ITEM 1.
DESCRIPTION OF BUSINESS
OVERVIEW
We are an independent energy company focused on the exploration, exploitation, and development of unconventional natural gas reserves. Our unconventional natural gas projects target shale plays where large acreage blocks can be easily evaluated with a series of low cost test wells. Shale plays tend to be characterized by high drilling success and relatively low drilling costs when compared to conventional exploration and development plays. Our project areas are focused in the Antrim shale of Michigan and New Albany shale of Southern Indiana and Western Kentucky.
In 1969, we commenced operations to explore and mine natural resources under the name Royal Resources, Inc. In July 2001, we reorganized our business to pursue oil and natural gas exploration and development opportunities and changed our name to Cadence Resources Corporation (“Cadence”). We acquired Aurora Energy, Ltd. ("Aurora") on October 31, 2005 through the merger of our wholly-owned subsidiary with and into Aurora. The acquisition of Aurora was accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes. The Aurora executive management team also assumed management control at the time the merger closed, and we moved our corporate offices to Traverse City, Michigan. Effective May 11, 2006, Cadence amended its articles of incorporation to change the parent name to Aurora Oil & Gas Corporation (“AOG”).
During 2008, due to the current global economic crisis coupled with significant losses in production, significant deficiencies in working capital, loss of revenue due to the termination of our natural gas derivatives, and increases in interest rates on our debt obligations, we have been unable to gain access to the credit markets. As a result, our drilling activities have substantially decreased and we have had to adjust our short-term strategy, placing less emphasis on drilling and more emphasis on cash conservation and pursuing farmout relationships in order to develop our undeveloped reserves. We continue discussions with existing lenders to restructure our debt and are currently undergoing an Antrim remediation program to address our decline in production.
Our revenue, profitability and future rate of growth are substantially dependent on our ability to find, develop and acquire gas reserves that are economically recoverable based on prevailing prices of natural gas and oil. Historically, the energy markets have been very volatile and it is likely that oil and natural gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of natural gas and oil that can be economically produced.
As an early stage developer of properties, we have successfully accumulated a large acreage base of unconventional shale opportunities. As we develop these leaseholds, we anticipate reserve growth will be our initial focus followed by a more traditional balance between reserve and production growth. The following table sets forth our approximate leasehold acreage as of December 31, 2008:
As of December 31, 2008, our proved reserves decreased by approximately 68.6 bcfe from December 31, 2007, to approximately 98.0 bcfe. Of the 98.0 bcfe, 73% was in our Antrim shale properties and 73% was proved developed. The New Albany shale provided a modest increase in proved reserves during the year, adding a net 1.0 bcfe, which is a 4% increase over the 25.0 bcfe reported on December 31, 2007. The Antrim shale proved reserves were reduced by a net 69.3 bcfe due to the following developments:
·
Reserves were reduced by 3.0 bcfe due to production during the year.
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A reduction in natural gas prices (from an average of $7.18 per mcf on December 31, 2007, to an average of $6.07 per mcf on December 31, 2008) has caused a reduction in the volume of natural gas that can be economically produced. We attribute approximately 7.9 bcfe of the reduction in Antrim shale proved reserves to be attributable to lower natural gas prices.
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As a result of changes in regulatory criteria, the Michigan Department of Environmental Quality (“DEQ”) forced us to plug 5 wells and shut in 13 wells during 2008 due to water quality issues, resulting in a setback in our efforts to dewater the Antrim shale in the Arrowhead project. Furthermore, the DEQ blocked our efforts to drill additional wells needed for dewatering. With no means to effectively dewater the project area, performance of the existing wells resulted in net reserve reduction of 7.1 bcfe on the three producing units in the project.
·
Due to the DEQ issues cited above, the absence of available capital needed to install infrastructure for existing wells and drill additional wells, and lack of performance of wells in the Arrowhead project, the proved reserves associated with the Blue Lakes Unit, Tomahawk 26 Unit, Tomahawk 27 Unit and Tomahawk 35 Unit were eliminated, resulting in a reduction of 12.8 bcfe.
·
Our Antrim shale proved reserves have historically been determined by our third party reserve engineers using type curves derived from a combination of reservoir simulation and production performance from nearby more mature Antrim shale units operated by others. At the end of 2007, the type curves were modified to conform to our historical production history to date, but we had an insufficient amount of production on our working interest units to significantly alter the type curves. Now that we have sufficient data to develop decline curves for our wells, our engineers have based their projections of future production volumes on actual historical data from our own wells instead of representative data from other wells in the Antrim play. Not only did this affect the proved developed producing reserves, but the type curves for proved undeveloped reserves were modified accordingly. This resulted in type curves projecting lower reserves, and certain future drilling locations with proved undeveloped reserves were eliminated due to unacceptable economics. We estimate that approximately 41.3 bcfe of the reduction in Antrim shale proved reserves is attributable to this change.
·
We added 2.8 bcfe in extensions to proved reserves due to drilling activities in various areas.
Unconventional shale plays tend to be characterized by high drilling success rates. For the 12-month period ending December 31, 2008, we incurred $10.5 million to drill and participate in 26 (6 net) wells, with an 88% drilling success rate. Of the total 26 (6 net) wells, 14 (3 net) wells were drilled in the Antrim, with a 100% drilling success rate. The remaining 12 (3 net) wells were drilled in other plays with a 75% drilling success rate. Our drilling activities were significantly reduced during 2008 due to our financial constraints and inability to refinance or restructure our debt obligations. We also incurred $2.2 million on property and leasehold acquisitions. Average net daily production decreased from 8,787 mcfe per day in 2007 to 8,316 mcfe per day in 2008. Lower than expected production resulted from damage to our South Knox facility caused by fire and flooding, pumping deficiencies, and continued dewatering problems with the Antrim play. During the first and second quarter we also experienced delays from Warner Plant outages and heavy snowfall causing delays in response to freezing complications associated with compressors, booster stations, and water lines.
During 2008, we implemented a well enhancement program on our operated Antrim shale properties to address our decline in production. We completed well enhancement activities on 74 wells and experienced an approximate one to two days stoppage in production per well to complete the well enhancement activities. We also shut down the downhole pumps on various wells that were producing large volumes of water with insignificant volumes of gas. Since we discontinued the pumping operations on these wells, we have observed a detrimental impact on the gas production levels in the remaining producing wells. We believe that maximizing water production from all operated Antrim shale wells, regardless of their individual economic impact, is necessary to maximize gas production from the projects as a whole. Therefore, we have initiated a renewed well enhancement program in February 2009 that emphasizes measures that will increase water production. The program will be implemented in three phases throughout 2009 with the first phase incorporating the Hudson 19, Hudson 34, Hudson SW and Hudson West Units. As part of this process, we are planning to install water meters at each well location to track water production. Additional time will be required before measurable progress in production can be recognized. The table below highlights our portfolio of producing wells as of December 31, 2008.
Effective September 15, 2008, we closed the sale to Presidium Energy, LC (“Presidium”) of all our membership interest in a wholly owned subsidiary, AOK Energy, LLC (“AOK”). We participated in a joint venture project known as the “Oak Tree Project” through AOK which held all of our Woodford shale properties. Presidium is wholly owned and operated by John V. Miller, who served as our Vice President from November 1, 2005 until he resigned on February 29, 2008. Total sales price was $15 million, of which we received $3 million in cash and received a note receivable in the amount of $12 million. In connection with the sale, we also received a 3% overriding royalty interest in certain oil and gas leases located within the Oak Tree Project.
On October 1, 2008, we received a notice of early termination from BNP Paribas (“BNP”) with respect to our natural gas and interest rate swap derivatives (the “Early Termination Notice”) in accordance the 1992 International Swap Dealers Association, Inc. (“ISDA”) master agreement dated August 20, 2007 between the Company and BNP. For the year ended December 2008, the effect of the termination of our natural gas derivatives resulted in a loss of oil and gas revenue in the approximate amount of $1.2 million. Based on a sales price of $4.50 per mcf, we estimate lost revenues from our terminated natural gas contracts to be $10.8 million, $10.7 million, and $8.0 million for the years ending December 31, 2009, 2010, and 2011, respectively. As a result of the natural gas derivative contracts terminations, we are presently exposed to the fluctuation of natural gas prices.
On October 29, 2008, we entered into a farmout arrangement with Atlas Energy Resources, LLC (“Atlas”) to farm out our 64.43% interest in undeveloped acreage in the Wabash project. The Wabash project is a 121,702 gross acre New Albany shale project located in the Indiana counties of Clay, Greene, Owen, and Sullivan. Under the terms of the farmout arrangement, Atlas must (1) drill at least 20 horizontal wells on an annual basis, (2) pay a well site fee, (3) accept responsibility for any lease obligations, including payments for lease extensions, (4) provide us with an overriding royalty interest in production, and (5) allow us to participate as a working interest owner, if requested, in a 25% working interest in any leases pooled into a drilling unit. As of the filing of this Form 10-K, no drilling activities have commenced under the farmout arrangement and we declined an option to participate in 2 anticipated wells.
If Atlas fails to drill the minimum number of wells per year, the farmout agreement will automatically terminate for each lease not earned or subject to assignment. If Atlas fails to comply with any other provision or requirement, Atlas will have 30 days to correct the non-compliance. At the expiration of the 30 days if the non-compliance has not been corrected, the farmout agreement may be terminated at our option, and we would have the right to exercise all rights and remedies under the agreement.
Our Strategy
The objective of our business is to maximize shareholder value through the development of our substantial acreage base, which we expect to generate into significant increases in natural gas reserves and production growth. To achieve this objective, we employ the following strategies:
Establish a base of lower risk development projects. We have established an extensive leasehold position in the Antrim shale and New Albany shale. Both plays are at varying stages of their respective development life cycle. We believe the New Albany shale represents emerging plays, as development activity has only been initiated within the last several years. As we and others invest capital into these plays, we believe that increased information resulting from drilling and production data by all operators will lower the risk profile, enhance results and provide opportunities for creating natural gas reserves and production growth.
Improve financial flexibility. As an early-stage company with extensive development potential, we believe it is very important to have the right capital structure in place to facilitate our development activities. We continue discussions with existing lenders to restructure our debt. We are also seeking alternative financing arrangements. Due to the recent events within the banking industry and decline in operations, we are having difficulty restructuring our debt and securing alternative financing arrangements. Fostering stable financing for our producing properties and providing flexibility for pursuing our growth development strategy is dependent on restructuring our debt or securing alternative financing arrangements.
Generate growth through drilling and farmout arrangement. We expect to generate long-term reserve and production growth through farmout arrangements and drilling activities. We believe the experience and expertise of our management and technical teams enables us to identify and evaluate farmout arrangements and develop natural gas projects.
Optimize our asset portfolio. With extensive leasehold positions in two shale plays, as well as several smaller targeted projects in other locations, we believe that we have created a diverse asset portfolio which must be carefully developed to limit our risk profile. Due to challenges in the capital markets, our focus has shifted from drilling and operating natural gas and oil wells, to working in partnership with others to develop our assets. We expect to regularly review our projects to optimize the value of this asset portfolio, the result of which will include appropriate joint ventures, farm-outs, equity partnerships, acquisitions, or divestitures.
OPERATING AREAS
Antrim shale
Our Antrim shale properties are primarily located in northern Michigan and represent the majority of our production and proved reserves. Prior to 2008, we had focused on development drilling in the Antrim shale, creating a stable base of production and proved reserves. At December 31, 2008, we owned working interests in 652 (318 net) Antrim wells which included 48 (45 net) non-producing wells. In 2008, we drilled or participated in 14 gross (3 net) Antrim wells and completed 14 gross wells for a success rate of 100%. In 2007, we drilled 56 gross (35 net) Antrim wells and completed 54 gross wells for a success rate of 96%. We currently have 134,003 net acres leased, with approximately 39,956 acres developed in the Michigan Antrim shale play.
The Antrim shale underlies the entire Michigan basin. The primary producing trend for the shale runs across the northern portion of the Michigan basin from Lake Michigan to Lake Huron (160 miles). In most situations, Antrim shale is encountered by vertical drilling, though on occasion, we may determine that horizontal drilling is preferred. A simple completion procedure is employed, using industry-proven hydraulic fracturing technology. These wells are produced with a production system that is specifically designed to minimize pressure on the wells, pipelines, facilities, and reservoir. This is expected to increase the recoverability of the shale gas production, thereby providing the maximum recovery of natural gas.
The Antrim shale is a thick shale (140 to 200 feet), with a high organic content (up to 20%). Over 9,000 wells are currently producing in the Antrim shale and are expected to provide an average of 0.5 bcf of natural gas per well, with a productive life between 30 and 50 years.
A typical production curve for the shale suggests a peak rate of gas occurring within the first two years of production, after the shale reservoir has gone through a period of dewatering. Once the gas is able to fully release from the shale, the production will typically decline between 2% and 10% annually.
New Albany shale
Our New Albany shale properties are primarily located in southwestern Indiana and represent the majority of our developable acreage base. As with the Antrim shale, our New Albany shale operations are focused on the unconventional shale play. At December 31, 2008, we owned working interests in 56 (19 net) New Albany shale wells which included 25 (11 net) non-producing wells. In 2008, we did not drill or participate in any New Albany wells due to our financial constraints and inability to access capital. In 2007, we drilled or participated in 27 gross (11 net) New Albany shale wells and completed 27 gross wells for a success rate of 100%. We currently have 449,183 net acres leased, with approximately 5,148 net acres developed in the New Albany shale.
The New Albany shale underlies a substantial portion of the Illinois basin. The most productive portion of the trend appears to run across the southeastern portion of Illinois, the southern portion of Indiana and the northwestern portion of Kentucky. Our acreage position is located primarily in the central portion of that trend, crossing approximately 12 counties.
Though the New Albany shale has been successfully drilled and produced using vertical wells, it has been determined that the most productive method of development is horizontal drilling. At this time, the completion methods are very simple, typically open-hole only. These wells are produced with a production system that is specifically designed to minimize pressure on the wells, pipelines, facilities and reservoir. This is expected to increase the recoverability of shale gas production, thereby providing the maximum recovery of natural gas.
The New Albany shale is a thick shale (100 to over 200 feet), with high organic content (up to 25%). Over 200 vertical wells and less than 50 horizontal wells are currently producing in the New Albany shale. Horizontal wells are expected to provide an average of 1.2 bcf of natural gas per well with a productive life between 30 and 50 years. A typical production curve for the shale suggests a peak rate of gas and water occurs within the first 60 days of production. Together, the natural gas and water decline an average of 2% to 10% annually.
While the New Albany shale is our primary target, our acreage also includes a variety of producible oil and natural gas formations, including coalbed methane formations and those formations overlying Silurian-age reefs. Our New Albany shale drilling efforts will also provide useful information about these other producible formations for future evaluation strategies. We believe this will provide further insight into our ability to predict the commerciality of the resource.
Drilling techniques and natural gas processing
We are experienced at drilling both vertical and horizontal wells. In the Antrim, our first choice would typically be vertical drilling, although in some situations, we may determine that horizontal drilling is preferred. Our drilling technique in the New Albany shale continues to evolve as we seek to improve cost containment and producibility. Horizontal drilling has become our development method of first choice in the New Albany shale, primarily because of the high angled natural fractures. We seek to maximize intersections of the east-west natural fractures through horizontal drilling, as we believe that this will optimize production results.
For shale gas wells, we generally use a production system that is designed to achieve low pressure on the wells, pipelines, facilities and reservoir. This is done by keeping natural fractures open to the well bore and by using low-pressure gas processing near well sites. Using this low-pressure production approach, we seek to increase the recoverability of shale gas production through reduction of reservoir pressure, thereby enhancing dewatering and gas recovery.
In the Michigan Antrim, we use a simple proven completion procedure with industry proven hydraulic fracturing technology. This procedure involves drilling through several pay zones, setting and cementing casing, and drilling an extended rat-hole, which is used for gas-water separation. The wells are then hydraulically fractured with a specifically designed fracture procedure incorporating multiple stages with enhanced diversion methods to increase effective vertical coverage. Imaging logs are used to identify which zones are best fractured and will yield commercial gas production. For horizontal New Albany shale wells, minimal stimulation has been required to date to make economic gas wells. In exploratory areas of the New Albany and Antrim, shale log analysis is incorporated to enhance fracturing and completion design.
In order to contain costs, we try to keep facilities for gas processing decentralized. Salt water disposal wells are drilled close to the compression facilities, near to each field’s wells. Skid mounted separators that can be easily upgraded or downsized are used at the site of the salt water disposal wells. The localized disposal of water reduces power demand. Different reservoirs contain different amounts of water. We cannot accurately predict the actual amount of time required for dewatering with respect to each well. The period of time during which the gas production rate is limited by the Antrim shale dewatering process is estimated to be two years or more, thereby delaying peak revenue production.
We use skid mounted booster compressors to maximize compression efficiencies from the well to the transportation line. We also seek to maintain low pressure in the gathering systems. Gas is usually produced at low wellhead pressure from a wellbore equipped with five and one-half inch or seven inch diameter production casing and through a polypipe flowline that has a minimum diameter of four inches.
One strategy we use to minimize costs is to minimize the use of land surface. This is accomplished by using small well sites in open areas near roads using localized facilities as described above. We continue to explore innovations in technology and methodologies that will reduce production costs and increase efficiencies. We may use other drilling, completion and operating procedures than those described above if, in our opinion, alternative procedures will generate higher returns.
Our wells are drilled by outside drilling companies. We believe that there is currently enough capacity available in the areas in which we are working that we will not have a problem finding one or more drilling companies available to meet our time schedule for drilling wells. However, over time, circumstances could change as development activity in the industry accelerates.
Oil and natural gas reserves
The following table presents information as of December 31, 2008, with respect to our estimated proved reserves. Estimates of our future net revenues from proved reserves are discounted to present value using an annual discount rate of 10% (PV-10), using oil and natural gas prices in effect as of the dates of such estimates, held constant throughout the life of the properties. The information presented is based on a reserve report prepared by Data & Consulting Services Division of Schlumberger Technology Corporation (“Schlumberger”). According to this report, approximately 44% of our proved reserves are classified as either proved developed non-producing or proved undeveloped.
(a)
Proved reserves are those quantities of gas which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under current economic conditions, operating methods, and government regulations.
(b)
Developed reserves are expected to be recovered from existing wells. Undeveloped reserves are expected to be recovered: (i) from new wells on undrilled acreage; (ii) from deepening existing wells to a different reservoir; or (iii) where relatively large expenditure is required to recomplete an existing well or install production or transportation facilities for primary or improved recovery projects.
(c)
Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proved reserves. The estimated future net revenues were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2008. The estimated future production is priced at December 31, 2008, without escalation, using an average of $41.30 per bbl and an average of $6.07 per mmbtu, in each case adjusted for transportation fees and regional price differentials. PV-10 is a non-GAAP financial measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure - standardized measure of discounted future net cash flow - in the following table:
Management uses present value of future net revenue, which is calculated without deducting estimated future income tax expense, and the present value thereof as one measure of the value of our current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts use this measure in similar ways.
Acreage
The following table sets forth as of December 31, 2008, the gross and net acres of both developed and undeveloped oil and gas leases which we hold. “Gross” acres are the total number of acres in which we own a working interest. “Net” acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our options to acquire additional leaseholds which have not been exercised.
(a)
Developed refers to the number of acres which are allocated or assignable to producing wells or wells capable of production. Developed acreage includes acreage having wells shut-in awaiting the addition of infrastructure.
(b)
Undeveloped refers to lease acreage on which wells have not been developed or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
(c)
While we are focused on developing the shale, our acreage covers a variety of different formations in addition to the shale that have the possibility of being developed and marketed.
Production and price information
The following table summarizes sales volumes, sales prices, and production cost information for the periods indicated ($ in thousands):
Productive wells
The following table sets forth as of December 31, 2008, information relating to the productive wells in which we owned a working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Drilling activities
The following table sets forth information with respect to wells drilled and completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
(a)
An exploratory well is a well drilled either in search of a new, as yet undiscovered, oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of being completed in that reservoir.
(b)
A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
(c)
A dry well is an exploratory or development well that is not a producing well or a well that has either been plugged or has been converted to another use.
(d)
At December 31, 2007, we had 3 gross (1 net) wells in the process of being drilled which are included in the December 31, 2008 totals.
(e)
At December 31, 2008, we had 5 gross (1 net) wells in the process of being drilled.
Sale of production
We market natural gas and oil production on a competitive basis for our operated properties. In most cases, we connect to nearby high pressure transmission pipelines and utilize a gas marketing firm for the sale of production. Effective June 1, 2007, we entered into a firm sales contract with Integrys Energy Services, Inc. (formerly WPS) for 5,000 mmbtu per day at MichCon city-gate for the period June 1, 2007, through December 31, 2008. Since the expiration of the firm sales contract on December 31, 2008, the Company has been negotiating 4,500 mmbtu per day on a month by month basis. We are currently in discussions about the possibility of entering into a long term contract. Our average daily production for operated Antrim was 5,259 mmbtu per day for 2008. Integrys Energy Services, Inc. is our primary marketing partner for the majority of our Michigan operated properties. In addition, we have established other base contracts primarily for future natural gas sales in Indiana and Michigan. We set the firm delivery volume obligation under these contracts on either a monthly or a daily basis with the amount of the obligation varying from month to month or day to day. As new wells come online and production volume increases, new production will be sold under the base contracts on a spot market pricing structure.
Prices for oil and natural gas fluctuate fairly widely based on supply and demand. Supply and demand are influenced by weather, foreign policy and industry practices. Nonetheless, in light of historical fluctuations in prices, there can be no assurance at what price we will be able to sell our oil and natural gas. It is possible that prices will be low at the time periods in which the wells are most productive, thereby reducing overall returns.
Hedging
Our results of operations and operating cash flows are impacted by the fluctuations in the market prices of natural gas. To mitigate a portion of the exposure to adverse market changes, we will periodically enter into various derivative instruments with a major financial institution. The purpose of the derivative instrument is to provide a measure of stability to our cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative instrument reduces our exposure on the hedged production volumes to decreases in commodity prices and limits the benefit we might otherwise receive from any increases in commodity prices on the hedged production volumes.
On October 1, 2008, we received a notice of early termination from BNP with respect to our then existing natural gas and interest rate swap derivatives (the “Early Termination Notice”) in accordance the 1992 International Swap Dealers Association, Inc. (“ISDA”) master agreement dated August 20, 2007 between the Company and BNP. The Early Termination notice amounted to approximately $1.6 million for the interest rate swap derivative and $0.6 million for the natural gas derivatives. The total settlement amount due in the approximate amount of $2.2 million has been classified as a liability included with the senior secured credit facility. For the year ended December 31, 2008, the effect of the termination of our natural gas derivatives resulted in a loss of oil and gas revenue in the approximate amount of $1.2 million. If natural gas continues selling at current prices, our oil and gas revenue will be impacted negatively due to the inability to benefit from gains resulting from hedged production. Based on a sales price of $4.50 per mcf, we estimate lost revenues from our terminated natural gas contracts to be $10.8 million, $10.7 million, and $8.0 million for the years ending December 31, 2009, 2010, and 2011, respectively. As a result of the natural gas derivative contracts and interest rate contract terminations, we are presently exposed to the fluctuation of natural gas prices and fluctuation of interest rates.
Other properties
On October 4, 2005, we purchased office space in the Copper Ridge Professional Center Five, located in Traverse City, Michigan. Our unit contains approximately 14,645 square feet on the second floor of a three story building, plus common areas and 15 covered parking spaces. We moved our corporate offices into this space on December 5, 2005.
Employees
As of December 31, 2008, we had 61 full-time employees and 2 part-time employees. Of our 61 full-time employees 29 are employed by Bach Services & Manufacturing Co. LLC, a subsidiary engaged in oil and gas field services. We are not a party to any collective bargaining agreements. We believe that our relations with our employees are good.
Competition and markets
We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and natural gas leases, marketing of oil and natural gas, and obtaining goods, services and labor. Many of our competitors have substantially larger financial and other resources than we have. Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties and our limited number of employees. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Renewable energy sources may become more competitive in the future.
The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control including, but not limited to, the amount of domestic production and imports of foreign oil and liquefied natural gas, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation, the conduct of drilling operations and federal regulation of natural gas. In addition, the restructuring of the natural gas pipeline industry virtually eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. Producers of natural gas have therefore been required to develop new markets among gas marketing companies, end users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing arena, generally affect the supply of and/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.
Regulatory considerations
Proposals and proceedings that might affect the oil and gas industry are periodically presented to Congress, the Federal Energy Regulatory Commission (“FERC”), the Minerals Management Service (“MMS”), state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. The natural gas industry is heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, except for the water quality issue described below, we currently do not anticipate that compliance with existing federal, state and local laws, rules and regulations, will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.
Our operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used or generated in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells in a given state and may limit the number of wells or the locations at which we can drill.
Currently, there are no federal, state or local laws that regulate the price for our sales of natural gas, natural gas liquids, crude oil or condensate. However, the rates charged and terms and conditions for the movement of gas in interstate commerce through certain intrastate pipelines and production area hubs are subject to regulation under the Natural Gas Policy Act of 1978, as amended. Pipeline and hub construction activities are, to a limited extent, also subject to regulations under the Natural Gas Act of 1938, as amended. While these controls do not apply directly to us, their effect on natural gas markets can be significant in terms of competition and cost of transportation services, which in turn can have a substantial impact on our profitability and costs of doing business. Additional proposals and proceedings that might affect the natural gas and crude oil extraction industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations. We do not believe that we will be affected by any action taken in any materially different respect from other crude oil and natural gas producers, gatherers and marketers with whom we compete.
State regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements. This regulation has not generally been applied against producers and gatherers of natural gas to the same extent as processors, although natural gas gathering may receive greater regulatory scrutiny in the future.
Our oil and natural gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials (“NORM”) are subject to stringent environmental regulation. Compliance with environmental regulations is generally required as a condition to obtaining drilling permits. State inspectors frequently inspect regulated facilities and review records required to be maintained for document compliance. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries, fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures.
Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and natural gas exploration, development and production operations, and consequently may impact our operations and costs. These regulations include, among others, (i) regulations by the Environmental Protection Agency (“EPA”), and various state agencies regarding approved methods of disposal for certain hazardous and non-hazardous wastes; (ii) the Comprehensive Environmental Response, Compensation and Liability Act, and analogous state laws, which regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may require certain pollution controls with respect to air emissions from our operations; (iv) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage and disposal of NORM.
A permit from the EPA and the Michigan Department of Environmental Quality (‘DEQ”) or a state regulatory agency (Indiana) must be obtained before we may drill a salt water disposal well. The amount of time required to obtain such a permit varies from state to state, but can take as much as six or more months in Michigan. Since many gas wells can only be produced if a salt water disposal well is available, the salt water disposal well permit requirement may delay the commencement of production.
In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM are present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Michigan and Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we are able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributed to us under applicable state, federal or local laws or regulations.
We believe that we are in substantial compliance with all currently applicable environmental laws and regulations. We are currently in discussions with the DEQ regarding water quality issues from certain wells in Arrowhead, Blue Chip, and Gaylord Fishing Club projects. In 2007, the DEQ instituted a water sampling and monitoring requirement for wells north of a line of demarcation that includes most of our Antrim projects. The drilling permits for new wells in this area now require produced water monitoring and reporting of gas and water volume and water quality. If the water produced by a well has levels of chloride or total dissolved solids concentration below specified levels, we may be required to shut-in the well. If such wells cannot be remediated so that fresh water is no longer produced, we may be required to plug such wells.
In September 2007, the DEQ collected and analyzed water samples from certain wells in the Arrowhead, Blue Chip, and Gaylord Fishing Club projects. On January 31, 2008, we met with the DEQ to review the analyses. Since the water composition in most of the wells fell within the range deemed by the DEQ to be fresh water, the DEQ requested that we plug six wells, plug or remediate an additional 15 wells, and collect water samples from the remaining wells that had not been previously sampled. We agreed to plug five of the six wells requested and collected a new round of water samples from each requested well for additional analysis.
In September 2008, we received a notice of violation from the DEQ requesting a proposal from management to plug 25 wells in the Arrowhead and Blue Chip projects. Five of the wells listed on this notice had been agreed to during the January 31, 2008 meeting and were plugged during 2008. In December 2008, we met again with the DEQ to discuss the remaining wells. We agreed to shut-in three additional wells, bringing total shut-in wells to 13, and continue to provide water samples for the remaining wells for further analysis. We are expecting to meet again with the DEQ in March 2009 to discuss the results. There is no assurance that we will not be required to plug the remaining wells in the Arrowhead project. If we are required to plug the remaining wells, operations are not expected to be materially impacted as most of these wells are uneconomic. We anticipate plugging costs of approximately $12,000 per well if we are required to plug the remaining wells.
To date, compliance with environmental laws and regulations has not required the expenditure of any material amount of money. Since environmental laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. To our knowledge, other than the potential water quality issue described above, there are currently no material adverse environmental conditions that exist on any of our properties and there are no current or threatened actions or claims by any local, state or federal agency, or by any private landowner against us pertaining to such a condition. Further, we are not aware of any currently existing condition or circumstance that may give rise to such actions or claims in the future.
Where you can find more information
We are subject to the information and reporting requirements of the Exchange Act and are therefore required to file annual, quarterly, and current reports, proxy statements, and other information with the Securities and Exchange Commission (“SEC”). You may read any materials we file with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. The report, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.
Our principal executive offices are located at 4110 Copper Ridge Drive, Suite 100, Traverse City, Michigan 49684, and our telephone number is 231-941-0073. Our website is www.auroraogc.com. Our report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are posted on our website as soon as reasonably possible after they are electronically filed with the SEC and are available to you through our website free of charge. You may also request a copy of our SEC filings at no cost by writing or telephoning us at the above address attention investor relations. Information contained on our website does not constitute a part of this report.
ITEM 1A.
ITEM 1A. RISK FACTORS
RISKS RELATED TO OUR BUSINESS
We are currently in default with our lenders.
We are currently in default under our senior secured credit facility and second lien term loan. We are currently operating under a forbearance agreement with the senior secured credit facility which expires on April 30, 2009. We received notice of default under the second lien term loan in October 2008. Under the terms of the second lien term loan no enforcement action can be taken against us for at least 180 days beginning November 24, 2008. While we have previously entered into a series of forbearance agreements and voluntary standstill periods there can be no assurance once the current forbearance period ends under the senior secured credit facility and the 180 days expires under the second lien term loan that the lenders will not enforce their rights and remedies under the agreements and demand partial or full payment.
We are currently in discussions with our current lenders to restructure our debt obligations and continue to seek alternative financing arrangements. There can be no assurance we will be successful in restructuring our debt or finding alternative financing arrangements. If we are unsuccessful restructuring our current debt obligations or securing alternative financing arrangements, our liquidity would be affected in a material manner and we may elect to file for bankruptcy protection.
Our independent registered public accounting firm’s report on our 2008 consolidated financial statements contains an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern.
As a result of our recurring losses from operations, loss of production, significant deficiencies in working capital, increases in interest rates, termination of our natural gas and interest rate derivatives, and limited capital resources, our independent registered public accounting firm’s report on our consolidated financial statements as of December 31, 2008 and the years ended December 31, 2008 and 2007 includes an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern.
We have a history of losses.
We reported a net loss for the years ended December 31, 2008, 2007 and 2006. There can be no assurance that we will be able to achieve and maintain profitability.
Natural gas prices are volatile. A substantial decrease in natural gas prices would significantly affect our business and impede our growth.
Our revenues, profitability and future growth depend upon prevailing natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas that we can economically produce. It is possible that prices will be low at the time periods in which the wells are most productive, thereby reducing overall returns. It is possible that prices will drop so low that production will become uneconomical. Ongoing production costs that will continue include equipment maintenance, compression and pumping costs. If production becomes uneconomical, we may decide to discontinue production until prices improve.
Prices for natural gas fluctuate widely. For example, from January 1, 2006, through December 31, 2008, natural gas prices quoted for the near month NYMEX contract have ranged from a low of $4.67 per mmbtu to a high of $13.61 per mmbtu. The prices for natural gas are subject to a variety of factors beyond our control, including:
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the level of consumer product demand;
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weather conditions and fluctuating and seasonal demand;
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domestic and foreign governmental relations, regulations, and taxation;
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the price and availability of alternative fuels;
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political conditions in oil and natural gas producing regions;
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the domestic and foreign supply of oil and natural gas including U.S. inventories of natural gas and oil reserves;
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speculative trading and other market uncertainty;
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technological advances affecting energy consumption;
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impact of energy conservation efforts;
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the cost, proximity and capacity of natural gas pipelines and other transportation facilities; and
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overall domestic and global economic conditions.
Failure to hedge our production may result in losses.
On October 1, 2008, we received a notice of early termination for all our natural gas derivatives due to our default on the senior secured credit facility and second lien term loan. Currently, we do not have the ability to hedge our production due to our bank defaults and the lack of borrowing base capacity to meet margin calls. By failing to hedge our production, we are more adversely affected by declines in natural gas prices than our competitors who are currently engaged in hedging arrangements. For example, for the year ended December 31, 2008, the effect of the termination of our natural gas derivatives resulted in a loss of oil and gas revenue in the approximate amount of $1.2 million. If natural gas continues selling at current prices, our oil and gas revenue will be impacted negatively due to the inability to benefit from gains resulting from hedged production. Based on a sales price of $4.50 per mcf, we estimate lost revenues from our terminated natural gas contracts to be $10.8 million, $10.7 million, and $8.0 million for the years ending December 31, 2009, 2010, and 2011, respectively.
Failure to develop reserves could adversely affect our production and cash flows.
Our success depends upon our ability to find, develop or acquire natural gas reserves that are economically recoverable. We will need to conduct successful exploration or development activities, joint venture relationships, and/or acquire properties containing proved reserves. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to expand our natural gas reserves from cash flows, and external sources of capital may be limited or unavailable. Our drilling and joint venture activities may not result in significant reserves, and we may not have continuing success drilling productive wells. Exploratory drilling involves more risk than development drilling because exploratory drilling is designed to test formations in which proved reserves have not been discovered. Additionally, while our revenues may increase if prevailing gas prices increase significantly, our finding costs for reserves also could increase, and we may not be able to finance additional exploration or development activities. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, including our joint venture partnerships, all of which are subject to the risks discussed elsewhere in this section.
Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future.
Leases covering approximately 148,429 of our 651,389 net acres, or 23%, are scheduled to expire on or before December 31, 2009. An additional 72% of our net acres are scheduled to expire in the years 2010 and 2011. If we are unable or choose not to renew these leases or any leases scheduled for expiration beyond December 31, 2009 we will lose the right to develop the acreage that is covered by an expired lease which would impair our ability to expand our reserves and production.
Most of our current development activity and producing properties are located in Michigan and Indiana, making us vulnerable to risks associated with operating in this region.
Our current development activity is concentrated in Michigan and Indiana, and our currently producing properties are located primarily in a six-county area in Michigan. As a result, we may be disproportionately exposed to the impact of drilling and other delays or disruptions of production from these regions caused by weather conditions, governmental regulation, lack of field infrastructure, or other events which impact these areas.
Our potential drilling locations comprise an estimation of part of our future drilling plans over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
As of December 31, 2008, we had over 3,700 net potential drilling locations to be included in our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to find joint venture or farmout partners to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. Because of these uncertainties, we do not know whether we will be able to find suitable joint venture or farmout partners, whether our numerous potential drilling locations will ever be drilled, or whether natural gas will ever be produced from these or any other potential drilling locations, which could materially affect our business.
We do not operate a substantial amount of our properties.
We conduct much of our oil and natural gas exploration, development and production activities in joint ventures with others. In some cases, we act as operator and retain significant management control. In other cases, we have reserved only an overriding royalty interest and have surrendered all management rights. In still other cases, we have reserved the right to participate in management decisions, but do not have ultimate decision-making authority. As of December 31, 2008, we operated 31% of our gross wells and 63% of our net wells. We anticipate that in the future the percentage of gross wells that we operate may decline. As a result of these varying levels of management control, for those properties that we do not operate, we have no control over:
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the number and location of wells to be drilled;
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the timing of drilling and re-completing of wells;
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the field company hired to drill and maintain the wells;
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the timing and amounts of production;
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the approval of other participants in drilling wells;
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development and operating costs;
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capital calls on working interest owners; and
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pipeline nominations.
These and other aspects of the operation of our properties and the success of our drilling and development activities will in many cases be dependent on the expertise and financial resources of our joint venture partners and third-party operators.
We may be unable to make acquisitions of producing properties or prospects or successfully integrate them into our operations.
Acquisitions of producing properties and undeveloped oil and natural gas leases have been an essential part of our long-term growth strategy. As of December 31, 2008, we had acquired approximately 1,164,460 (651,389 net) acres with 98,050 mmcfe in net proved reserves. We may not be able to identify suitable acquisitions in the future or to finance these acquisitions on favorable terms or at all. In addition, we compete against other companies for acquisitions, many of whom have substantially greater managerial and financial resources than we have. The successful acquisition of producing properties and undeveloped natural gas leases requires an assessment of the properties’ potential natural gas reserves, future natural gas prices, development costs, operating costs, potential environmental and other liabilities and other factors beyond our control. These assessments are necessarily inexact and their accuracy inherently uncertain. Such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geological characteristics or geographic location than existing properties. Our acquisitions may not be integrated successfully into our operations and may not achieve desired profitability objectives.
We may lose key management personnel.
Our current management team has substantial experience in the oil and natural gas business. We do not currently have employment agreements with any members of our management team. The loss of any of these individuals could adversely affect our business. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable replacement will be found.
Much of our proved reserves are not yet generating production revenues.
Of our proved natural gas reserves as of December 31, 2008, approximately 56% are classified as proved developed producing, 17% are classified as proved developed non-producing, and 27% are classified as proved undeveloped.
You should be aware that our ability to convert proved reserves into revenues is subject to certain limitations, including the following:
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Reserves characterized as proved developed producing reserves may be producing predominantly water and generate little or no production revenue;
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Production revenues from estimated proved developed non-producing reserves will not be realized until some time in the future, after we have installed supporting infrastructure or taken other necessary steps. It will be necessary to incur additional capital expenditures to install this required infrastructure, and we are currently unable to access significant capital for these expenditures;
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Production revenues from estimated proved undeveloped reserves will not be realized until after such time, if ever, as we make significant capital expenditures with respect to the development of such reserves, including expenditures to fund the cost of drilling wells, dewatering the wells, and building the supporting infrastructure, and we are currently unable to access significant capital for these expenditures; and
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The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of the costs associated with developing these reserves in accordance with industry standards, no assurance can be given that our estimates of capital expenditures will prove accurate, that our financing sources will be sufficient to fully fund our planned development activities, or that development activities will be either successful or in accordance with our schedule. We cannot control the performance of our joint venture partners on whom we depend for development of a substantial number of properties in which we have an economic interest and which are included in our reserves. Further, any significant decrease in oil and natural gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled. No assurance can be given that any wells will yield commercially viable quantities.
Our oil and natural gas reserve data are estimates based on assumptions that may be inaccurate and existing economic and operating conditions that may differ from future economic and operating conditions.
Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based upon assumptions that may change from year to year and vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Information regarding discounted future net cash flows should not be considered as the current market value of the estimated oil and natural gas reserves that will be attributable to our properties. Examples of items that may cause our estimates to be inaccurate include, but are not limited to, the following:
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The estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower;
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Because we have limited historical production and operating cost data to draw upon, the estimated production volume and operating costs used to calculate our reserve values may be inaccurate;
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Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation;
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The reserve report for our Michigan Antrim and New Albany shale properties assumes that production will be generated from each well for a period of 50 years. Because production is expected for such an extended period of time, the probability is enhanced that conditions at the time of production will vary materially from the current conditions used to calculate future net cash flows;
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The 10% discount factor, which is required by the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 69 to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks that will be associated with our operations or the oil and natural gas industry in general;
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We may be unable to expend the capital resources required to achieve and maintain production within the time frame assumed in the calculation of revenues; and
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Unanticipated regulatory problems not contemplated in the calculation of reserves may defer or impair production.
Drilling for and producing natural gas are high-risk activities with many uncertainties.
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
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the high cost, shortages or delivery delays of equipment and services;
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unexpected operational events and drilling conditions;
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adverse weather conditions, including flooding;
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facility or equipment malfunctions;
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title problems;
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pipeline ruptures or spills;
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compliance with environmental and other governmental requirements;
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unusual or unexpected geological formations;
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formations with abnormal pressures;
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injury or loss of life;
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environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or , including groundwater contamination;
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fires, blowouts, craterings and explosions; and
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uncontrollable flows of natural gas or well fluids.
Any one or more of the factors discussed above could reduce or delay our receipt of production revenues, thereby reducing our earnings. In addition, any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.
Although we will maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe 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. The occurrence of an event that is not fully covered by insurance could reduce our results of operations.
Drilling and production delays may occur.
In order to generate revenues from the sale of oil and natural gas production from new wells, we must complete significant development activity. Delay in receiving governmental permits, adverse weather, natural disasters such as fire and flooding, a shortage of labor or parts, and/or dewatering time frames may cause delays, as discussed below. These delays will result in delays in achieving and maintaining revenues from these new wells.
Oil and natural gas producers often compete for experienced and competent drilling, completion and facilities installation vendors and production laborers. The unavailability of experienced and competent vendors and laborers may cause development and production delays.
From time to time, vendors of equipment needed for oil and natural gas drilling and production become backlogged, forcing delays in development until suitable equipment can be obtained.
For each new well, before drilling can commence, we will have to obtain a drilling permit from the state in which the well is located. We will also have to obtain a permit for each salt water disposal well. It is possible that for reasons outside of our control, the issuance of the required permits will be delayed, thereby delaying the time at which production is achieved. We have previously experienced a delay in receiving permits from the State of Michigan, Department of Environmental Quality ("DEQ"), for drilling horizontal wells, while the DEQ further reviews this drilling methodology. As a result of these delays, we have had to defer the drilling of certain wells in the Antrim shale until the review by the DEQ was completed and permits were issued. The DEQ has also forced us to discontinue operations in certain areas, and has required us to plug certain wells as a result of the outcome of water quality tests. We have no control over this type of regulatory delay or loss of producing wells.
Adverse weather may postpone any drilling or development activity, forcing delays until more favorable weather conditions develop. This is more likely to occur during the winter and spring months, but can occur at other times of the year.
Different natural gas reservoirs contain different amounts of water. The actual amount of time required for dewatering with respect to each well cannot be predicted with accuracy. The period of time when the volume of gas that is produced is limited by the dewatering process may be extended, thereby delaying revenue production. A well producing too much water may have to be plugged.
We do not own any drilling equipment.
Since we do not own any drilling equipment, we are affected by competition for drilling rigs and the availability of related equipment. In the past, on occasion the oil and natural gas industry has experienced shortages of drilling rigs, equipment, and personnel which has delayed development drilling and other exploration activities and has caused significant price increases. We are unable to predict when or if such shortages may again occur or how they would affect our development and exploration program.
Production levels cannot be predicted with certainty.
Until a well is drilled and has been in production for a number of months, we will not know what volume of production we can expect to achieve from the well. Even after a well has achieved its full production capacity, we cannot be certain how long the well will continue to produce or the production decline that will occur over the life of the well. Estimates as to production volumes and production life are based on studies of similar wells (of which there are relatively few in the New Albany play) and, therefore, are speculative and not fully reliable. As a result, our revenue budgets for producing wells may prove to be inaccurate.
Pipeline capacity may be inadequate.
Because of the nature of natural gas development, there may be periods of time when pipeline capacity is inadequate to meet our gas transportation needs. It is often the case that as new development comes online, pipelines are close to or at capacity before new pipelines are built. During periods when pipeline capacity is inadequate, we may be forced to reduce production or incur additional expense as existing production requires additional compression to enter existing pipelines.
Our reliance on third parties for gathering and distribution could curtail future exploration and production activities.
The marketability of our production will depend on the proximity of our reserves to, and the capacity of, third party facilities and services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or insufficient capacity of these facilities and services could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our properties, which would adversely affect our financial condition and performance. During 2006, our production was hampered by curtailments in a third-party processing facility. We have since completed construction of our own processing facility and built an alternate pipeline route in response to this curtailment.
There is a potential for increased costs.
The oil and natural gas industry has historically experienced periods of rapidly increasing drilling and production costs, frequently during times of increased drilling activities. If significant cost increases occur with respect to our development activity, we may have to reduce the number of wells we drill, which may adversely affect our financial performance.
We may incur compression difficulties and expense.
As production of natural gas increases, more compression is generally required to compress the production into the pipeline. As more compression is required, production costs increase, primarily because more fuel is required in the compression process. Furthermore, because compression is a mechanical process, a breakdown may occur that will cause us to be unable to deliver natural gas until repairs are made.
Our electricity sources may be unreliable, resulting in interference with production.
We have experienced a problem with periodic electricity outages, particularly in the area of our Antrim wells. Because our pumps are powered by electricity, such outages can reduce our production until each of the affected pumps is restarted.
Equipment failures may reduce our production.
We have experienced significant production down time due to failed equipment in our wells and production facilities. There is no assurance that our well enhancement program will remediate this problem, or that we will be able to retain the services of experts who can improve the maintenance and repair of our wells sufficiently to reduce down time.
We may not have good and marketable title to our properties.
It is customary in the oil and natural gas industry that upon acquiring an interest in a non-producing property, only a preliminary title investigation is done at that time and that a drilling title opinion is done prior to the initiation of drilling, neither of which can substitute for a complete title investigation. We have followed this custom to date and intend to continue to follow this custom in the future. Furthermore, title insurance is not available for mineral leases, and we will not obtain title insurance or other guaranty or warranty of good title. If the title to our prospects should prove to be defective, we could lose the costs that we have incurred in their acquisition or incur substantial costs for curative title work.
Competition in our industry is intense, and we are smaller and have a more limited operating history than most of our competitors.
We compete with major and independent oil and natural gas companies for property acquisitions and for the equipment and labor required to develop and operate these properties. Most of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for oil and natural gas prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment.
Oil and natural gas operations involve various operating risks.
The oil and natural gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks. Personal injuries, damage to property and equipment, reservoir damage, or loss of reserves may occur if such a catastrophe occurs, any one of which could cause us to experience substantial losses. In addition, we may be liable for environmental damage caused by previous owners of properties purchased or leased by us. To illustrate this risk, in late December 2006, a well in which we had a 13.33% cost interest (10% working interest) experienced a blow-out. Our associated liability was $762,000, only $266,666 of which was covered by insurance.
Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect our ability to produce and market our natural gas and crude oil. Production from natural gas wells in many geographic areas of the United States has been curtailed or shut-in for considerable periods of time due to a lack of market demand, and such curtailments may continue for a considerable period of time in the future. There may be an excess supply of natural gas in areas where our operations will be conducted. If so, it is possible that there will be no market or a very limited market for our production.
As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds available for exploration, development or acquisitions.
We may lack insurance that could lower risks to our investors.
We have procured insurance policies for general liability, property/pollution, well control and director and officer liability in amounts considered by management to be adequate, as well as a $20 million excess liability umbrella policy. Nonetheless, the policy limits may be inadequate in the case of a catastrophic loss, and there are some risks that are not insurable. We have limited business interruption insurance. An uninsured loss could adversely affect our financial performance.
We may incur non-cash charges to our operations as a result of current and future financing transactions.
Under current accounting rules and requirements, we may incur additional non-cash charges to future operations beyond the stated contractual interest payments required under our current and potential future credit facilities. While such charges are generally non-cash, they would impact our results of operations and earnings per share and could be material.
We may be required under accounting rules to take write-downs.
Under full cost accounting rules, capitalized costs of proved oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded. As of December 31, 2008, we recorded a ceiling write-down of $78.5 million. The write-down of oil and gas properties is not reversible at a later date. Additional write-downs in future years may be required if the ceiling is exceeded again.
We face risks rising from potential material weaknesses in our internal control environment.
Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our disclosure controls or our internal audit controls can prevent all possible error or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute assurances that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations on all control systems, no evaluation of controls can provide absolute assurance that we have detected all control issues and instances of fraud, if any. These inherent limitations include the realities that judgments in decision making can be faulty and that breakdowns can occur because of error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurances that any design will succeed in achieving its stated goals under all potential future condition;, over time, controls may be inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
At December 31, 2008, a material weakness was identified in our reserve reporting process as further described in management’s report on internal control over financial reporting included in Item 8 of this report. While management believes we will be able to successfully remediate this material weakness, our remedial actions may prove to be ineffective or inadequate and expose us to further risk of misstatements in our financial statements. In such circumstances, investors and other users of our financial statements may lose confidence in the reliability of our financial information and we could fail to comply with certain representations, warranties and covenants in our debt and other financing-related agreements or be obligated to incur additional costs to improve our internal controls.
Because we handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.
The operations of our wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:
•
the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;
•
the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;
•
Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our facilities; and
•
Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under our insurance policies.
We are subject to complex federal, state and local laws and regulations that could adversely affect our business.
Oil and natural gas operations are subject to various federal, state and local government laws and regulations, which may be changed from time to time in response to economic or political conditions. Matters that are typically regulated include:
• discharge permits for drilling operations;
• drilling bonds;
• reports concerning operations;
• spacing of wells;
• unitization and pooling of properties;
• environmental protection; and
• taxation.
From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of natural gas and crude oil. We also are subject to changing and extensive tax laws, the effects of which we cannot predict.
The development, production, handling, storage, transportation and disposal of natural gas and crude oil, by-products and other substances and materials produced or used in connection with oil and natural gas operations are subject to laws and regulations primarily relating to protection of human health and the environment. The discharge of natural gas, crude oil or pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may result in the assessment of civil or criminal penalties or require us to incur substantial costs of remediation. As described above, we have recently been required to plug wells as a result of water quality issues.
Legal and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, could harm our business, results of operations and financial condition.
RISKS RELATED TO THE OWNERSHIP OF OUR STOCK
We may experience volatility in our stock price.
For the 36-month period ended December 31, 2008, our stock traded as high as $4.59 per share and as low as $0.07 per share. The market price of our common stock may fluctuate significantly in response to a number of factors some of which are within our control such as non compliance with debt covenants and other lender requirements and lack of access to credit markets. Other factors are beyond our control, including:
• changes in natural gas prices;
• changes in the natural gas industry and the overall economic environment;
• quarterly variations in operating results;
• changes in financial estimates by securities analysts;
• changes in market valuations of other similar companies;
•
announcements by us or our competitors of new discoveries or of significant technical innovations, contracts, acquisitions, strategic partnerships or joint ventures;
• additions or departures of key personnel;
• any deviations in net sales or losses from levels expected by securities analysts; and
• future sales of our common stock.
In addition, the stock market from time to time experiences extreme volatility that has often been unrelated to the performance of particular companies. These market fluctuations may cause our stock price to fall regardless of our performance.
Our articles of incorporation contain provisions that discourage a change of control.
Our articles of incorporation contain provisions that could discourage an acquisition or change of control without our Board of Directors’ approval. Our articles of incorporation authorize our Board of Directors to issue preferred stock without shareholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire control of us, even if that change of control might be beneficial to our shareholders.
You may experience dilution of your ownership interests due to the future issuance of shares of our common stock, which could have an adverse effect on our stock price.
We may, in the future, issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present shareholders. Our authorized capital stock consists of 250,000,000 shares of common stock and 20,000,000 shares of preferred stock with such designations, preferences and rights as may be determined by our Board of Directors. On December 31, 2008, we had 103,282,788 shares of common stock outstanding and no shares of preferred stock outstanding.
At December 31, 2008, we had warrants and options outstanding that were exercisable for 4,533,944 shares of our common stock. We have an additional 2,257,500 shares available for award as either option or stock grants under our existing incentive plans. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock, preferred stock, or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, private placements of our securities for capital raising purposes, debt refinancing, or for other business purposes. In the future, we may engage in public offerings of our stock. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.
The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets.
The issuance of a large number of shares of our common stock in connection with future acquisitions, equity financing, debt restructuring or otherwise, could cause the market price of our common stock to decline significantly. As of December 31, 2008, we had approximately 103.3 million shares of common stock issued and outstanding, including approximately 5.0 million shares of our common stock held or controlled by our executive officers and directors. Of those 5.0 million shares, 0.5 million are eligible for resale on two S-8 registration statements and the balance are eligible for sale under Rule 144 ("Rule 144") under the Securities Act of 1933, as amended (the "Securities Act"). We have two currently effective S-8 registration statements that, combined, include 469,996 shares owned or controlled by our executive officers and directors that are registered for resale.
We could be delisted, resulting in a less robust trading market for our shares.
Because of our recent financial difficulties and low trading price, we are at risk of being delisted by the NYSE Alternext US LLC (formerly known as the American Stock Exchange). If this occurs, our shares may be traded over the counter, which is likely to result in lower visibility for our stock and lower trading volumes.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.
PROPERTIES
Information regarding our properties is included in Item 1 of this report.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
Refer to Note 12 beginning on page 91 of the Form 10-K.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of our security holders for the quarter ended December 31, 2008.
PART II
ITEM 5.
ITEM 5. MARKET FOR COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
PRICE RANGE OF COMMON STOCK
Our common stock trades under the symbol AOG on the NYSE Alternext US LLC (formerly known as the American Stock Exchange) ("AMEX"). The following chart shows the range of high and low sales prices for our common stock for each fiscal quarter in the two most recent fiscal years.
On March 3, 2009, the last reported sale price of our common stock on AMEX was $0.07 and there were 103,282,788 shares of our common stock outstanding and approximately 498 holders of record.
DIVIDEND POLICY
There have been no cash dividends declared on our common stock since we were formed. We do not intend to pay cash dividends on our common stock for the foreseeable future. Our current credit facilities prohibit us from declaring dividends.
STOCK PERFORMANCE GRAPH
The graph below compares the monthly performance of our common stock to the Russell 2000 Index and the AMEX Natural Gas Index for the period beginning on the close of trading on the AMEX on December 29, 2006, and ending on the close of trading on the AMEX on December 31, 2008. The graph assumes a $100 investment in our common stock and each of the indices and reinvestment of dividends.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
During October 2005, the Company (formerly Cadence) acquired Aurora through the wholly-owned subsidiary with and into Aurora. As a result of the merger, Aurora became a wholly-owned subsidiary.
In October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it was authorized to issue compensatory options to purchase up to 1,000,000 shares of common stock. Aurora issued options to purchase a total of 580,000 shares of Aurora's common stock under this plan, which upon closing the merger, converted into the right to acquire up to 1,160,000 shares of our common stock. Because of the merger, no further awards will be made under this plan.
In 2001, Aurora's Board of Directors and shareholders approved the adoption of an Equity Compensation Plan for Non-Employee Directors. This plan provided that each non-employee director is entitled to receive options to purchase 100,000 shares of Aurora's common stock, issuable in increments of options to purchase 33,333 shares each year over a period of three years, so long as the director continues in office. Prior to the merger closing, Aurora had issued options to purchase a total of 309,997 shares of Aurora common stock under this plan, which upon closing the merger converted to the right to acquire 619,994 shares of our common stock. Because of the merger, no further awards will be made under this plan.
In 2004, our Board of Directors adopted a 2004 Equity Incentive Plan. Our shareholders approved this plan, also in 2004. This plan provides for the grant of options or restricted shares for compensatory purposes for up to 1,000,000 shares of common stock. The number of shares issued or subject to options issued under this plan total 910,500. Although we do not intend to make any further awards under this plan, the plan currently continues to exist.
In March 2006, our Board of Directors adopted, and in May 2006 our shareholders approved, the 2006 Stock Incentive Plan. This Plan provides for the award of options or restricted shares for compensatory purposes for up to 8,000,000 shares. As of December 31, 2008, we had awarded restricted stock and options to purchase restricted stock in a total amount of 5,742,500 shares, leaving 2,257,500 shares available for future awards.
We have awarded compensatory options and warrants to individuals that are considered outside the awards issued under our 2004 Equity Incentive Plan. Aurora has also issued compensatory options and warrants to individuals that are considered outside the awards issued under its 1997 Stock Option Plan and Equity Compensation Plan for Non-Employee Directors.
The following chart sets forth certain information as of December 31, 2008 regarding the shares of our common stock (i) issuable upon exercise of options or warrants granted as compensation for services; and (ii) available for grant under existing plans (No of Securities in thousands).
(a)
Warrants to purchase 56,000 shares (these are Aurora conversion shares originally issued to purchase 28,000 shares of Aurora common stock) were issued to Nathan A. Low's designees in compensation for investment banking services rendered.
UNREGISTERED EQUITY SALES/PURCHASES
None.
ITEM 6.
ITEM 6. SELECTED HISTORICAL FINANCIAL DATA
The following table sets forth our December 31, 2008, 2007, 2006, 2005, and 2004 year end selected financial data as of and for each of the periods indicated. The data as of and for the years ended December 31, 2008, 2007, 2006, 2005, and 2004 is derived from our audited consolidated financial statements for the periods indicated. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and audited consolidated financial statements and related notes included elsewhere in this report. The following information is not necessarily indicative of our future financial results.
(a)
We acquired Aurora Energy, Ltd. (“Aurora”) on October 31, 2005 through the merger of our wholly-owned subsidiary with and into Aurora. The acquisition of Aurora was accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes. As a result of the reverse merger, the historical financial statements presented for periods prior to the acquisition date are the financial statements of Aurora. The operations of the former Cadence Resources Corporation (now known as Aurora Oil & Gas Corporation) businesses have been included in the financial statements from the date of acquisition.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Data” and the consolidated financial statements and related notes included elsewhere in this report. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this report.
Executive Summary
We are an independent energy company focused on the exploration, exploitation, and development of unconventional natural gas reserves. Our unconventional natural gas projects target shale plays where large acreage blocks can be easily evaluated with a series of low cost test wells. Shale plays tend to be characterized by high drilling success and relatively low drilling costs when compared to conventional exploration and development plays. Our project areas are focused in the Antrim shale of Michigan and New Albany shale of Southern Indiana and Western Kentucky.
In 1969, we commenced operations to explore and mine natural resources under the name Royal Resources, Inc. In July 2001, we reorganized our business to pursue oil and gas exploration and development opportunities and changed our name to Cadence Resources Corporation (“Cadence”). We acquired Aurora Energy, Ltd. ("Aurora") on October 31, 2005 through the merger of our wholly-owned subsidiary with and into Aurora. The acquisition of Aurora was accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes. The Aurora executive management team also assumed management control at the time the merger closed, and we moved our corporate offices to Traverse City, Michigan. Effective May 11, 2006, Cadence amended its articles of incorporation to change the parent name to Aurora Oil & Gas Corporation (“AOG”).
Operational Highlights
As of December 31, 2008, our leasehold acres were 1,164,460 (651,389 net) which represent a 9% decrease over our December 31, 2007 net acres. This decrease primarily resulted from the sale of our Oak Tree Project acreage of 37,325 (33,219 net) acres in September 2008 which accounted for all our acreage within the Woodford shale play located in Oklahoma. Our remaining leasehold acres are included in the following plays: 286,390 (134,003 net) leasehold acres in the Antrim shale play, 787,595 (449,183 net) acres in the New Albany shale play, and 90,475 (68,203 net) acres in the Other play areas.
With regard to our drilling activities, we drilled or participated in 26 (6 net) wells for the year ended December 31, 2008, with an 88% success rate. As of December 31, 2008, we had 628 (281 net) producing wells, 31 (11 net) wells awaiting hook-up, 20 (7 net) wells undergoing resource assessment and 54 (37 net) wells temporarily abandoned.
We began 2008 with estimated proved reserves of 166.6 bcfe and at December 31, 2008 had 98.0 bcfe, a decrease of 68.6 bcfe, or 41%. The New Albany shale provided a modest increase in proved reserves during the year, adding a net 1.0 bcfe, which is a 4% increase over the 25 bcfe reported on December 31, 2007. The Antrim shale proved reserves were reduced by a net 69.3 bcfe due to the following recent developments:
·
Reserves were reduced by 3.0 bcfe due to production during the year.
·
A reduction in natural gas prices (from an average of $7.18 per mcf on December 31, 2007, to an average of $6.07 per mcf on December 31, 2008) has caused a reduction in the volume of natural gas that can be economically produced. We attribute approximately 7.9 bcfe of the reduction in Antrim shale proved reserves to be attributable to lower natural gas prices.
·
As a result of changes in regulatory criteria, the Michigan Department of Environmental Quality (“DEQ”) forced us to plug 5 wells and shut in 13 wells during 2008 due to water quality issues, resulting in a setback in our efforts to dewater the Antrim shale in the Arrowhead project. Furthermore, the DEQ blocked our efforts to drill additional wells needed for dewatering. With no means to effectively dewater the project area, performance of the existing wells resulted in net reserve reduction of 7.1 bcfe on the three producing units in the project.
·
Due to the DEQ issues cited above, the absence of available capital needed to install infrastructure for existing wells and drill additional wells, and lack of performance of wells in the Arrowhead project, the proved reserves associated with the Blue Lakes Unit, Tomahawk 26 Unit, Tomahawk 27 Unit and Tomahawk 35 Unit were eliminated, resulting in a reduction of 12.8 bcfe.
·
Our Antrim shale proved reserves have historically been determined by our third party reserve engineers using type curves derived from a combination of reservoir simulation and production performance from nearby more mature Antrim shale units operated by others. At the end of 2007, the type curves were modified to conform to our historical production history to date, but we had an insufficient amount of production on our working interest units to significantly alter the type curves. Now that we have sufficient data to develop decline curves for our wells, our engineers have based their projections of future production volumes on actual historical data from our own wells instead of representative data from other wells in the Antrim play. Not only did this affect the proved developed producing reserves, but the type curves for proved undeveloped reserves were modified accordingly. This resulted in type curves projecting lower reserves, and certain future drilling locations with proved undeveloped reserves were eliminated due to unacceptable economics. We estimate that approximately 41.3 bcfe of the reduction in Antrim shale proved reserves is attributable to this change.
·
We added 2.8 bcfe in extensions to proved reserves due to drilling activities in various areas.
Oil and natural gas production for 2008 was 3,044,112 mcfe, or a 5% decrease over the 3,207,155 mcfe produced in 2007. During 2008, production continued to be hampered by wells undergoing resource assessment and dewatering in the Antrim along with damages caused by a fire in our South Knox project. During 2008, we implemented a well enhancement program on our operated Antrim shale properties to address our decline in production. We completed well enhancement activities on 74 wells and experienced an approximate one to two days stoppage in production per well to complete the well enhancement activities. We also shut down the downhole pumps on various wells that were producing large volumes of water with insignificant volumes of gas. Since we discontinued the pumping operations on these wells, we have observed a detrimental impact on the gas production levels in the remaining producing wells. We believe that maximizing water production from all operated Antrim shale wells, regardless of their individual economic impact, is necessary to maximize gas production from the projects as a whole. Therefore, we have initiated a renewed well enhancement program in February 2009 that emphasizes measures that will increase water production. The program will be implemented in three phases throughout 2009 with the first phase incorporating the Hudson 19, Hudson 34, Hudson SW and Hudson West Units. As part of this process, we are planning to install water meters at each well location to track water production. Additional time will be required before measurable progress in production can be recognized. Our average daily production for 2008 was 8,317 mcfe per day compared to 8,787 mcfe per day in 2007. Daily production for operated properties was 5,259 mcfe and 6,397 mcfe for 2008 and 2007, respectively. Daily production for non-operated properties was 3,058 and 2,390 mcfe for 2008 and 2007, respectively.
Effective September 15, 2008, we closed on the sale to Presidium Energy, LC (“Presidium”) of all our membership interest in a wholly owned subsidiary, AOK Energy, LLC (“AOK”). We participated in a joint venture project known as the “Oak Tree Project” through AOK. Presidium is wholly owned and operated by John V. Miller, who served as our Vice President from November 1, 2005 until he resigned on February 29, 2008. Total sales price was $15 million, of which we received $3 million in cash and entered into a note receivable in the amount of $12 million. Under the terms of the note receivable, Presidium is required to make monthly interest only payments calculated at 9.0%. The entire outstanding principal balance along with all accrued interest is due September 10, 2010. In connection with the sale, we also received a 3% overriding royalty interest in certain oil and gas leases located in various counties in Oklahoma.
On October 29, 2008, we entered into a farmout arrangement with Atlas Energy Resource, LLC (“Atlas”) to farm out our 64.43% interest in undeveloped acreage in the Wabash project. The Wabash project is a 121,702 gross acre New Albany shale project located in the Indiana counties of Clay, Greene, Owen, and Sullivan. Under the terms of the farmout arrangement Atlas must (1) drill at least 20 horizontal wells on an annual basis, (2) pay a well site fee, (3) accept responsibility for any lease obligations, including payments for lease extensions, (4) provide us with an overriding royalty interest on production, and (5) allow us to participate as a working interest owner, if requested, in a 25% working interest in any leases pooled into a drilling unit. As of the filing of this Form 10-K, no drilling activities have commenced under the farmout arrangement.
Other Developments
On October 3, 2008, we received a notice of default from BNP with respect to the senior secured credit facility (the “Notice of Default). The Notice of Default states that an event of default occurred under (1) Section 10.01(a) of the senior secured credit facility due to our failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million, (2) Section 10.01(g) of the senior secured credit facility due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (3) Section 10.01(f) of the senior secured credit facility due to our failure to pay the settlement amount of approximately $2.2 million ($0.6 million for natural gas derivatives and $1.6 million for interest rate derivative) by the due date of October 2, 2008, in connection with the Early Termination Notice, and (4) Sections 8.14, 8.18, and 9.01 of the senior secured credit facility and second lien term loan (cross default) due to our failure to comply with certain financial and non-financial covenants.
The Notice of Default informed us, as of October 1, 2008, that the interest rate under the senior secured credit facility shall bear interest at the default rate of prime plus 3.0%, thereby increasing our current interest rate under the senior secured credit facility by 2% to approximately 8.0% (which has since declined to the current rate of 6.25% at March 4, 2009).
On October 6, 2008, we received a notice of default from Laminar with respect to the second lien term loan (“the “Term Loan Notice of Default”). The Term Loan Notice of Default states that an event of default occurred under (1) Section 10.01(g) of the second lien term loan due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (2) Section 10.01(f) of the second lien term loan due to our failure to pay the settlement amount of approximately $2.2 million ($0.6 million for natural gas derivatives and $1.6 million for interest rate derivative) by the due date of October 2, 2008, in connection with the Early Termination Notice, (3) Sections 8.14, 8.18, and 9.01 of the second lien term loan and the senior secured credit facility (cross default) due to our failure to comply with certain financial and non-financial covenants, and (4) Section 10.01(f) and (g) of the second lien term loan due to our failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million under Section 10.01(a) of the senior secured credit facility (cross default). Laminar and the syndication under the second lien term loan cannot take any enforcement or similar actions against us or our property for at least 180 days beginning November 24, 2008 pursuant to the terms of the Intercreditor Agreement, dated August 20, 2007, between the second lien term loan syndication and the senior secured credit facility syndication.
The Term Loan Notice of Default also informed us, as of October 1, 2008, that the interest rate under the second lien term loan will bear interest at the default rate thereby increasing our current interest rate under the Term Loan by 2% to approximately 15.5%.
Consequently, all of the above debt is classified as current liabilities as of December 31, 2008.
On February 12, 2009, we entered into a forbearance agreement to the senior secured credit facility (the “Second Forbearance Agreement”) with BNP Paribas (“BNP” or the “Administrative Agent”) and the syndication. In accordance with the Second Forbearance Agreement, during the period from December 31, 2008 until April 30, 2009 (the “Second Forbearance Period”), BNP will forbear and refrain from (i) accelerating any loans outstanding and (ii) taking any other enforcement action under the senior secured credit facility at law or otherwise as a result of designated defaults or potential defaults, provided we comply with the forbearance covenants (collectively, the “Second Forbearance Covenants”).
A summary of the Second Forbearance Covenants is as follows: (i) we shall retain and employ a financial advisor, (ii) we shall deliver to the Administrative Agent an initial detailed budget on or before February 20, 2009, and provide subsequent monthly updates, (iii) we shall deliver to the Administrative Agent prior week aggregated cash balances on or before the last business day of the current week, (iv) no later than February 23, 2009, we will execute (or cause to be executed) additional mortgages and no later than February 18, 2009, we will execute (or cause to be executed) other security instruments such that, after giving effect to such additional mortgages and other security instruments, the syndication will have liens on 100% of our oil and gas properties, promissory notes, all significant overriding royalties, and all significant farmout agreements prior to such date, (v) we must obtain prior written approval of the Administrative Agent to farmout any assets or sell any assets for more than $200,000; (vi) we shall provide the Administrative Agent notice of any unwritten or written expressions of interest with respect to the purchase of assets of the Company or any of its subsidiaries for an amount in excess of $2.0 million, (vii) we and the financial advisor shall participate in weekly conference calls with the Administrative Agent and the syndication during which a financial officer of the Company must provide updates on restructuring, sale prospects, and cost reduction efforts, (viii) we must deliver to the Administrative Agent copies of any detailed audit reports, management letters, or recommendations submitted to the board of directors, (ix) no later than February 28, 2009, we must deliver a restructuring plan to resolve the borrowing base deficiency, (x) we must maintain a liquidity position of at least $4.0 million during Second Forbearance Period, and (xi) no later than February 23, 2009, we must obtain the consent of the second lien term loan syndication for us to defer until no earlier than the termination of the Second Forbearance Period, payment of the scheduled interest payment currently payable to the second lien term loan syndication on February 24, 2009.
Our failure to comply with the Second Forbearance Covenants will terminate the Second Forbearance Agreement and allow the syndication to exercise any or all of their rights and remedies purportedly provided to them under the senior secured credit facility.
On February 18, 2009, we executed the mortgages, security agreement and pledge agreement necessary to provide the senior secured credit facility lenders a first secured lien on substantially all of our oil and gas properties not previously pledged to them. We have also complied with the other Second Forbearance Covenants, except that we have not obtained the consent of the second lien lenders to defer payment of the $1.6 million interest payment scheduled to be paid on the second lien term loan on February 24, 2009. We have received correspondence from BNP dated February 27, 2009 indicating that the first lien lenders agree not to declare a forbearance termination event as a result of our failure to obtain the consent of the second lien lenders to defer payment of the interest scheduled to be paid on February 24, 2009, as long as we do not actually make the interest payment during the Second Forbearance Period. The entire $1.6 million interest payment owed to the second lien lenders has been recorded as a liability included with the second lien term loan debt obligation. As more fully described above, Laminar and the second lien term loan syndication cannot take any enforcement or similar actions against us or our property for at least 180 days beginning November 24, 2008.
RESULTS OF OPERATIONS
Operating Statistics
The following table sets forth certain key operating statistics for the years ended December 31, 2008, 2007, and 2006:
Year Ended December 31, 2008, compared with Year Ended December 31, 2007
General. For the year ended December 31, 2008, we had a net loss of $107.4 million, or $(1.04) per diluted common share, on total revenues of $29.8 million. This compares to a net loss of $4.4 million, or $(0.04) per diluted common share, on total revenue of $28.2 million during the year ended December 31, 2007. The $103.0 million increase in net loss is primarily attributable to goodwill write-off in the amount of $19.4 million, ceiling write-down of oil and gas properties in the amount of $78.5 million, increase in interest expense in the amount of $4.6 million, increase in oil and gas depletion and amortization in the amount of $1.6 million, increase in production and lease operating expense of $1.6 million, and increase in general and administrative expense of $1.1 million. The increases in expenses were offset by a decrease in other assets depreciation and amortization of $1.2 million and loss of debt extinguishment of $3.4 million. The remaining revenues and expenses amount to a decrease of $0.6 million.
Oil and Natural Gas Sales. During 2008, oil and natural gas sales were $25.2 million compared to $26.7 million in 2007. We produced 3,044,112 mcfe at a weighted average price of $8.28 compared to 3,207,155 mcfe at a weighted average price of $8.33. This decrease in oil and gas sales was primarily related to the realization of losses from natural gas derivative contracts in the amount of $3.5 million. The losses realized on natural gas derivative contracts were offset by increases in natural gas prices. We had 281 net wells producing as of December 31, 2008, as compared to 305 net wells producing as of December 31, 2007. The decrease in producing net wells is attributable to our effort to reduce operating expenses by shutting in various uneconomic wells. Production from the Antrim shale play represented approximately 86% of our oil and natural gas revenue for 2008.
The following table summarizes our oil and natural gas revenue by play/trend in the periods set forth below:
Production from the year ended December 31, 2008 compared to the year ended December 31, 2007, decreased by 5%. Lower than expected production resulted from damage to our South Knox facility caused by a fire and flooding, pumping deficiencies, and continued dewatering problem within the Antrim play. During the first and second quarter, we also experienced delays from Warner Plant outages and heavy snowfall causing delays in response to freezing complications associated with compressors, booster stations, and water lines.
We have also instituted an Antrim remediation program pursuant to which we plan to reinstate to producing status certain uneconomic wells that we previously shut in due to significant water production. Since we shut in these wells, we have observed gas production from surrounding wells simultaneously declining. We believe pumping water from these uneconomic wells will increase gas production from the surrounding wells. As part of this process, we are also planning to install water meters at each well location to track water production.
Pipeline Transportation and Processing. Pipeline transportation and processing revenues were $0.7 million in 2008 compared to $0.6 million in 2007. This amount represents billings to royalty and working interest owners which are not expected to fluctuate significantly from year-to-year.
Field Service and Sales. Field service and sales revenues were $3.1 million in 2008 compared to $0.4 million in 2007. In 2007, the majority of services performed by our field services subsidiary, Bach Services and Manufacturing Co., LLC (“Bach”), were performed for us. The increase in 2008 was attributable to shifting Bach’s services to unrelated third parties.
Interest and Other Revenues. Interest and other revenues were $0.9 million in 2008 compared to $0.5 million in 2007. The increase is primarily related to interest received on the Presidium Energy, LC note receivable in the amount of $0.3 million.
Production Taxes. Production taxes were $1.3 million in 2008 compared to $1.1 million in 2007. This increase is attributed to an increase in natural gas prices which determined the amount of production taxes charged for Michigan properties. On a unit of production basis, production taxes were $0.44 per mcfe in 2008 compared to $0.35 per mcfe in 2007.
Production and Lease Operating Expenses. Our production and lease operating expenses include services related to producing oil and natural gas, such as post-production costs, which includes marketing, transportation, processing and expenses to operate the wells and equipment on producing leases.
Production and lease operating expenses were $10.0 million in 2008 compared to $8.4 million in 2007. On a unit of production basis, production and lease operating expenses were $3.29 per mcfe in 2008 compared to $2.62 per mcfe in 2007. The increase in 2008 was attributable to increased energy costs, pumping costs, repair, and maintenance associated with meters, compressors, pumps, production personnel, and compressor sale-leaseback expenses. We also incurred one-time charges amounting to $1.2 million or $0.41 per mcfe related to compression repair and workover charges related to our well enhancement program.
On a component basis, post-production expenses were $2.8 million, or $0.93 per mcfe in 2008 compared to $1.9 million, or 0.59 per mcfe, in 2007. Increase in post-production expenses were primarily related to additional sulfide treatment and pipeline transportation charges, including one-time retroactive charges associated with transportation adjustments to royalty owners. Lease operating expenses were $7.2 million, or $2.36 per mcfe, in 2008 compared to $6.5 million, or $2.03 per mcfe in 2007. Increases in lease operating expenses were primarily related to one-time charges for compression repair and workover charges related to our well enhancement program.
Production and lease operating expenses for operated properties were $3.46 per mcfe in 2008 while non-operated production and lease operating expenses were $2.97 per mcfe in 2008. Our operated Arrowhead, Black Bear East, Hudson West, and South Knox projects are negatively impacting our operating cost controls and efficiency due to dewatering, and flooding and fire damages in our South Knox project. During 2008, we have experienced improving results from the Blue Chip, Chandler North, and Gaylord Fishing Club projects, primarily as a result of reducing our operating expenses by shutting in various uneconomical wells. Production and lease operating expenses for operated properties excluding Arrowhead, Black Bear East, Hudson West, and South Knox projects were $2.89 per mcfe in 2008.
Pipeline and Processing Operating Expenses. Pipeline and processing operating expenses were $0.6 million in 2008 compared to $0.5 million in 2007. This increase was the result of incurring additional post-production costs which we were previously absorbing as operating expenses.
Field Service Expenses. Field services expenses were $2.4 million in 2008 compared to $0.3 million in 2007 which are attributable to shifting services performed by Bach to unrelated third party customers.
General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees and office related expense. General and administrative expenses in 2008 increased by $1.0 million, or 13%, from 2007. This increase was primarily the result of additional legal and consulting services and charge offs in connection with (1) refinancing efforts amounting to $1.3 million, (2) write-off of capitalized costs incurred investigating strategic alternatives amounting to $0.2 million, (3) write-off of acquisition costs associated with the Acadian letter of intent in the amount of $0.2 million as a result of our decision not to proceed with the acquisition, (4) write-off of impaired mineral properties, other investments, patent and fixed assets amounting to $0.5 million, and (5) general legal costs incurred for corporate matters in the amount of $0.2 million. This increase was offset by a decrease in payroll and related costs by $0.8 million to $5.4 million in 2008 due to lower employee payroll, bonus expense, and stock-based compensation along with a reduction in professional fees primarily related to reduced accounting, audit, engineering, and Sarbanes Oxley fees in the amount of $0.6 million.
We follow the full cost method of accounting under which all costs associated with property acquisition, exploration, and development activities are capitalized. We capitalize certain internal costs that can be directly identified with our acquisition, exploration, and development activities and do not include any costs related to production, general corporate overhead, or similar activities. We capitalized $0.6 million of payroll and benefit costs for 2008 compared to $1.3 million in 2007. This decrease was primarily related to the reduction in the number of employees associated with acquisition, exploration and development activities along with limited drilling which has reduced our ability to capitalize associated costs.
Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $5.4 million and $3.8 million during 2008 and 2007, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This increase is the result of $7.5 million being added to proved properties in the full cost pool and signification reduction of underlying reserves. As a result of the significant reduction in reserves of approximately 62.8 bcfe, a fourth quarter adjustment of approximately $1.7 million was recorded for 2008. The average DD&A cost per mcfe was $1.86 and $1.18 in 2008 and 2007, respectively.
Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $1.2 million in 2008, compared to $2.4 million in 2007. This decrease was primarily the result of the complete amortization of certain intangible assets during January 2008 associated with the Cadence merger.
Interest Expense. Interest expense was $9.2 million in 2008 and $4.6 million in 2007. This increase is due to the higher utilization of debt. In addition, as part of the forbearance and amendment agreements executed during June 2008, more fully described in the liquidity section following and our defaults on the senior secured credit facility and second lien term loan, interest rates for the senior secured credit facility and second lien term loan increased resulting in an additional $4.5 million of interest charges for 2008.
Goodwill Impairment. We recorded a $19.4 million goodwill impairment loss related to the reverse acquisition of Cadence entered into in 2005 of $16.0 million and acquisition of Bach executed in 2006 of $3.4 million. For the acquisition of Cadence, we measured goodwill impairment using quoted market prices adjusted for known synergies and other benefits arising from subsidiaries. For the Bach acquisition, we measured goodwill using the anticipated sales price of Bach derived from internal valuations.
Ceiling Write-down of Oil and Gas Properties. During 2008, we recognized a ceiling write-down of oil and gas properties in the amount of $78.5 million as a result of the carrying amount of oil and gas properties subject to amortization exceeding the full cost ceiling limitations.
Taxes, Other. Other taxes include state franchise taxes, state income taxes, and state business taxes. We have significant net operating loss carry forwards, thus no federal income tax expense has been recognized. Tax expense was $0.1 million in 2008, compared to $19,021 in 2007. This increase is primarily related to our estimated state of Oklahoma tax liability associated with the sale of our Oak Tree Project.
Year Ended December 31, 2007, compared with Year Ended December 31, 2006
General. For the year ended December 31, 2007, we had a net loss of $4.4 million, or $(0.04) per diluted common share, on total revenues of $28.2 million. This compares to a net loss of $1.9 million, or $(0.02) per diluted common share, on total revenue of $22.4 million during the year ended December 31, 2006. The $5.8 million increase in revenue represents increased production and improved price realization as a result of higher market prices and financial hedging. In addition, the net loss of $4.4 million in 2007 included $3.4 million in a one time charge on debt extinguishment and $2.2 million in stock-based compensation expense.
Oil and Natural Gas Sales. During 2007, oil and natural gas sales were $26.7 million compared to $21.6 million in 2006. We produced 3,207,155 mcfe at a weighted average price of $8.33 compared to 2,653,427 mcfe at a weighted average price of $8.14. This increase in production was due to new wells placed on-line and production growth of existing wells. We had 305 net wells producing as of December 31, 2007 as compared to 214 net wells producing as of December 31, 2006. The 2007 weighted average price included $3.9 million of realized gains from the gas derivative contracts. Production from the Antrim shale play represented approximately 91% of our oil and natural gas revenue for 2007.
The following table summarizes our oil and natural gas revenue by play/trend in the periods set forth below:
Other Revenues. Other revenues increased by $0.7 million, or 88%, to $1.5 million in 2007 from $0.8 million in 2006. This increase is attributed to two acquisitions completed in 2006 and the sale of mining claims in 2007. The first acquisition is the Hudson gas properties with pipeline business component and the second acquisition is Bach which provides oil and natural gas field services.
Production Taxes. Production taxes were $1.1 million in 2007 compared to $0.9 million in 2006. This increase is attributed to production growth and the state mix of production. On a unit of production basis, production taxes were $0.35 per mcfe in 2007 compared to $0.33 per mcfe in 2006.
Production and Lease Operating Expenses. Our production and lease operating expenses include services related to producing oil and natural gas, such as post production costs, including marketing and transportation, and expenses to operate the wells and equipment on producing leases.
Production and lease operating expenses were $8.4 million in 2007 compared to $6.0 million in 2006. On a unit of production basis, production and lease operating expenses were $2.62 per mcfe in 2007 compared to $2.24 per mcfe in 2006. The increase in 2007 was primarily attributable to our expanding operations which increased energy costs, property taxes, pumping costs, repair, and maintenance associated with meters, compressors and pumps, and outside labor. On a component basis, post-production expenses were $1.9 million, or $0.59 per mcfe in 2007 compared to $1.2 million or $0.46 per mcfe in 2006 and lease operating expenses were $6.5 million, or $2.03 per mcfe in 2007 compared to $4.7 million, or $1.78 per mcfe in 2006.
Production and lease operating expenses for operated properties were $2.64 per mcfe in 2007 compared to $2.23 per mcfe in 2006. Non-operated production and lease operating expenses were $2.91 per mcfe in 2007 compared to $2.74 in 2006. Our operated Arrowhead and Chandler North projects negatively impacted our operating cost controls and efficiency due to extensive dewatering needs. Production and lease operating expenses for operated properties excluding Arrowhead and Chandler North were $2.51 per mcfe in 2007.
Pipeline Operating Expense and Field Services Expenses. Pipeline operating expenses were $0.5 million in 2007 compared to $0.3 million in 2006. Field services expenses were $0.3 million in 2007 compared to $0.1 million in 2006, which was attributable to the Bach acquisition in October 2006.
General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees and office related expense. General and administrative expenses in 2007 increased by $0.5 million, or 6%, from 2006. This increase is the result of increases in our employee and related costs.
Payroll and related costs increased by $1.5 million to $6.3 million in 2007. This included staffing additions and merit increases ($0.8 million), stock-based compensation ($0.3 million), 2007 retention bonuses ($0.2 million) and health care ($0.2 million). Legal, accounting, and other consulting services were reduced by $0.4 million to $1.4 million in 2007 compared to $1.8 million in 2006, even though Section 404 of the Sarbanes-Oxley Act of 2002 was implemented for $0.2 million. Insurance had a slight increase of $65,000 due to coverage associated with Bach, while there were offsets of $0.4 million from the disposal of legacy Cadence stock investments and a correction of the stock ledger associated with a prior Cadence transaction.
We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration and development activities and did not include any costs related to production, general corporate overhead or similar activities. During the year ended December 31, 2007, we capitalized $1.3 million of payroll and benefit costs to oil and natural gas properties.
Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $3.8 million and $2.7 million during 2007 and 2006, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This increase is the result of $46.1 million being added to proved properties in the full cost pool, production growth, and the underlying reserves increasing by 13.1 bcfe. The average DD&A cost per mcfe was $1.18 and $1.01 in 2007 and 2006, respectively
Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $2.4 million in 2007, compared to $2.1 million in 2006. This increase was primarily the result of additions in other assets.
Interest Expense. Interest expense was $4.6 million in 2007 and $4.6 million in 2006 which remain relatively stable given higher utilization of debt to continue our growth strategy of acquiring and developing operating interests in the Antrim shale and the New Albany shale.
Loss on Debt Extinguishment. We recorded $3.4 million as a loss on debt extinguishment due to the termination of the mezzanine debt held by TCW. Under the termination provisions, we were required to pay certain fees and prepayment charges associated with early termination. The following represents the expenses incurred: (i) $0.35 million payment of interest make-whole provision from August 21, 2007, through September 27, 2007; (ii) $1.25 million payment of prepayment premium; (iii) $0.2 million payment for a make-whole provision on principal greater than $30 million; and (iv) $1.6 million write-off of unamortized debt issuance cost
Taxes, Other. Tax expense was $19,021 in 2007, compared to $0.3 million in 2006. This decrease represents a 2005 Indiana tax refund of approximately $46,000 and a $45,000 reduction in estimated Louisiana state taxes. We have significant net operating loss carry forwards, thus no federal income tax expense has been recognized.
LIQUIDITY AND CAPITAL RESOURCES
Our financial statements for the year ended December 31, 2008, have been prepared on a going concern basis which contemplates the realization of assets and the settlement of liabilities in the normal course of business. With the loss of production and significant deficiencies in working capital along with an increase in interest rates and the termination of our natural gas and interest rate derivatives more fully described in the following paragraphs, our operations and existing cash balances are not sufficient to support interest requirements on existing debt balances for longer than one year. We are currently in default under the senior secured credit facility and second lien term loan more fully described in the following paragraphs. We recognize our continued existence is dