secretary, Resolute Energy Corporation, 1675 Broadway, Suite 1950, Denver, Colorado 80202. You may also read and copy any materials the Company files 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 the Company files with the SEC. The Company’s website and the information contained on or connected to its website is not incorporated by reference herein and its web address is included as an inactive textual reference only.
ITEM 1A.
ITEM 1A.
RISK FACTORS
You should consider carefully the following risk factors, as well as the other information set forth in this Form 10-K.
Risks Related to Resolute’s Business, Operations and Industry
The risk factors set forth below are not the only risks that may affect Resolute’s business. Resolute’s business could also be affected by additional risks not currently known to it or that it currently deems to be immaterial. If any of the following risks were actually to occur, Resolute’s business, financial condition or results of operations could be materially adversely affected.
Resolute’s oil production from its Aneth Field Properties is presently connected by pipeline to only one customer, and such sales are dependent on gathering systems and transportation facilities that Resolute does not control. With only one pipeline connected customer, when these facilities or systems are unavailable, Resolute’s operations can be interrupted and its revenue reduced.
The marketability of Resolute’s oil and gas production depends in part upon the availability, proximity and capacity of pipelines, gas gathering systems, and processing facilities owned by third parties. In general, Resolute does not control these facilities and its access to them may be limited or denied due to circumstances beyond its control. A significant disruption in the availability of these facilities could adversely impact Resolute’s ability to deliver to market the oil and gas Resolute produces, and thereby cause a significant interruption in its operations. In some cases, Resolute’s ability to deliver to market its oil and gas is dependent upon coordination among third parties who own pipelines, transportation and processing facilities that Resolute uses, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt Resolute’s operations. These are risks for which Resolute generally does not maintain insurance.
With respect to oil produced at its Aneth Field Properties, Resolute operates in a remote part of southeastern Utah, and currently Resolute sells all of its crude oil production to a single customer, Western. Resolute and Western, with the consent of NNOG, entered into a new contract effective September 1, 2009, covering the joint crude oil volumes of Resolute and NNOG from Aneth Field with an initial term of one year and continuing month-to-month thereafter, with either party having the right to terminate after the initial term, upon ninety days’ notice. The contract may also be terminated by Western after December 30, 2009, upon sixty days notice, if Western is not able to renew its right-of-way agreements with the Navajo Nation or if such rights-of-way are declared invalid and either Western is prevented from using such rights-of way or the Navajo Nation declares Western to be in trespass with respect to such rights-of-way. Resolute’s crude oil production is currently transported to a terminal that serves Western’s two refineries in the region via a crude oil pipeline owned by NNOG. In November 2009, Western announced that it intended to discontinue refining operations at one of its two refineries. See Business and Properties - Marketing and Customers - Aneth Field. There are presently no pipelines in service that run the entire distance from Resolute’s Aneth Field Properties to any alternative markets. If Western did not purchase Resolute’s crude oil, Resolute would have to transport its crude oil to other markets by a combination of the NNOG pipeline, truck and rail, which would result, in the short term, in a lower price relative to the NYMEX price than it currently receives. Resolute may in the future receive prices with a greater differential to NYMEX than it currently receives, which if not offset by increases in the NYMEX price for crude oil could result in a material adverse effect on Resolute’s financial results.
Resolute would also have to find alternative markets if Western’s refining capacity in the region is temporarily or permanently shut-down for any reason or if NNOG’s pipeline to Western’s refineries is temporarily or permanently shut-in for any reason. Resolute does not have any control over Western’s decisions with respect to its refineries. Resolute would also not have control over similar decisions by any replacement customers.
Resolute customarily ships crude oil to Western daily and receives payment on the twentieth day of the month following the month of production. As a result, at any given time, Western owes Resolute between 20 and 50 days of production revenue. Based upon average production from Aneth Field during the three months ended December 31, 2009, and a NYMEX oil price of $80.00 per barrel, Western could owe Resolute between $8 million and $20 million. If Western defaults on its obligation to pay Resolute for the crude oil it has delivered,
Resolute’s income would be materially and negatively affected. Both Moody’s Investor Services and Standard & Poor’s have assigned credit ratings to Western’s long-term debt that are below investment grade and Standard & Poor’s has recently put Western on credit watch negative.
With respect to its Wyoming operations, Resolute does not have any long-term supply or similar agreements with entities for which it acts as a producer and currently sells most of its Wyoming oil production under a purchase agreement with a single purchaser. Resolute is therefore dependent upon its ability to sell oil and gas at the prevailing wellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable and not decline.
Current financial conditions may have effects on Resolute’s business and financial condition that Resolute cannot predict.
Turmoil in the global financial system may continue to have an impact on Resolute’s business and financial condition, and Resolute may continue to face challenges if conditions in the financial markets do not improve. Resolute’s ability to access the capital markets has been restricted as a result of this turmoil and may be restricted in the future when Resolute would like, or need, to raise capital. The financial turmoil may also limit the number of prospects for Resolute’s development and acquisition, or make such transactions uneconomic or difficult to consummate, and make it more difficult for Resolute to develop its reserves. The economic situation could also adversely affect the collectability of Resolute’s trade receivables and cause Resolute’s commodity hedging arrangements, if any, to be ineffective if Resolute’s counterparties are unable to perform their obligations or seek bankruptcy protection. It may also adversely affect any of Resolute’s partners’ ability to fulfill their obligations under operating agreements and Resolute may be required to fund these expenditures from other sources or reduce Resolute’s planned activities. Additionally, the global economic situation could lead to further reduced demand for oil and gas, lower product prices or continued product price volatility which would have a negative effect on Resolute’s revenue.
Inadequate liquidity could materially and adversely affect Resolute’s business operations in the future.
Resolute’s ability to generate cash flow depends upon numerous factors related to its business that may be beyond its control, including:
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the amount of oil and gas it produces;
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the price at which it sells its oil and gas production and the costs it incurs to market its production;
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the effectiveness of its commodity price hedging strategy;
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the development of proved undeveloped properties and the success of its enhanced oil recovery activities;
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the level of its operating and general and administrative costs;
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its ability to replace produced reserves;
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prevailing economic conditions;
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government regulation and taxation;
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the level of its capital expenditures required to implement its development projects and make acquisitions of additional reserves;
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its ability to borrow under its revolving credit facility;
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its debt service requirements contained in its revolving credit facility or future debt agreements;
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fluctuations in its working capital needs; and
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timing and collectability of receivables.
Resolute’s planned operations, as well as replacement of its production and reserves, will require additional capital that may not be available.
Resolute’s business is capital intensive, and requires substantial expenditures to maintain currently producing wells, to make the acquisitions of additional reserves and/or conduct its exploration, exploitation and development program necessary to replace its reserves, to pay expenses and to satisfy its other obligations, which will require cash flow from operations, additional borrowings or proceeds from the issuance of additional equity, or some combination thereof, which may not be available to Resolute.
For example, Resolute expects to spend an additional $377.4 million of capital expenditures over the next 28 years (including CO2 purchases) to implement and complete its proved developed non-producing and proved undeveloped CO2 flood projects. Resolute expects to incur approximately $161.7 million of these future capital expenditures between 2010 and 2012 based on its year-end 2009 SEC case reserve report. To the extent Resolute’s production and reserves decline faster than it anticipates, Resolute will require a greater amount of capital to maintain its production. Resolute’s ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by its financial condition at the time of any such financing or offering, the covenants in its revolving credit facility or future debt agreements, adverse market conditions or other contingencies and uncertainties that are beyond its control. Resolute’s failure to obtain the funds necessary for future activities could materially affect its business, results of operations and financial condition. Even if Resolute is successful in obtaining the necessary funds, the terms of such financings could limit Resolute’s activities and its ability to pay dividends. In addition, incurring additional debt may significantly increase Resolute’s interest expense and financial leverage, and issuing additional equity may result in significant equity holder dilution.
A significant part of Resolute’s development plan involves the implementation of its CO2projects. The supply of CO2 and efficacy of the planned projects is uncertain, and other resources may not be available or may be more expensive than expected, which could adversely impact production, revenue and earnings, and may require a write-down of reserves.
Producing oil and gas reservoirs are depleting assets generally characterized by declining production rates that vary depending upon factors such as reservoir characteristics. A significant part of Resolute’s business strategy depends on its ability to successfully implement CO2 floods and other development projects it has planned for its Aneth Field Properties in order to counter the natural decline in production from the field. As of December 31, 2009, approximately 65% of Resolute’s estimated net proved reserves were classified as proved developed non-producing and proved undeveloped, meaning Resolute must undertake additional development activities before it can produce those reserves. These development activities involve numerous risks, including insufficient quantities of CO2, project execution risks and cost overruns, insufficient capital to allocate to these projects, and inability to obtain equipment and materials that are necessary to successfully implement these projects.
A critical part of Resolute’s development strategy depends upon its ability to purchase CO2. Resolute currently has entered into contracts to purchase CO2 from two suppliers, EMGP and Kinder Morgan. The contract with EMGP expires June 30, 2010; the contract with Kinder Morgan expires in 2016. All of the CO2 Resolute has under contract comes from the McElmo Dome field. Following the termination of the EMGP contract in June 2010, all of Resolute’s CO2 will be supplied under the Kinder Morgan contract. If Resolute is unable to purchase sufficient CO2 under either of its existing contracts, or from Kinder Morgan after June 2010, either because Resolute’s suppliers are unable or are unwilling to supply the contracted volumes, Resolute would have to purchase CO2 from other owners of CO2 in the McElmo Dome field or elsewhere. In such an event, Resolute may not be able to locate substitute supplies of CO2 at acceptable prices or at all. In addition, certain suppliers of CO2, such as Kinder Morgan, use CO2 in their own tertiary recovery projects. As a result, if Resolute needs to purchase additional volumes of CO2, these suppliers may not be willing to sell a portion of their supply of CO2 to Resolute if their own demand for CO2 exceeds their supply. Additionally, even if adequate supplies are available for delivery from the McElmo Dome field, Resolute could experience temporary or permanent shut-ins of Resolute’s pipeline that delivers CO2 from that field to its Aneth Field Properties. If Resolute is unable to obtain the CO2 it requires and is unable to undertake its development projects or if Resolute’s development projects are significantly delayed, Resolute’s recoverable reserves may not be as much as it currently anticipates, it will not realize its expected incremental production, and its expected decline in the rate of production from its Aneth Field Properties will be accelerated. If Resolute’s requirements for CO2 were to decrease, it could be required to incur
costs for CO2 that it has not purchased or to purchase more CO2 than it could use effectively. For more information about Resolute’s minimum financial obligations under these contracts, please read “Resolute’s Business - Planned Operating and Development Activities.” For more information about Resolute’s CO2 development program and Resolute’s minimum financial obligations under these contracts, please read “Resolute’s Business - Planned Operating and Development Activities.”
In addition, Resolute’s estimate of future development costs, including with respect to its planned CO2 development projects, is based on Resolute’s current expectation of prices and other costs of CO2, equipment and personnel Resolute will need in the future to implement such projects. Resolute’s actual future development costs may be significantly higher than Resolute currently estimates, and delays in executing its development projects could result in higher labor and other costs associated with these projects. If costs become too high, Resolute’s future development projects may not be economical and Resolute may be forced to abandon its development projects.
Furthermore, the results Resolute obtains from its CO2 flood projects may not be the same as it expected when preparing its estimate of net proved reserves. Lower than expected production results or delays in when Resolute first realizes additional production as a result of its CO2 flood projects will reduce the value of its reserves, which could reduce its ability to incur indebtedness, require Resolute to use cash to repay indebtedness, and require Resolute to write-down the value of its reserves. Therefore, Resolute’s future reserves, production and future cash flow are highly dependent on Resolute’s success in efficiently developing and exploiting its current estimated net proved undeveloped reserves.
Resolute is a party to contracts that require it to pay for a minimum quantity of CO2. These contracts limit Resolute’s ability to curtail costs if its requirements for CO2 decrease.
Resolute’s contracts with Kinder Morgan and EMGP require Resolute to take, or pay for if not taken, a minimum volume of CO2 on a monthly basis. The take-or-pay obligations result in minimum financial obligations through 2016, in the case of the Kinder Morgan contract, and through 2010 in the case of the EMGP contract. The take-or-pay provisions in both contracts allow Resolute to subsequently apply take-or-pay payments made to volumes subsequently taken, but these provisions have limitations and Resolute may not be able to utilize all such amounts paid if the limitations apply or if Resolute does not subsequently take sufficient volumes to utilize the amounts previously paid.
Oil and gas prices are volatile and change for reasons that are beyond Resolute’s control. Decreases in the price Resolute receives for its oil and gas production can adversely affect its business, financial condition, results of operations and liquidity and impede its growth.
The oil and gas markets are highly volatile, and Resolute cannot predict future prices. Resolute’s revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect Resolute’s financial results and impede its growth. Prices for oil and gas may fluctuate widely in response to relatively minor changes in the supply of and demand for the commodities, market uncertainty and a variety of additional factors that are beyond Resolute’s control, such as:
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domestic and foreign supply of and demand for oil and gas, including as a result of technological advances affecting energy consumption and supply;
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weather conditions;
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overall domestic and global political and economic conditions;
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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
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the price of foreign imports;
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political and economic conditions in oil producing countries, including the Middle East and South America;
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technological advances affecting energy consumption;
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variations between product prices at sales points and applicable index prices;
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domestic, tribal and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the capacity, cost and availability of oil and gas pipelines and other transportation and gathering facilities, and the proximity of these facilities to its wells;
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the availability of refining and processing capability;
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factors specific to the local and regional markets where Resolute’s production occurs; and
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the price and availability of alternative fuels.
In the past, the price of crude oil has been extremely volatile, and Resolute expects this volatility to continue. For example, during the twelve months ended December 31, 2009, the NYMEX price for light sweet crude oil ranged from a high of $81.04 per Bbl to a low of $33.98 per Bbl. For calendar year 2008, the range was from a high of $145.28 per Bbl to a low of $33.03 per Bbl, and for the five years ended December 31, 2009, the price ranged from a high of $145.28 per Bbl to a low of $31.41 per Bbl.
A decline in oil and gas prices can significantly affect many aspects of Resolute’s business, including financial condition, revenue, results of operations, liquidity, rate of growth and the carrying value of Resolute’s oil and gas properties, all of which depend primarily or in part upon those prices. For example, declines in the prices Resolute receives for its oil and gas adversely affect its ability to finance capital expenditures, make acquisitions, raise capital and satisfy its financial obligations. In addition, declines in prices reduce the amount of oil and gas that Resolute can produce economically and, as a result, adversely affect its quantities of proved reserves. Among other things, a reduction in its reserves can limit the capital available to Resolute, as the maximum amount of available borrowing under its revolving credit facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantities of those reserves.
Resolute’s estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities of Resolute’s proved reserves.
Resolute’s estimate of proved reserves for the period ended December 31, 2009, is based on the quantities of oil and gas that engineering and geological analyses demonstrate with reasonable certainty to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., independent petroleum engineers, audited reserve and economic evaluations of all properties that were prepared by Resolute on a well-by-well basis. Oil and gas reserve engineering is not exact; it relies on subjective interpretations of data that may be inaccurate or incomplete and requires predictions and assumptions of future reservoir behavior and economic conditions. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:
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the assumed accuracy of field measurements and other reservoir data;
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assumptions regarding expected reservoir performance relative to historical analog reservoir performance;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future oil and gas prices; and
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assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:
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the quantities of oil and gas that are ultimately recovered;
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the timing of the recovery of oil and gas reserves;
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the production and operating costs incurred; and
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the amount and timing of future development expenditures.
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. As a result of all these factors, Resolute may make material changes to reserves estimates to take into account changes in its assumptions and the results of its development activities and actual drilling and production.
If these assumptions prove to be incorrect, Resolute’s estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and Resolute’s estimates of the future net cash flows from its reserves could change significantly. In addition, if declines in oil and gas prices result in its having to make substantial downward adjustments to its estimated proved reserves, or if its estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require Resolute to make downward adjustments, as a non-cash impairment charge to earnings, to the carrying value of Resolute’s oil and gas properties. If Resolute incurs impairment charges in the future, Resolute could have a material adverse effect on its results of operations in the period incurred and on its ability to borrow funds under its credit facility.
The standardized measure of future net cash flows from Resolute’s net proved reserves is based on many assumptions that may prove to be inaccurate. Any material inaccuracies in Resolute’s reserve estimates or underlying assumptions will materially affect the quantities and present value of its proved reserves.
Actual future net cash flows from Resolute’s oil and gas properties will be determined by the actual prices Resolute receives for oil and gas, its actual operating costs in producing oil and gas, the amount and timing of actual production, the amount and timing of Resolute’s capital expenditures, supply of and demand for oil and gas and changes in governmental regulations or taxation, which may differ from the assumptions used in creating estimates of future cash flows.
The timing of both Resolute’s production and its incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor Resolute uses when calculating discounted future net cash flows in compliance with guidance from the Financial Accounting Standards Board may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Resolute or the oil and gas industry in general.
Currently, substantially all of Resolute’s oil producing properties are located on the Navajo Reservation, making Resolute vulnerable to risks associated with laws and regulations pertaining to the operation of oil and gas properties on Native American tribal lands.
Substantially all of Resolute’s Aneth Field Properties, which represent approximately 93% of Resolute’s total proved reserves and approximately 75% of Resolute’s production (on an equivalent barrel basis) at December 31, 2009, are located on the Navajo Reservation in southeastern Utah. Operation of oil and gas interests on Indian lands presents unique considerations and complexities. These arise from the fact that Indian tribes are “dependent” sovereign nations located within states, but are subject only to tribal laws and treaties with, and the laws and Constitution of, the United States. This creates a potential overlay of three jurisdictional regimes - Indian, federal and state. These considerations and complexities could arise around various aspects of Resolute’s operations, including real property considerations, employment practices, environmental matters and taxes.
For example, Resolute is subject to the Navajo Preference in Employment Act. This law requires that it give preference in hiring to members of the Navajo Nation, or in some cases other Native American tribes, if such a person is qualified for the position, rather than hiring the most qualified person. A further regulatory requirement is imposed by the Navajo Nation Business Opportunity Act which requires Resolute to give preference to businesses owned by Navajo persons when it is hiring contractors. These regulatory restrictions can negatively affect Resolute’s ability to recruit and retain the most highly qualified personnel or to utilize the most experienced and economical contractors for its projects.
Furthermore, because tribal property is considered to be held in trust by the federal government, before Resolute can take actions such as drilling, pipeline installation or similar actions, it is required to obtain approvals from various federal agencies that are in addition to customary regulatory approvals required of oil and gas producers operating on non-Indian property. Resolute also is required to obtain approvals from the Resources Committee, which is a standing committee of the Navajo Nation Tribal Council, before Resolute can take similar actions with respect to its Aneth Field Properties. These approvals could result in delays in its implementation of, or otherwise prevent it from implementing, its development program. These approvals, even if ultimately obtained, could result in delays in Resolute’s ability to implement its development program.
In addition, under the Native American laws and regulations, Resolute could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of Resolute’s operations and subject it to administrative, civil and criminal penalties, including the assessment of natural resource damages.
For additional information about the legal complexities and considerations associated with operating on the Navajo Reservation, please read “Resolute’s Business - Laws and Regulations Pertaining to Oil and Gas Operations on Navajo Nation Lands.”
NNOG has options to purchase a portion of Resolute’s Aneth Field Properties.
NNOG has a total of six options to purchase for cash at fair market value, in the aggregate, up to 30.0% of Resolute’s interest in the Chevron Properties and 30.0% of its interest in the ExxonMobil Properties. These options become exercisable over a period of time if financial hurdles related to recovery by Resolute of its investments are met. If NNOG exercises its purchase options in full, it could acquire from Resolute undivided working interests representing an 18.15% working interest in the Aneth Unit, a 22.5% working interest in the McElmo Creek Unit and a 17.7% working interest in the Ratherford Unit. If NNOG were to exercise any of these options, Resolute might not be able to effectively redeploy the cash received from NNOG. For additional information about NNOG’s purchase right, please read “Resolute’s Business - Relationship with the Navajo Nation.”
The statutory preferential purchase right held by the Navajo Nation to acquire transferred Navajo Nation oil and gas leases and NNOG’s right of first negotiation could diminish the value Resolute may be able to receive in a sale of its properties.
Nearly all of Resolute’s Aneth Field Properties are located on the Navajo Reservation. The Navajo Nation has a statutory preferential right to purchase at the offered price any Navajo Nation oil and gas lease or working interest in such a lease at the time a proposal is made to transfer the lease or interest. The existence of this right can make it more difficult to sell a Navajo Nation oil and gas lease because this right may discourage third parties from purchasing such a lease and, therefore, could reduce the value of Resolute’s leases if it were to attempt to sell them. In addition, under the terms of Resolute’s Cooperative Agreement with NNOG, Resolute is obligated to first negotiate with NNOG to sell its Aneth Field Properties before it may offer to sell such properties to any other third party. This contractual right could make it more difficult for Resolute to sell its Aneth Field Properties. For additional information about the right of first negotiation for the benefit of NNOG, please read “Resolute’s Business - Relationship with the Navajo Nation.”
All of Resolute’s producing properties are located in two geographic areas, making it vulnerable to risks associated with operating in only two geographic areas.
A substantial amount of Resolute’s sales of oil and gas and 93% of its total proved reserves at December 31, 2009, are currently located in its Aneth Field Properties in the southeast Utah portion of the Paradox Basin in the Four Corners area of the southwestern United States. Essentially all of the remainder of Resolute’s sales of oil and gas and 7% of its total proved reserves are predominantly located in Hilight Field in the Powder River Basin in northeastern Wyoming and southeastern Montana. As a result of Resolute’s lack of diversification in asset type and location, any delays or interruptions of production from these wells caused by such factors as governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation of oil produced from the wells in these fields, price fluctuations, natural disasters or shut-downs of the pipelines
connecting its Aneth Field production to refineries would have a significantly greater impact on Resolute’s results of operations than if Resolute possessed more diverse assets and locations.
Lack of geographic diversification also affects the prices to be received for Resolute’s oil and gas production from its properties, since prices are determined to a significant extent by factors affecting the regional supply of and demand for oil and gas, including the adequacy of the pipeline and processing infrastructure in the region to transport or process Resolute’s production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and gas production and the actual (frequently lower) price Resolute may receive for its production.
Developing and producing oil and gas are costly and high-risk activities with many uncertainties that could adversely affect Resolute’s financial condition or results of operations, and insurance may not be available or may not fully cover losses.
There are numerous risks associated with developing, completing and operating a well, and cost factors can adversely affect the economics of a well. Resolute’s development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
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high costs, shortages or delivery delays of rigs, equipment, labor or other services;
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unexpected operational events and/or conditions;
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reductions in oil or gas prices or increases in the differential between index oil or gas prices and prices received by Resolute;
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increases in severance taxes;
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limitations on Resolute’s ability to sell its crude oil or gas production;
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adverse weather conditions and natural disasters;
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facility or equipment malfunctions, and equipment failures or accidents;
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pipe or cement failures and casing collapses;
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compliance with environmental and other governmental requirements;
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environmental hazards, such as leaks, oil spills, pipeline ruptures and discharges of toxic gases;
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lost or damaged oilfield development and service tools;
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unusual or unexpected geological formations, and pressure or irregularities in formations;
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fires, blowouts, surface craterings and explosions;
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shortages or delivery delays of equipment and services;
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title problems;
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objections from surface owners and nearby surface owners in the areas where Resolute operates; and
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uncontrollable flows of oil, gas or well fluids.
Any of these or other similar occurrences could reduce Resolute’s cash from operations or result in the disruption of Resolute’s operations, substantial repair costs, significant damage to property, environmental pollution and impairment of its operations. The occurrence of these events could also affect third parties, including persons living near Resolute’s operations, Resolute’s employees and employees of Resolute’s contractors, leading to injuries or death.
Insurance against all operational risk is not available to Resolute, and pollution and environmental risks generally are not fully insurable. Additionally, Resolute may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes
in the insurance markets subsequent to the terrorist attacks on September 11, 2001, have made it more difficult for Resolute to obtain coverage for terrorist attacks and related risks. Resolute may not be able to obtain the levels or types of insurance it would otherwise have obtained prior to these market changes, and any insurance coverage Resolute does obtain may contain large deductibles or it may not cover all hazards or potential losses. Losses and liabilities from uninsured and underinsured events or a delay in the payment of insurance proceeds could adversely affect Resolute’s business, financial condition and results of operations.
Exploration and development drilling may not result in commercially productive reserves.
Resolute may not encounter commercially productive reservoirs through its drilling operations. In 2010, Resolute expects to incur approximately $30 million of capital expenditures for acreage acquisition, exploration and development drilling, most significantly in the Williston Basin properties in North Dakota. The new wells Resolute drills or participates in may not be productive and the Company may not recover all or any portion of its investment in such wells. The seismic data and other technologies Resolute uses do not allow it to know conclusively prior to drilling whether it will find oil or gas or, if found, that the hydrocarbons will be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Resolute’s efforts will be unprofitable if it drills dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, Resolute’s drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions; and
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compliance with environmental and other governmental requirements.
If Resolute does not make acquisitions of reserves on economically acceptable terms, Resolute’s future growth and ability to maintain production will be limited to only the growth it intends to achieve through the development of its proved developed non-producing and proved undeveloped reserves.
Producing oil and gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from Resolute’s existing wells declines in a different manner than Resolute has estimated and can change under other circumstances. Resolute’s future oil and gas reserves and production and, therefore, Resolute’s cash flow and income are highly dependent upon its success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves.
Resolute intends to grow by bringing its proved developed non-producing reserves into production, developing its proved undeveloped reserves and exploring for and finding additional reserves on its non-proved properties. Resolute’s ability to further grow depends in part on its ability to make acquisitions, particularly in the event NNOG exercises its options to increase its working interest in the Aneth Field Properties. Resolute may be unable to make such acquisitions because it is:
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unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with the seller;
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unable to obtain financing for these acquisitions on economically acceptable terms; or
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outbid by competitors.
If Resolute is unable to acquire properties containing proved reserves at acceptable costs, Resolute’s total level of proved reserves and associated future production will decline as a result of its ongoing production of its reserves.
Any acquisitions Resolute completes are subject to substantial risks that could negatively affect its financial condition and results of operations.
Even if Resolute does make acquisitions that it believes will enhance its growth, financial condition or results of operations, any acquisition involves potential risks, including, among other things:
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the validity of Resolute’s assumptions about the acquired properties or company’s reserves, future production, the future prices of oil and gas, infrastructure requirements, environmental and other liabilities, revenue and costs;
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an inability to integrate successfully the properties and businesses Resolute acquires;
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a decrease in Resolute’s liquidity to the extent it uses a significant portion of its available cash or borrowing capacity to finance acquisitions or operations of the acquired properties;
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a significant increase in its interest expense or financial leverage if Resolute incurs debt to finance acquisitions or operations of the acquired properties;
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the assumption of unknown liabilities, losses or costs for which Resolute is not indemnified or for which Resolute’s indemnity is inadequate;
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the diversion of management’s attention from other business concerns;
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an inability to hire, train or retain qualified personnel to manage and operate Resolute’s growing business and assets;
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unforeseen difficulties encountered in operating in new geographic areas; and
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customer or key employee losses at the acquired businesses.
Resolute’s decision to acquire a property or business will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
Also, Resolute’s reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential problems. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. The potential risks in making acquisitions could adversely affect Resolute’s ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.
Resolute’s future debt levels may limit its flexibility to obtain additional financing and pursue other business opportunities.
Resolute expects to have the ability to incur additional debt under its revolving credit facility, subject to borrowing base limitations. Resolute’s increased level of indebtedness could have important consequences to Resolute, including:
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Resolute’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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covenants contained in Resolute’s existing and future credit and debt arrangements will require it to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;
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Resolute will need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and
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Resolute’s debt level will make it more vulnerable than its competitors with less debt to competitive pressures or a downturn in its business or the economy generally.
Resolute’s ability to service its indebtedness will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond Resolute’s control. If Resolute’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing Resolute’s indebtedness, or seeking additional equity capital or bankruptcy protection. Resolute may not be able to effect any of these remedies on satisfactory terms or at all.
Resolute’s revolving credit facility has substantial financial and operating covenants that restrict Resolute’s business and financing activities and prohibit Resolute from paying dividends. Future borrowing agreements would likely include similar restrictions.
The operating and financial covenants in Resolute’s senior secured revolving credit facility restrict Resolute’s ability to finance future operations or capital needs or to engage, expand or pursue its business activities. Resolute’s revolving credit facility currently restricts, and it anticipates that any amendment to such facility would restrict, its ability to:
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incur indebtedness;
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grant liens;
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make acquisitions and investments;
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lease equipment;
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redeem or prepay other debt;
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pay dividends to shareholders or repurchase shares;
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enter into transactions with affiliates; and
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enter into a merger, consolidation or sale of assets.
The revolving credit agreement matures in March 2014, unless extended, and is secured by all of Resolute’s oil and gas properties as well as a pledge of all ownership interests in operating subsidiaries. The revolving credit agreement has a borrowing base (currently $260 million) determined by the lenders based on their evaluation of the value of the collateral. Resolute is required to maintain a consolidated current ratio of at least 1.0 to 1.0 at the end of any fiscal quarter; and may not permit its Maximum Leverage Ratio (consolidated indebtedness to consolidated EBITDA as defined in the credit agreement) to exceed 4.0 to 1.0 at the end of each fiscal quarter. Resolute’s revolving credit facility does not permit it to pay dividends to shareholders.
Resolute may enter into additional borrowing agreements which would likely include additional operating and financial covenants.
Shortages of qualified personnel or field equipment and services could affect Resolute’s ability to execute its plans on a timely basis, reduce its cash flow and adversely affect its results of operations.
The demand for qualified and experienced geologists, geophysicists, engineers, field operations specialists, landmen, financial experts and other personnel in the oil and gas industry can fluctuate significantly, often in correlation with oil and gas prices, causing periodic shortages. From time to time, there also have been shortages of drilling rigs and other field equipment, as demand for rigs and equipment has increased along 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 gas prices generally stimulate increased demand and result in increased prices for
drilling rigs, crews and associated supplies, equipment and services. Historically, increased demand resulting from high commodity prices have at times significantly increased costs and resulted in some difficulty in obtaining drilling rigs, experienced crews and related services. Resolute may continue to experience such difficulties in the future. If shortages persist or prices continue to increase, Resolute’s profit margin, cash flow and operating results could be adversely affected and Resolute’s ability to conduct its operations in accordance with current plans and budgets could be restricted.
Resolute’s hedging activities could reduce its net income, which could reduce the price at which the Company’s stock may trade.
To achieve more predictable cash flow and to reduce Resolute’s exposure to adverse changes in the price of oil and gas, Resolute has entered into, and plans to enter into in the future, derivative arrangements covering a significant portion of its oil and gas production. These derivative arrangements could result in both realized and unrealized hedging losses. Resolute’s derivative instruments are subject to mark-to-market accounting treatment, and the change in fair market value of the instrument is reported in Resolute’s statement of operations each quarter, which has resulted in, and will in the future likely result in, significant unrealized net gains or losses.
As of December 31, 2009, Resolute had in place oil and gas swaps, oil and gas collars and a gas basis hedge. These included oil swaps covering approximately 75% of its anticipated 2010 oil production at a weighted average price of $67.24 per Bbl, oil collars covering approximately 4% of its anticipated 2010 oil production with a floor of $105.00 per Bbl and ceiling of $151.00 per Bbl, gas swaps covering approximately 73% of its anticipated 2010 gas production at a weighted average price of $9.69 per MMBtu, and a CIG gas basis hedge priced at $2.10 per MMBtu covering approximately 34% of its anticipated 2010 gas production. Additional instruments are also in place for future years and are summarized in the table below. Resolute expects to continue to use hedging arrangements to reduce commodity price risk with respect to its estimated production from producing properties. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Resolute - How Resolute Evaluates Its Operations - Production Levels, Trends and Prices” and “Management’s Discussion and Analysis of Financial Condition and Results of Resolute - Quantitative and Qualitative Disclosures About Market Risk.”
Resolute’s actual future production during a period may be significantly higher or lower than it estimates at the time it enters into derivative transactions for such period. If the actual amount is higher than it estimates, it will have more unhedged production and therefore greater commodity price exposure than it intended. If the actual amount is lower than the nominal amount that is subject to Resolute’s derivative financial instruments, it might be forced to satisfy all or a portion of its derivative transactions without the benefit of the cash flow from its sale of
the underlying physical commodity, resulting in a substantial diminution of its liquidity. As a result of these factors, Resolute’s derivative activities may not be as effective as it intends in reducing the volatility of its cash flows, and in certain circumstances may actually increase the volatility of its cash flows.
In addition, Resolute’s derivative activities are subject to the risk that a counterparty may not perform its obligation under the applicable derivative instrument. If hedge counterparties, some of which have received governmental support in connection with the ongoing credit crisis, are unable to make payments to Resolute under its hedging arrangements, Resolute’s results of operations, financial condition and liquidity would be adversely affected.
The effectiveness of hedging transactions to protect Resolute from future oil price declines will be dependent upon oil prices at the time it enters into future hedging transactions as well as its future levels of hedging, and as a result its future net cash flow may be more sensitive to commodity price changes.
As Resolute’s hedges expire, more of its future production will be sold at market prices unless it enters into additional hedging transactions. Resolute’s revolving credit facility prohibits it from entering into hedging arrangements for more than 85% of its production from projected proved developed producing reserves using economic parameters specified in its credit agreements. The prices at which Resolute hedges its production in the future will be dependent upon commodity prices at the time it enters into these transactions, which may be substantially lower than current prices. Accordingly, Resolute’s commodity price hedging strategy will not protect it from significant and sustained declines in oil and gas prices received for its future production. Conversely, Resolute’s commodity price hedging strategy may limit its ability to realize cash flow from commodity price increases. It is also possible that a larger percentage of Resolute’s future production will not be hedged as the Company’s hedging policies may change, which would result in its oil revenue becoming more sensitive to commodity price changes.
The nature of Resolute’s assets exposes it to significant costs and liabilities with respect to environmental and operational safety matters. Resolute is responsible for costs associated with the removal and remediation of the decommissioned Aneth Gas Processing Plant.
Resolute may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to its oil and gas exploitation, production and other activities. These costs and liabilities could arise under a wide range of environmental, health and safety laws and regulations, including agency interpretations thereof and governmental enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, cleanup and site restoration costs and liens, the denial or revocation of permits or other authorizations and the issuance of injunctions to limit or cease operations. Compliance with these laws and regulations also increases the cost of Resolute’s operations and may prevent or delay the commencement or continuance of a given operation. In addition, claims for damages to persons or property may result from environmental and other impacts of its operations.
Resolute has an interest in the Aneth Gas Processing Plant, which is currently being decommissioned. Under Resolute’s purchase agreement with Chevron, Chevron is responsible for indemnifying Resolute against the decommissioning and clean-up or remediation costs allocable to the 39% interest Resolute purchased from it. Under Resolute’s purchase agreement with ExxonMobil, however, Resolute is responsible for the decommissioning and clean-up or remediation cost allocable to the interests it purchased from ExxonMobil, which is 25% of the total cost of the project. If Chevron fails to pay its share of the decommissioning costs in accordance with the purchase agreement, Resolute could be held responsible for 64% of the total costs to decommission and remediate the Aneth Gas Processing Plant. Chevron is managing the decommissioning process and, based on Resolute’s current estimate, the total cost of the decommissioning is $28.0 million. $17.1 million has already been incurred and paid for as of December 31, 2009. This estimate does not include any costs for any possible subsurface clean-up or remediation of the site.
The Aneth Gas Processing Plant site was previously evaluated by the U.S. EPA for possible listing on the NPL of sites contaminated with hazardous substances with the highest priority for clean-up under the CERCLA. Based
on its investigation, the EPA concluded no further investigation was warranted and that the site was not required to be listed on the NPL. The Navajo Environmental Protection Agency now has primary jurisdiction over the Aneth Gas Processing Plant site, however, and Resolute cannot predict whether it will require further investigation and possible clean-up, and the ultimate cleanup liability may be affected by the recent enactment by the Navajo Nation of a Navajo CERCLA. In some matters, the Navajo CERCLA imposes broader obligations and liabilities than the federal CERCLA. Resolute has been advised by Chevron that a significant portion of the subsurface clean-up or remediation costs, if any, would be covered by an indemnity from the prior owner of the plant, and Chevron has provided Resolute with a copy of the pertinent purchase agreement that appears to support its position. Resolute cannot predict whether any subsurface remediation will be required or what the costs of the subsurface clean-up or remediation could be. Additionally, it cannot be certain whether any of such costs will be reimbursable to it pursuant to the indemnity of the prior owner. To the extent any such costs are incurred and not reimbursed pursuant to the indemnity from the prior owner, Resolute would be liable for 25% of such costs as a result of its acquisition of the ExxonMobil Properties. Please read “Resolute’s Business - Aneth Gas Processing Plant” for additional information about this liability.
Strict or joint and several liability to remediate contamination may be imposed under environmental laws, which could cause Resolute to become liable for the conduct of others or for consequences of its own actions that were in compliance with all applicable laws at the time those actions were taken. New or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Please read “Resolute’s Business - Environmental, Health and Safety Matters and Regulation” for more information.
Resolute may be unable to compete effectively with larger companies, which may adversely affect its operations and ability to generate and maintain sufficient revenue.
The oil and gas industry is intensely competitive, and Resolute competes with companies that have greater resources. Many of these companies not only explore for and produce oil and gas, but also refine and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than Resolute’s financial or human resources permit. In addition, these companies may have a greater ability to continue exploration or exploitation activities during periods of low oil and gas market prices. Resolute’s larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than Resolute can, which would adversely affect Resolute’s competitive position. Resolute’s ability to acquire additional properties and to discover reserves in the future will depend upon its ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Resolute is subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Exploration, exploitation, development, production and marketing operations in the oil and gas industry are regulated extensively at the federal, state and local levels. In addition, substantially all of Resolute’s current leases in the Aneth Field are regulated by the Navajo Nation. Some of its future leases may be regulated by Native American tribes. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and properly abandon oil and gas wells and other recovery operations. Under these laws and regulations, Resolute could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of Resolute’s operations or denial or revocation of permits and subject Resolute to administrative, civil and criminal penalties. In addition, the President’s budget and other legislative proposals would terminate various tax deductions currently available to companies engaged in oil and gas development and production. Tax deductions that are proposed to be terminated include the deduction for intangible drilling and development costs, the deduction for qualified tertiary injectant expenses, and the domestic manufacturing deduction. If enacted, the elimination of these deductions will adversely affect our business.
Part of the regulatory environment in which Resolute operates includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production activities. In addition, Resolute’s activities are subject to regulation by oil and gas producing states and the Navajo Nation regarding conservation practices, protection of correlative rights and other concerns. These regulations affect Resolute’s operations and could limit the quantity of oil and gas it may produce and sell. A risk inherent in Resolute’s CO2 flood project is the need to obtain permits from federal, state, local and Navajo Nation tribal authorities. Delays or failures in obtaining regulatory approvals or permits or the receipt of an approval or permit with unreasonable conditions or costs could have a material adverse effect on Resolute’s ability to exploit its properties. Additionally, the oil and gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect Resolute’s profitability. Proposed GHG, or GHG, reporting rules, and proposed GHG cap and trade legislation are two examples of proposed changes in the regulatory climate that would affect Resolute. Furthermore, Resolute may be placed at a competitive disadvantage to larger companies in the industry, which can spread these additional costs over a greater number of wells and larger operating staff. Please read “Resolute’s Business - Environmental, Health and Safety Matters and Regulation” and “Resolute’s Business - Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect Resolute.
Possible regulation related to global warming and climate change could have an adverse effect on Resolute’s operations and demand for oil and gas.
Recent scientific studies have suggested that emissions of GHG including CO2 and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of GHG. In addition, several states have already taken legal measures to reduce emissions of GHG. As a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA also may be required to regulate GHG emissions from mobile sources (e.g. cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of GHG. Other nations have already agreed to regulate emissions of GHG, pursuant to the United Nations Framework Convention on Climate Change, and the subsequent “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of GHG to below 1990 levels by 2012. Passage of state or federal climate control legislation or other regulatory initiatives or the adoption of regulations by the EPA and state agencies that restrict emissions of GHG in areas in which Resolute conducts business could have an adverse effect on Resolute’s operations and demand for oil and gas.
Resolute depends on a limited number of key personnel who would be difficult to replace.
Resolute depends substantially on the performance of its executive officers and other key employees. Resolute has not entered into any employment agreements with any of these employees, and Resolute does not maintain key person life insurance policies on any of these employees. The loss of any member of the senior management team or other key employees could negatively affect Resolute’s ability to execute its business strategy.
Terrorist attacks aimed at Resolute’s facilities or operations could adversely affect its business.
The United States has been the target of terrorist attacks of unprecedented scale. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected Resolute’s operations to increased risks. Any terrorist attack at Resolute’s facilities, or those of its customers or suppliers, could have a material adverse effect on Resolute’s business.
Work stoppages or other labor issues at Resolute’s facilities could adversely affect its business, financial position, results of operations, or cash flows.
As of December 31, 2009, approximately 40 of Resolute’s field level employees were represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, and covered by a collective bargaining agreement. Although Resolute believes that its relations with its employees are generally satisfactory, if Resolute is unable to reach agreement with any of its unionized work
groups on future negotiations regarding the terms of their collective bargaining agreements, or if additional segments of Resolute’s workforce become unionized, Resolute may be subject to work interruptions or stoppages. Work stoppages at the facilities of Resolute’s customers or suppliers may also negatively affect Resolute’s business. If any of Resolute’s customers experience a material work stoppage, the customer may halt or limit the purchase of Resolute’s products. Moreover, if any of Resolute’s suppliers experience a work stoppage, its operations could be adversely affected if an alternative source of supply is not readily available. Any of these events could be disruptive to Resolute’s operations and could adversely affect its business, financial position, results of operations, or cash flows.
Resolute may be required to write down the carrying value of its properties in the future.
Resolute uses the full cost accounting method for oil and gas exploitation, development and exploration activities. Under the full cost method rules, Resolute performs a ceiling test and if the net capitalized costs for a cost center exceed the ceiling for the relevant properties, it writes down the book value of the properties. Accordingly, Resolute could recognize impairments in the future if oil and gas prices are low, if Resolute has substantial downward adjustments to its estimated proved reserves, if Resolute experiences increases in its estimates of development costs or deterioration in its exploration and development results.
At December 31, 2009, using its year-end reserve estimates prepared in accordance with the recently promulgated SEC rules, total capitalized costs exceeded the full cost ceiling by approximately $150 million. No impairment expense was recorded at December 31, 2009, as the Company requested and received an exemption from the SEC to exclude the Resolute Transaction from the full cost ceiling assessment for a period of twelve months following the acquisition, provided the Company can demonstrate that the fair value of the acquired properties exceed the carrying value in the interim periods through June 30, 2010.
At the time of the Resolute Transaction, Resolute valued the properties using NYMEX forward strip prices for a period of five years and then held prices flat thereafter. The Company also used various discount rates and other risk factors depending on the classification of reserves. Management believes this internal pricing model reflected the fair value of the assets acquired. Under full cost ceiling test rules, the commodity price utilized was equal to the twelve-month unweighted arithmetic average of first day of the month prices, resulting in an average NYMEX oil price of $61.18 per barrel of oil and an average Henry Hub spot market price of gas of $3.87 per MMBtu of gas, which may not be indicative of actual fair market values.
The request for exemption was made because the Company believes that the fair value of the Resolute Transaction properties can be demonstrated beyond a reasonable doubt to exceed unamortized cost. Management continues to believe that its internal model utilizing NYMEX strip prices continues to reflect the fair value of these reserves and clearly exceeds carrying value at December 31, 2009.
While commodity prices have increased since September 30, 2009, Resolute recognizes that due to volatility associated with oil and gas prices, a downward trend could occur. If such a case were to occur and is deemed to be other than temporary, Resolute would assess Resolute’s properties for impairment during the requested exemption period. Further, if Resolute cannot demonstrate that fair value exceeds the unamortized carrying costs during the exemption periods, it will recognize impairment.
Compliance with the Sarbanes-Oxley Act of 2002 and other obligations of being a public company will require substantial financial and management resources.
Section 404 of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, will require that the Company implement, evaluate and report on its system of internal controls. If the Company fails to implement and maintain the adequacy of its internal controls, it could be subject to regulatory scrutiny, civil or criminal penalties and/or stockholder litigation. Any inability to provide reliable financial reports could harm the Company’s business. Section 404 of the Sarbanes-Oxley Act also requires that the Company’s independent registered public accounting firm report on management’s evaluation of the Company’s system of internal controls. In addition, as a newly public company, Resolute has been required to assume additional reporting and disclosure responsibilities, which will require the hiring of additional personnel and the establishment of additional systems. Any failure to implement required new or improved controls or systems, or difficulties encountered in the
implementation of adequate controls over its financial processes and reporting and disclosures in the future, could harm the Company’s operating results or cause the Company to fail to meet its reporting obligations. Inferior internal controls could also cause investors to lose confidence in the Company’s reported financial information, which could have a negative effect on the trading price of the shares of Company common stock.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
Legal Proceedings
In February of 2008, Resolute and, separately, the Navajo Nation and NNOG, filed Protests and Motions for Intervention with FERC objecting to a February 8, 2008, tariff filing by Western Refining Pipeline Company, a subsidiary of Western Refining, Inc. The filing was with respect to service on the 16 inch diameter Tex-New Mex Crude Oil Pipeline that runs from Jal, New Mexico to a pipeline terminal known as Bisti, south of Farmington, New Mexico. Resolute, the Navajo Nation and NNOG complained that Western was using the pipeline to implement an anti-competitive market scheme designed to drive down the price of crude oil in the Four Corners area in violation of the Interstate Commerce Act. FERC ruled that the protesting parties lacked standing to intervene. In August of 2008, Resolute appealed the FERC order to the United States Court of Appeals for the District of Columbia Circuit. On February 26, 2010, the court decided that the FERC order was not reviewable and dismissed the appeal. Resolute has not decided whether it will take further action on this matter.
Resolute is not a party to any other material pending legal or governmental proceedings, other than ordinary routine litigation incidental to its business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, Resolute’s management believes that the resolution of any of its pending proceedings will not have a material adverse effect on its financial condition or results of operations.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Price Range of Common Stock and Number of Holders
Resolute’s common stock is listed on the New York Stock Exchange under the symbol “REN”.
The following table sets forth the high and the low sale prices per share of Resolute’s common stock for the period from September 28, 2009 (inception) through December 31, 2009. The closing price of the common stock on March 29, 2010 was $12.21
As of March 29, 2010, there were approximately 80 record holders of Resolute’s common stock.
Resolute’s warrants are listed on the New York Stock Exchange under the symbol “RENWS”.
The following table sets forth the high and the low sale prices per share of Resolute’s warrants for the period from September 28, 2009 (inception) through December 31, 2009. The closing price of the warrants on March 29, 2010 was $2.46.
Unregistered Sales of Equity Securities
Not applicable.
Dividend Policy
Resolute has not declared any cash dividends on its common stock since inception and has no plans to do so in the foreseeable future. The ability of Resolute’s Board of Directors to declare any dividend is subject to limits imposed by the terms of its credit agreement, which currently prohibit Resolute from paying dividends on its common stock. Resolute’s ability to pay dividends is also subject to limits imposed by Delaware law. In determining whether to declare dividends, the Board of Directors will consider the limits imposed by credit agreement, financial condition, results of operations, working capital requirements, future prospects and other factors it considers relevant.
Comparison of Cumulative Return
The following graph compares the cumulative return on a $100 investment in Resolute common stock from September 28, 2009, the date the common stock began trading on the New York Stock Exchange, through December 31, 2009, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the S&P 500 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. The indices are included for comparative purpose only. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
COMPARISON OF CUMULATIVE TOTAL RETURN
AMONG RESOLUTE ENERGY CORPORATION, THE RUSSELL 2000 INDEX,
AND THE S&P 500 ENERGY INDEX
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following table presents Resolute’s selected historical financial data for the years ended December 31, 2009 and 2008 and for the period from inception in 2007 to December 31, 2007. The consolidated balance sheet and income statement information are derived from Resolute’s audited financial statements included elsewhere in this report. HACI was the accounting acquirer and, accordingly, the historical financial data below reflects HACI since its inception in 2007. Results of oil and gas operations are reflected from the date of the Resolute Transaction in September 2009. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
References to the “Company,” “us” or “we” refer to Resolute Energy Corporation (“Resolute”), a corporation formed to consummate a business combination between Hicks Acquisition Company I, Inc. (“HACI”), Resolute and Resolute Holdings Sub, LLC. “Predecessor Resolute” refers to the companies acquired by Resolute in the Resolute Transaction, as defined below, with respect to their operations prior to September 25, 2009, the date of the Resolute Transaction. The following discussion and analysis should be read in conjunction with the consolidated financial statements and the notes thereto contained elsewhere in this report. Due to the nature of the Resolute Transaction, two sets of financial statements are presented in this report. The first set covers the reporting company, Resolute, including a pro forma presentation of Resolute giving effect to the Resolute Transaction and the acquisition of a net profits interest of RWI (defined below) as if they had occurred on January 1, 2008. The second set covers the predecessor company, Predecessor Resolute, through September 24, 2009. This discussion is presented in two parts, the first relating to the business of Resolute, and the second setting forth comparative data with respect to Predecessor Resolute.
RESOLUTE ENERGY CORPORATION
The following section of MD&A addresses the business of Resolute, the Resolute Transaction, how Resolute evaluates its operations, factors that affect Resolute’s operations and the results of operations, liquidity and capital resources of Resolute as the successor to HACI. HACI was the accounting acquirer in the Resolute financial statements presented herein. As such, the Resolute financial statements reflect the operations of HACI on a stand-alone basis prior to September 25, 2009, the date of closing of the Resolute Transaction, and reflect Predecessor Resolute’s operations as part of Resolute for the period from September 25, 2009, through December 31, 2009.
Overview
Resolute is an independent oil and gas company engaged in the acquisition, exploration, development and production of oil, gas and hydrocarbon liquids. Resolute’s strategy is to grow through exploration, exploitation and industry standard enhanced oil recovery projects.
As of December 31, 2009, Resolute’s estimated net proved reserves were approximately 64 million equivalent barrels of oil (“MMBoe”), of which approximately 54% were proved developed reserves and approximately 77% were oil. The standardized measure of Resolute’s estimated net proved reserves as of December 31, 2009, was $361 million. See Note 15 to the Consolidated Financial Statements.
Resolute focuses its efforts on increasing reserves and production while controlling costs at a level that is appropriate for long-term operations. Resolute’s future earnings and cash flow from existing operations are dependent on a variety of factors including commodity prices, exploitation and recovery activities and its ability to manage its overall cost structure at a level that allows for profitable production.
The Resolute Transaction
On September 25, 2009 (the “Acquisition Date”), Resolute consummated a business combination under the terms of a Purchase and IPO Reorganization Agreement dated as of August 2, 2009 (the “Acquisition Agreement”) by and among us, HACI, Resolute Holdings Sub, LLC (“Sub”), Resolute Subsidiary Corporation, a wholly-owned subsidiary of Resolute (“Merger Sub”), Resolute Aneth, LLC, a subsidiary of Sub (“Aneth”), Resolute Holdings, LLC and HH-HACI, L.P. (the “Sponsor”), pursuant to which HACI stockholders acquired a majority of the outstanding shares of capital stock of Resolute and Resolute acquired all of the operating companies previously owned by Sub (the “Resolute Transaction”). Prior to September 25, 2009, HACI was a blank check company formed for the purpose of acquiring, or acquiring control of, through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination one or more businesses or assets.
As a result of the Resolute Transaction, through a series of transactions, shareholders of HACI common stock, par value $0.0001 per share, acquired approximately 82% of the outstanding shares of Resolute common stock, par value $0.0001 per share (“Resolute common stock”), and Sub owned approximately 18% of the outstanding Resolute common stock, excluding, in each case, warrants, options and the Resolute Earnout Shares (as defined below). HACI transferred $327 million remaining in its trust account, after payment of expenses of $11 million and redemption of HACI common stock and warrants in the amount of $201 million, to Aneth in exchange for a membership interest in Aneth. Sub then contributed its direct and indirect ownership interests in its operating subsidiaries to HACI. Merger Sub merged with and into HACI, with HACI surviving the merger and continuing as a wholly-owned subsidiary of Resolute. As required by the Acquisition Agreement, the $327 million was used to repay amounts owed under Aneth’s credit facilities.
In exchange for Sub’s contribution of its operating subsidiaries and as a result of the other transactions contemplated by the Acquisition Agreement, Sub acquired (i) 9,200,000 shares of Resolute common stock, (ii) 4,600,000 warrants to purchase Resolute common stock at a price of $13.00 per share, with a five year life and subject to a trigger price of $13.75 per share (the “Resolute Founders Warrants”), (iii) 2,333,333 warrants to purchase Resolute common stock at a price of $13.00 per share, with a five year life (the “Resolute Sponsors Warrants”), and (iv) 1,385,000 shares of Resolute common stock subject to forfeiture in the event a trigger price of $15.00 is not exceeded within five years following the closing of the Resolute Transaction and that have no economic rights until such trigger is met (the “Resolute Earnout Shares”). Of the 9,200,000 shares of Resolute common stock issuable to Sub, 200,000 were issued to employees of Predecessor Resolute who became employees of Resolute upon closing of the Resolute Transaction in recognition of their services. 100,000 shares vested immediately and the remaining 100,000 shares will vest on the one year anniversary of the Acquisition Date, provided the recipient remains employed by the Company on that date. At the effective time of the Resolute Transaction, each outstanding share of HACI common stock was converted into the right to receive one share of Resolute common stock.
In connection with the Resolute Transaction, 7,335,000 shares of HACI’s common stock and 4,600,000 warrants to purchase HACI common stock held by the Sponsor were cancelled and forfeited and an additional 1,865,000 shares held by the Sponsor were converted into 1,865,000 Resolute Earnout Shares. As a result of the consummation of the Resolute Transaction, the Sponsor, together with its initial pre-public offering stockholders, owned (i) 4,600,000 shares of Resolute common stock, (ii) 9,200,000 Resolute Founders Warrants, (iii) 4,666,667 Resolute Sponsors Warrants, and (iv) 1,865,000 Resolute Earnout Shares.
At the effective time of the Resolute Transaction, each of the 55,200,000 outstanding warrants that were issued in HACI’s initial public offering (the “Public Warrants”) was converted, at the election of the warrantholder, into either (i) the right to receive $0.55 in cash or (ii) when properly tendered, the right to receive one warrant to purchase one share of Resolute common stock (a “Resolute Warrant”) at a exercise price of $13.00, subject to adjustment. The number of total Resolute Warrants was limited to 27,600,000. Warrants that were voted against the Warrant Amendment (as defined below) were, at the effective time of the Resolute Transaction, converted into the right to receive $0.55 in cash. Because more than 50% of the HACI warrantholders elected to receive Resolute Warrants, the properly voted and tendered warrants were exchanged pro rata. The Resolute Warrants have a five year life and are subject to redemption upon 30 days prior notice (as defined) at $.01 per Resolute Warrant, at the Company’s option, when the price of Resolute’s common stock equals or exceed $18.00 per share for a specified period.
How Resolute Evaluates Its Operations
Resolute’s management uses a variety of financial and operational measurements to analyze its operating performance. These measurements include: (i) production levels, trends and prices, (ii) reserve and production volumes and trends, (iii) operating expenses and general and administrative expenses, (iv) operating cash flow, and (v) EBITDA.
Production Levels, Trends and Prices. Oil and gas revenue is the product of Resolute’s production multiplied by the price that it receives for that production. Because the price that Resolute receives is highly dependent on many factors outside of its control, except to the extent that it has entered into hedging arrangements that can influence its net price either positively or negatively, production is the primary revenue driver over which it has
some influence. Although Resolute cannot greatly alter reservoir performance, it can aggressively implement exploitation activities that can increase production or diminish production declines relative to what would have been the case without intervention. Examples of activities that can positively influence production include minimizing production downtime due to equipment malfunction, well workovers and cleanouts, recompletions of existing wells in new parts of the reservoir, and expanded secondary and tertiary recovery programs. Total production for 2010 is expected to be between 2.7 and 2.8 MMBoe, or an average of 7,400 to 7,700 Boe per day.
The price of crude oil has been extremely volatile, and Resolute expects that this volatility will continue. Given the inherent volatility of crude oil prices, Resolute plans its activities and budget based on sales price assumptions that it believes to be reasonable. Resolute uses hedging arrangements to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices. These instruments limit its exposure to declines in prices, but also limit its expected benefits if prices increase. Changes in the price of oil or gas will result in the recognition of a non-cash gain or loss recorded in other income or expense due to changes in the fair value of the hedging arrangements. Recognized gains or losses only arise from payments made or received on monthly settlements of contracts or if a contract is terminated prior to its expiration. Resolute typically enters into hedging arrangements that cover a significant portion of its estimated future oil and gas production. Resolute currently has such hedging arrangements in place through 2012, with lesser volumes hedged in 2013. Resolute has oil and gas derivatives in place for 2010 covering the aggregate average daily oil volumes of 3,850 barrels of oil at NYMEX weighted average prices of $69.19; daily gas volumes of 3,800 MMBtu at NYMEX weighted average prices of $9.69; and 1,800 MMBtu per day of CIG basis gas hedges at $2.10 per MMBtu. These derivatives provide price protection on an estimated 66% at the midpoint of previously announced guidance relating to 2010 oil production and 55% at the midpoint of previously announced guidance relating to 2010 gas production.
Reserve and Production Volumes and Trends. From inception, Predecessor Resolute grew its reserve base through a focused acquisition strategy, completing three significant acquisitions. Predecessor Resolute acquired substantially all of its Aneth Field Properties through two significant purchases: the acquisition of the Chevron Properties was completed in November 2004 followed by the acquisition of the ExxonMobil Properties in April 2006. Predecessor Resolute acquired all of its Wyoming Properties through the purchase of Primary Natural Resources, Inc. (now known as Resolute Wyoming, Inc. (“RWI”)) in July 2008. Resolute looks to acquire similar producing properties that have upside potential through low-risk development drilling and exploitation projects. Resolute believes that its knowledge of various domestic, on shore operating areas, strong management and staff and solid industry relationships will allow it to find, capitalize on and integrate strategic acquisition opportunities.
At December 31, 2009, Resolute had estimated net proved reserves of approximately 42 MMBoe that were classified as proved developed non-producing and proved undeveloped. An estimated 40 MMBoe, or 95%, of those reserves are attributable to recoveries associated with expansions, extensions and processing of the tertiary recovery CO2 floods that are currently in operation on Resolute’s Aneth Field Properties. Resolute expects to incur approximately $377 million of capital expenditures over the next 28 years (including purchases of CO2 under existing contracts), in connection with bringing those incremental reserves attributable to Resolute’s CO2 flood projects into production. Resolute believes that these expenditures will result in significant increases in its oil and gas production.
Operating Expenses. Operating expenses are costs associated with the operation of oil and gas properties and are classified as lease operating expenses and production and ad valorem taxes. Direct labor, repair and maintenance, workovers, utilities and contract services comprise the most significant portion of lease operating expenses. Resolute monitors its operating expenses in relation to the amount of production and the number of wells operated. Some of these expenses are relatively independent of the volume of hydrocarbons produced, but may fluctuate depending on the activities performed during a specific period. Other expenses, such as taxes and utility costs, are more directly related to production volumes or reserves. Severance taxes, for example, are charged based on production revenue and therefore are based on the product of the volumes that are sold and the price received therefor. Ad valorem taxes are based on the value of reserves. Because Resolute operates on the Navajo Reservation, it also pays a possessory interest tax, which is effectively an ad valorem tax assessed by the Navajo Nation. Resolute’s largest utility expense is for electricity that is used primarily to power the pumps
in producing wells and the compressors behind the injection wells. The more fluid that is moved, the greater the amount of electricity that is consumed. In the recent past, higher oil prices led to higher demand for drilling rigs, workover rigs, operating personnel and field supplies and services, which in turn caused increases in the costs of those goods and services. Resolute projects 2010 cash lease operating expenses of $17.75 to $18.25 per Boe of production. Production taxes for 2010 are expected to be 13.5% to 14.5% of 2010 production revenue.
General and Administrative Expenses. Resolute monitors its general and administrative expenses carefully, attempting to balance the cash effect of incurring general and administrative costs against the benefits of, among other things, hiring and retaining highly qualified staff who can add value to the Company’s asset base. In the current period the Company’s general and administrative expenses were high, primarily due to costs incurred in consummating the Resolute Transaction. In future periods, absent other transactions, Resolute anticipates that general and administrative costs will be significantly lower. However, management anticipates that, effective with the Resolute Transaction, the Company will incur material additional annual general and administrative expenses that are associated with being a publicly traded company. These expenses include compensation and benefit expenses of certain additional personnel, increased fees paid to independent auditors, lawyers, independent petroleum engineers and other professional advisors, costs associated with shareholder reports, investor relations activities, registrar and transfer agent fees, increased director and officer liability insurance costs and director compensation. Resolute expects G&A expense will be $3.00 to $3.50 per Boe of production, excluding non-cash stock-based compensation expense.
Operating Cash Flow. Operating cash flow is the cash directly derived from Resolute’s oil and gas properties, before considering such things as administrative expenses and interest costs. Operating cash flow on a per unit of production basis is a measure of field efficiency, and can be compared to results obtained by operators of oil and gas properties with characteristics similar to Resolute’s to evaluate relative performance. Aggregate operating cash flow is a measure of Resolute’s ability to sustain overhead expenses and costs related to capital structure, including interest expenses.
EBITDA. EBITDA (a non-GAAP measure) is defined by the Company as consolidated net income adjusted to exclude interest expense, interest income, income taxes, depletion, depreciation and amortization, impairment expense, accretion of asset retirement obligation, change in fair value of derivative instruments, expiration of puts, non-cash equity-based compensation expense and noncontrolling interest. This definition is consistent with the definition of EBITDA in Resolute’s existing credit agreement. EBITDA is also a financial measure that Resolute expects will be reported to its lenders and used as a gauge for compliance with some of the financial covenants under its revolving credit facility.
EBITDA is used as a supplemental liquidity or performance measure by Resolute’s management and by external users of its financial statements such as investors, commercial banks, research analysts and others, to assess:
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the ability of Resolute’s assets to generate cash sufficient to pay interest costs;
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the financial metrics that support Resolute’s indebtedness;
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Resolute’s ability to finance capital expenditures;
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financial performance of the assets without regard to financing methods, capital structure or historical cost basis;
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Resolute’s operating performance and return on capital as compared to those of other companies in the exploration and production industry, without regard to financing methods or capital structure; and
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the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. Because Resolute has borrowed money to finance its operations, interest expense is a necessary element of its costs and its ability to generate gross margins. Because Resolute uses capital assets, depletion, depreciation and amortization are
also necessary elements of its costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, Resolute believes that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as EBITDA, to evaluate its financial performance and liquidity. EBITDA excludes some, but not all, items that affect net income, operating income and net cash provided by operating activities and these measures may vary among companies. Resolute’s EBITDA may not be comparable to EBITDA or EBITDA of any other company because other entities may not calculate these measures in the same manner.
Factors That Significantly Affect Resolute’s Financial Results
Revenue, cash flow from operations and future growth depend substantially on factors beyond Resolute’s control, such as economic, political and regulatory developments and competition from other sources of energy. Crude oil prices have historically been volatile and may be expected to fluctuate widely in the future. Sustained periods of low prices for crude oil could materially and adversely affect Resolute’s financial position, its results of operations, the quantities of oil and gas that it can economically produce, and its ability to obtain capital.
Like all businesses engaged in the exploration for and production of oil and gas, Resolute faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. Resolute attempts to overcome this natural decline by implementing secondary and tertiary recovery techniques and by acquiring more reserves than it produces. Resolute’s future growth will depend on its ability to enhance production levels from existing reserves and to continue to add reserves in excess of production. Resolute will maintain its focus on costs necessary to produce its reserves as well as the costs necessary to add reserves through production enhancement, drilling and acquisitions. Resolute’s ability to make capital expenditures to increase production from existing reserves and to acquire more reserves is dependent on availability of capital resources, and can be limited by many factors, including the ability to obtain capital in a cost-effective manner and to timely obtain permits and regulatory approvals.
Results of Operations
Through September 24, 2009, HACI’s efforts had been primarily limited to organizational activities, activities relating to its initial public offering, activities relating to identifying and evaluating prospective acquisition candidates, and activities relating to general corporate matters; HACI had not generated any revenue, other than interest income earned on the proceeds of its initial public offering.
For the purposes of management’s discussion and analysis of results of operations of Resolute, management has analyzed the year ended December 31, 2009, in comparison to the year ended December 31, 2008, for HACI. Any references to the 2009 or 2008 period refer to these specific periods and companies. However, as a result of the Resolute Transaction, the 2009 period includes 98 days of oil and gas operations, while the 2008 period has no such activity.
Key measurements for the year ended December 31, 2009 were as follows:
Subsequent to the Acquisition Date, the results of operations include Resolute and its subsidiaries (including HACI). For the year ended December 31, 2009, Resolute had a loss before income taxes of $65.1 million, a decrease of $71.1 million, as compared to income before income taxes of approximately $6.0 million for the year ended December 31, 2008. The decrease is primarily attributable to $16.6 million of Resolute Transaction costs, $46.3 million of unrealized losses related to the change in the fair value of our derivative instruments and a $6.8 million decrease in interest income during the year ended December 31, 2009. For the year ended December 31, 2009, Resolute earned approximately $0.8 million in interest income, as compared to $7.6 million in 2008. Interest income decreased in 2009 due to a decrease in cash and cash equivalents and cash held in trust, as well as a decrease in interest rates as a result of market conditions.
For the year ended December 31, 2008, Resolute had income before income taxes of approximately $6.0 million, an increase of $1.9 million as compared to income before income taxes of $4.1 million for the year ended December 31, 2007. The increase is primarily attributable to $2.4 million of additional interest income in 2008. For the year ended December 31, 2008, Resolute earned approximately $7.6 million in interest income, as compared to $5.2 million in 2007. Interest income increased in 2008 due to a significant increase in cash and cash equivalents as well as a full year of operations versus ten months of operations in 2007.
Revenue, lease operating expenses, depletion, depreciation, amortization and asset retirement obligation accretion, interest expense and loss on derivative instruments for the periods prior to September 25, 2009, relate solely to Predecessor Resolute’s operations and are not included in the Resolute Management Discussion and Analysis. For additional management discussion and analysis of the results of the acquired business, please see the management discussion and analysis for the Predecessor Resolute in this Annual Report on Form 10-K below.
Unaudited Pro Forma Results of Operations
The following unaudited pro forma consolidated financial information below is provided to supplement the financial statement presentations contained in this Form 10-K. Such unaudited pro forma data is prepared as if the Resolute Transaction and the 2008 acquisition of a net profits interest by RWI occurred on January 1, 2008. These pro forma results eliminate certain activities of HACI as well as certain other non-recurring items in order to present what the Company believes is representative of the underlying business of the Company. The unaudited pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved if the Resolute Transaction had taken place at the beginning of the earliest period presented or that may result in the future. The pro forma adjustments made are based on certain assumptions that Resolute believes are reasonable based on currently available information.
The pro forma loss from operations was $26.6 million in 2009, a decrease of $149.6 million, or 85%, as compared to the pro forma loss from operations of $176.2 million in 2008. The components of this decrease are analyzed below.
Pro forma revenue was $127.8 million in 2009, a decrease of $107.8 million, or 46%, as compared to the $235.6 million in 2008. The decrease in pro forma revenue was principally due to the 41% decrease in average sales price to $47.07 per Boe in 2009 from $80.02 in 2008. Additionally, pro forma production declined 8% to 2.7 MMBoe in 2009 from 2.9 MMBoe in 2008, principally due to the loss of production from CBM wells that produced during all of 2008, but were shut-in during a majority of 2009 due to low commodity prices.
Pro forma combined lease operating expenses and production and ad valorem taxes were $68.8 million in 2009, a decrease of $21.2 million, or 24%, as compared to $90.0 million in 2008. Pro forma production taxes declined $10.8 million, or 37%, principally as a result of lower revenue, and lease operating expenses declined $10.4 million, or 17%, as Resolute and Predecessor Resolute endeavored to reduce lease operating and workover costs during the low commodity price environment in 2009.
Pro forma general and administrative (and write-off of deferred acquisition costs) expenses were $31.9 million in 2009, an increase of $10.1 million, or 46%, as compared to $21.8 million in 2008. The increase is principally due to the $19.1 million of acquisition and transaction costs expensed in 2009, as compared to the $5.1 million of similar costs in 2008. Offsetting decreases were principally due to the $3.7 million of equity-based compensation in 2009, as compared to the $7.9 million of similar cost in 2008.
Pro forma depletion, depreciation, amortization and accretion expense was $40.1 million in 2009, a decrease of $14.9 million, or 27%, as compared to the $55.0 million in 2008. The decrease is partially due to the 8% decrease in pro forma production noted above, but is primarily due to the lower pro forma carrying cost of proved oil and gas properties in 2009 following the $245.0 million of impairment of proved properties recorded at December 31, 2008, and the additional $13.3 million impairment recorded at March 31, 2009.
Liquidity and Capital Resources
During 2009, the Company used $12.2 million in operating activities, primarily as a result of changes in working capital, provided $210.0 million in investing activities for the Resolute Transaction, and used $198.2 million in financing activities from equity purchase agreements related to the Resolute Transaction. At December 31, 2009, the Company had $0.5 million in cash and $109.6 million in debt outstanding under its Credit Facility (as defined below). Unused availability under the Credit Facility at December 31, 2009, was $121.9 million. Subsequent to December 31, 2009, Resolute’s primary sources of liquidity are expected to be cash generated from operating activities, amounts available under its Credit Facility and funds from future private and public equity and debt offerings. Resolute does not anticipate paying dividends to holders of its common stock.
Resolute plans to reinvest a sufficient amount of its cash flow in its development operations in order to maintain its production over the long term, and plans to use external financing sources as well as cash flow from operations and cash reserves to increase its production.
If cash flow from operating activities does not meet expectations, Resolute may reduce its expected level of capital expenditures and/or fund a portion of its capital expenditures using borrowings under its Credit Facility, issuances of debt and equity securities or from other sources, such as asset sales. There can be no assurance that needed capital will be available on acceptable terms or at all. Resolute’s ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in its credit facility. If Resolute is unable to obtain funds when needed or on acceptable terms, it may not be able to complete acquisitions that may be favorable to it or finance the capital expenditures necessary to maintain production or proved reserves.
If Resolute incurs significant indebtedness in the future, its ability to obtain additional financing may be impaired, its ability to make changes in its business may become impaired due to covenant restrictions, a significant portion of its cash flow will be used to make payments in respect of principal and interest on the debt, rather than being available for operating or capital expenditures, and thus put Resolute at a competitive disadvantage as compared to its competitors that have less debt, and may limit its ability to pursue other business opportunities.
Resolute plans to continue its practice of hedging a significant portion of its production. Hedge arrangements are generally settled within five days of the end of the month. As is typical in the oil and gas industry, however, Resolute does not generally receive the proceeds from the sale of its crude oil production until the 20th day of the month following the month of production. As a result, when commodity prices increase above the fixed price in the derivative contacts, Resolute will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before receiving the proceeds from the sale of the hedged production. If this occurs, Resolute may use working capital borrowings to fund its operations.
Revolving Credit Facility
Resolute’s credit facility is with a syndicate of banks led by Wachovia Bank, National Association (the “Credit Facility”) with Aneth as the borrower. The Credit Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value and future cash flows of Resolute’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base is re-determined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such re-determinations. Under certain circumstances, either Resolute or the lenders may request an interim re-determination. As of December 31, 2009, the borrowing base was $240 million and unused availability under the borrowing base was $121.9 million. The borrowing base availability has been reduced by $8.5 million in conjunction with letters of credit issued to vendors at December 31, 2009.
The Credit Facility matures on April 13, 2011 and, to the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity.
The outstanding balance under the Credit Facility accrues interest, at Aneth’s option, at either (a) the London Interbank Offered Rate, plus a margin which varies from 2.5% to 3.5%, or (b) the Alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Federal Funds Effective Rate plus 0.5%, plus a margin which varies from 1.0% to 2.0%. Each such margin is based on the level of utilization under the borrowing base. As of December 31, 2009, the weighted average interest rate on the outstanding balance under the facility was 3.30%. The Credit Facility is collateralized by substantially all of the proved oil and gas assets of Aneth and RWI, and is guaranteed by Resolute and its subsidiaries other than Aneth.
The Credit Facility includes terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Resolute was in compliance with all terms and covenants of the Credit Facility at December 31, 2009.
On March 30, 2010, the Company entered into a Restated Credit Agreement (the “Restated Agreement”). Under the terms of the Restated Agreement, the borrowing base was increased from $240.0 million to $260.0 million and the maturity date was extended to March 2014. At Resolute’s option, the outstanding balance under the Credit Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 2.25% to 3.0% or (b) the Alternative Base Rate, defined as the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Federal Funds Effective Rate plus 0.5%, or (iii) an adjusted London Interbank Offered Rate plus 1%, plus a margin which ranges from 1.25% to 2.0%.
As of March 30, 2010, Resolute had borrowings of $115.4 million under the borrowing base, resulting in an unused availability of $136.1 million.
Off Balance Sheet Arrangements
Resolute does not have any off-balance sheet financing arrangements other than operating leases. Resolute has not guaranteed any debt or commitments of other entities or entered into any options on non-financial assets.
Contractual Obligations
Resolute has the following contractual obligations and commitments as of December 31, 2009:
1)
Included in long-term debt is the outstanding principal amount under Resolute’s Credit Facility. This table does not include future commitment fees, interest expense or other fees because the Credit Facility is floating rate instrument, and the Company cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.
2)
Operating equipment leases consist of compressors and other oil and gas field equipment used in the CO2 project.
3)
Under the terms of Resolute’s purchase agreement with ExxonMobil, Resolute is obligated to make annual deposits into an escrow account that will be used to fund plugging and abandonment liabilities associated with the ExxonMobil Properties.
4)
Represents the minimum take-or-pay quantities associated with Resolute’s existing CO2 purchase contracts. For purposes of calculating the future purchase obligation under these contracts, Resolute has assumed the purchase price over the term of the contracts was the price in effect as of December 31, 2009.
5)
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. Resolute’s total asset retirement obligations were $9.2 million at December 31, 2009.
Critical Accounting Policies
The discussion and analysis of Resolute’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires Resolute to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. The application of accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Resolute evaluates estimates and assumptions on a regular basis. Resolute bases estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ, perhaps materially, from these estimates and assumptions used in preparation of Resolute’s financial statements. Provided below is an expanded discussion of the most significant accounting policies, estimates and judgments. Resolute believes these accounting policies reflect Resolute’s most significant estimates and assumptions used in the preparation of the financial statements.
Oil and Gas Properties. Resolute uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, improved recovery systems and a portion of general and administrative expenses are capitalized within the cost center.
Resolute conducts tertiary recovery projects on a portion of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Under the full cost method, all development costs are capitalized at the time incurred. Development costs include charges associated with access to and preparation of well locations, drilling and equipping development wells, test wells, and service wells including injection wells; acquiring, constructing, and installing production facilities and providing for improved recovery systems. Improved recovery systems include all related facility development costs and the cost of the acquisition of tertiary injectants, primarily purchased CO2. The development cost related to CO2 purchases are incurred solely for the purpose of gaining access to incremental reserves not otherwise recoverable. The accumulation of injected CO2, in combination with additional purchased and recycled CO2, provide future economic value over the life of the project.
In contrast, other costs related to the daily operation of the improved recovery systems include, but are not limited to, compression, electricity, separation, re-injection of recovered CO2 and water, are considered production costs and are expensed as incurred. Costs incurred to maintain reservoir pressure are also expensed as incurred.
Capitalized general and administrative 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.
Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary
lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense as appropriate.
Pursuant to full cost accounting rules, Resolute must perform a ceiling test each quarter on its proved oil and gas assets. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs.
No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil reserves of the cost center.
Depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of asset retirement obligations and future development costs of proved reserves, including, but not limited to, costs to drill and equip development wells, constructing and installing production and processing facilities, and improved recovery systems including the cost of required future CO2 purchases.
Oil and Gas Reserve Quantities. Resolute’s estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows affect Resolute’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. Resolute prepares reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC and FASB guidelines. The accuracy of Resolute’s reserves estimates is a function of many factors including but not limited to the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Resolute’s proved reserves estimates are a function of many assumptions, any or all of which could deviate significantly from actual results. As such, reserves estimates may vary materially from the ultimate quantities of oil, gas and natural gas liquids reserves eventually recovered.
Derivative Instruments and Hedging Activities. Resolute enters into derivative contracts to manage its exposure to oil and gas price volatility. Derivative contracts may take the form of futures contracts, swaps or options. Realized and unrealized gains and losses related to commodity derivatives are recognized in other income (expense). Realized gains and losses are recognized in the period in which the related contract is settled. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the consolidated statement of cash flows.
FASB Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging, requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of a derivative are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivative hedging instruments must be recorded in either other comprehensive income or current earnings, depending on the nature and designation of the instrument. Presently, Resolute’s management has determined that the benefit of the financial statement presentation available under the provisions of FASB ASC Topic 815, which may allow for its derivative instruments to be reflected as cash flow hedges, is not commensurate with the administrative burden required to support that treatment. As a result,
Resolute marked its derivative instruments to fair value in accordance with the provisions of FASB ASC Topic 815 and recognized the changes in fair market value in earnings. Gains and losses on derivative instruments reflected in the consolidated statement of operations incorporate both realized and unrealized values.
Asset Retirement Obligations. Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
Resolute’s estimated asset retirement obligation liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.
Equity-Based Compensation. Resolute accounts for stock-based compensation in accordance with FASB ASC Topic 718, which requires it to measure the grant date fair value of equity awards given to employees in exchange for services, and to recognize that cost, less estimated forfeitures, over the period that such services are performed.
Income taxes. Deferred tax assets and liabilities are recorded to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The ability to realize the deferred tax assets is routinely assessed. If the conclusion is that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance. The future taxable income is considered when making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). Income tax positions are also required to meet a more-likely-than-not recognition threshold to be recognized in the financial statements. Tax positions that previously failed to meet the more-likely-than-not threshold are recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not threshold are derecognized in the first subsequent financial reporting period in which that threshold is no longer met.
Accounting Standards Update
In June of 2009, the FASB established the ASC as the single source of authoritative GAAP for all non-governmental entities with the exception of authoritative guidance from the SEC. All other accounting literature is considered non-authoritative. The ASC changes the way the Company cites authoritative guidance within the Company’s financial statements and notes to the financial statements. The ASC is effective for periods ending on or after September 15, 2009, and did not have a material impact on the Company’s consolidated financial statements.
Resolute adopted FASB ASC Topic 805, Business Combinations, on January 1, 2009. This guidance establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the contingent and identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The nature and magnitude of the specific effects of this guidance on the consolidated financial statements will depend upon the nature, terms and size of the acquisitions consummated after the effective date.
In January 2010, the FASB issued additional guidance to improve disclosure requirements related to fair value measurements and disclosures. Specifically, this guidance requires disclosures about transfers in and out of Level 1 and 2 fair value measurements, activity in Level 3 fair value measurements (See Note 12 of the Resolute Energy Corporation Consolidated Financial Statements for Level 1, 2 and 3 definitions), greater desegregation of
the amounts on the consolidated balance sheets that are subject to fair value measurements and additional disclosures about the valuation techniques and inputs used in fair value measurements. This guidance is effective for annual reporting periods beginning after December 31, 2009, except for disclosure of Level 3 fair value measurement roll forward activity, which is effective for annual reporting periods beginning after December 15, 2010. The Company is currently assessing the impact this guidance will have on the consolidated financial statements.
On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system. This system, which was developed by several industry organizations, is a widely accepted standard for the management of petroleum resources. Key revisions include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The FASB ASC was updated in January of 2010 to align the oil and gas reserve estimation and disclosure requirements in the ASC with the SEC’s oil and gas reporting requirements. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. Resolute adopted the requirements for the year ended December 31, 2009 and the consolidated financial statements were affected in the following manner:
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The price used in calculating reserves changed from a single-day closing price measured on the last day of the Company’s fiscal year to a 12-month average first of the month price for the previous twelve months as of the balance sheet date. This average price was utilized in the Company’s depletion and ceiling test calculations.
•
The notes to the consolidated financial statements include additional financial reporting disclosures.
PREDECESSOR RESOLUTE
The following section of MD&A addresses the period-to-period comparisons of operating results for Predecessor Resolute.
Period Ended September 24, 2009, Compared to the Year Ended December 31, 2008
For the purposes of management’s discussion and analysis of results of operations of Predecessor Resolute, management has presented the 267 day period ended September 24, 2009 in comparison to the 366 day year ended December 31, 2008. Any references to the 2009 or 2008 period refer to these specific periods. As such, the 2009 period is 27.0% shorter than the 2008 period.
Revenue. Revenue from oil and gas activities decreased to $85.3 million during 2009, from $229.2 million during 2008. The key revenue measurements were as follows:
Total production decreased 28.8% during 2009 as compared to 2008, decreased only 2.4% during 2009 on a daily basis as compared to 2008. The overall production decrease was primarily due to shut-in of CBM wells in 2009 that were producing in 2008 and the shorter 2009 production period. This decrease was mitigated on a daily basis by increased CO2 production response in Aneth versus 2008. The average sales price per Boe decreased by 47.7% in 2009 as compared to 2008 due to lower commodity pricing in 2009.
Operating Expenses. Operating expenses consists of lease operating expense, depletion, depreciation and amortization, impairment of proved property and general administrative expenses. Predecessor Resolute assessed lease operating expenses in part by monitoring the expenses in relation to production volumes and the number of wells operated.
Lease operating expenses consist of lease operating expenses, including labor, field office rent, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, workover expenses, ad valorem, severance and other taxes and other customary charges.
Lease operating expenses per Boe decreased during 2009 as compared to 2008 as follows:
Lease operating expenses decreased to $46.8 million during 2009, from $86.0 million during 2008. The $39.2 million, or 45.6%, decrease was principally attributable to an approximately $16.5 million decrease in ad valorem, severance and other taxes generally caused by lower sales, $5.8 million decrease in workover expenses, $6.0 million decrease in labor costs and a $4.1 million decrease in equipment materials and supplies, as well as the shorter 2009 operating period.
Depletion, depreciation, amortization and accretion expenses decreased to $21.9 million during 2009, as compared to $50.3 million during 2008. The $28.4 million, or 56.5%, decrease is principally due to a decrease in the per Boe depletion, depreciation and amortization rate from $17.83 per Boe in 2008 to $10.90 per Boe in 2009 due to the reduction in the carrying value of proved oil and gas properties in 2009 following the impairment of proved properties at December 31, 2008 and March 31, 2009.
Pursuant to full cost accounting rules, Predecessor Resolute performed a ceiling test each quarter on its proved oil and gas assets. As a result of this limitation on capitalized costs, Predecessor Resolute included a provision for an impairment of oil and gas property costs for 2009 and 2008 of $13.3 million and $245.0 million, respectively.
General and administrative expenses include the costs of Predecessor Resolute’s employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. Predecessor Resolute monitors general and administrative expenses in relation to the amount of production and the number of wells operated.
General and administrative expenses decreased to $8.1 million during 2009, as compared to $20.2 million during 2008. The $12.1 million, or 60.0%, decrease in the absolute level of general and administrative expenses principally resulted from a $5.1 million decrease in non-cash charges to compensation expense associated with equity-based compensation, a $4 million decrease in salaries and wages, and a $1.8 million decrease in professional fees.
Other Income (Expense). All oil and gas derivative instruments are accounted for under mark-to-market accounting rules, which provide for the fair value of the contracts to be reflected as either an asset or a liability on the balance sheet. The change in the fair value during an accounting period is reflected in the income statement for that period. During 2009, the fair value of oil and gas derivatives decreased by $23.5 million. This amount included approximately $1.9 million of realized gains on oil and gas derivatives, including a realized loss of $12.5 million that was incurred to cash settle a 2010 hedge position as required under the terms of the Resolute Transaction and $25.4 million of decreases in the unrealized future value of oil and gas derivatives. During 2008, the fair value of oil and gas derivatives increased by $96.0 million. This amount included approximately $120.6 million of unrealized gain in the future value of oil and gas derivatives and $24.6 million of realized losses from monthly settlements.
Interest expense was $18.4 million during 2009, as compared to $33.1 million during 2008. The $14.7 million, or 44.4%, decrease is attributable to lower interest rates and to the shorter 2009 period.
Income Tax Benefit (Expense). Income tax benefit recognized during 2009 was $5.0 million, as compared to an income tax benefit of $18.3 million in 2008. The 2009 period included the effect of the reversal of a $0.4 million contingent tax liability due to the expiration of the statute of limitations and recording $14.4 million in deferred income tax expense.
Year Ended December 31, 2008, Compared to the Year Ended December 31, 2007
Revenue. Revenue increased to $229.2 million during 2008, from $173.3 million during 2007. The key revenue measures were as follows:
The increase in revenue was primarily due to a 29.3% increase in the average sales price in 2008 excluding hedges as compared to the average sales price in 2007, as well as a 2% increase in production in 2008. The increase in production is due in part to Predecessor Resolute’s ongoing efforts to enhance day-to-day production
in its Aneth Field Properties. Average sales price, excluding the effects of hedges, increased to $81.19 per Boe during 2008, as compared to $62.81 per Boe during 2007.
Lease Operating Expenses. Lease operating expenses increased to $86.0 million for 2008, from $66.7 million for 2007. The increase of $19.3 million in lease operating expenses for 2008, was attributable to an $8.9 million increase in production taxes due principally to higher product prices, a $3.7 million increase in field services, a $2.4 million increase in repairs and maintenance and a $4.3 million increase in other costs. The increase in non-tax related production expense was due primarily to the escalation in virtually all oil and gas industry costs induced by the high levels of industry activity during 2008.
General and Administrative Expenses. General and administrative expenses decreased to $20.2 million during 2008, from $40.3 million during 2007, due primarily to the recognition of a non-cash charge to equity based compensation expense of $34.5 million in 2007 as compared to $7.9 million in 2008.
Impairment of Proved Properties. Pursuant to full cost accounting rules, Predecessor Resolute performed a ceiling test each quarter on its proved oil and gas assets. As a result of this limitation on capitalized costs, Predecessor Resolute included a provision for an impairment of oil and gas property cost for 2008 and 2007 of $245.0 and $0 million, respectively.
Depletion, Depreciation and Amortization Expenses. Depletion, depreciation and amortization increased to $50.3 million for 2008, from $27.8 million for 2007, due to an increase in the depletion, depreciation and amortization rate which primarily resulted from a reduction in future economic recoverable reserves associated with significantly reduced energy prices during the latter half of 2008.
Other Income (Expense). All of Predecessor Resolute’s oil and gas derivative instruments are accounted for under mark-to-market accounting rules, which provide for the fair value of the contracts to be reflected as either an asset or a liability on its balance sheet. During 2008, Predecessor Resolute recognized a $96.0 million gain on its derivative contracts. This amount included approximately $32.8 million of realized losses, which was partially offset by an $8.2 million gain on the forward sales of derivative contracts and a $120.6 million unrealized gain in the fair market value of these contracts. During 2007, the fair value of Predecessor Resolute’s oil hedges decreased by $106.2 million. This amount included approximately $4.7 million of realized losses and a $101.5 million decline in the future value of future contracts.
Interest expense was $33.1 million for 2008, compared to $35.9 million for 2007. The decrease is attributable to a reduction in long term debt during 2008 as well as a reduction in interest rates.
ITEM 7A.
ITEM 7A.
QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk and Hedging Arrangements
Resolute’s major market risk exposure is in the pricing applicable to oil and gas production. Realized pricing on Resolute’s unhedged volumes of production is primarily driven by the spot market prices applicable to oil production and the prevailing price for gas. Pricing for oil production has been volatile and unpredictable for several years, and Resolute expects this volatility to continue in the future. The prices Resolute receives for unhedged production depend on many factors outside of Resolute’s control.
Resolute periodically hedges a portion of its oil and gas production through swaps, puts, calls, collars and other such agreements. The purpose of the hedges is to provide a measure of stability to Resolute’s cash flows in an environment of volatile oil and gas prices and to manage Resolute’s exposure to commodity price risk.
Under the terms of its Credit Agreement the form of derivative instruments to be entered into is at Resolute’s discretion, not to exceed 80% of its anticipated production from proved developed producing properties utilizing economic parameters specified in its credit agreements, including escalated prices and costs.
By removing the price volatility from a significant portion of Resolute’s oil production, Resolute has mitigated, but not eliminated, the potential effects of changing prices on the cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, certain of these derivative contracts also limit the benefits Resolute would receive from increases in commodity prices. It is Resolute’s policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers.
As of December 31, 2009, Resolute had entered into certain commodity swap contracts. The following table represents Resolute’s commodity swaps with respect to its oil production through 2013:
Resolute also uses basis swaps in connection with gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the index price at which the gas production is sold. The table below sets forth Resolute’s outstanding basis swaps as of December 31, 2009:
As of December 31, 2009, Resolute had entered into certain commodity collar contracts. The following table represents Resolute’s commodity collars with respect to its oil and production:
Interest Rate Risk
At December 31, 2009, Resolute has $109.6 million of outstanding debt. Interest is calculated under the terms of the agreement based on a LIBOR spread. A 10% increase in LIBOR would result in an estimated $0.1 million increase in annual interest expense. Resolute does not currently intend to enter into any hedging arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.
Credit Risk and Contingent Features in Derivative Instruments
Resolute is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. All counterparties are also lenders under Resolute’s Credit Facility. For these contracts, Resolute is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Credit Facility. Resolute’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events, and set-off provisions. Resolute has set-off provisions with its lenders that, in the event of counterparty default, allow Resolute to set-off amounts owed under the Credit Facility or other general obligations against amounts owed for derivative contract liabilities.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is included below in “Item 15. Exhibits, Financial Statements Schedules”.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Attached as exhibits to this report are certifications of our CEO and CFO required pursuant to Rule 13a-14 under the Exchange Act. This section includes information concerning the controls and procedures evaluation referred to in the certifications. Our management, with the participation of Nicholas J. Sutton, our Chief Executive Officer, and Theodore Gazulis, our Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2009. Based on the evaluation, those officers have concluded that:
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our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
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our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Internal Control Over Financial Reporting
There has not been any change in the Company’s internal control over financial reporting that occurred during the quarterly period ended December 31, 2009, that has materially affected, or is reasonably likely to affect, the Company’s internal control over financial reporting.
The Company’s Annual Report on Form 10-K for the year ending December 31, 2009, does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
Not applicable
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE
Directors
The following table sets forth certain information as of March 29, 2010, regarding the composition of the Board of Directors, including the term of each director.
Nicholas J. Sutton is the Chief Executive Officer and has been a director of the Company since the Company’s formation in July 2009. Mr. Sutton has been the Chief Executive Officer and a member of the board of managers of Predecessor Resolute and of Holdings since their founding in 2004. Mr. Sutton was a co-founder and the Chief Executive Officer of HS Resources, Inc., a New York Stock Exchange listed company, from 1978 until the company’s acquisition by Kerr-McGee Corporation in late 2001. From 2002 until the formation of Resolute Holdings, LLC in 2004, Mr. Sutton was a director of Kerr-McGee. Currently, Mr. Sutton is a director of Tidewater, Inc., the owner and operator of the world’s largest fleet of vessels serving the global offshore oil industry, and a member of the Board of the St. Francis Memorial Hospital Foundation. He also is a member of the Society of Petroleum Engineers and of the American Association of Petroleum Geologists. In determining Mr. Sutton’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his experience and expertise in the oil and gas industry, his track record in growing public oil and gas companies, including managing acquisition programs, as well as his role in the founding of Holdings and the Resolute Transaction. In addition, Mr. Sutton has degrees in engineering and law, and has attended the Harvard Owner/President Management program, giving him expertise in all of the areas of importance to the Company.
James M. Piccone is the President, General Counsel, Secretary and has been a director of the Company since the Company’s formation in July 2009. Mr. Piccone has been the President, General Counsel, Secretary and a member of the board of managers of Predecessor Resolute and of Holdings since their formation in 2004. From January 2002 until January 2004 Mr. Piccone was Senior Vice President and General Counsel for Aspect Energy, LLC, a private oil and gas company. Mr. Piccone also served as a contract attorney for Aspect Energy from October 2001 until January 2002. Mr. Piccone served as Vice President - General Counsel and Secretary of HS Resources from May 1995 until the acquisition of HS Resources by Kerr-McGee in August 2001. Mr. Piccone is admitted to the practice of law in Colorado and is a member of local and national bar associations. He is a member of the American Association of Corporate Counsel. In determining Mr. Piccone’s qualifications to serve on our Board of Directors, the Board or Directors has considered, among other things, his management and legal expertise, his knowledge of the oil and gas industry and the role he played in the success of HS Resources and Holdings, including his role in the Resolute Transaction.
Richard L. Covington was elected to the Company’s Board of Directors in September 2009. Mr. Covington has been a member of the Compensation and Corporate Governance/Nominating Committees since September 25, 2009. He is a managing director of the Natural Gas Partners private equity funds. He has been a member of the board of managers of Holdings since its founding in 2004. Mr. Covington joined Natural Gas Partners in 1997. Prior to joining NGP, Mr. Covington was a senior shareholder at the law firm of Thompson & Knight, LLP, in Dallas, Texas. Mr. Covington serves on the investment committee of NGP Capital Resources
Company and as a director of numerous private energy companies. In determining Mr. Covington’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his experience and expertise in the legal and finance aspects of the oil and gas industry and his role as a key advisor to Resolute from the founding of Holdings to the present.
William H. Cunningham was elected to the Company’s Board of Directors in September 2009. Dr. Cunningham has been a member of the Audit Committee since September 25, 2009, and between September 25, 2009 and December 15, 2009 was also a member of the Compensation and Corporate Governance/Nominating Committees. He was a director of Hicks Acquisition Company I, Inc. from October 2007 through September 2009. Since 1979, Dr. Cunningham has served as a professor of marketing at the University of Texas at Austin and he has held the James L. Bayless Chair for Free Enterprise at the University of Texas at Austin since 1985. From 1983 to 1985 he was Dean of the College of Business Administration and Graduate School of Business of the University of Texas at Austin, from 1985 to 1992 he served as the President of the University of Texas at Austin and from 1992 to 2000 he served as the Chancellor (Chief Executive Officer) of the University of Texas System. Dr. Cunningham currently serves on the Board of Directors of Lincoln National Corporation, a New York Stock Exchange listed holding company for insurance, investment management, broadcasting and sports programming businesses; Southwest Airlines, an airline listed on the New York Stock Exchange; and Lin Television, a New York Stock Exchange listed company that owns a number of television stations. Dr. Cunningham currently serves as a member of the Board of Trustees of John Hancock Mutual Funds. Dr. Cunningham received a Bachelor of Business Administration degree in 1966, a Master of Business Administration degree in 1967 and a Ph.D. in 1971, each from Michigan State University. Dr. Cunningham was president and chief executive officer of IBT Technologies, a privately held e-learning company, from December 2000 through December 2001. IBT Technologies filed for bankruptcy in December 2001 and has been liquidated. In determining Mr. Cunningham’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his academic experience in corporate governance matters in law schools and graduate business programs, his service on more than 20 corporate boards, including in many instances as chairman of the audit committee of public companies, and his experience and expertise in marketing and management.
James E. Duffy was elected to the Company’s Board of Directors in September 2009. Mr. Duffy has been a member of the Compensation and Audit Committees since September 25, 2009, and between September 25, 2009 and December 15, 2009 was also a member of the Corporate Governance/Nominating Committee. He is a co-founder and, since 2003, Chairman of StreamWorks Products Group, Inc., a private consumer products development company that manufactures products for the sport fishing, industrial safety, specialty tool and outdoor recreation industries. From 1990 to 2001 he served as Chief Financial Officer and Director of HS Resources, Inc. until its sale to Kerr-McGee Corporation. Prior to that time, he served as Chief Financial Officer and Director of a division of Tidewater, Inc. He was also a general partner in a boutique investment banking business specializing in the oil and gas business, and began his career with Arthur Young & Co in San Francisco. He is a certified public accountant. In determining Mr. Duffy’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his experience and expertise in oil and gas finance, accounting, and banking as well as his position as chief financial officer of two public oil and gas companies and his service as an audit manager for a major accounting firm with engagement responsibility for public and private entities.
Kenneth A. Hersh was elected to the Company’s Board of Directors in September 2009. Mr. Hersh has been a member of the Compensation and Corporate Governance/Nominating Committees since September 25, 2009. He is the Chief Executive Officer of NGP Energy Capital Management, L.L.C. and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1989. He has been a member of the board of managers of Holdings since its founding in 2004. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of the energy group in the investment banking division of Morgan Stanley & Co. He currently serves on the investment committee and as a director of NGP Capital Resources Company, serves as a director of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy Partners, L.P., and as a director of numerous private companies. In determining Mr. Hersh’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his experience and expertise in finance,
investment banking and management in the energy industry and his extensive record of investing in and helping to develop numerous private and public oil and gas companies.
Thomas O. Hicks, Jr. was elected to the Company’s Board of Directors in September 2009. Mr. Hicks has been a member of the Corporate Governance/Nominating Committee since September 25, 2009, and between September 25, 2009 and December 15, 2009 was also a member of the Compensation Committee. He was a vice president of HACI from February 2007 through September 2009 and was its secretary from August 2007 to September 2009. Mr. Hicks has served as a vice president of Hicks Holdings since 2005. Hicks Holdings is a Dallas-based family holding company for the Hicks family and a private investment firm which owns and manages assets in sports and real estate and makes corporate acquisitions. Mr. Hicks has served as Alternate Governor for the Dallas Stars Hockey Club. In 2004 and 2005, Mr. Hicks served as Director, Corporate and Suite Sales, for the Texas Rangers Baseball Club. From 2001 to 2003, Mr. Hicks was an analyst at Greenhill & Co. LLC, a New York based merchant banking firm. As an analyst, Mr. Hicks was involved in numerous private equity, mergers and acquisition advisory and financial restructuring transactions. Mr. Hicks currently serves as the chairman of the Campaign for Children in Crisis for Big Brother Big Sisters Organization of North Texas, and is on the boards of Big Brothers Big Sisters of North Texas, the Texas Rangers Foundation, Capital for Kids and is a member of Business Executives for National Security. In determining Mr. Hick’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his experience and expertise in sales, banking and management.
William J. Quinn was elected to the Company’s Board of Directors in September 2009. Mr. Quinn has been a member of the Compensation Committee since September 25, 2009, and between September 25, 2009, and December 15, 2009, was also a member of the Corporate Governance/Nominating Committee. He is the Executive Vice President of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds, having served in those or similar capacities since 1998. He has been a member of the board of managers of Holdings since its founding in 2004. He currently serves on the investment committee of NGP Capital Resources Company, and is a director of Eagle Rock Energy Partners, L.P., and of its general partner, Eagle Rock Energy G&P, LLC. He also serves as a member of the board of numerous private energy companies. In determining Mr. Quinn’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his extensive experience and expertise in finance and in the energy industry.
Robert M. Swartz was elected to the Company’s Board of Directors in September 2009. Mr. Swartz has been a member of the Audit Committee since September 25, 2009, and between September 25, 2009, and December 15, 2009, was also a member of the Compensation and Corporate Governance/Nominating Committees. He was a senior vice president of HACI from September 2007 until September 2009, and currently serves as a managing director and partner of Hicks Equity Partners LLC. Mr. Swartz is on the Board of Directors of Anvita Health. From 1999 until 2007, Mr. Swartz served in various positions at Centex Corporation, a New York Stock Exchange home building company, serving as Senior Vice President of Strategic Planning and Mergers and Acquisitions from 1999 to 2000 and serving as Chairman and Chief Executive Officer of Centex HomeTeam Services from 2000 to 2007. From 1997 until 1999, Mr. Swartz served as Executive Vice President of FirstPlus Financial Group, Inc., a consumer finance company in Dallas, Texas. In 1996, Mr. Swartz served as president and chief executive officer of AMRE, Inc. a nationwide home services provider. From 1994 to 1995, Mr. Swartz served as President of Recognition International, an NYSE high-technology company and previously served from 1990 to 1993 as that company’s chief financial officer. Mr. Swartz received a Bachelors of Science degree in accounting from the State University of New York in Albany in 1973 and a Master of Business Administration degree in finance from New Hampshire College in 1976. Mr. Swartz is a Certified Public Accountant. In determining Mr. Swartz’s qualifications to serve on our Board of Directors, the Board of Directors has considered, among other things, his experience and expertise in mergers and acquisitions, finance, accounting and management.
Current Executive Officers
The following table sets forth certain information as of March 29, 2010, regarding the current executive officers of the Company.
Nicholas J. Sutton - See above under Directors for Mr. Sutton’s biography.
James M. Piccone - See above under Directors for Mr. Piccone’s biography.
Richard F. Betz has been Senior Vice President of the Company since September 25, 2009, and was Vice President - Business Development of the Company from July 2009 to September 2009. He has been Vice President, Business Development of Predecessor Resolute and Holdings since their founding in 2004. From September 2001 to January 2004, Mr. Betz was involved in various financial consulting activities related to the energy industry. Prior to that, Mr. Betz spent seventeen years with Chase Securities and successor companies, where he was involved primarily in oil and gas corporate finance. Mr. Betz was a Managing Director in the oil and gas investment banking coverage group with primary responsibility for mid-cap exploration and production companies as well as leveraged finance and private equity. In that capacity, Mr. Betz worked with the HS Resources management team for approximately twelve years.
Dale E. Cantwell has been Senior Vice President, Operations of the Company since September 25, 2009, and was Vice President - Operations of the Company from July 2009 to September 2009. He has been Vice President, Operations of Predecessor Resolute and Holdings since their founding in 2004. From March 2003 to January 2004, Mr. Cantwell was a private investor. After the acquisition of HS Resources by Kerr-McGee in August 2001 until February 2003, Mr. Cantwell was Vice President of Kerr-McGee Rocky Mountain Corporation. Prior to that, Mr. Cantwell was Vice President of Operations for HS Resources D-J Basin District. From 1979 until joining HS Resources in 1993, he worked for Amoco Production Company in various engineering and marketing capacities. Mr. Cantwell is a member of the Society of Petroleum Engineers.
Theodore Gazulis has been Senior Vice President and Chief Financial Officer of the Company since September 25, 2009, and was Vice President of Finance, Chief Financial Officer and Treasurer of the Company from July 2009 to September 2009. He has been Vice President - Finance, Treasurer and Assistant Secretary of Predecessor Resolute and Holdings since their founding in 2004. Mr. Gazulis served as a Vice President of HS Resources from 1984 until its merger with Kerr-McGee in 2001. Mr. Gazulis had primary responsibility for HS Resources’ capital markets activity and for investor relations and information technology. Subsequent to HS Resources’ acquisition by Kerr-McGee and prior to the formation of Resolute Natural Resources Company, Mr. Gazulis was a private investor and also undertook assignments with two privately-held oil and gas companies, serving on the Board of Directors of Contour Energy Co. and performing the functions of the Chief Financial Officer of Venoco, Inc. on a consulting basis. Prior to joining HS Resources, he worked for Amoco Production Company and Sohio Petroleum Company. He is a member of the American Association of Petroleum Geologists.
Janet W. Pasque has been Senior Vice President, Land and Development of the Company since September 25, 2009, and was Vice President - Land of the Company from July 2009 to September 2009. She has been Vice President, Land of Predecessor Resolute and Holdings since their founding in 2004. Ms. Pasque was a Vice President of HS Resources where she had responsibility for the land department and joint responsibility for the company’s exploration activities from 1993 until the company’s acquisition by Kerr-McGee in late 2001. Subsequent to the HS Resources acquisition by Kerr-McGee, Ms. Pasque managed the land functions
at Kerr-McGee Rocky Mountain Corp. until early 2003. Ms. Pasque served as a land consultant from 2003 until the founding of Resolute Holdings, LLC in 2004. Prior to joining HS Resources in 1993, Ms. Pasque worked for Texaco Inc. and Champlin Petroleum Company. Ms. Pasque is a member of the American Association of Professional Landmen.
Family Relationships
There are no family relationships among any of the Company’s directors and executive officers.
The Company Board of Directors and Committees
Director Independence
Under the rules of the NYSE, a majority of the members of the Board of Directors and all of the members of certain committees must be composed of “independent directors,” as defined in the rules of the NYSE. In general, an “independent director” is a person other than an officer or employee of the Company or any other individual who has a relationship, which, in the opinion of the Company’s Board of Directors, would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Additional independence and qualification requirements apply to our directors serving on certain committees. The Company has standing audit, compensation, corporate governance/nominating and finance committees, each of which is composed entirely of independent directors, under each of the applicable standards. The Company’s Board of Directors has determined that, other than Messrs. Sutton and Piccone, each member of the Board of Directors is independent under the NYSE rules. In making that determination, the Board of Directors considered the relationships of Messrs. Swartz, and Hicks with HACI and HH-HACI, L.P., a Delaware limited partnership, and the relationships of Messrs. Hersh, Covington and Quinn with various NGP entities.
General
The Company’s business is managed under the direction of its Board of Directors. In connection with its oversight of the Company’s operations and governance, the Board of Directors has adopted, among other things, the following:
•
Corporate Governance Guidelines to implement certain policies regarding the governance of the Company;
•
a Code of Business Conduct and Ethics to provide guidance to directors, officers and employees with regard to certain ethical and compliance issues;
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Charters of the Audit Committee, the Compensation Committee and the Corporate Governance/Nominating Committee of the Board of Directors;
•
an Insider Trading Policy to facilitate compliance with insider trading regulations;
•
an Audit Committee Whistleblower Policy to allow directors, officers and employees (i) to make confidential anonymous submissions regarding concerns with respect to accounting or auditing matters and (ii) provides for the receipt of complaints regarding accounting, internal controls or auditing; and
•
a Stockholder and Interested Parties Communication Policy pursuant to which holders of our securities and other interested parties can communicate with the Board of Directors, Board Committees and/or individual directors.
Other than the Insider Trading Policy, each of these documents can be viewed on the Company’s website, available at: www.resoluteenergy.com under the “Investor Relations” tab, subheading “Corporate Governance.” Copies of the foregoing documents and disclosures are available without charge to any person who requests them. Requests should be directed to Resolute Energy Corporation, Attn: Secretary, 1675 Broadway, Suite 1950, Denver, Colorado 80202.
Non-Management Sessions
The Board of Directors schedules regular executive sessions involving exclusively non-management directors as required by NYSE rules. Mr. Covington, as the Lead Independent Director, presides at all such executive sessions
Audit Committee
The Company has a separately designated Audit Committee, the members of which are Messrs. Duffy, Cunningham and Swartz, with Mr. Swartz serving as Chairman. The primary function of the Audit Committee is to assist the Board of Directors in its oversight of its financial reporting process. Among other things, the committee is responsible for reviewing and selecting our independent registered public accounting firm and reviewing our accounting practices and policies, and to serve as an independent and objective party to monitor the financial reporting process. The Board of Directors has determined that each of Mr. Swartz, Mr. Duffy and Mr. Cunningham qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of SEC Regulation S-K and that each member of the committee is independent for purposes of SEC Rule 10A-3, and “financially literate” for purposes of applicable NYSE rules. See “Directors, Executive Officers and Corporate Governance - Directors” for a summary of the business experience of each member of the committee.
Corporate Governance/Nominating Committee
The charter of the corporate governance/nominating committee provides that director candidates recommended by security holders will be considered on the same basis as candidates recommended by other persons. A security holder who wishes to recommend a candidate should send complete information regarding the candidate to Resolute Energy Corporation, Attn: Secretary, 1675 Broadway, Suite 1950, Denver, Colorado 80202. The information provided with respect to the nominee should include five years of professional background, academic qualifications, whether the nominee has been subject to any legal proceedings in the past 10 years, the relationship between the security holder and the nominee, and any other specific experience, qualifications, attributes or skills that qualify the nominee for the board. The committee will assess each candidate, including candidates recommended by security holders, by evaluating all factors it considers appropriate, which may include career specialization, relevant technical skills or financial acumen, diversity of viewpoint and industry knowledge. The charter provides that nominees must meet certain minimum qualifications. In particular, a nominee must:
•
have displayed the highest personal and professional ethics, integrity and values and sound business judgment;
•
be highly accomplished in his or her field, with superior credentials and recognition and broad experience at the administrative or policy-making level in business, government, education, technology or public interest;
•
have relevant expertise and experience and be able to offer guidance and advice to the chief executive officer based on that expertise and experience;
•
with respect to a majority of directors, be independent and able to represent all stockholders and be committed to enhancing long term stockholder value; and
•
have sufficient time available to devote to the activities of the Board of Directors and to enhance his or her knowledge of the Company’s business.
The committee does not have a formal policy with respect to the consideration of diversity when assessing director nominees, but considers diversity as part of its overall assessment of the board’s functioning and needs.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our directors and executive officers, and persons who own more than ten percent of our common stock, to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of our common stock. To our knowledge, based solely on a review of the copies of such reports available to us and written representations that no other reports were
required, we believe that all reporting obligations of our officers, directors and greater than ten percent stockholders under Section 16(a) were satisfied during the year ended December 31, 2009, except as follows: Resolute Holdings, LLC, a beneficial owner of more than 10% of our common stock, filed late one Form 4; Natural Gas Partners VII, a beneficial owner of more than 10% of our common stock, filed late one Form 3; and Kenneth A. Hersh, a director, filed late one Form 5.
Code of Ethics
The Company has adopted a code of ethics that applies to directors, officers and employees that complies with the rules and regulations of the NYSE and SEC. The Code of Ethics is posted on the Company’s website, at www.resoluteenergy.com, under the “Investor Relations” tab, subheading “Corporate Governance.” All amendments to, and waivers granted under, the Company’s code of ethics will be disseminated on the Company’s website in the manner required by SEC and NYSE rules.
Communications with the Board
In recognition of the importance of providing stockholders and other interested parties with the ability to communicate with members of the Board of Directors and with non-management directors, the Board of Directors has adopted a Stockholder and Interested Parties Communication Policy, a copy of which is available on our website. Pursuant to the policy, security holders and other interested persons may direct correspondence to the Board of Directors or to any individual director by mail to the following address: c/o Resolute Energy Corporation, Attention: Lead Independent Director, 1675 Broadway, Suite 1950, Denver, Colorado 80202.
Communications should not exceed 1,000 words in length and should indicate (i) the type and amount of Resolute securities held by the person submitting the communication and/or the nature of the person’s other interest in Resolute, (ii) any personal interest the person has in the subject matter of the communication and (iii) the person’s mailing address, e-mail address and telephone number. Unless the communication relates to an improper topic (e.g., it contains offensive content or advocates that we engage in illegal activities) or it fails to satisfy the procedural requirements of the policy, we will deliver it to the person(s) to whom it is addressed.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Summary Compensation Table
The following table summarizes the total compensation paid or earned by our principal executive officer, our principal financial officer and four other most highly compensated executive officers (the “Named Executive Officers”) who served as executive officers from September 25, 2009, the date the Company became a public reporting entity, through December 31, 2009.
1)
Each of the executive officers assumed such position with the Company upon completion of the Resolute Transaction on September 25, 2009, at which time the Company became a reporting company pursuant to the Securities Exchange Act of 1934. Prior to that time, each executive officer was employed by Predecessor Resolute, and, in that capacity, received the following salary and other compensation for the period from January 1, 2009 through September 24, 2009 (no other compensation was paid during that period):
2)
Each of the executive officers is also an officer of Holdings, and has received equity and other compensation in such capacity. Such compensation is not included in the above table.
3)
$13,111 of the bonus relates to matching 401(k) contributions that would have been made in 2009 in respect of 2008 employee contributions in accordance with policies of Predecessor Resolute. Because Predecessor Resolute had suspended its matching contributions in 2009, Resolute determined to pay the amount of such matching contributions in the form of a cash payment.
4)
Consists of (i) contributions pursuant to the Company’s 401(k) plan to match employee contributions made in 2009 and (ii) the value of parking paid for by the Company. The 401(k) matching contribution was paid in 2010, but accrued on the Company’s financial statements in 2009.
5)
Mr. Sutton and Mr. Piccone are also directors of the Company but received no compensation for their services as directors.
2009 Grants of Plan-Based Awards
The Company has one equity incentive plan, the 2009 Performance Incentive Plan (the “Plan”), pursuant to which the Company may grant stock options, restricted stock, restricted stock units and stock appreciation rights. The Plan provides for the issuance of up to 2,657,744 shares of common stock. No plan-based awards have been made to the Named Executive Officers in 2009.
Outstanding Equity Awards at Fiscal Year End
There were no equity awards outstanding under the Plan at December 31, 2009.
Option Exercises and Stock Vested in 2009
No options to purchase Company common stock were exercised by Named Executive Officers in 2009, and no options held by Named Executive Officers vested in 2009.
2009 Pension Benefits
The Company has no defined benefit pension plans.
2009 Nonqualified Deferred Compensation Plans
In the year ended December 31, 2009, the Company had no nonqualified plan that provides for deferral of compensation.
Potential Payments Upon Termination or Change of Control of Resolute
There are currently no agreements under which the Named Executive Officers would be entitled to receive payments upon termination or upon a change of control of the Company.
Compensation Discussion and Analysis of the Company
The Company began operations on September 25, 2009, and the Board of Directors and Compensation Committee assumed their positions at that date. The Compensation Committee is in the process of developing its compensation policies and philosophy for executive officers, and in February 2010 engaged Effective Compensation, Inc., an independent compensation consultant, to advise with respect to development of comprehensive compensation philosophy and practices for executives and other employees.
Overview of the Company’s Compensation Program. The Company’s Board of Directors has responsibility for establishing, implementing and continually monitoring adherence with the Company’s compensation philosophy. The Board of Directors has delegated to the Compensation Committee of the Board of Directors its responsibilities with respect to development of a compensation program and implementation of that program. The Compensation Committee will be solely responsible for determining the compensation of the CEO and will make recommendations to the Board of Directors regarding the compensation of other executive officers. It will also administer equity incentive plans, and make recommendations to the Board of Directors regarding awards under the Incentive Plan. Generally, the types of compensation and benefits that are provided to the Company’s executive officers are similar to those provided to the Company’s other officers and employees. The Company does not have compensation plans that are solely for executive officers.
Compensation Philosophy and Objectives. The Company believes that the most effective compensation program is one that is designed to reward all employees, not just executives, for the achievement of the Company’s short-term and long-term strategic goals. As a result, the Company’s compensation philosophy is to provide all employees with cash incentives or a combination of cash and equity-based incentives that foster the continued growth and overall success of the Company and encourage employees to maximize stockholder value.
Under this philosophy, all the Company employees, from the most senior executives of the organization to entry level, have aligned interests. When establishing its total compensation, the Company has the following objectives:
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to attract, retain and motivate highly qualified and experienced individuals;
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to provide financial incentives, through an appropriate mix of fixed and variable pay components, to achieve the organization’s key financial and operational objectives;
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to ensure that a portion of total compensation is “at risk” in the form of equity compensation; and
•
to offer competitive compensation packages that are consistent with the Company’s core values, including the balance of fairness to the individual and the organization, and the demand for commitment and dedication in the performance of the job.
Setting the Company’s Executive Compensation. The Compensation Committee is developing a comprehensive compensation plan that will encompass all elements of compensation for executives and all employees. The committee expects that process to be completed in the first half of 2010. Following development of the comprehensive plan and 2010 implementation, executive compensation will be reviewed by the compensation committee no less frequently than annually. Compensation is expected to be based on the foregoing objectives, and to include as integral components base salary and annual and long-term incentive-based cash and non-cash compensation. In performing its compensation reviews and making its compensation decisions regarding the compensation of the Company’s chief executive officer and other executive officers, the Compensation Committee of the Board of Directors will conduct an ongoing review of compensation data from other oil and gas companies of comparable size and scope. In establishing executive compensation, base salaries are expected to be targeted near the midpoint of a range established by this peer review, although adjustments are made for such things as experience, market factors or exceptional performance, among others, and potential total compensation, including annual incentive compensation, are expected to be at the upper range of total compensation at comparable companies if performance targets are met. Annual cash incentive and equity incentive awards will be designed to reflect progress toward company-wide financial goals and personal objectives, as well as salary grade level, and to balance rewards for short-term and long-term performance. Long-term incentive compensation will be used to reward and to encourage long-term performance and an alignment of interests between the individual and the organization. Long-term incentive grants will be used not only to reward prior performance, but also to retain executive officers and other employees and provide incentives for future exceptional performance. To the extent that business success makes long-term incentive awards more valuable, an individual’s total compensation may move from the median to the high end of ranges established with reference to peer data.
There is no pre-established policy or target for the allocation between either cash and non-cash or short-term and long-term incentive compensation for executive officers. Rather, the compensation committee engages in an individual analysis for each executive. Factors affecting compensation include: (i) the Company’s annual performance; (ii) impact of the employee’s performance on the Company’s results; (iii) the Company’s objective to provide total compensation that is higher than competitive levels when aggressive goals of the Company are exceeded; and (iv) internal equity. The size of the long-term incentive compensation grants will typically increase with the level of responsibility of the executive position. For the chief executive officer, long term incentive grants are typically the largest element of the total compensation package.
Executive officers generally receive the same benefits as other employees. The Company has matched 401(k) contributions made by all employees, including executive officers, in 2009.
Executive Compensation Components. The principal components of compensation for executive officers are:
•
base salary;
•
cash bonus;
•
long-term incentive compensation; and
•
401(k) and other benefits.
Relative Size of Major Compensation Elements. The combination of base salary, annual cash incentives and equity awards comprises total direct compensation. In setting executive compensation, the compensation committee considers the aggregate compensation payable to an executive officer and the form of that compensation. The compensation committee seeks to achieve the appropriate balance between immediate cash rewards and long-term financial incentives for the achievement of both annual and long-term financial and non-financial objectives.
The compensation committee may decide, as appropriate, to modify the mix of base salary, annual cash incentives and long-term equity incentives to best fit an executive officer’s specific circumstances. For example, the compensation committee may make the decision to award more cash and not award an equity grant. This provides more flexibility to the Company to reward executive officers appropriately as they near retirement, when they may only be able to partially fulfill the vesting required for equity grants. The compensation committee may also increase the size of equity grants to an executive officer if the total number of career equity grants does not adequately reflect the executive’s current position with the Company.
Timing of Compensation Decisions. In the first half of 2010, the Company will undertake a comprehensive analysis of its compensation system and establish performance and other goals. After this process is completed, it is expected that all elements of the executive officers’ compensation will be reviewed each February, including a review of financial, operating and personal objectives with respect to the prior year’s results. At that time, the financial, operating and personal objectives and performance targets will be determined for the current year. The Board of Directors or the compensation committee may, however, review salaries or grant equity incentives at other times in connection with new appointments or promotions or other extraordinary events that occur during the year, or under other circumstances that it deems appropriate.
The following table summarizes the approximate timing of significant compensation events:
Event
Timing
Base salary review and recommendation.
First quarter of the fiscal year for base salary for the current year.
Executive performance evaluation and corresponding compensation recommendations.
Results approved in February of each fiscal year for annual cash bonus with respect to prior year.
Earned incentive compensation paid in March.
Granting of long term incentives to executives.
No set period.
External consultants’ analyses provided to the compensation committee evaluating executive compensation.
No set period.
Establish executive officer performance objective(s).
February of each fiscal year for the current year.
Base Salary. The Company provides executive officers with a base salary to compensate them for services rendered during the fiscal year. Base salaries for each of the Named Executive Officers were reset following the consummation of the Resolute Transaction, as follows: base salary levels for Messrs. Betz, Cantwell and Gazulis and Ms. Pasque were set at $300,000, for Mr. Piccone at $350,000, and for Mr. Sutton at $500,000. This decision reflected increased responsibilities associated with public company status, as well as other factors. The compensation committee reviewed survey data compiled by a third party of publicly available information of salary levels for executives at companies in the oil and gas industry with a market capitalization comparable to that of the Company. In addition, the compensation committee considered the then-current salary levels of executives. Prior to the Resolute Transaction in 2009, all Named Executive Officers had been executive officers of Resolute Holdings. Each executive had an agreed annual salary level of $175,000 per year, which reflected private company salary and equity arrangements for a start-up company that were no longer applicable to a much larger public company. Salaries had been unchanged since 2004, and these levels were not considered competitive with market rates. In addition, executives had foregone salary increases and had agreed to salary reductions from agreed salary levels in 2009 in response to cash flow concerns of Resolute Holdings.
Base salary for executive officers for 2010 will take into consideration salaries of executives of comparable companies in the oil and gas industry, individual performance, comparison to internal peer positions, the relative
performance of the Company during the year, and overall performance against the Company objectives. Base salaries will be reviewed and adjusted pursuant to the procedures discussed above.
There are occasions when a base salary can be reduced such as when an executive officer moves to a position of lesser responsibility in the organization. Alternatively, a base salary can be frozen for a number of years until it falls in line with comparable positions.
Cash Bonus. Cash bonuses to executive officers will be made at the discretion of the Board of Directors. Cash bonuses totaling $578,055 were awarded in December 2009 to the Named Executive Officers for services during 2009. Each bonus was equal to approximately one quarter of each executive’s annual salary at year-end 2009, subject to certain adjustments and special considerations. Mr. Sutton received a bonus of $138,100, Mr. Piccone a bonus of $100,600, and Messrs. Gazulis and Cantwell and Ms. Pasque each received bonuses of $88,100 and Mr. Betz received a bonus of $75,000. Factors considered in awarding this bonus included the exemplary efforts made by such executives in completing the Resolute Transaction and in transitioning to public company status. In addition, the bonuses took into consideration the salary reductions agreed to by the executives in 2009: Mr. Sutton had agreed to a 50% reduction in his salary from February 2009 and other executives had agreed to a 10% reduction in salary from April 2009. The Committee also considered, in determining the amount of the bonuses, that the Company’s normal policy of matching employee 401(k) contributions had been suspended in 2009 (with respect to 2008 contributions) and that Named Executive Officers received no bonus in 2009 for services in 2008.
The Committee expects that future year-end cash bonuses would range from 0% to 150% of each executive’s annual base salary, depending on an executive’s position of responsibility and an assessment of that executive’s contribution to the success of the Company. Performance targets will be established, and bonuses will reflect a combination of time vesting and achievement of performance objectives.
Employment Agreements. The Company expects to enter into employment agreements with the Named Executive Officers in 2010. It is expected that the employment agreements will provide for (i) base salary, (ii) bonuses to be earned by achievement of specified performance targets, (iii) severance and change of control benefits, (iv) non-competition and non-solicitation provisions, (v) obligations to maintain the confidentiality of the Company information, and (vi) assignment of all intellectual property rights to the Company.
Retirement and Other Benefit Plans. All of the Company’s employees will be eligible to participate in a 401(k) plan. While the Company will have the option but not the requirement to match all or a portion of employee contributions to the 401(k) plan, a matching contribution was made in 2010 for 2009 contributions.
Long-Term Incentive Compensation. The Company has adopted the 2009 Incentive Performance Plan (the “Incentive Plan”), providing for long-term equity based awards intended to compensate key employees, consultants and directors. The principal terms of the Incentive Plan are summarized below under the caption “2009 Incentive Performance Plan.”
Other Benefits Plans. The Company offers a variety of health and benefit programs to all employees, including medical, dental, vision, life insurance and disability insurance. The Company’s executive officers are generally eligible to participate in these employee benefit plans on the same basis as the rest of the Company’s employees.
Compensation Programs and Potential of Risks -
The Company has determined that the risks arising from its compensation policies and practices are not reasonably likely to have a material adverse effect on the Company.
Director Summary Compensation Table
The following table summarizes the compensation we paid to our non-employee directors between September 25, 2009, the date the Company commenced operations, and December 31, 2009.
1) Messrs. Sutton and Piccone are not included in this table because as employees of the Company they receive no additional compensation for their services as directors. The compensation received by Messrs. Sutton and Piccone as employees is shown in “- Executive Officer Compensation in 2009 - Summary Compensation Table.”
On December 14, 2009, the compensation committee recommended, and the Board of Directors approved, the following annual compensation for non-employee directors: annual retainer of $50,000, fees of $2,000 for each Board of Directors meeting and $1,000 for each committee meeting, and additional compensation of $7,500 for each committee chairman. In addition, non-employee directors would receive equity compensation, in a form to be determined by the compensation committee, having a value of $50,000 annually. The cash fees appearing in the above table reflects this compensation arrangement for 2009. While the Board of Directors authorized the directors to receive equity compensation for services as a director for the period from September 25, 2009 to December 31, 2009, the form and terms of any such equity compensation were subject to analysis of legal, tax and other factors and had not been determined by the end of 2009. As a result, no awards were made in 2009, but awards of 1,373 shares were made to each non-employee director on March 16, 2010 with respect to 2009 services. See “Security Ownership of Certain Beneficial Owners and Management”.
In addition, each director will be reimbursed for his or her out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees. Each director is covered by a liability insurance policy paid for by the Company and is indemnified, to the fullest extent permitted under Delaware law, by the Company for his or her actions associated with being a director. The Company entered into indemnification agreements with each of its directors.
Compensation Committee Report
We, the Compensation Committee of the Board of Directors, have reviewed and discussed the Compensation Discussion and Analysis with the management of the Company, and, based on such review and discussion, have recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2009.
Compensation Committee:
James E. Duffy, Chairman
Richard L. Covington
Kenneth A. Hersh
William J. Quinn
2009 INCENTIVE PERFORMANCE PLAN
The Company adopted the 2009 Incentive Performance Plan (the “Incentive Plan”) in July 2009, and the Incentive Plan was approved by the sole stockholder of the Company at that time. This summary is qualified in its entirety by the full text of the Incentive Plan.
Purpose. The purpose of the Incentive Plan is to promote the success of the Company and the interests of its stockholders by providing an additional means for the Company to attract, motivate, retain and reward directors, officers, employees and other eligible persons (including consultants and advisors) through the grant of awards and incentives for high levels of individual performance and improved financial performance of the Company. Equity-based awards are also intended to further align the interests of award recipients and the Company’s stockholders.
Administration. The Company’s Board of Directors or one or more committees consisting of independent directors appointed by the Company’s Board of Directors will administer the Incentive Plan. Our Board of Directors has delegated general administrative authority for the Incentive Plan to the compensation committee, which is comprised of directors who qualify as independent under rules promulgated by the SEC and The New York Stock Exchange listing standards. Except with respect to grants to non-employee directors, a committee may delegate some or all of its authority with respect to the Incentive Plan to another committee of directors and certain limited authority to grant awards to employees may be delegated to one or more officers of the Company. For purposes of Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”), Rule 16b-3 of the Securities Exchange Act of 1934, as amended, the rules of the New York Stock Exchange (“NYSE”) and for grants to non-employee directors, the Incentive Plan must be administered by a committee consisting solely of independent directors. The appropriate acting body, be it the Company’s Board of Directors, a committee within its delegated authority, or an officer within his or her delegated authority, is referred to in this plan description as the Administrator.
The Administrator has broad authority under the Incentive Plan with respect to award grants including, without limitation, the authority:
•
to select participants and determine the type(s) of award(s) that they are to receive;
•
to determine the number of shares that are to be subject to awards and the terms and conditions of awards, including the price (if any) to be paid for the shares or the award;
•
to cancel, modify, or waive the Company’s rights with respect to, or modify, discontinue, suspend, or terminate any or all outstanding awards, subject to any required consents;
•
to accelerate or extend the vesting or exercisability or extend the term of any or all outstanding awards subject to any required consent;
•
subject to the other provisions of the Incentive Plan, to make certain adjustments to an outstanding award and to authorize the conversion, succession or substitution of an award;
•
to allow the purchase price of an award or shares of Company common stock to be paid in the form of cash, check, or electronic funds transfer, by the delivery of already-owned shares of Company common stock or by a reduction of the number of shares deliverable pursuant to the award, by services rendered by the recipient of the award, by notice of third party payment or by cashless exercise, on such terms as the Administrator may authorize, or any other form permitted by law.
Eligibility. Persons eligible to receive awards under the Incentive Plan include officers and employees of the Company or any of its subsidiaries, directors of the Company, and certain consultants and advisors to the Company or any of its subsidiaries.
Authorized Shares. The maximum number of shares of Company Common Stock that may be issued pursuant to awards under the Incentive Plan is 2,657,744. No awards were made in 2009. The Incentive Plan generally provides that shares issued in connection with awards that are granted by or become obligations of the Company through the assumption of awards (or in substitution for awards) in connection with an acquisition of another Company will not count against the shares available for issuance under the Incentive Plan.
No Repricing. In no case (except due to an adjustment to reflect a stock split or similar event or any repricing that may be approved by stockholders) will any adjustment be made to a stock option or stock appreciation right award under the Incentive Plan (by amendment, cancellation and regrant, exchange or other means) that would constitute a repricing of the per share exercise or base price of the award.
Types of Awards. The Incentive Plan authorizes stock options, stock appreciation rights, restricted stock, restricted stock units, stock bonuses and other forms of awards that may be granted or denominated in Company common stock or units of Company common stock, as well as cash bonus awards. The Incentive Plan retains flexibility to offer competitive incentives and to tailor benefits to specific needs and circumstances. Any award may be paid or settled in cash.
Stock Options. A stock option is the right to purchase shares of Company common stock at a future date at a specified price per share (the “exercise price.”) The per share exercise price of an option generally may not be less than the fair market value of a share of Company common stock on the date of grant. The maximum term of an option is ten years from the date of grant. An option may be either an incentive stock option or a nonqualified stock option. Incentive stock options are taxed differently than nonqualified stock options and are subject to more restrictive terms under the Code and the Incentive Plan. Incentive stock options may be granted only to employees of the Company or a subsidiary.
Stock Appreciation Rights. A stock appreciation right is the right to receive payment of an amount equal to the excess of the fair market value of shares of Company common stock on the date of exercise of the stock appreciation right over the base price of the stock appreciation right. The base price will be established by the Administrator at the time of grant of the stock appreciation right and generally cannot be less than the fair market value of a share of Company common stock on the date of grant. Stock appreciation rights may be granted in connection with other awards or independently. The maximum term of a stock appreciation right is ten years from the date of grant.
Restricted Stock. Shares of restricted stock are shares of Company common stock that are subject to certain restrictions on sale, pledge, or other transfer by the recipient during a particular period of time (the “restricted period”). Subject to the restrictions provided in the applicable award agreement and the Incentive Plan, a participant receiving restricted stock may have all of the rights of a stockholder as to such shares, including the right to vote and the right to receive dividends.
Restricted Stock Units. A restricted stock unit (“RSU”), represents the right to receive one share of Company common stock on a specific future vesting or payment date. Subject to the restrictions provided in the applicable award agreement and the Incentive Plan, a participant receiving RSUs has no stockholder rights until shares of common stock are issued to the participant. RSUs may be granted with dividend equivalent rights.
Cash Awards. The Administrator, in its sole discretion, may grant cash awards, including without limitation, discretionary awards, awards based on objective or subjective performance criteria, and awards subject to other vesting criteria.
Other Awards. The other types of awards that may be granted under the Incentive Plan include, without limitation, stock bonuses, performance stock, dividend equivalents, and similar rights to purchase or acquire shares of Company common stock.
Performance-Based Awards. The Administrator may grant awards that are intended to be performance-based compensation within the meaning of Section 162(m) of the Code (“Performance-Based Awards”). Performance-Based Awards are in addition to any of the other types of awards that may be granted under the Incentive Plan (including options and stock appreciation rights which may also qualify as performance-based compensation for Section 162(m) purposes). Performance-Based Awards may be in the form of restricted stock, performance stock, stock units, other rights, or cash bonus opportunities.
The vesting or payment of Performance-Based Awards (other than options or stock appreciation rights) will depend on the absolute or relative performance of the Company on a consolidated, subsidiary, segment, division, or business unit basis. The Administrator will establish the targets on which performance will be measured based on criterion or criteria selected by the Administrator. The Administrator must establish criteria and targets in advance of applicable deadlines under the Code and while the attainment of the performance targets remains
substantially uncertain. The Administrator may use any criteria it deems appropriate for this purpose, and applicable criteria may include one or more of the following: earnings per share, cash flow (which means cash and cash equivalents derived from either net cash flow from operations or net cash flow from operating, financing and investing activities), total stockholder return, gross revenue, revenue growth, operating income (before or after taxes), net earnings (before or after interest, taxes, depreciation and/or amortization), return on equity, capital employed, or on assets or net investment, cost containment or reduction, operating margin, debt reduction, finding and development costs, production growth or production growth per share, reserve replacement or reserve replacement per share or any combination thereof. The performance measurement period with respect to an award may be as short as three months to as long as ten years. Performance targets will be adjusted to mitigate the unbudgeted impact of material, unusual or nonrecurring gains and losses, accounting changes or other extraordinary events not foreseen at the time the targets were set unless the Administrator provides otherwise at the time of establishing the targets.
Performance-Based Awards may be paid in stock or in cash. Before any Performance-Based Award (other than an option or stock appreciation right) is paid, the Administrator must certify that the performance target or targets have been satisfied. The Administrator has discretion to determine the performance target or targets and any other restrictions or other limitations of Performance-Based Awards and may reserve discretion to reduce payments below maximum award limits.
Acceleration of Awards; Possible Early Termination of Awards. Generally, and subject to limited exceptions set forth in the Incentive Plan, if any person acquires more than 50% of the outstanding common stock or combined voting power of the Company, if there are certain changes in a majority of the Company Board of Directors, if stockholders prior to a transaction do not continue to own more than 50% of the voting securities of the Company (or a successor or a parent) following a reorganization, merger, statutory share exchange or consolidation or similar corporate transaction involving the Company or any of its subsidiaries, a sale or other disposition of all or substantially all of the Company’s assets or the acquisition of assets or stock of another entity by the Company or any of its subsidiaries, or if the Company is dissolved or liquidated, then awards then-outstanding under the Incentive Plan may become fully vested or paid, as applicable, and may terminate or be terminated upon consummation of such a change in control event. The Administrator also has the discretion to establish other change in control provisions with respect to awards granted under the Incentive Plan. For example, the Administrator could provide for the acceleration of vesting or payment of an award in connection with a change in control event that is not described above or provide that any such acceleration shall be automatic upon the occurrence of any such event.
Transfer Restrictions. Awards under the Incentive Plan generally are not transferable by the recipient other than by will or the laws of descent and distribution, or pursuant to domestic relations orders, and are generally exercisable during the recipient’s lifetime only by the recipient. Any amounts payable or shares issuable pursuant to an award generally will be paid only to the recipient or the recipient’s beneficiary or representative. The Administrator has discretion, however, to establish written conditions and procedures for the transfer of awards to other persons or entities, as long as such transfers comply with applicable federal and state securities laws.
Adjustments. As is customary in incentive plans of this nature, the share limit and the number and kind of shares available under the Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends, or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the stockholders.
No Limit on Other Authority. The Incentive Plan does not limit the authority of the Company’s Board of Directors or any committee to grant awards or authorize any other compensation, with or without reference to Company common stock, under any other plan or authority.
Termination of, or Changes to, the Incentive Plan. The Administrator may amend or terminate the Incentive Plan at any time and in any manner. Stockholder approval for an amendment will be required only to the extent then required by applicable law or any applicable listing agency or required under Sections 162, 409A, 422 or 424 of the Code to preserve the intended tax consequences of the Incentive Plan. For example, stockholder approval
will be required for any amendment that proposes to increase the maximum number of shares that may be delivered with respect to awards granted under the Incentive Plan. Adjustments as a result of stock splits or similar events will not, however, be considered an amendment requiring stockholder approval. Unless terminated earlier by the Board of Directors, the authority to grant new awards under the Incentive Plan will terminate ten years from the date of its adoption, or July 31, 2019. Outstanding awards generally will continue following the expiration or termination of the Incentive Plan. Generally speaking, outstanding awards may be amended by the Administrator (except for a repricing), but the consent of the award holder is required if the amendment (or any plan amendment) materially and adversely affects the holder.
Awards Under the Incentive Plan. No awards were made under the Incentive Plan in 2009. Because future awards under the Incentive Plan will be granted in the discretion of the Company’s Board of Directors or a committee of the board, the type, number, recipients and other terms of future awards cannot be determined at this time.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth certain information regarding shares of our common stock issuable upon the exercise of options granted under our compensation plans as of December 31, 2009.
1)
Awards under the 2009 Performance Incentive Plan may be made in the form of options, restricted stock, restricted stock units or stock appreciation rights. At December 31, 2009, no awards of any form had been granted.
Compensation Committee Interlocks and Insider Participation
No member of the compensation committee has been an officer or employee of the Company. None of the Company’s executive officers serves as a member of the Board of Directors or the compensation committee of any entity that has one or more executive officers serving on the Company’s Board of Directors, or on the compensation committee of the Company’s Board of Directors.
Confidentiality and Non-Competition Agreements
Each of the executive officers entered into a Confidentiality and Non-Competition Agreement (“Confidentiality Agreement”) dated January 23, 2004, at the time of the formation of Predecessor Resolute. In this agreement, each officer agreed: (i) that all intellectual property developed, and business opportunities as to which such executive became aware, during his employment belong to Predecessor Resolute, (ii) to maintain confidentiality of proprietary information, and (iii) to turn over to Predecessor Resolute all business records during, and upon termination of, employment.
In addition, Predecessor Resolute has the right, in its sole discretion, to agree to make severance payments to any executive officer for up to eighteen months following termination other than for Cause (as defined), or upon voluntary resignation following a reduction in annual salary. Severance payments would be equal to the executive’s salary immediately prior to termination. During the period in which severance payments are being made, the executive may not engage in the oil and gas business in an area within a ten mile radius of the boundaries of any property interest of Predecessor Resolute (the “Non-Compete”). In addition, the executive is
subject to the Non-Compete, even if no severance is paid, if the executive resigns other than following a salary reduction, the executive is terminated for Cause, or the executive has breached any material provision of the Confidentiality Agreement. In addition, executive is in all events prohibited during the eighteen months following termination from inducing any other employee of Predecessor Resolute to terminate his employment or cease providing services to Predecessor Resolute. Upon the consummation of the Resolute Transaction, these agreements became agreements of Resolute.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners and Management
The following table, based in part upon information supplied by officers, directors and principal stockholders, sets forth certain information known to the Company with respect to beneficial ownership of the Company’s common stock par value $0.0001 per share (“Common Stock”) as of March 29, 2010, by (i) each person known to the Company to be a beneficial owner of more than 5% of the Company’s Common Stock, (ii) each Named Executive Officer (see “Executive Compensation - Summary Compensation Table”), (iii) each director of the Company, and (iv) all directors and executive officers of the Company as a group. Except as otherwise indicated, each person has sole voting and investment power with respect to all shares shown as beneficially owned, subject to community property laws where applicable. Voting power is the power to vote or direct the voting of securities, and dispositive power is the power to dispose of or direct the disposition of securities. Except as otherwise indicated, the address of the persons listed below is c/o Resolute Energy Corporation, 1675 Broadway, Suite 1950, Denver, Colorado 80202.
For purposes of this beneficial ownership table, (x) “Earnout Shares” are shares of Common Stock subject to forfeiture, unless at any time prior to September 25, 2014, either (a) the closing sale price of Common Stock exceeds $15.00 per share for 20 trading days in any 30 trading day period or (b) a change in control event occurs in which Common Stock is valued at greater than $15.00 per share, (y) “Founder’s Warrants” are warrants which entitle the holder to purchase one share of Company Common Stock at a price of $13.00 per share, subject to adjustment, commencing any time after the last sale price of Common Stock exceeds $13.75 for any 20 days within any 30 day trading period prior to September 25, 2014, and (z) “Sponsor’s Warrants” are warrants which entitle the holder to purchase one share of Common Stock at a price of $13.00 per share at any time prior to September 25, 2014. For purposes of calculating beneficial ownership, Earnout Shares and shares issuable on exercise of Sponsor’s Warrants are considered to be beneficially owned by the holders thereof, but shares issuable on exercise of Founder’s Warrants are not considered to be beneficially owned by such holders.
(1) Security ownership information for beneficial owners is taken from statements filed with the Securities and Exchange Commission pursuant to Sections 13(d), 13(g) and 16(a) and information made known to the Company. Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and generally includes voting or investment power with respect to securities. Shares of common stock subject to options or warrants that are currently exercisable or exercisable within 60 days of the date of the table are deemed to be outstanding for the purpose of computing the percentage ownership of the person holding those options or warrants, but are not treated as outstanding for the purpose of computing the percentage ownership of any other person. The percentage of beneficial ownership is based on 53,160,375 shares of common stock outstanding as of March 29, 2010.
(2) This disclosure is based on the Schedule 13D/A filed with the SEC on October 29, 2009 by SPO Advisory Corp. on behalf of SPO Partners II, L.P., SPO Advisory Partners, L.P., San Francisco Partners, L.P., SF Advisory Partners, L.P., SPO Advisory Corp., John H. Scully, William E. Oberndorf, William J. Patterson and Edward H. McDermott. Messrs. Scully, Oberndorf, Patterson and McDermott are the four controlling persons of SPO Advisory Corp., which is the sole general partner of the sole general partners of SPO Partners II, L.P. and San Francisco Partners, L.P., and may be deemed to beneficially own the shares owned by SPO Partners II, L.P. and San Francisco Partners, L.P. Of these shares, SPO Partners II, L.P., through its sole general partner, SPO Advisory Partners, L.P., holds sole voting and dispositive power over 17,672,325 shares (9,502,800 shares of Company Common Stock and warrants covering 8,169,525 shares of Company common stock issuable upon exercise); SPO Advisory Partners, L.P., through its sole general partner, SPO Advisory Corp, and in its capacity as sole general partner of SPO Partners II, L.P., holds sole voting and dispositive power over 17,672,325 shares (9,502,800 shares of Company Common Stock and warrants covering 8,169,525 shares of Company Common Stock issuable upon exercise); San Francisco Partners, L.P., through its sole general partner, SF Advisory Partners, L.P., holds sole voting and dispositive power over 607,253 shares (327,500 shares of Company Common Stock and warrants covering 279,753 shares of Company Common Stock issuable upon exercise); SF Advisory Partners, L.P., through its sole general partner SPO Advisory Corp and in its capacity as sole general partner of San Francisco Partners, L.P. holds sole voting and dispositive power over 607,253 shares (327,500 shares of Company Common Stock and warrants covering 279,753 shares of Company Common Stock issuable upon exercise); SPO Advisory Corp, in its capacity as (i) sole general partner of SPO Advisory Partners, L.P., holds sole voting and dispositive power with respect to 9,502,800 shares of Company Common Stock and warrants covering 8,169,525 shares of Company Common Stock issuable upon exercise, and as (ii) the sole general partner of SF Advisory Partners, L.P. holds sole voting and dispositive power with respect to 327,500 shares of Company Common Stock and warrants covering 279,753 shares of Company Common Stock issuable upon exercise; and power is exercised through its four controlling persons, John H. Scully, William E. Oberndorf, William J. Patterson and Edward H. McDermott. John H. Scully holds sole voting power over 3,913 shares held in the John H. Scully Individual Retirement Account, which is self-directed, and shared voting and dispositive power over 18,279,578 shares (there are 9,830,300 shares of Company Common Stock and warrants covering 8,449,278 shares of Company Common Stock issuable upon exercise) beneficially owned by Mr. Scully solely in his capacity as one of four controlling persons of SPO Advisory Corp. William E. Oberndorf holds sole voting and dispositive power over 135,788 shares held in the William E. Oberndorf Individual Retirement Account, which is self-directed, and shared voting and dispositive power over 18,279,578 shares (there are 9,830,300 shares of Company Common Stock and warrants covering 8,449,278 shares of Company Common Stock issuable upon exercise) beneficially owned by Mr. Oberndorf solely in his capacity as one of four controlling persons of SPO Advisory Corp. William J. Patterson holds sole voting and dispositive power over 358 shares held in the William J. Patterson Individual Retirement Account, which is self-directed, and shared voting and dispositive power over 18,279,578 shares (there are 9,830,300 shares of Company Common Stock and warrants covering 8,449,278 shares of Company Common Stock issuable upon exercise) beneficially owned by Mr. Patterson solely in his capacity as one of four controlling persons of SPO Advisory Corp. Edward H. McDermott holds sole voting and dispositive power over 1,422 shares held in the Edward H. McDermott Individual Retirement Account, which is self-directed, and shared voting and dispositive power over 18,279,578 shares (there are 9,830,300 shares of Company Common Stock and warrants covering 8,449,278 shares of Company Common Stock issuable upon exercise) beneficially owned by Mr. McDermott solely in his capacity as one of four controlling persons of SPO Advisory Corp.
(3) This disclosure is based on a Schedule 13G/A filed on January 29, 2010 by Pine River Capital Management L.P. on behalf of Brian Taylor and Nisswa Acquisition Master Fund Ltd. with the SEC on January 29, 2010. The reporting person shares voting and dispositive power over 4,542,222 shares with Brian Taylor and shares voting and dispositive power over 4,333,177 shares with Nisswa Acquisition Master Fund Ltd.
(4) This disclosure is based on a (i) Schedule 13D/A filed by Thomas O. Hicks on behalf of HH-HACI, L.P. (“HH LP”), HH-HACI GP, LLC, (“HH LLC”, the general partner of HH LP) and Mr. Hicks, the sole member of HH LLC, and (ii) a Form 4 filed by HH LP, each of which was filed with the SEC on October 21, 2009. HH LLC has sole voting and dispositive power over 430 shares (which includes 124 Earnout Shares) and shared voting and dispositive power over 301,913 shares (which includes 87,093 Earnout Shares). HH LLC also owns 613 Founder’s Warrants. HH LP has sole voting power and dispositive over 301, 913 shares (which includes 87,093 Earnout Shares), HH LP also owns 429,636 Founder’s Warrants. Thomas O. Hicks has sole voting and dispositive power over 7,200,301 shares and shared voting and dispositive power over 2,836,622 shares. The 7,200,301 shares includes 730,894 Earnout Shares and 4,666,667 Sponsor’s Warrants. Mr. Hicks also owns 3,605,481 Founder’s Warrants. The 2,836,622 shares over which Mr. Hicks has shared voting and dispositive power include 430 shares of Company Common Stock held by HH LLC, 301,913 shares of Company Common Stock held by HH LP (each described above) and 2,534,279 shares of Company Common Stock held by Mr. Hicks’ charitable foundation and estate planning entities for his family. The 2,534,279 shares include 731,079 Earnout Shares. Mr. Hicks’ charitable foundation and estate planning entities also own 3,606,400 Founders Warrants. HH LLC disclaims beneficial ownership of shares of Company Common Stock owned by HH LP, except to the extent of its pecuniary interest. Mr. Hicks disclaims beneficial ownership of any shares held by other entities, except to the extent of his pecuniary interest.
(5) This disclosure is based on a Schedule 13G/A filed by Advisory Research Energy Fund, L.P. with the SEC on February 12, 2010. Advisory Research Energy Fund, L.P. shares with its general partner, Advisory Research, Inc., voting and dispositive power over these shares, which include 2,516,466 shares underlying currently exercisable warrants. Advisory Research Energy Fund, L.P. claims beneficial ownership over 3,766,466 shares.
(6) This disclosure is based on a Schedule 13G/A filed by Advisory Research Inc. with the SEC on February 12, 2010. Advisory Research Inc. shares voting and dispositive power over these shares, which include 2,516,466 shares underlying currently exercisable warrants. Advisory Research Inc. manages accounts that may have the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of, the 8,021,250 shares. The interest of one such account, owned by Advisory Research Energy Fund L.P., relates to ownership over 3,766,466 shares, and is reported separately.
(7) Based on (i) a Form 3 filed by Natural Gas Partners VII, L.P. (“NGP VII”) with the SEC on February 16, 2010, (ii) a Schedule 13D filed with the SEC on February 22, 2010 on behalf of Kenneth A. Hersh, NGP VII and Resolute Holdings, LLC (“Resolute Holdings”) and (iii) a Form 5 filed by Kenneth Hersh with the SEC on February 16, 2010. NGP VII shares voting and dispositive power over 4,008,152 shares and has sole voting and dispositive power over 6,276,166 shares. Securities beneficially owned are comprised as follows: (i) direct ownership of 6,276,166 shares of Company Common Stock distributed by Resolute Holdings to NGP VII on December 21, 2009 in a pro rata distribution by Resolute Holdings to its members for no consideration; (ii) indirect ownership of 289,719 shares of Company Common Stock owned directly by NGP-VII Income Co-Investment Opportunities, L.P. (“Co-Invest”) and received in a pro rata distribution by Resolute Holdings to its members for no consideration. NGP VII owns 100% of NGP Income Management, L.L.C., which is the sole general partner of Co-Invest. NGP VII may be deemed to be the indirect beneficial owner of the 289,719 shares of Company Common Stock owned by Co-Invest; (iii) indirect ownership of 1,385,100 shares of Common Stock (including 1,385,000 Earnout Shares) owned by Resolute Holdings. NGP VII and Co-Invest own approximately 71% of the outstanding membership interests of Resolute Holdings and therefore may be deemed to be the indirect beneficial owners of the Common Stock owned by Resolute Holdings; (iv) indirect ownership of 2,333,333 Sponsor’s Warrants owned by Resolute Holdings. Resolute Holdings also owns 4,600,000 Founder’s Warrants. NGP VII may be deemed to be the indirect beneficial owner of warrants owned by Resolute Holdings. NGP VII disclaims beneficial ownership of the reported securities except to the extent of its pecuniary interest therein.
(8) Includes 10,284,318 shares over which Mr. Hersh has shared voting and dispositive power. Mr. Hersh is an Authorized Member of GFW VII, L.L.C., which is the sole general partner of G.F.W. Energy VII, L.P., which is the
sole general partner of NGP VII. Thus, Mr. Hersh may be deemed to indirectly beneficially own all the Company Common Stock directly and/or indirectly deemed beneficially owned by NGP VII. Mr. Hersh disclaims beneficial ownership of the reported securities except to the extent of his pecuniary interest therein.
(9) Resolute Holdings has sole voting and dispositive power over 3,718,433 shares, consisting of (i) 1,385,000 Earnout Shares, (ii) 100 shares of Company Common Stock and (iii) 2,333,333 Sponsor’s Warrants. Resolute Holdings also owns 4,600,000 Founder’s Warrants. NGP VII and Co-Invest own approximately 71% of the outstanding membership interests of Resolute Holdings and therefore may be deemed to be the indirect beneficial owners of the Common Stock and warrants owned by Resolute Holdings.
(10) All shares are held in a trust over which the reporting person is a co-trustee.
(11) Messrs. Hersh, Quinn and Covington have waived their director compensation that would have been paid through the issuance of Company common stock on March 16, 2010.
(12) Includes 1,373 shares of restricted stock granted pursuant to the 2009 performance incentive plan. 343 shares vested on the date of grant, March 16, 2010, 343 shares vest on the first and second anniversaries of the date of grant, and 344 shares vest on the third anniversary of the date of grant.
(13) Includes 38,462 shares held by the reporting person in custodial accounts.
(14) Includes (i) 23,000 shares of Company Common Stock, (ii) 9,325 Earnout Shares; Excludes 45,999 Founder’s Warrants.
(15) Includes (i) 99,666 shares of Company Common Stock, (ii) 40,409 Earnout Shares; Excludes 199,332 Founder’s Warrants.
(16) Includes 46,692 shares held by the reporting person in custodial accounts.
(17) Includes (i) 23,000 shares of Company Common Stock,(ii) 9,325 Earnout Shares; Excludes 46,000 Founder’s Warrants.
(18) Includes 4,120 shares of restricted stock that are subject to future vesting.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
At the time of the closing of the Resolute Transaction, $1.3 million was held in bank accounts of Predecessor Resolute that represented payments received by Predecessor Resolute with respect to a tax distribution payable to Resolute Holdings. Following the Resolute Transaction, Resolute paid such amounts to Resolute Holdings.
The Company’s Review, Approval or Ratification of Transactions with Related Parties
Pursuant to the Company’s Code of Business Conduct and Ethics, the Board of Directors will review and approve all relationships and transactions in which it and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of its voting securities and their family members, have a direct or indirect material interest. In approving or rejecting such proposed relationships and transactions, the Board of Directors shall consider the relevant facts and circumstances available and deemed relevant to this determination. The Company has designated James M. Piccone as the compliance officer to generally oversee compliance with the Code of Conduct.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEE AND SERVICES
On September 14, 2009, the Registration Statement on Form S-4 relating to the Resolute Transaction was declared effective by the Securities and Exchange Commission. On December 21, 2009, KPMG LLP accepted its appointment as the Company’s principal accountant. No fees were billed to Resolute by KPMG LLP during 2009. Resolute anticipates incurring audit fees from KPMG LLP of approximately $300,000, relating to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.
The charter of the Audit Committee includes certain policies and procedures regarding the pre-approval of audit and non-audit services performed by an outside accountant. The committee is required to pre-approve all engagement letters and fees for all auditing services (including providing comfort letters in connection with securities underwritings) and permissible non-audit services, subject to any exception under Section 10A of the Exchange Act and the rules promulgated thereunder. Pre-approval authority may be delegated to a committee member or a subcommittee, and any such member or subcommittee shall report any decisions to the full committee at its next scheduled meeting.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
See “Item 8 Financial Statements and Supplementary Data”.
(a)(3) 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.
RESOLUTE ENERGY CORPORATION
Dated: March 30, 2010
By:
/s/ Nicholas J. Sutton
Nicholas J. Sutton, Chief Executive Officer and Director
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.
FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Resolute Energy Corporation
We have audited the accompanying consolidated balance sheets of Resolute Energy Corporation and subsidiaries (successor by merger to Hicks Acquisition Company I, Inc.) (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period then ended, and for the period from February 26, 2007 (inception) to December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financials 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Resolute Energy Corporation and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the two-year period then ended, and for the period from February 26, 2007 (inception) to December 31, 2007 in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Denver, Colorado
March 30, 2010
RESOLUTE ENERGY CORPORATION
Consolidated Balance Sheets
(in thousands, except share amounts)
See notes to consolidated financial statements
RESOLUTE ENERGY CORPORATION
Consolidated Statements of Operations
(in thousands, except per share data)
See notes to consolidated financial statements
RESOLUTE ENERGY CORPORATION
Consolidated Statements of Stockholders’ Equity
(in thousands)
See notes to consolidated financial statements
RESOLUTE ENERGY CORPORATION
Consolidated Statements of Cash Flows
(in thousands)
See notes to consolidated financial statements
RESOLUTE ENERGY CORPORATION
Notes To Consolidated Financial Statements
Note 1 - Organization and Nature of Business
Resolute Energy Corporation (“Resolute” or the “Company”), a Delaware corporation incorporated on July 28, 2009, was formed to consummate a business combination with Hicks Acquisition Company I, Inc. (“HACI”), a Delaware corporation incorporated on February 26, 2007. Resolute is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, gas and natural gas liquids (“NGL”). The Company conducts all of its activities in the United States of America, principally in the Paradox Basin in southeastern Utah and the Powder River Basin in Wyoming.
HACI was a blank check company that was formed to acquire through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination, one or more businesses or assets. HACI’s initial public offering (the “Offering”) was consummated on October 3, 2007, and HACI received proceeds of approximately $529.1 million. Upon the consummation of the Resolute Transaction, described below, $11.7 million of deferred underwriters’ commission were forgiven and were recognized as additional paid in capital. HACI sold to the public 55,200,000 units (one share and one warrant) at a price of $10.00 per unit, including 7,200,000 units issued pursuant to the exercise of the underwriter’s over-allotment option. Simultaneous with the consummation of the Offering, HACI consummated the private sale of 7,000,000 warrants (the “Sponsor Warrants”) to HH-HACI, L.P., a Delaware limited partnership (the “Sponsor”), at a price of $1.00 per Sponsor Warrant, generating gross proceeds, before expenses, of $7.0 million (the “Private Placement”). Net proceeds received from the consummation of both the Offering and Private Placement of Sponsor Warrants totaled approximately $536.1 million, net of underwriter’s commissions and offering costs. The net proceeds were placed in a trust account at JPMorgan Chase Bank, N.A. with Continental Stock Transfer & Trust Company acting as trustee. HACI had neither engaged in any operations nor generated any operating revenue prior to the business combination with Resolute.
On September 25, 2009 (the “Acquisition Date”), HACI consummated a business combination under the terms of a Purchase and IPO Reorganization Agreement (“Acquisition Agreement”) with Resolute and Resolute Holdings Sub, LLC (“Sub”), whereby, through a series of transactions, HACI’s stockholders collectively acquired a majority of the outstanding shares of Resolute common stock (the “Resolute Transaction”). Immediately prior to the consummation of the Resolute Transaction, Resolute owned, directly or indirectly, 100% of the equity interests of Resolute Natural Resources Company, LLC (“Resources”), WYNR, LLC (“WYNR”), BWNR, LLC (“BWNR”), RNRC Holdings, Inc. (“RNRC”), and Resolute Wyoming, Inc. (“RWI”) (formerly known as Primary Natural Resources, Inc. (“PNR”)), and owned a 99.996% equity interest in Resolute Aneth, LLC (“Aneth”), (collectively “Predecessor Resolute”). The entities comprising Predecessor Resolute prior to the Resolute Transaction were wholly owned by Sub (except for Aneth, which was owned 99.996%), which in turn is a wholly owned subsidiary of Resolute Holdings, LLC (“Holdings”).
The Resolute Transaction was accounted for using the acquisition method, with HACI as the accounting acquirer, and resulted in a new basis of accounting reflecting the fair values of the Predecessor Resolute assets and liabilities at the Acquisition Date. Accordingly, the accompanying consolidated financial statements are presented on Resolute’s new basis of accounting (see Note 3 for details). HACI is the surviving entity and periods prior to September 25, 2009 reflected in this report represent activity related to HACI’s formation, its initial public offering and identifying and consummating a business combination. The operations of Predecessor Resolute have been incorporated beginning September 25, 2009.
Note 2 - Summary of Significant Accounting Policies
Basis of Presentation
The consolidated financial statements include the historical accounts of HACI and, subsequent to the Acquisition Date, include Resolute and its subsidiaries, and have been prepared in accordance with accounting
principles generally accepted in the United States (“GAAP”). All significant intercompany transactions have been eliminated upon consolidation.
In connection with the preparation of the consolidated financial statements, Resolute evaluated subsequent events after the balance sheet date. Certain prior period amounts have been reclassified to conform to the current period presentation.
Assumptions, Judgments and Estimates
The preparation of the consolidated financial statements in conformity with GAAP requires management to make various assumptions, judgments and estimates to determine the reported amounts 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. Accordingly, actual results could differ from amounts previously established.
Significant estimates with regard to the consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative assets and liabilities, the estimated expense for share based compensation and depletion, depreciation, and amortization.
Fair Value of Financial Instruments
The carrying amount of Resolute’s financial instruments, namely cash and cash equivalents, accounts receivable and accounts payable, approximate their fair value because of the short-term nature of these instruments. The long-term debt (see Note 7) has a recorded value that approximates its fair market value. The fair value of derivative instruments (see Note 11) is estimated based on market conditions in effect at the end of each reporting period.
Industry Segment and Geographic Information
Resolute conducts operations in one industry segment, the crude oil, gas and NGL exploration and production industry. All of Resolute’s operations and assets are located in the United States, and all of its revenue is attributable to domestic customers. Resolute considers gathering, processing and marketing functions as ancillary to its oil and gas producing activities, and therefore are not reported as a separate segment.
Cash, Cash Equivalents, and Marketable Securities
For purposes of reporting cash flows, Resolute considers all highly liquid investments with original maturities of three months or less at date of purchase to be cash equivalents. Resolute periodically maintains cash and cash equivalents in bank deposit accounts and money market funds which may be in excess of federally insured amounts. Resolute has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
Cash and cash equivalents held in trust are with JPMorgan Chase Bank, N.A., and Continental Stock Transfer & Trust Company serves as the trustee. The Company considers all highly liquid investments placed in trust with original maturities of three months or less to be cash equivalents. The Company had $250.0 million held in trust at December 31, 2008.
Marketable securities held in trust were with JPMorgan Chase Bank, N.A., and Continental Stock Transfer & Trust Company serves as the trustee. The marketable securities held in trust were invested in U.S. Treasury Bills with a maturity of 180 days or less. The Company had $290.1 million held in trust at December 31, 2008.
Amounts held in trust were restricted as to use until consummation of an initial qualifying business combination.
Accounts Receivable
The Company’s accounts receivable at December 31, consists of the following (in thousands):
Concentration of Credit Risk
Financial instruments that potentially subject Resolute to concentrations of credit risk consist primarily of trade, production and derivative settlement receivables. Resolute derived approximately 87% and 9% of its total 2009 revenue from Western and WGR Asset Holding Company, LLC, respectively. If Resolute was compelled to sell its crude oil to an alternative market, costs associated with the transportation of its production would increase, and such increase could materially and negatively affect its operations. The concentration of credit risk in the oil and gas industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. Commodity derivative contracts expose Resolute to the credit risk of non-performance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, all of which are financial institutions participating in Resolute’s Credit Facility (see Note 7).
Oil and Gas Properties
Resolute uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, improved recovery systems and a portion of general and administrative expenses are capitalized on a country-wide basis (the “cost center”).
Resolute conducts tertiary recovery projects on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Under the full cost method, all development costs are capitalized at the time incurred. Development costs include charges associated with access to and preparation of well locations, drilling and equipping development wells, test wells, and service wells including injection wells, and acquiring, constructing, and installing production facilities and providing for improved recovery systems. Improved recovery systems include all related facility development costs and the cost of the acquisition of tertiary injectants, primarily purchased carbon dioxide (“CO2”). The development cost related to CO2 purchases are incurred solely for the purpose of gaining access to incremental reserves not otherwise recoverable. The accumulation of injected CO2, in combination with additional purchased and recycled CO2, provides future economic value over the life of the project.
In contrast, other costs related to the daily operation of the improved recovery systems are considered production costs and are expensed as incurred. These costs include, but are not limited to, compression, electricity, separation, re-injection of recovered CO2 and water and reservoir pressure maintenance.
Capitalized general and administrative and operating 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. Resolute capitalized general and administrative and operating costs related to its acquisition, exploration and development activities of $0.1 million during 2009. No general and administrative and operating costs were capitalized during 2008 or 2007.
Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. The Company’s investments in unproved properties are related to exploration plays in the Black Warrior
Basin in Alabama and the Big Horn Basin in Wyoming. The Company expects to evaluate these locations for the existence of proved reserves in the next two to four years. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense as appropriate. During 2009, Resolute transferred $3.9 million in unproved property costs to the full cost pool.
No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain or loss significantly alters the relationship between the capitalized costs and proved oil reserves of the cost center.
Depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of asset retirement obligations and future development costs of proved reserves, including, but not limited to, costs to drill and equip development wells, constructing and installing production and processing facilities, and improved recovery systems, including the cost of required future CO2purchases.
Pursuant to full cost accounting rules, Resolute must perform a ceiling test each quarter on its proved oil and gas assets. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs. There have been no provisions for impairment of oil and gas property costs for the periods ended December 31, 2009, 2008 and 2007, respectively.
The Company’s full cost pool is solely comprised of assets attributable to the Resolute Transaction. In accordance with Regulation S-X Article 4-10 and rules for full cost accounting for proved oil and gas properties, Resolute performed a ceiling test at December 31, 2009 using its year-end reserve estimates prepared in accordance with the recently promulgated SEC rules. Total capitalized costs exceeded the full cost ceiling by approximately $150 million; however, no impairment was recognized at December 31, 2009, as the Company requested and received an exemption from the Securities and Exchange Commission (the “SEC”) to exclude the Resolute Transaction from the full cost ceiling assessment for a period of twelve months following the acquisition, provided the Company can demonstrate that the fair value of the acquired properties exceeds the carrying value in the interim periods through June 30, 2010. The request for exemption was made because the Company could demonstrate beyond a reasonable doubt that the fair value of the Resolute Transaction oil and gas properties exceed unamortized cost at the Acquisition Date and at December 31, 2009.
At the Acquisition Date, Resolute valued its oil and gas properties using NYMEX forward strip prices for a period of five years and then held prices flat thereafter. The Company also used various discount rates and other risk factors depending on the classification of reserves. Management believes this internal pricing model reflected the fair value of the assets acquired. Under full cost ceiling test rules, the commodity price utilized was equal to the trailing twelve-month unweighted arithmetic average of first day of the month prices resulting in an average NYMEX oil price of $61.18 per barrel of oil and an average Henry Hub spot market price for gas of $3.87 per MMBtu of gas, which may not be indicative of actual fair market values.
While commodity prices have increased since September 30, 2009, the Company recognizes that due to the volatility associated with oil and natural gas prices, a downward trend could occur. If such a case were to occur and is deemed to be other than temporary, the Company would assess the Resolute Transaction properties for
impairment during the requested exemption period. Further, if the Company cannot demonstrate that fair value exceeds the unamortized carrying costs during the exemption periods, the Company will recognize impairment.
Other Property and Equipment
Other property and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Field offices are depreciated over fifteen to twenty years. Leasehold improvements are depreciated, using the straight line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.
Impairment of Long-Lived Assets Other than Oil and Gas Properties
Resolute evaluates long-lived assets for impairment or when indicators of possible impairment are present. Resolute performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets and if the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to the assets’ fair value and an impairment loss is recorded against the long-lived asset. There have been no provisions for impairment recorded for the periods ended December 31, 2009, 2008 and 2007.
Asset Retirement Obligation
Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
The restricted cash of $13.0 million located on the Company’s consolidated balance sheet at December 31, 2009 in non-current other assets is legally restricted for the purpose of settling asset retirement obligations related to Predecessor Resolute’s purchase of properties from a subsidiary of ExxonMobil Corporation and its affiliates (“ExxonMobil Properties”) (See Note 13).
Resolute’s estimated asset retirement obligation liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit- adjusted risk-free rate estimated at the time the liability is incurred or revised. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. Asset retirement obligations are valued utilizing Level 3 fair value measurement inputs. See Note 12.
The following table provides a reconciliation of Resolute’s asset retirement obligations at December 31, (in thousands):
Derivative Instruments
Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging, requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of a derivative are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivative hedging instruments must be recorded in either other comprehensive income or current earnings, depending on the nature and designation of the instrument. Presently, Resolute’s management has determined that the benefit of cash flow hedge accounting, which may allow for its derivative instruments to be reflected as cash flow hedges, is not commensurate with the administrative burden required to support that treatment. As a result, Resolute marks its derivative instruments to fair value on the consolidated balance sheets and recognizes the changes in fair market value in earnings. Gains and losses on derivative instruments reflected in the consolidated statements of operations incorporate both the realized and unrealized amounts.
Resolute enters into derivative contracts to manage its exposure to oil and gas price volatility. Derivative contracts may take the form of futures contracts, swaps or options. Realized and unrealized gains and losses related to commodity derivatives are recognized in other income (expense). Realized gains and losses are recognized in the period in which the related contract is settled. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the statement of cash flows.
Revenue Recognition
Oil and gas revenue is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and the collectability of the revenue is probable. Oil and gas revenue is recorded using the sales method.
RWI is party to three well suspension agreements (the “Agreements”). The counterparties to the Agreements from time to time may submit a request to RWI to suspend well operations or defer drilling plans on certain acreage under lease to RWI in exchange for non-refundable payments. Revenue is recognized for these payments over the expected development plan or until such time as the specified properties are released from suspension and RWI may proceed with exploration of these properties. During 2009, the Company recognized $0.2 million in income related to the Agreements
General and Administrative Expenses
General and administrative expenses are reported net of amounts capitalized to oil and gas properties and of reimbursements of overhead costs that are billed to working interest owners of the oil and gas properties operated by Resolute. In addition, the Company recorded $16.6 million of transaction costs related to the Resolute Transaction for the year ended December 31, 2009 (see Note 3). No transaction costs were recognized in 2008 and 2007.
Income Taxes
Income taxes and uncertain tax positions are accounted for in accordance with FASB ASC Topic 740, Accounting for Income Taxes. Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. A valuation allowance is established when necessary to reduce deferred tax assets to the amount expected to be realized. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth FASB ASC Topic 740.
Accounting Standards Update
In June of 2009, the FASB established the ASC as the single source of authoritative GAAP for all non-governmental entities with the exception of authoritative guidance from the SEC. All other accounting literature is considered non-authoritative. The ASC changes the way the Company cites authoritative guidance within the Company’s financial statements and notes to the financial statements. The ASC is effective for periods ending on or after September 15, 2009, and did not have a material impact on the Company’s consolidated financial statements.
Resolute adopted FASB ASC Topic 805, Business Combinations, on January 1, 2009. This guidance establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the contingent and identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The nature and magnitude of the specific effects of this guidance on the consolidated financial statements will depend upon the nature, terms and size of the acquisitions consummated after the effective date. Resolute expensed approximately $3.5 million of deferred acquisition costs in its 2009 consolidated financial statements as the new guidance no longer allowed deferral of these costs.
In January of 2010, the FASB issued additional guidance to improve disclosure requirements related to fair value measurements and disclosures. Specifically, this guidance requires disclosures about transfers in and out of Level 1 and 2 fair value measurements, activity in Level 3 fair value measurements (See Note 12 for Level 1, 2 and 3 definitions), greater desegregation of the amounts on the consolidated balance sheets that are subject to fair value measurements and additional disclosures about the valuation techniques and inputs used in fair value measurements. This guidance is effective for annual reporting periods beginning after December 31, 2009, except for disclosure of Level 3 fair value measurement roll forward activity, which is effective for annual reporting periods beginning after December 15, 2010. The Company is currently assessing the impact this guidance will have on the consolidated financial statements.
On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system. This system, which was developed by several industry organizations, is a widely accepted standard for the management of petroleum resources. Key revisions include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. FASB ASC Topic 932 was updated in January of 2010 to align the oil and gas reserve estimation and disclosure requirements in the ASC with the SEC’s oil and gas reporting requirements. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. Resolute adopted the requirements for the year ended December 31, 2009 and the consolidated financial statements were impacted in the following manner:
•
The price used in calculating reserves changed from a single-day closing price measured on the last day of the Company’s fiscal year to a 12-month average first of the month price for the previous twelve months as of the balance sheet date. This average price was utilized in the Company’s depletion and ceiling test calculations.
•
The notes to the consolidated financial statements include additional financial reporting disclosures.
Note 3 -
Acquisitions and Divestitures
Resolute Transaction
On September 25, 2009, HACI completed the Resolute Transaction with Resolute, through which, in a series of transactions, HACI’s stockholders collectively acquired a majority of the outstanding shares of Resolute common stock, and the Company acquired, directly or indirectly, 100% of the equity interests comprising Predecessor Resolute, with the exception of Aneth, in which the Company indirectly acquired a 99.996% equity interest. The total purchase price was allocated to the acquired assets and liabilities assumed of Predecessor Resolute based on their respective fair values as determined by management.
The total purchase price was comprised of the following (in thousands):
The business combination was accounted for using the acquisition method, in which HACI was the accounting acquirer, and resulted in a new basis of accounting reflecting the fair values of the Predecessor Resolute assets acquired and liabilities assumed. The following table presents the preliminary allocation of the purchase price at September 25, 2009, based on the estimated fair values of assets acquired and liabilities assumed (in thousands):
The fair value of acquired properties was determined based upon numerous inputs, many of which were unobservable (which are defined as Level 3 inputs). The significant inputs used in estimating the fair value were: (1) NYMEX crude oil and natural gas futures prices (observable), (2) projections of the estimated quantities of oil and gas reserves, (3) projections regarding rates and timing of production, (4) projections regarding amounts and timing of future development and abandonment costs, (5) projections regarding the amounts and timing of operating costs and property taxes, (6) estimated risk adjusted discount rates and (7) estimated inflation rates. As a result of applying the above assumptions, the Company estimated the aggregate fair value of the oil and gas assets acquired at $622.5 million for proved properties and $11.1 million for unevaluated properties. Portions of the consideration paid were valued using a Black-Scholes model which is also a Level 3 input. The fair value of the acquired current assets and current liabilities equaled their stated amounts due to their short-term maturities. The fair value of the debt assumed under the Credit Facility approximated its stated amount due to the variable interest rate grid and its May 2011 maturity date. The fair value of derivative assets and liabilities were determined consistent with the basis described in Note 12 - Fair Value Measurements. There were no identifiable intangibles acquired and no goodwill was recognized as identifiable assets acquired and the liabilities assumed approximated the purchase price.
The Company has not yet submitted final tax returns for Predecessor Resolute for the period ended September 24, 2009. Any adjustments to the tax returns may impact the estimated fair value of the assets and liabilities acquired. Any adjustments will be reflected retrospectively.
In connection with the Resolute Transaction, HACI acquired an estimated 72.8% membership interest in Aneth in exchange for HACI’s payment to Aneth of $325 million (the “HACI Contribution”), which Aneth used to repay a portion of the debt outstanding under Aneth’s credit facilities.
Immediately following the repayment of debt, Sub contributed to the Company its interests in Predecessor Resolute in exchange for:
(i)
9,200,000 shares of Company common stock, 200,000 of which were issued to service providers (employees of Predecessor Resolute who became employees of Resolute upon consummation of the Resolute Transaction) in recognition of their services. 100,000 shares vested immediately on September 25, 2009 and the remaining 100,000 shares will vest on the one year anniversary of the Acquisition Date, provided the recipient remains an employee of the Company;
(ii)
4,600,000 new Company Founders Warrants, (“New Founder Warrants”) issued in exchange for Old Founder’s Warrants (defined below) to purchase Company common stock with a strike price of $13.00, a trigger price of $13.75 and a five year term from the date of the Resolute Transaction; and
(iii)
1,385,000 Company earnout shares, which are shares of Company common stock (with voting rights) (“Earnout Shares”) that will be forfeited if the price of Company common stock does not exceed $15.00 per share for 20 trading days in any 30 trading day period within five years from the date of the Resolute Transaction.
Immediately prior to the Resolute Transaction, 7,335,000 shares of common stock and 4,600,000 sponsor warrants of HACI that had been issued to the founder of HACI (“Founder Shares” and “Old Founder Warrants,” respectively) were cancelled and forfeited. Sponsor Warrants of 2,333,333 were sold to Sub by the sponsor in exchange for Sub’s payment of $1,166,667 to the Sponsor. Sponsor Warrants were warrants to purchase the common stock of HACI held by the Sponsor that were exchanged in the Resolute Transaction for New Sponsor Warrants to purchase Company common stock with a strike price of $13.00 and a five year term.
Immediately following the HACI Contribution and simultaneously with Sub’s contribution of Predecessor Resolute, Resolute Subsidiary Corporation, a wholly owned subsidiary of Resolute, merged with and into HACI, with HACI surviving. HACI continues as a wholly-owned subsidiary of Resolute and the outstanding shares of HACI common stock and outstanding HACI warrants, including outstanding Old Founder Warrants and Sponsor Warrants, were exchanged for Sub’s contribution. After the Resolute Transaction, the former HACI stockholders and warrant holders have no direct equity ownership interest in HACI.
Pro Forma Financial Information
The unaudited pro forma consolidated financial information in the table below summarizes the results of operations of the Company as though the Resolute Transaction had occurred as of the beginning of each period presented. The pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of the earliest period presented or that may result in the future. The pro forma adjustments made are based on certain assumptions that Resolute believes are reasonable based on currently available information.
The unaudited pro forma financial information for the years ended December 31, 2009 and 2008 combine the historical results of HACI and Predecessor Resolute. Additionally, the 2008 period includes the pro forma results of a net profits overriding royalty interest (“NPI”) acquired by RWI on July 31, 2008, as though the NPI had been acquired as of January 1, 2008.
Note 4 -
Earnings per Share
The Company computes earnings per share using the two class method. Basic net income per share is computed using the weighted average number of common shares outstanding during the period. Diluted net income per share is computed using the weighted average number of common shares and, if dilutive, potential common shares outstanding during the period. Potentially dilutive shares consist of the incremental shares issuable under the outstanding warrants and earnout shares.
The treasury stock method is used to measure the dilutive impact of potentially warrants. When there is a loss, all potentially dilutive shares will be anti-dilutive. As such, there were no dilutive shares for the year ended December 31, 2009 and therefore, the impact of 48,400,000 warrants and 3,250,000 earnout shares outstanding for the year ended December 31, 2009, were not included in the calculation of diluted loss per share. In 2008 and 2007, 76,000,000 warrants were contingently issuable and were excluded from the calculation of diluted earnings per share.
The liquidation rights of the holders of the Company’s common stock and common stock that were subject to redemption are identical, except with respect to redemption rights for dissenting shareholders in an acquisition by the Company. As a result, the undistributed earnings for each year are allocated based on the contractual participation rights of the common stock and common stock subject to redemption as if the earnings for the year had been distributed. The undistributed earnings are allocated to common stock subject to redemption based on their pro-rata right to income earned by the trust and, in 2009, their share of administrative expenses. Subsequent to the Resolute Transaction, no common stock subject to redemption remains outstanding.
The following table sets forth the computation of basic and diluted net income per share of common stock and common stock subject to redemption (in thousands except per share data):
A summary of the activity associated with warrants during 2009, 2008 and 2007 is as follows (in thousands):
Warrants entitle the holder to purchase one share of Company common stock at a price of $13.00 per share and expire on September 25, 2014.
Note 5 -
Marketable Securities Held in Trust
The carrying amount, including accrued interest, gross unrealized holding gains, gross unrealized holding losses, and fair value of held-to-maturity marketable securities by major security type and class of security are as follows (in thousands):
The treasury bills classified as held-to-maturity mature within one year. On September 25, 2009, the marketable securities held in trust were distributed in connection with the Resolute Transaction (see Note 3).
Note 6 -
Related Party Transactions
HACI agreed to pay up to $10,000 a month for office space and general and administrative services to Hicks Holdings Operating LLC (“Hicks Holdings”), an affiliate of HACI’s founder and chairman of the board, Thomas O. Hicks. Services commenced after the effective date of the Offering and were terminated on the Acquisition Date due to the consummation of the Resolute Transaction. The Company expensed $0.1 million during each of the periods ended December 31, 2009, 2008 and 2007 under this agreement.
During 2009, Resources carried a payable for payments received on behalf of affiliate, Holdings, for Holdings’ transactions not related to Resolute. Resources paid Holdings $1.3 million in satisfaction of this payable during 2009.
Note 7 -
Long Term Debt
Resolute’s credit facility is with a syndicate of banks led by Wachovia Bank, National Association (the “Credit Facility”) with Aneth as the borrower. The Credit Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value of Resolute’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base is re-determined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such re-determinations. Under certain circumstances, either Resolute or the lenders may request an interim re-determination. As of December 31, 2009, the borrowing base was $240 million and outstanding borrowings were $109.6 million. Unused availability under the borrowing base as of December 31, 2009 was $121.9 million. The borrowing base availability has been reduced by $8.5 million in conjunction with letters of credit issued to vendors at December 31, 2009. The Credit Facility matures on April 13, 2011 and, to the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity.
The outstanding balance under the Credit Facility accrues interest, at Aneth’s option, at either (a) the London Interbank Offered Rate, plus a margin which varies from 2.5% to 3.5%, or (b) the Alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Federal Funds Effective Rate plus 0.5%, plus a margin which varies from 1.0% to 2.0%. Each such margin is based on the level of utilization under the borrowing base. As of December 31, 2009, the weighted average interest rate on the outstanding balance under the facility was 3.30%. The Credit Facility is collateralized by substantially all of the proved oil and gas assets of Aneth and RWI, and is guaranteed by Resolute and its subsidiaries other than Aneth.
The Credit Facility includes terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Resolute was in compliance with all terms and covenants of the Credit Facility at December 31, 2009.
On March 30, 2010, the Company entered into a Restated Credit Agreement (the “Restated Agreement”). Under the terms of the Restated Agreement, the borrowing base was increased from $240.0 million to $260.0 million and the maturity date was extended to March 2014. At Resolute’s option, the outstanding balance under the Credit Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 2.25% to 3.0% or (b) the Alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Federal Funds Effective Rate plus 0.5%, or (iii) an adjusted London Interbank Offered Rate plus 1%, plus a margin which ranges from 1.25% to 2.0%.
As of March 30, 2010, Resolute had borrowings of $115.4 million under the borrowing base, resulting in an unused availability of $136.1 million.
Note 8 -
Income Taxes
The following table summarizes the components of the provision for income taxes (in thousands):
The provision for income taxes for the periods ended December 31, 2009, 2008 and 2007 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to income before income taxes. This difference relates primarily to state income taxes and estimated permanent differences as follows (in thousands):
The tax effects of temporary differences that give rise to significant portions of the deferred income tax assets and liabilities are presented below (in thousands):
As set forth in Note 3, the Company acquired Predecessor Resolute’s assets and liabilities in a partially tax-free transaction pursuant to Section 351 of the Internal Revenue Code. Accordingly, the Company established a
deferred tax liability of $75.5 million as part of the acquisition accounting to give effect to the differing financial accounting and income tax bases of the acquired assets and liabilities.
The Company has U.S. net operating loss carryforwards of $25.2 million at December 31, 2009, which will begin expiring in 2025. Of the $25.2 million, $6.0 million would not be available for use until 2011 and after.
The Company adopted the accounting for uncertain tax positions per FASB ASC Topic 740, Accounting for Income Taxes, from inception. This guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This guidance requires that the Company recognize in the consolidated financial statements, only those tax positions that are “more-likely-than-not” of being sustained, based on the technical merits of the position. As a result of the implementation of this guidance, the Company performed a comprehensive review of the Company’s material tax positions. This guidance had no effect on the Company’s financial position, cash flows or results of operations at for 2009, 2008 or 2007 as the Company had no unrecognized tax benefits. The Company’s policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. The Company has no accrued interest or penalties related to uncertain tax positions as of December 31, 2009 or 2008.
The Company is subject to the following material taxing jurisdictions: U.S. federal, Colorado, Utah and the Navajo Nation. The tax years that remain open to examination by the Internal Revenue Service are the years 2006 through 2009. The tax years that remain open to examination by Colorado and Utah are 2005 through 2009. Resource’s 2007 tax return is currently under examination in the U.S. federal jurisdiction.
Note 9 -
Stockholders’ Equity and Equity Based Awards
Preferred Stock
The Company is authorized to issue up to 1,000,000 shares of preferred stock, par value $0.0001 with such designations, voting and other rights and preferences as may be determined from time to time by the Board of Directors. No shares were issued and outstanding as of December 31, 2009 or December 31, 2008.
Common Stock
The authorized common stock of the Company consists of 225,000,000 shares. The holders of the common shares are entitled to one vote for each share of common stock. In addition, the holders of the common stock are entitled to receive dividends when, as and if declared by the Board of Directors. At December 31, 2009, the Company had 53,154,883 shares of common stock issued and outstanding. HACI had 69,000,000 common shares issued and outstanding at December 31, 2008.
Of the 53,154,883 shares of common stock outstanding at December 31, 2009, 3,250,000 are classified as Earnout Shares. Earnout Shares are common stock of Resolute subject to forfeiture in the event that an earnout target of $15.00 per share is not met by September 25, 2014. The Earnout Shares have voting rights and are transferable; however, they are not registered for resale and do not participate in dividends until the trigger price is met.
Holders of 30% of public common stock, less one share, had the right to vote against any acquisition proposal and demand conversion of their shares for a pro rata portion of cash and marketable securities held in trust, less certain adjustments. As a result, HACI classified 16,559,999 of the total 69,000,000 common shares issued during 2007 as common stock, subject to possible redemption for $160.8 million. The common stock subject to redemption participated in the net income of HACI. Income or loss attributable to common stock subject to redemption was considered in the calculation of earning per share and the deferred interest attributable to common stock subject to possible redemption was accrued. Upon consummation of the Resolute Transaction, the $160.8 million temporary equity was reclassified to common stock and additional paid-in capital and 11,592,084 shares were redeemed. The deferred interest attributable to the shares of common stock not redeemed of $1.9 million was reclassified to stockholders’ equity.
Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with FASB ASC Topic 718, Stock Compensation.
On July 31, 2009, the Company adopted the 2009 Stock Incentive Performance Plan (the “Incentive Plan”), providing for long-term equity based awards intended as a means for the Company to attract, motivate, retain and reward directors, officers, employees and other eligible persons through the grant of awards and incentives for high levels of individual performance and improved financial performance of the Company. Equity-based awards are also intended to further align the interests of award recipients and the Company’s stockholders. The Company’s Board of Directors or one or more committees appointed by the Company’s Board of Directors will administer the Incentive Plan. The maximum number of shares of Company common stock that may be issued pursuant to awards under the Incentive Plan is 2,657,744.
The Incentive Plan authorizes stock options, stock appreciation rights, restricted stock, restricted stock units, stock bonuses and other forms of awards that may be granted or denominated in Company common stock or units of Company common stock, as well as cash bonus awards. The Incentive Plan retains flexibility to offer competitive incentives and to tailor benefits to specific needs and circumstances. Any award may be paid or settled in cash at the Company’s option. As of December 31, 2009, no long-term equity based awards have been granted.
On September 25, 2009, the Company and Sub entered into a Retention Bonus Award Agreement calling for the award to employees of the Company of 200,000 shares of Company common stock that would otherwise have been issued to Sub in the Resolute Transaction. Resolute accounts for these awards under the provisions of FASB ASC Topic 718. Fifty percent of each employee award was awarded without restriction and fifty percent of each employee award was granted contingent upon the employee remaining employed by the Company for one year following the closing of the Resolute Transaction. As of December 31, 2009, employees had forfeited 11,697 shares under this agreement, leaving 88,303 unvested shares outstanding. The compensation expense to be recognized for the awards was measured based on the Company’s traded stock price at the date of the Resolute Transaction. For the year ended December 31, 2009, the Company recorded $1.1 million of stock based compensation expense for this award, of which $0.9 million was recorded in general and administrative expense and $0.2 million was recorded in lease operating expense. The remaining expense will be recognized over the remaining vesting period ending on September 25, 2010.
Note 10 -
Employee Benefits
The Company offers a variety of health and benefit programs to all employees, including medical, dental, vision, life insurance and disability insurance. The Company’s executive officers are generally eligible to participate in these employee benefit plans on the same basis as the rest of the Company’s employees. The Company offers a 401(k) plan for all eligible employees. For the year ended December 31, 2009, the Company expensed $0.5 million in connection with matching of employee contributions. No matching contributions were made in 2008 or 2007. Employee benefit plans may be modified or terminated at any time by the Company’s Board of Directors.
On October 22, 2009, the Company’s Board of Directors approved (i) cash awards to employees in the aggregate amount of approximately $1.5 million, with 50% of each award to an employee to be paid currently and 50% to be paid one year from closing if the employee remains employed by the Company; (ii) the payment to each employee who had been subject to a salary reduction in 2009 a lump sum payment equal to the amount of the reduction, such payments aggregating to approximately $0.3 million; and (iii) the payment of lump sum payments to employees approximately equal to the amount they would have received as matching 401(k) contributions for 2008 had Predecessor Resolute made a matching contribution in accordance with past practice, such bonuses amounting to approximately $0.6 million.
Time Vested Cash Awards
Prior to the Resolute Transaction, certain employees of Predecessor Resolute hold time vested cash awards (“Awards”). All of the Awards bear simple interest of 15% per annum commencing January 1, 2008, and are payable in three installments, with the first installment paid on January 1, 2009 and the remaining two installments payable on January 1, 2010 and 2011. The Awards are accounted for as deferred compensation. The annual payments are paid contingent upon the employee’s continued employment with Resolute and there is potential for forfeiture of the Awards. Accordingly, Resolute will accrue the Awards and related return for the respective year on an annual basis. For the year ended December 31, 2009, $0.1 million of compensation expense related to the Awards was recognized. The remaining amount to be paid at December 31, 2009 for all Awards is $0.3 million.
Note 11 -
Derivative Instruments
Effective January 1, 2009, new authoritative accounting guidance regarding derivative instruments and hedging activities requires entities to provide greater transparency about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows.
Resolute enters into commodity derivative contracts to manage its exposure to oil and gas price volatility. Resolute has not elected to designate derivative instruments as cash flow hedges under the provisions of FASB ASC Topic 815. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying consolidated statements of operations. Realized and unrealized gains and losses from Resolute’s price risk management activities are recognized in other income (expense), with realized gains and losses recognized in the period in which the related production is sold. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the statement of cash flows. Commodity derivative contracts may take the form of futures contracts, swaps or options.
As of December 31, 2009, Resolute had entered into certain commodity swap contracts. The following table represents Resolute’s commodity swaps through 2013:
Resolute also uses basis swaps in connection with gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the index price at which the gas production is sold. The table below sets forth Resolute’s outstanding basis swaps as of December 31, 2009.
As of December 31, 2009, Resolute had entered into certain commodity collar contracts. The following table represents Resolute’s commodity collars:
Resolute’s derivative instruments are not designated and do not qualify for hedge accounting under the FASB ASC. For financial reporting purposes, Resolute does not offset the fair value amounts of derivative assets and liabilities with the same counterparty. See Note 12 for the location and fair value amounts of Resolute’s commodity derivative instruments reported in the consolidated balance sheets at December 31, 2009.
Because Resolute’s derivative instruments are not designated and do not qualify for hedge accounting under the FASB ASC, the gains and losses are included in other income (expense) in the consolidated statements of operations. The table below summarizes the location and amount of commodity derivative instrument losses reported in the consolidated statements of operations (in thousands):
Credit Risk and Contingent Features in Derivative Instruments
Resolute is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. All counterparties are lenders under Resolute’s Credit Facility. Accordingly, Resolute is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Credit Facility. Resolute’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events, and set-off provisions. Resolute has set-off provisions with its lenders that, in the event of counterparty default, allow Resolute to set-off amounts owed under the Credit Facility or other general obligations against amounts owed for derivative contract liabilities.
The maximum amount of loss in the event of all counterparties defaulting is $0 as of December 31, 2009, due to the set off provisions noted above.
Note 12 - Fair Value Measurements
Resolute fully adopted this guidance as it relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g. those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of goodwill and other long-lived assets) as of January 1, 2009. The full adoption did not have a material impact on Resolute’s consolidated financial statements or its disclosures.
FASB ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The guidance establishes a hierarchy for determining the fair values of assets and liabilities, based on the significance level of the following inputs:
•
Level 1 - Quoted prices in active markets for identical assets or liabilities.
•
Level 2 - Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
•
Level 3 - Significant inputs to the valuation model are unobservable.
An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Resolute’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Following is a description of the valuation methodologies used by Resolute as well as the general classification of such instruments pursuant to the hierarchy.
As of December 31, 2009, Resolute’s commodity derivative instruments were required to be measured at fair value on a recurring basis. Resolute used the income approach in determining the fair value of its derivative instruments, utilizing present value techniques for valuing its swaps and basis swaps and option-pricing models for valuing its collars. Inputs to these valuation techniques include published forward index prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. Substantially all of these inputs are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the valuation hierarchy.
The following is a listing of Resolute’s assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2009 (in thousands):
Note 13 - Commitments and Contingencies
CO2 Take-or-Pay Agreements
Resolute is party to two take-or-pay purchase agreements, each with a different supplier, under which Resolute has committed to buy specified volumes of CO2. The purchased CO2 is for use in Resolute’s enhanced tertiary recovery projects in Aneth Field. In each case, Resolute is obligated to purchase a minimum daily volume of CO2 or pay for any deficiencies at the price in effect when delivery was to have occurred. The CO2 volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in these take-or-pay purchase agreements. Therefore, Resolute expects to avoid any payments for deficiencies.
One contract was effective July 1, 2006, with a four year term. As of December 31, 2009, future commitments under this purchase agreement amounted to approximately $3.0 million in 2010, based on prices in effect at December 31, 2009. The second contract was entered into on May 25, 2005, and was amended on July 1, 2007, and has a ten year term. Future commitments as of December 31, 2009 under this purchase agreement amounted to approximately $62.3 million through June 2016 based on prices in effect on December 31, 2009.
The annual minimum obligation by year is as follows (in thousands):
Crude Production Purchase Agreement
Resolute sells all of its crude oil production from the Aneth field to a single customer, Western Refining Southwest, Inc. (“Western”), a subsidiary of Western Refining, Inc. Resolute and Western entered into a new contract on August 27, 2009, effective September 1, 2009. The new contract provides for a minimum price equal to the NYMEX price for crude oil less a fixed differential of $6.25 per Bbl. The contract provides for an initial term of one year and continuing month-to-month thereafter, with either party having the right to terminate after the initial term, upon ninety days written notice. The contract may also be terminated by Western after December 31, 2009, upon sixty days written notice, if Western is not able to renew its right-of-way agreements with the Navajo Nation or if such rights-of-way are declared invalid and Western is prevented from using such rights-of-way.
Operating Leases
For 2009, 2008 and 2007, month-to-month office facilities rental payments charged to expense were approximately $0.3 million, $0.1 million and $0.1 million, respectively. Future rental payments for office facilities under the terms of non-cancelable operating leases as of December 31, 2009 were approximately $0.5 million and $0.4 million for the years ending December 31, 2010 and 2011, respectively. As of December 31, 2009, the Company does not have any office facility leases in effect for 2012 and beyond. In February 2010, the Company entered into an amended office lease agreement. Under this agreement the Company will incur future annual rental payments of an additional $0.1 million through 2013.
The Company is also party to several field equipment and compressor leases used in the CO2 project. Future rental payments under the terms of these leases amount to annual payments of $2.7 million through 2014 with total lease obligations of $6.0 million thereafter. Rental expense for 2009 was $0.5 million. No rental expense was incurred under these leases in 2008 or 2007.
Escrow Funding Agreement
Under the terms of Predecessor Resolute’s purchase of the ExxonMobil Properties, Predecessor Resolute and Navajo Nation Oil and Gas Company (“NNOG”) were required to fund an escrow account sufficient to complete abandonment, well plugging, site restoration and related obligations arising from ownership of the acquired interests. The contribution net to Aneth’s working interest, is included in other assets: restricted cash in the consolidated balance sheets of December 31, 2009. Aneth is required to make additional deposits to the escrow account annually. Beginning in 2010 and continuing through 2016, Aneth must fund approximately $1.8 million per year. In years after 2016, Aneth must fund additional payments averaging approximately $0.9 million per year until 2031. Total contributions from the date of acquisition through 2031 will aggregate $26.9 million. Annual interest earned in the escrow account becomes part of the balance and reduces the payment amount required for funding the escrow account each year. As of December 31, 2009, Aneth has funded the 2009 annual contractual amount of approximately $1.8 million required to meet its future obligation.
NNOG Purchase Options
In connection with Predecessor Resolute’s acquisition of the ExxonMobil Properties and the acquisition from Chevron Corporation and its affiliates (“Chevron”) of 75% of Chevron’s interest in Aneth Field (“Chevron Properties”) in 2005, pursuant to the terms of the Cooperative Agreement, Predecessor Resolute granted to NNOG three separate but substantially similar purchase options which became obligations of Resolute through the Resolute Transaction. Each purchase option entitles NNOG to purchase from Resolute up to 10% of Resolute’s interest in each of the Chevron Properties and the ExxonMobil Properties. Each purchase option entitles NNOG to purchase, for a limited period of time, the applicable portion of Resolute’s interest in the Chevron Properties or the ExxonMobil Properties, at Fair Market Value (as defined in the agreement), which is determined without giving effect to the existence of the Navajo Nation preferential purchase right or the fact that the properties are located within the Navajo Nation. Each option becomes exercisable based upon Resolute’s achieving a certain multiple of payout of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout
includes the effect of Resolute’s hedging program. The multiples of payout that trigger the exercisability of the purchase option are 100%, 150% and 200%. The options are not exercisable prior to four years from the acquisition except in the case of a sale of such assets by, or a change of control of, Aneth. In that case, the first option for 10% would be accelerated and the other options would terminate. Assuming the purchase options are not accelerated due to a change of control of Aneth, Resolute expects that the initial payout associated with the purchase options granted will occur no sooner than 2013.
The following table demonstrates the maximum net undivided working interest in each of the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit that NNOG could acquire upon exercising each of its purchase options under the Cooperative Agreement. The exercise by NNOG of its purchase options in full would not give it the right to remove Resolute as operator of any of the units.
Note 14 -
Oil and Gas Producing Activities
Costs incurred during 2009 related to oil and gas property acquisition, exploration and development activities, including the fair value of oil and gas properties acquired in the Resolute Transaction are summarized as follows (in thousands):
*
Includes $4.4 million of acquired CO2.
Net capitalized costs related to Resolute’s oil and gas producing activities at December 31, were as follows (in thousands):
Note 15 -
Supplemental Oil and Gas Information (unaudited)
Reserve Engineering and Auditor Qualifications:
Company reserves are prepared by, or under the direct supervision of, the Company’s Reservoir Engineering Manager and are then reviewed internally by senior management and audited by a qualified independent auditor. The professional qualifications of the Reservoir Engineering Manager meet or exceed the qualification of reserve estimators and auditors as set forth by the Society of Petroleum Engineers. The Reservoir Engineering Manager has more than 27 years of practical petroleum engineering and reserve estimation and evaluation experience as well as experience as a qualified reserve estimator and auditor.
The Company’s reserve data is audited by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis. Within NSAI, the technical person primarily responsible for auditing the Company’s reserve estimates has been practicing consulting petroleum engineering at NSAI since 1997. Additionally, this person has more than 28 years of practical experience in petroleum engineering, with more than 12 years experience in the estimation and evaluation of reserves.
Oil and Gas Reserve Quantities:
Resolute had no oil and gas reserves prior to the acquisition of Predecessor Resolute. Accordingly, the following table presents Resolute’s estimated net proved oil and gas reserves and the present value of such estimated net proved reserves as of December 31, 2009. The reserve data as of December 31, 2009 was prepared by Resolute and was audited by NSAI. Users of this information should be aware that the process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Presented below is a summary of the changes in estimated reserves (in thousands):
1)
The gas column includes NGL volumes.
2)
The negative revisions are primarily due to commodity pricing attributable to utilization of average first of month fiscal year commodity prices.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
The following summarizes the policies used in the preparation of the accompanying oil and gas reserves disclosures, standardized measures of discounted future net cash flows from proved oil and gas reserves and the reconciliations of standardized measures at December 31, 2009. The information disclosed is an attempt to present the information in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable to Resolute’s interest in oil and gas properties as of December 31, 2009. Due to the Resolute Transaction, only 2009 activity is presented. Proved reserves are estimated quantities of oil and gas that 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 were 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 was compiled by applying average annual prices of crude oil and gas relating to Resolute’s proved reserves to the year-end quantities of those reserves.
3)
The future cash flows were 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 were based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credits and allowances relating to Resolute’s proved oil and natural gas reserves.
5)
Future net cash flows were 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 Resolute’s oil and 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 following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by FASB ASC Topic 932:
The principal sources of change in the standardized measure of discounted future net cash flows are:
Note 16 -
Quarterly Financial Data (unaudited)
The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2009 and 2008 (in thousands except per share data):
To the Managing Members of
Resolute Natural Resources Company, LLC, Resolute Aneth, LLC, WYNR, LLC, and BWNR, LLC
and
To the Board of Directors of RNRC Holdings, Inc. and Resolute Wyoming, Inc
Denver, Colorado
We have audited the accompanying combined balance sheet of Resolute Natural Resources Company, LLC and related combined companies as of December 31, 2008, and the related combined statements of operations, shareholder’s/member’s equity (deficit), and cash flows for the period from January 1, 2009 to September 24, 2009, and the years ended December 31, 2008 and 2007. The combined financial statements include the accounts of Resolute Natural Resources Company, LLC and five related companies, Resolute Aneth, LLC, WYNR, LLC, BWNR, LLC, RNRC Holdings, Inc. and Resolute Wyoming, Inc. These companies are under common ownership and common management. These combined financial statements are the responsibility of the companies’ management. Our responsibility is to express an opinion on the combined financial statements based on our audits. The combined financial statements give retrospective effect to a percentage of the acquisition of Resolute Wyoming, Inc. as discussed in Note 2 to the combined financial statements. We did not audit the balance sheet of Resolute Wyoming, Inc. as of December 31, 2007 or the related statements of operations, shareholder’s equity and cash flows of Resolute Wyoming, Inc. for the year ended December 31, 2007, which statements reflect total assets constituting 19% of combined total assets as of December 31, 2007, and total revenues constituting 18% of combined total revenues for the year ended December 31, 2007. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Resolute Wyoming, Inc., is based solely on the report of the other auditors.
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. The companies are not required to have, nor were we engaged to perform, an audit of their 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 companies’ 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, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the combined financial statements referred to above present fairly, in all material respects, the combined financial position of Resolute Natural Resources Company, LLC and related companies at December 31, 2008 and the combined results of their operations and combined cash flows for the period from January 1, 2009 to September 24, 2009, and each of the years ended December 31, 2008 and 2007, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the combined financial statements, the combined financial statements have been retrospectively adjusted for the change in accounting for noncontrolling interests.
/s/ Deloitte & Touche LLP
Denver, Colorado
March 29, 2010
RESOLUTE NATURAL RESOURCES COMPANY, LLC,
RESOLUTE ANETH, LLC, WYNR, LLC, BWNR, LLC,
RESOLUTE WYOMING, INC.,
RNRC HOLDINGS, INC.
Combined Balance Sheet
(in thousands, except share amounts)
See notes to combined financial statements
RESOLUTE NATURAL RESOURCES COMPANY, LLC,
RESOLUTE ANETH, LLC, WYNR, LLC, BWNR, LLC,
RESOLUTE WYOMING, INC.,
RNRC HOLDINGS, INC.
Combined Statements of Operations
(in thousands)
See notes to combined financial statements
RESOLUTE NATURAL RESOURCES COMPANY, LLC
RESOLUTE ANETH, LLC
WYNR, LLC
BWNR, LLC
RESOLUTE WYOMING, INC.
RNRC HOLDINGS, INC.
Combined Statements of Shareholder’s/Member’s Equity (Deficit)
(in thousands, except for shares)
See notes to combined financial statements
RESOLUTE NATURAL RESOURCES COMPANY, LLC
RESOLUTE ANETH, LLC
WYNR, LLC
BWNR, LLC
RESOLUTE WYOMING, INC.
RNRC HOLDINGS, INC.
Combined Statements of Cash Flows
(in thousands)
See notes to combined financial statements
RESOLUTE NATURAL RESOURCES COMPANY, LLC
RESOLUTE ANETH, LLC
WYNR, LLC
BWNR, LLC
RESOLUTE WYOMING, INC.
RNRC HOLDINGS, INC.
Notes to Combined Financial Statements
Note 1 - Description of the Companies and Business
Resolute Natural Resources Company, LLC (“Resources”), previously a Delaware corporation incorporated on January 22, 2004 and converted to a limited liability company on September 30, 2008, Resolute Aneth, LLC (“Aneth”), a Delaware limited liability company established on November 12, 2004, WYNR, LLC (“WYNR”), a Delaware limited liability company established on August 25, 2005, BWNR, LLC (“BWNR”), a Delaware limited liability company established on August 19, 2005, RNRC Holdings, Inc. (“RNRC”), a Delaware corporation incorporated on September 19, 2008 and Resolute Wyoming, Inc. (“RWI”) (formerly Primary Natural Resources, Inc. (“PNR”)), a Delaware corporation incorporated on November 21, 2003 (the change of name to RWI was effective September 29, 2008) (together, “Predecessor Resolute” or the “Companies”) are engaged in the acquisition, exploration, development, and production of oil, gas and natural gas liquids (“NGL”), primarily in the Paradox Basin in southeastern Utah and the Powder River Basin in Wyoming. The Companies are wholly owned subsidiaries of Resolute Holdings Sub, LLC (“Sub”), which in turn is a wholly owned subsidiary of Resolute Holdings, LLC (“Holdings”).
Note 2 -
Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The accompanying combined financial statements of Predecessor Resolute have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The 2009, 2008 and 2007 combined financial statements include the accounts of Resources and the five related companies: Aneth, WYNR, BWNR, RNRC and RWI. The conversion of Resources to an LLC and the formation of RNRC had no impact on the comparability of the combined financial statements. These companies are under common ownership and common management. All intercompany balances and transactions have been eliminated in combination.
On July 31, 2008, Predecessor Resolute acquired RWI. 87.23% of the acquisition of RWI was accounted for as a combination of entities under common control, which is similar to the pooling of interests method of accounting for business combinations. Accordingly, the combined financial statements give retrospective effect to these transactions, and therefore, Predecessor Resolute’s results from January 1, 2008, through July 31, 2008, include 87.23% of the operations of RWI. The remaining 12.77% of the acquisition of RWI was accounted for using the purchase method. Accordingly, the accompanying combined financial statements reflect the 12.77% as not owned until the acquisition on July 31, 2008.
On September 25, 2009 (the “Acquisition Date”), Hicks Acquisition Company I, Inc. (“HACI”) consummated a business combination under the terms of a Purchase and IPO Reorganization Agreement (the “Acquisition Agreement”) with Resolute Energy Corporation (“Resolute”), pursuant to which, through a series of transactions, HACI’s stockholders collectively acquired a majority of the outstanding equity of the Companies (the “Resolute Transaction”), and Resolute owns, directly or indirectly, 100% of the equity interests of Resources, WYNR, BWNR, RNRC, and RWI, and indirectly owns a 99.996% equity interest in Aneth. References to 2009 in these Notes relate to the 267 day period ended September 24, 2009, unless otherwise specified.
Subsequent to the issuance of the unaudited combined interim financial statements included in Form 10-Q for the quarterly period ended September 30, 2009 of Resolute Energy Corporation, management identified a classification error in the statement of cash flows for the period ended September 24, 2009. The error relates to
the recording of a routine end-of-period adjustment made to changes in “accounts payable and accrued expenses” in the operating activities section in order to exclude any unpaid liabilities incurred during the period to acquire assets. The accompanying statement of cash flows for the period ended September 24, 2009 has been restated, resulting in a $2.8 million increase in cash flows provided by operating activities and cash flows used in investing activities, respectively.
Assumptions, Judgments, and Estimates
The preparation of the combined financial statements in conformity with GAAP requires management to make various assumptions, judgments and estimates to determine the reported amounts 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. Accordingly, actual results could differ from amounts previously established.
Significant estimates with regard to the combined financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative assets and liabilities, the estimated expense for equity based compensation and depletion, depreciation, and amortization.
Fair Value of Financial Instruments
The carrying amount of Predecessor Resolute’s financial instruments, namely cash and cash equivalents, accounts receivable and accounts payable, approximate their fair value because of the short-term nature of these instruments. The fair value to the notes receivable and payable approximate their fair market value. The long-term debt has a recorded value that approximates its fair market value since its variable interest rate is tied to current market rates.
Cash Equivalents
For purposes of reporting cash flows, Predecessor Resolute considers all highly liquid investments with original maturities of three months or less at date of purchase to be cash equivalents. Predecessor Resolute periodically maintains cash and cash equivalents in bank deposit accounts and money market funds which may be in excess of federally insured amounts. Predecessor Resolute has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
Concentration of Credit Risk
Financial instruments that potentially subject Predecessor Resolute to concentrations of credit risk consist primarily of trade and production receivables. Predecessor Resolute derived 81% and 13% of its total 2009 revenue from Western Refining, Inc. and WGR Asset Holding Company, LLC, respectively. Predecessor Resolute derived 80% and 11% of its 2008 and 2007 revenue from Western Refining, Inc, and WGR Asset Holding Company, LLC, respectively. The concentration of credit risk in a single industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. Commodity derivative contracts expose Predecessor Resolute to the credit risk of non-performance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, each of which is a financial institution participating in Predecessor Resolute’s bank credit agreement. As of December 31, 2008, Predecessor Resolute recorded an allowance for doubtful accounts of $0.7 million.
Oil and Gas Properties
Predecessor Resolute uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, improved recovery systems and a portion of general and administrative expenses are capitalized within the cost center.
Predecessor Resolute conducts tertiary recovery projects on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Under the full cost method, all development costs are capitalized at the time incurred. Development costs include charges associated with access to and preparation of well locations, drilling and equipping development wells, test wells, and service wells including injection wells; acquiring, constructing, and installing production facilities and providing for improved recovery systems. Improved recovery systems include all related facility development costs and the cost of the acquisition of tertiary injectants, primarily purchased CO2. The development cost related to CO2 purchases are incurred solely for the purpose of gaining access to incremental reserves not otherwise recoverable. The accumulation of injected CO2, in combination with additional purchased and recycled CO2, provide future economic value over the life of the project.
In contrast, other costs related to the daily operation of the improved recovery systems are considered production costs and are expensed as incurred. These costs include, but are not limited to, compression, electricity, separation, re-injection of recovered CO2 and water. Costs incurred to maintain reservoir pressure are also expensed as incurred.
Capitalized general and administrative and operating 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. Predecessor Resolute capitalized general and administrative and operating costs of $0.3 million, $1.6 million and $3.5 million related to its acquisition, exploration and development activities in 2009, 2008 and 2007, respectively.
Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense as appropriate.
Pursuant to full cost accounting rules, Predecessor Resolute must perform a ceiling test each quarter on its proved oil and gas assets. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs. As a result of this limitation on capitalized costs, the accompanying combined financial statements include a provision for an impairment of oil and gas property cost in 2009 and 2008 of $13.3 million and $245.0 million, respectively. No provisions for impairment were booked in 2007.
No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain or loss significantly alters the relationship between the capitalized costs and proved oil reserves of the cost center.
Depletion and amortization of oil and gas properties is computed on the unit-of-production method based on proved reserves. Amortizable costs include estimates of asset retirement obligations and future development costs of proved reserves, including, but not limited to, costs to drill and equip development wells, constructing and installing production and processing facilities, and improved recovery systems, including the cost of required future CO2purchases.
Other Property and Equipment
Other property and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated from three to five years. Field offices are depreciated from fifteen to twenty years. Leasehold improvements are depreciated, using the straight line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.
Asset Retirement Obligations
Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability. See Note 4.
Impairment of Long-Lived Assets
For non-oil and gas properties, Predecessor Resolute follows Financial Accounting Standards Board (“FASB”) Accounting Standards Codifications (“ASC”) Topic 360, Property Plant and Equipment, which requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of such assets. In the evaluation of the fair value and future benefits of long-lived assets, Predecessor Resolute performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets. If the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to its fair value. Other than the full cost ceiling test impairment discussed in the oil and gas properties accounting policy, there were no provisions for impairment in 2009, 2008 and 2007.
Deferred Financing Costs
Deferred financing costs are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced. The unamortized balance of these costs was approximately $6.4 million as of December 31, 2008.
Derivative Instruments
Predecessor Resolute enters into derivative contracts to manage its exposure to oil and gas price volatility. Derivative contracts may take the form of futures contracts, swaps or options. Realized and unrealized gains and losses related to commodity derivatives are recognized in other income (expense). Realized gains and losses are recognized in the period in which the related contract is settled. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element.
Derivatives deemed to contain a financing element are reported as financing activities in the statement of cash flows.
Predecessor Resolute recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of a derivative are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivative hedging instruments are recorded in current earnings, depending on the nature and designation of the instrument. Presently, Predecessor Resolute’s management has determined that the benefit of the financial statement presentation which may allow for its derivative instruments to be reflected as cash flow hedges is not commensurate with the administrative burden required to support that treatment. As a result, Predecessor Resolute marked its derivative instruments to fair value during 2009, 2008 and 2007 and recognized the changes in fair market value in earnings. The gain or loss on derivative instruments reflected in the combined statement of operations incorporate both the realized and unrealized amounts.
Revenue Recognition
Oil revenue is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and if the collectability of the revenue is probable. Gas revenue is recorded using the sales method. Under this method, Predecessor Resolute recognizes revenue based on actual volumes of gas sold to purchasers. Predecessor Resolute and other joint interest owners may sell more or less than their entitlement share of the volumes produced. A liability is recorded and the revenue is deferred if Predecessor Resolute’s excess sales of gas volumes exceed its estimated remaining recoverable reserves. Resolute had no significant gas imbalances at December 31, 2008.
RWI is party to a twenty year Well Suspension Agreement (the “Agreement”) with Thunder Basin Coal Company, LLC and Ark Land Company (collectively “TBCC”). The initial term of the agreement does not exceed 20 years from October 1, 2006. However, both RWI or TBCC have the option to extend the agreement 10 years beyond the expiration of the initial term. Under the agreement, TBCC will pay RWI $2.6 million in exchange for suspension of well operations or deferral of drilling plans by RWI on certain acreage under lease to RWI. The non-refundable payment is payable to RWI in three installments over a period of three years beginning January 1, 2008. Revenue is recognized over TBCC’s expected development plan or until such time the specified properties are released from suspension and RWI may proceed with exploration of these properties. RWI recognized revenue related to the Agreement of $0.5 million, $0.4 million and $0.4 million in other revenue during 2009, 2008 and 2007, respectively.
RWI is party to two additional well suspension agreements (the “Agreements”). The counterparties to these Agreements from time to time may submit a request to RWI to suspend well operations or defer drilling plans on certain acreage under lease to RWI in exchange for non-refundable payments. Revenue is recognized for these payments over the expected development plan or until such time the specified properties are released from suspension and RWI may proceed with exploration of these properties. During 2009, the Company recognized $0.1 million in income related to the Agreements.
General and Administrative Expenses
General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners of the oil and gas properties operated by Predecessor Resolute.
Income Taxes
Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. RNRC and RWI use the asset and liability method of accounting for deferred income taxes. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the combined financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A
valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. Effective January 1, 2007, Resources (prior to converting to an LLC) and RWI adopted the uncertainty provision of FASB ASC Topic 740, Accounting for Income Taxes. In accordance with this guidance, Resources (prior to converting to an LLC), RNRC and RWI income tax positions must meet a more-likely-than-not recognition threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within interest expense and general and administrative expenses, respectively.
Aneth, WYNR, BWNR and Resources are limited liability companies. As limited liability companies, Aneth, WYNR, BWNR and Resources (subsequent to converting to an LLC) are tax flow-through entities and, therefore, the related tax obligation, if any, is borne by the owners.
Industry Segment and Geographic Information
At September 24, 2009, Predecessor Resolute conducted operations in one industry segment, that being the crude oil, gas and natural gas liquids exploration and production industry. Predecessor Resolute considers gathering, processing and marketing functions as ancillary to its oil and gas producing activities, and therefore are not reported as a separate segment. All of Predecessor Resolute’s operations and assets are located in the United States, and all of its revenue is attributable to domestic customers.
Change in Accounting Principle
In June 2006, the FASB issued guidance which creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The guidance also focuses on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition of certain tax positions.
Resources and RWI adopted this guidance on January 1, 2007 and RNRC adopted this guidance on September 30, 2008. As a result of the implementation of this guidance, Resources recognized a $0.5 million increase in the liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings and a corresponding increase in other long-term liabilities. There was no impact related to RWI and RNRC’s adoption of this guidance.
Accounting Standards Update
Predecessor Resolute adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations on January 1, 2009. FASB ASC Topic 805 establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the contingent and identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. FASB ASC Topic 805 is effective for financial statements issued for fiscal years beginning after December 15, 2008. The nature and magnitude of the specific effects of FASB ASC Topic 805 on the combined financial statements will depend upon the nature, terms and size of the acquisitions consummated after the effective date. There have not been any acquisitions since adoption.
In April 2009, the FASB issued ASC Topic 825-10-65-1, Interim Disclosures about Fair Value of Financial Instruments which requires disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. FASB ASC Topic 825-10-65-1 is effective for interim and annual reporting periods ending after June 15, 2009. The adoption of this pronouncement did not have an impact on Predecessor Resolute’s combined financial statements, other than additional disclosures.
In April 2009, the FASB issued ASC 820-10-65-4, Determining Fair Value When the Volume or Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly. FASB ASC Topic 820-10-65-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and requires that companies provide interim and annual disclosures of the inputs and valuation technique(s) used to measure fair value. FASB ASC Topic 820-10-65-4 is effective for interim and annual reporting periods ending after June 15, 2009 and is to be applied prospectively. The adoption of this pronouncement did not have an impact on Predecessor Resolute’s combined financial statements.
Predecessor Resolute adopted FASB ASC Topic 810-10-65-1, Noncontrolling Interests in Consolidated Financial Statements - an amendment to Accounting Research Bulletin (“ARB”) No. 51, on January 1, 2009. FASB ASC Topic 810-10-65-1 changed the accounting and reporting requirements for minority interests, which are now characterized as noncontrolling interests and are classified as a component of equity in the accompanying combined balance sheet. FASB ASC Topic 810-10-65-1 requires retroactive adoption of the presentation and disclosure requirements for existing noncontrolling interests, with all other requirements applied prospectively. Accordingly, Predecessor Resolute has reclassified net income attributable to noncontrolling interests on the combined statements of operations, to below net income for all periods presented.
In March 2008, the FASB issued ASC Topic 815-10-65, Disclosures about Derivative Instruments and Hedging Activities - An Amendment of FASB Statement 133. FASB ASC Topic 815-10-65 enhances required disclosures regarding derivatives and hedging activities, including enhanced disclosures regarding: (a) how an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under the derivatives and hedging Topic of the ASC, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Predecessor Resolute adopted this pronouncement as of January 1, 2009 (see Note 10).
Predecessor Resolute adopted FASB ASC Topic 855, Subsequent Events on April 1, 2009, which established general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this pronouncement did not have a material impact on Predecessor Resolute’s combined financial statements.
Predecessor Resolute adopted FASB ASC Topic 105-10-65-1, The “FASB Accounting Standards Codification” and the Hierarchy of Generally Accepted Accounting Principles on July 1, 2009. This pronouncement is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. This pronouncement established only two levels of GAAP, authoritative and nonauthoritative. The ASC was not intended to change or alter existing GAAP, and it therefore did not have any impact on Predecessor Resolute’s combined financial statements, other than to modify certain existing disclosures. The ASC is the source of authoritative, nongovernmental GAAP, except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the ASC is considered nonauthoritative.
Note 3 -
Acquisitions
ExxonMobil Acquisition
On April 14, 2006, Aneth acquired from Exxon Mobil Corporation and its affiliates (“ExxonMobil”) 75% of the ExxonMobil interests in Aneth Field, (the “ExxonMobil Properties”) along with various other related assets, including ExxonMobil’s interest in the Aneth gas compression facility, its interest in a CO 2 pipeline which serves the field, and office facilities in Cortez, Colorado.
Under the terms of the Purchase and Sale Agreement for the ExxonMobil Properties, Predecessor Resolute and Navajo Nation Oil and Gas Company (“NNOG”) were required to fund an escrow account sufficient to complete abandonment, well plugging, site restoration and related obligations arising from ownership of the acquired interests. The contribution required at the date of acquisition of $10.0 million, or $7.5 million net to Aneth’s interest, is included in restricted cash in the combined balance sheet as of December 31, 2008. Aneth is required to make additional deposits to the escrow account annually. Beginning in 2007 and continuing through
2016, Aneth must fund approximately $1.8 million annually. As of September 24, 2009, Aneth had funded this annual obligation. In years after 2016, Aneth must fund additional payments averaging approximately $0.9 million until 2031. Total contributions from the date of acquisition through 2031 will aggregate $53.4 million, or $40.0 million net to the Aneth interest. Annual interest earned in the escrow account becomes part of the balance and reduces the payment amount required for funding the escrow account each year. As of December 31, 2008 Aneth has funded the 2008 annual contractual amount required to meet its future obligation, approximately $1.8 million.
Net Profits Overriding Royalty Interest Contribution
On July 31, 2008 Predecessor Resolute entered into an asset contribution agreement with NGP-VII Income Co-Investment Opportunities, LLC (“NGP Co-Invest”), whereby NGP Co-Invest contributed a certain overriding net profits royalty interests (“NPI”) in oil and gas properties of RWI to Holdings for a total of 2,184,445 common units (value of $19.7 million) as consideration.
On July 31, 2008, RWI acquired the contributed NPI from Holdings for $19.4 million and allocated the $19.4 million to oil and gas properties after normal purchase price adjustments. The acquisition of the NPI was funded with $15.4 million cash and a note payable to Holdings. On December 31, 2008, Holdings contributed the note receivable and accrued interest in the amount of $4.1 million to Aneth.
Primary Natural Resources Acquisition
On July 31, 2008, Holdings completed the acquisition of PNR (a Natural Gas Partners, VII, L.P. (“NGP VII”) portfolio company). Upon closing, Holdings paid, as consideration, a total of 8,286,985 common units (value of $74.8 million) and $15.4 million in cash. NGP VII owns a significant equity position in Holdings.
The majority of the acquisition of PNR was accounted for as a combination of entities under common control, which is similar to the pooling of interests method of accounting for business combinations. Accordingly, the combined financial statements give retrospective effect to these transactions, and therefore, Predecessor Resolute’s results from January 1, 2007 through July 31, 2008, include 87.23% of the operations of RWI. Accordingly, the accompanying combined financial statements reflect the 12.77% not owned by Predecessor Resolute as a noncontrolling interest for results from January 1, 2007, through July 31, 2008.
The remaining portion of the acquisition of RWI not under common control, was accounted for using the purchase method in accordance with SFAS No. 141, Business Combinations, which was subsequently revised by FASB ASC Topic 805. 12.77% of the purchase price was allocated to acquired assets and liabilities based on their respective fair value as determined by management. The purchase price allocation is set forth below (in thousands).
The following table presents the pro forma operating results for years ended December 31, 2008 and 2007. The years ended December 31, 2008 and 2007 give effect as if the acquisition of PNR had occurred January 1, 2007. The pro forma results shown below are not necessarily indicative of the operating results that would have occurred if the transaction had occurred on such date. The pro forma adjustments made are based on certain
assumptions that Predecessor Resolute believes are reasonable based on currently available information (unaudited; in thousands):
Note 4-
Asset Retirement Obligations
Predecessor Resolute’s estimated asset retirement obligation liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount Predecessor Resolute’s abandonment liabilities range from 3.90% to 13.50%. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.
The following table provides a reconciliation of Predecessor Resolute’s asset retirement obligation (in thousands):
Note 5-Related Party Transactions
On April 1, 2005, Holdings entered into a joint venture arrangement with Wachovia Investment Holdings, LLC (“Wachovia Investment”) to form an oil and gas marketing and trading company, Odyssey Energy Services, LLC (“Odyssey”), allocating profits and losses 40% to Holdings and 60% to Wachovia Investment. Holdings made an initial capital contribution of $2.0 million, and agreed to be responsible for up to a total of $10.0 million of additional capital to cover certain potential liabilities. Holdings borrowed $2.0 million from Resources, which loan was evidenced by a note. Terms of the note included annual payment of interest at a rate of 4.09%. Interest income recognized on the note was $0.1 million in both 2008 and 2007. This note was paid in full on September 30, 2008.
Resources has received payments due Holdings for Holdings’ transactions not related to Predecessor Resolute. Such payments have not yet been reimbursed to Holdings. These payables are reflected on the combined balance sheet as “Accounts payable - Holdings” and carried a balance of approximately $1.3 million at December 31, 2008.
Note 6-Long Term Debt
Long term debt and current portion of long term debt consisted of the following (in thousands):
First Lien Facility
Predecessor Resolute’s credit facility is with a syndicate of banks led by Wachovia Bank, National Association (the “First Lien Facility”) with Aneth as the borrower. The First Lien Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value of Predecessor Resolute’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base is redetermined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such redeterminations. As of September 24, 2009, the borrowing base was $240.0 million and the unused availability under the borrowing base was $32.8 million. As of December 31, 2008 the borrowing base was $284.0 million and unused availability under the borrowing base was $77.8 million. The First Lien Facility matures on April 13, 2011 and, to the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity. On May 12, 2009, Predecessor Resolute entered into the Fourth Amendment to the Amended and Restated First Lien Credit Facility (“Fourth Amendment”) to redetermine its borrowing base and interest rates, and to amend its Maximum Leverage Ratio covenant (effective March 31, 2009). Under the terms of the Fourth Amendment, at Aneth’s option, the outstanding balance under the First Lien Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 2.5% to 3.5%, or (b) the Alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Federal Funds Effective Rate plus 0.5%, plus a margin which varies from 1.0% to 2.0%. Each such margin is based on the level of utilization under the borrowing base. On July 28, 2009, Resolute entered into the Fifth Amendment to the Amended and Restated First Lien Credit Facility (“Fifth Amendment”) to amend its Current Ratio covenant. Under the terms of the Fifth Amendment, the Current Ratio covenant was not applicable for the quarters ended March 31, 2009 and June 30, 2009. On September 17, 2009, Predecessor Resolute entered into the Sixth Amendment to the Amended and Restated First Lien Credit Facility to amend certain terms and sections in the agreement in order to allow for the Resolute Transaction. As of September 24, 2009 and December 31, 2008, the weighted average interest rate on the outstanding balance under the facility was approximately 4.0% and 5.0%, respectively. The First Lien Facility is collateralized by substantially all of the proved oil and gas assets of Aneth and RWI, and is guaranteed by all of the companies other than Aneth.
The First Lien Facility includes terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Predecessor Resolute was in compliance with all terms and covenants of the First Lien Facility at December 31, 2008. Predecessor Resolute was not in compliance with the First Lien Facility June 30, 2009 Maximum Leverage Ratio covenant. The Company entered into a waiver agreement with its First Lien Facility lenders on August 27, 2009, whereby the requirement to comply with the Maximum Leverage Ratio covenant for the period ended June 30, 2009 had been waived until the earlier to occur of (a) October 15, 2009 or (b) the Early Termination Date, defined as the date on which the lenders notify Predecessor Resolute that it has determined in its sole discretion that a material condition to the merger between Predecessor Resolute and HACI is unlikely to be satisfied by October 15, 2009 (“Waiver Termination Date”). Upon the Waiver Termination Date, the Maximum Leverage Ratio shall be calculated using the outstanding debt amount as of the Waiver Termination Date. The terms of the waiver allowed Predecessor Resolute to remain in compliance with the Maximum Leverage Ratio covenant at June 30, 2009 and
September 24, 2009. Predecessor Resolute was in compliance with all other terms and covenants of the First Lien Facility at September 24, 2009.
On September 25, 2009, Resolute repaid $99.5 million outstanding under the First Lien Facility with cash received from the Resolute Transaction.
Second Lien Facility
Predecessor Resolute’s term loan was with a group of lenders, with Wilmington Trust FSB as the agent (the “Second Lien Facility”) and with Aneth as the borrower. The Second Lien Facility carries a borrowing base of $225.0 million which was fully utilized at September 24, 2009 and December 31, 2008. Balances outstanding under the Second Lien Facility accrue interest at either (a) the adjusted London Interbank Offered Rate plus the applicable margin of 4.5%, or (b) the greater of (i) the Administrative Agent’s Prime Rate, (ii) the Administrative Agent’s Base CD rate plus 1%, or (iii) the Alternative Base Rate, plus the applicable margin of 3.5%. The Second Lien Facility was collateralized by substantially all of the proved oil and gas assets of Aneth and RWI, and was guaranteed by all of the companies other than Aneth. The claim of the Second Lien Facility lenders on the collateral was explicitly subordinated to the claim of the First Lien Facility lenders. As of September 24, 2009 and December 31, 2008, the weighted average interest rate on the outstanding balance under the facility was approximately 5.0% and 7.7%, respectively.
The Second Lien Facility included terms and covenants that placed limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Predecessor Resolute was in compliance with all terms and covenants of the Second Lien Facility at December 31, 2008. On August 28, 2009, Aneth gave notice to the lenders that it was in default of the Maximum Leverage Ratio covenant (calculated as the ratio of debt to trailing four quarter EBITDA), as measured at June 30, 2009. On September 1, 2009, lenders under the Second Lien Credit Facility declared the loan in default and accelerated the indebtedness. As a result of the declaration of default on September 1, 2009, default interest of an additional 2% per annum was imposed and the Company was prohibited from utilizing the Eurodollar interest option in future borrowings under the facility.
On September 25, 2009, Resolute repaid all amounts outstanding under the Second Lien Facility with cash received from the Resolute Transaction.
Note 7-Income Taxes
Resources (prior to September 30, 2008), RNRC and RWI recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the combined financial statements or tax returns. Deferred tax assets and liabilities are determined based on the differences between the financial statement and tax basis of assets and liabilities using the enacted tax rates in effect for the year in which the differences are expected to reverse. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that are not expected to be realized based on available evidence. Resources (subsequent to September 30, 2008), Aneth, BWNR and WYNR are pass-through entities for federal and state income tax purposes. As such, neither current nor deferred income taxes are recognized by these entities.
Significant components of Predecessor Resolute’s deferred tax assets (liabilities) are as follows (in thousands):
The provision for income taxes is as follows (in thousands):
Income tax expense (benefit) differed from amounts that would result from applying the U.S. statutory income tax rate to income before taxes as follows (in thousands):
*
Tax expense (benefit) is calculated based on taxable income of RNRC and RWI, which are taxable entities. Aneth, Sub, BWNR and WYNR are pass-through entities for federal and state income tax purposes. As such, neither current nor deferred income taxes are recognized by these entities.
As of September 24, 2009 and December 31, 2008, RNRC had no regular tax loss carryforward. As of September 24, 2009 and December 31, 2008, RWI had regular tax loss carryforwards of $11.3 million and $10.6 million, respectively.
Resources and RWI adopted the uncertainty provisions of FASB ASC Topic 740, Accounting for Income Taxes, on January 1, 2007 and RNRC adopted the uncertainty provisions of FASB ASC Topic 740 on September 30, 2008. As a result of the implementation of this guidance, Resources recognized approximately $0.5 million, including accrued interest and penalties of $0.1 million, as a contingent liability and an increase to the January 1, 2007 balance of accumulated deficit. As of December 31, 2008 the total contingent income tax liabilities and accrued interest was approximately $0.5 million and is reflected in current liabilities in the combined balance sheet in “Contingent tax liability.” During 2009, the previously unrecognized tax benefit in the amount of $0.4 million related to the uncertain tax position was recognized. Previously accrued interest and penalties were also reversed. This recognition and reversal resulted from the expiration of the applicable statute of limitations on September 15, 2009.
Resources (prior to September 30, 2008), RNRC and RWI recognize interest and penalties related to uncertain tax positions in interest expense and general and administrative expense, respectively. RWI and RNRC had no uncertain tax positions. Resources and RWI file income tax returns in the U.S. federal jurisdiction and various states. Resource’s 2007 tax return is currently under examination in the U.S. Federal jurisdiction. Furthermore, Resources and RWI’s tax years of 2006 and forward are subject to examination by the federal and state taxing authorities.
The following table summarizes the activity during the years related to the liability for unrecognized tax benefits (in thousands):
Note 8 -
Shareholder’s/Member’s Equity and Equity Based Awards
Common Stock
At September 24, 2009 and December 31, 2008, RNRC and RWI each had 1,000 shares of common stock, par value $0.01 and $1.00 per share, authorized, issued and outstanding, respectively.
Member’s Equity
At September 24, 2009 and December 31, 2008, member’s equity included Aneth, WYNR, BWNR and Resources.
Incentive Interests
Resources
“Incentive Units” were granted by Holdings to certain of its members who were also officers, as well as to other employees of Resources. The Incentive Units were intended to be compensation for services provided to Resources. The original terms of the five tiers of Incentive Units are as follows. Tier I units vest ratably over three years, but are subject to forfeiture if payout is not realized. Tier I payout is realized at the return of members’ invested capital and a specified rate of return. Tiers II through V vest upon certain specified multiples of cash payout. Incentive Units are forfeited if an employee of Predecessor Resolute is either terminated for cause or resigns as an employee. Any Incentive Units that are forfeited by an individual employee revert to the founding senior managers of Predecessor Resolute and, therefore, the number of Tier II through V Incentive Units is not expected to change.
On June 27, 2007, Holdings made a capital distribution of $100 million to its equity owners from the proceeds of the Second Lien Facility. This distribution caused both the Tier I payout to be realized and the Tier I Incentive Units to vest. As a result of the distribution, management determined that it was probable that Tiers II-V incentive unit payouts would be achieved.
Predecessor Resolute recorded $2.8 million, $3.7 million and $34.5 million of equity based compensation expense in general and administrative expense in the combined statements of operations for 2009, 2008, and 2007, respectively. An additional $0.1 million and $2.0 million of equity compensation expense was capitalized and recorded in oil and gas properties during 2008 and 2007, respectively. No equity compensation expense was capitalized in 2009.
Predecessor Resolute amortizes the estimated fair value of the Incentive Units over the remaining estimated vesting period using the straight-line method. The estimated weighted average fair value remaining of the Incentive Units was calculated using a discounted future net cash flows model. No Incentive Units vested during 2009 and 2008. In 2007, 11.6 million Incentive Units vested.
At December 31, 2008, there were 17,797,801 incentive units outstanding, of which 6,190,539 were not vested and have a weighted average grant date fair value of $2.08 per unit. There were no grants or forfeitures during 2009, 2008 and 2007.
Total unrecognized compensation cost related to Predecessor Resolute’s non-vested Incentive Units totaled $5.3 million and $8.1 million as of September 24, 2009 and December 31, 2008, respectively. Total unrecognized compensation cost related to Predecessor Resolute’s non-vested Incentive Units as of September 24, 2009 is expected to be recognized over weighted-average periods of 0.75 years, 1.75 years, 2.75 years and 2.75 years for the Tier II, Tier III, Tier IV and Tier V Incentive Units, respectively.
Resolute Wyoming, Inc.
The Primary Natural Resources Holdings, LLC (“PNRH”) Operating Agreement (the “Operating Agreement”) provided for the issuance of up to 900,000 “PNRH Incentive Interests,” consisting of 844,000 Incentive Units and 56,000 Incentive Options. PNR was wholly owned by PNRH prior to the PNR acquisition. There were two categories for Incentive Units, described as Tier I and Tier II. There was one category for Incentive Options described as Tier I. Tier I Incentive Units received preferential payout over Tier II. Of the 844,000 Incentive Units, 484,000 and 360,000 were classified as Tier I and Tier II, respectively. Holders of Incentive Units were entitled to cash distributions following the sale, merger or other transaction involving the stock or assets of PNR after the recovery of capital contributions plus a rate of return, specified as payout levels in the Operating Agreement. The 844,000 Tier I and Tier II Incentive Units were granted in January 2004 to certain members of PNR’s management.
Due to the acquisition of PNR on July 31, 2008, the performance criteria related to the PNRH Incentive Interests was achieved and the Incentive Interests fully vested. As a result, $4.2 million of equity based compensation expense was recorded in general and administrative expense in 2008. No further equity based compensation expense will be recorded related to these Incentive Interests.
Equity Appreciation Rights
In November 2006 and May 2008, 2,500,000 and 3,000,000 Equity Appreciation Rights (“EARs”) were authorized, respectively. The EARs are periodically granted by Sub to certain of Predecessor Resolute’s employees. The EARs represent contract rights to a certain portion of future distributions of cash by Sub.
Upon consummation of the Acquisition Agreement on September 25, 2009 the EARs plan was cancelled. Predecessor Resolute has not assigned any value or recognized any share based compensation expense related to the EARs because no distributions were made in respect of such EARs prior to the plan termination.
On May 29, 2008, Resources, on behalf of Sub, entered into Agreements with several employees permitting those employees to make an offer to exchange for cash some or all of the EARs issued in 2007 and prior under the EARs Plan, dated November 27, 2006. The participant could elect to offer to exchange all or any portion of their EARs for time vested cash awards equal to $2.00 per unit plus simple interest of 15% per annum, effective January 1, 2008. During 2008, a total of 395,000 units were exchanged from employees under this agreement.
Also on May 29, 2008, Resources, on behalf of Sub, granted incentive awards allowing employees to elect to receive a certain number of EARs or an amount of time vested cash awards of $1.00 per unit plus simple interest of 15% per annum, effective January 1, 2008. During 2008, a total of 1,659,000 EARs were granted and 213,700 time vested cash award units were issued.
All of the cash awards are payable in three installments on January 1, 2009, 2010 and 2011. Compensation expense related to the time vested cash awards of $0.2 million, $0.5 million and $0 was recognized, during 2009, 2008 and 2007, respectively. The time vested cash awards are accounted for as deferred compensation. The annual payments are paid based on the employee’s tenure with Resources and there is potential for forfeiture of the time vested payment, therefore Predecessor Resolute will accrue for each time vested payment and related return for the respective year on an annual basis.
A summary of the activity associated with the EARs plan during 2007, 2008 and 2009 is as follows:
The EARs plan was terminated on September 25, 2009, and all outstanding EARs were cancelled due to the Resolute Transaction. The time vested cash awards were not terminated.
Note 9 -
Defined Contribution Plan
Predecessor Resolute offers a 401(k) plan for all eligible employees. For the periods ended September 24, 2009 and December 31, 2008 and 2007, Predecessor Resolute contributed $0, $0.2 million and $0.8 million respectively, in connection with matching of employee contributions made in 2009, 2008 and 2007, respectively.
Note 10 -
Derivative Instruments
Predecessor Resolute enters into commodity derivative contracts to manage its exposure to oil and gas price volatility. Predecessor Resolute has not elected to designate derivative instruments as cash flow hedges under the provisions of FASB ASC Topic 815, Derivatives and Hedging. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying combined statements of operations. Realized and unrealized gains and losses from Predecessor Resolute’s price risk management activities are recognized in other income (expense), with realized gains and losses recognized in the period in which the related production is sold. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the statement of cash flows. Commodity derivative contracts may take the form of futures contracts, swaps or options.
As of September 24, 2009, Predecessor Resolute had entered into certain commodity swap contracts. The following table represents Predecessor Resolute’s commodity swaps with respect to its estimated oil and gas production from proved developed producing properties through 2013:
Predecessor Resolute also uses basis swaps in connection with gas swaps in order to fix the price differential between the NYMEX Henry Hub price and the index price at which the gas production is sold. The table below sets forth Predecessor Resolute’s outstanding basis swaps as of September 24, 2009.
As of September 24, 2009, Predecessor Resolute had entered into certain commodity collar contracts. The following table represents Predecessor Resolute’s commodity collars with respect to its estimated oil and gas production from proved developed producing properties:
For financial reporting purposes, Predecessor Resolute does not offset the fair value amounts of derivative assets and liabilities with the same counterparty. The table below summarizes the location and fair value amounts of Predecessor Resolute’s commodity derivative instruments reported in the combined balance sheet (in thousands):
Because Predecessor Resolute’s derivative instruments are not designated and do not qualify as hedging instruments under FASB ASC Topic 815, the gains and losses are included in other income (expense) in the combined statements of operations. The table below summarizes the location and amount of commodity derivative instrument gains and losses reported in the combined statements of operations for the periods presented below (in thousands):
Credit Risk and Contingent Features in Derivative Instruments
Predecessor Resolute is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. With the exception of one contract, all counterparties are also lenders under Predecessor Resolute’s First Lien Facility. For these contracts, Predecessor Resolute is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the First Lien Facility. The counterparty that is not among Predecessor Resolute’s lenders is a multinational energy company with a corporate credit rating of AA as classified by Standard and Poor’s. Predecessor Resolute’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events, and set-off provisions. Predecessor Resolute has set-off provisions with its lenders that, in the event of counterparty default, allow Predecessor Resolute to set-off amounts owed under the First Lien Facility or other general obligations against amounts owed for derivative contract liabilities.
The maximum amount of loss in the event of all counterparties defaulting is $0.3 million as of September 24, 2009, after netting any amounts payable by Predecessor Resolute to its counterparties.
See Note 11 for further discussion of derivative instruments.
Note 11 -
Fair Value Measurements
FASB ASC Topic 820, Fair Value Measurements and Disclosures clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. During 2008, Predecessor Resolute elected to not apply FASB ASC Topic 820 to nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities, including nonfinancial long-lived assets measured at fair value for an impairment assessment and asset retirement obligations initially measured at fair value.
Predecessor Resolute fully adopted FASB ASC Topic 820 as it relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g. those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of goodwill and other long-lived assets) as of January 1, 2009. The full adoption did not have a material impact on Predecessor Resolute’s combined financial statements or its disclosures.
FASB ASC Topic 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exact price) in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement establishes a hierarchy for grouping these assets and liabilities, based on the significance level of the following inputs:
•
Level 1 - Quoted prices in active markets for identical assets or liabilities.
•
Level 2 - Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
•
Level 3 - Significant inputs to the valuation model are unobservable.
An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Predecessor Resolute’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Following is a description of the valuation methodologies used by Predecessor Resolute as well as the general classification of such instruments pursuant to the hierarchy.
As of September 24, 2009 and December 31, 2008, Predecessor Resolute’s commodity derivative instruments were required to be measured at fair value. Predecessor Resolute used the income approach in determining the fair value of its derivative instruments, utilizing present value techniques for valuing its swaps and basis swaps and option-pricing models for valuing its collars. Inputs to these valuation techniques include published forward index prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. Substantially all of these inputs are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the valuation hierarchy.
The following is a listing of Predecessor Resolute’s assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2008 (in thousands):
Note 12 -
Commitments and Contingencies
CO2 Take-or-Pay Agreements
Resolute entered into two take-or-pay purchase agreements, each with a different supplier, under which Resolute has committed to buy specified volumes of CO2. The purchased CO2 is for use in Resolute’s enhanced tertiary recovery projects in Aneth Field. In each case, Resolute is obligated to purchase a minimum daily volume of CO2 or pay for any deficiencies at the price in effect when delivery was to have occurred. The CO2volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in this take-or-pay purchase agreement. Therefore, Resolute expects to avoid any payments for deficiencies. Predecessor Resolute acquired $8.9 million of CO2 during the period ended September 24, 2009.
One contract was effective July 1, 2006, with a four year term. As of December 31, 2008, future commitments under this purchase agreement amounted to approximately $1.9 million in 2009 and $1.9 million for 2010, based on prices in effect at December 31, 2008. The second contract was entered into on May 25, 2005, and was amended on July 1, 2007, and had a ten year term. Future commitments under this purchase agreement amounted to approximately $27.8 million through June 2016 based on prices in effect on December 31, 2008. The annual minimum obligation by year is as follows (in thousands):
Operating Leases
For the period ended September 24, 2009, and the years ended December 31, 2008 and 2007, month-to-month office facilities rental payments charged to expense under the terms of non-cancelable operating leases was approximately $0.5 million, $1.0 million and $0.8 million, respectively. Future rental payments for office facilities under the remaining terms of non-cancelable operating leases as of December 31, 2008 were approximately $410,000, $460,000, $399,000, $0 and $0 for the years ending December 31, 2009, 2010, 2011, 2012 and 2013.
Predecessor Resolute is also party to several field equipment and compressor leases used in the CO2 project. Rental expense for these leases for 2009, 2008 and 2007 was $1.3 million, $1.3 million and $0.1 million,
respectively. Future payments under these leases as of December 31, 2008 were approximately $1.4 million in 2009, $2.7 million from 2010 through 2013 and $8.5 million thereafter.
Escrow Funding Agreement
Under the terms of Predecessor Resolute’s purchase of the ExxonMobil Properties, Predecessor Resolute and Navajo Nation Oil and Gas Company were required to fund an escrow account sufficient to complete abandonment, well plugging, site restoration and related obligations arising from ownership of the acquired interests. The contribution net to Aneth’s working interest is approximately $1.8 million per year until 2016. In years after 2016, Aneth must fund approximately $0.9 million per year until 2031. Escrow funding payments are included in other assets: restricted cash in the combined balance sheet of December 31, 2008. As of December 31, 2008, Aneth had funded the 2008 annual contractual amount of approximately $1.8 million required to meet its future obligation.
NNOG Purchase Options.
In connection with acquisition of the ExxonMobil Properties and the acquisition from Chevron Corporation and its affiliates (“Chevron”) of 75% of Chevron’s interest in Aneth Field (“Chevron Properties”) in 2005, pursuant to the terms of the Cooperative Agreement, Predecessor Resolute granted to NNOG three separate but substantially similar purchase options. Each purchase option entitles NNOG to purchase from Predecessor Resolute up to 10% of Predecessor Resolute’s interest in the Chevron Properties and the ExxonMobil Properties. Each purchase option entitles NNOG to purchase, for a limited period of time, the applicable portion of Predecessor Resolute’s interest in the Chevron Properties and the ExxonMobil Properties, at Fair Market Value (as defined in the agreement), which is determined without giving effect to the existence of the Navajo Nation preferential purchase right or the fact that the properties are located within the Navajo Nation. Each option becomes exercisable based upon Predecessor Resolute’s achieving a certain multiple of payout of the relevant acquisition costs, subsequent capital costs and ongoing operating costs attributable to the applicable working interests. Revenue applicable to the determination of payout includes the effect of Predecessor Resolute’s hedging program. The options are not exercisable prior to four years from the acquisition except in the case of a sale of such assets by, or a change of control of, Aneth. In that case, the first option for 10% would be accelerated and the other options would terminate. Assuming the purchase options are not accelerated due to a change of control of Aneth, Predecessor Resolute expects that the initial payout associated with the purchase options granted will occur no sooner than 2013.
The following table demonstrates the maximum net undivided working interest in each of the Aneth Unit, the McElmo Creek Unit and the Ratherford Unit that NNOG could acquire upon exercising each of its purchase options under the Cooperative Agreement. The exercise by NNOG of its purchase options in full would not give it the right to remove Predecessor Resolute as operator of any of the units.
Crude Production Purchase Agreement
Predecessor Resolute sells all of its crude oil production from the Aneth field to a single customer, Western Refining Southwest, Inc. (“Western”), a subsidiary of Western Refining, Inc. Predecessor Resolute and Western entered into a new contract on August 27, 2009, effective September 1, 2009. The new contract provides for a minimum price equal to the NYMEX price for crude oil less a fixed differential of $6.25 per Bbl. The contract provides for an initial term of one year and continuing month-to-month thereafter, with either party having the right to terminate after the initial term, upon ninety days written notice. The contract may also be terminated by Western after December 31, 2009, upon sixty days written notice, if Western is not able to renew its right-of-way agreements with the Navajo Nation or if such rights-of-way are declared invalid and Western is prevented from using such rights-of-way.
Note 13 -
Oil And Gas Producing Activities
Costs incurred in oil and gas property acquisition, exploration and development activities are summarized as follows (in thousands):
Net capitalized costs related to Resolute’s oil and gas producing activities were as follows (in thousands):
Note 14 -
Supplemental Oil and Gas Information (unaudited)
Oil and Gas Reserve Quantities:
The following table presents our estimated net proved oil and gas reserves and the present value of such estimated net proved reserves as of September 24, 2009, December 31, 2008, and 2007. The reserve data as of December 31, 2008 and 2007 were prepared by Predecessor Resolute and 100 percent and 90 percent, respectively, were audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Users of this information should be aware that the process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the
subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosure.
Presented below is a summary of the changes in estimated reserves (in thousands):
1)
The oil revision is due to a reduction in the anticipated performance of the Aneth field, Aneth drilling program and the tertiary recovery, all amounting to approximately 35% of the total. The majority of the remaining oil revision and the gas revision are attributable to performance of the Wyoming properties, all of which are partially offset by an increase in product pricing.
2)
The oil and gas revisions are attributable to the changes in prices of oil and gas.
3)
Includes NGL volumes.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
The following summarizes the policies used in the preparation of the accompanying oil and gas reserves disclosures, standardized measures of discounted future net cash flows from proved oil and gas reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable to Predecessor Resolute’s interest in oil and gas properties as of September 24, 2009 and December 31, 2008 and 2007. Proved reserves are estimated quantities of oil and gas that 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 were 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 was compiled by applying year-end prices of crude oil and gas relating to Resolute’s proved reserves to the year-end quantities of those reserves.
3)
The future cash flows were 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 were based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credits and allowances relating to Predecessor Resolute’s proved oil and natural gas reserves.
5)
Future net cash flows were 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 Predecessor Resolute’s oil and 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 following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by FASB ASC Topic 932, Extractive Activities - Oil and Gas:
(1)
Future income taxes are related to RWI’s oil and gas properties. Aneth is a pass through entity, therefore, there are no future income taxes associated with its oil and gas properties.
The principal sources of change in the standardized measure of discounted future net cash flows are: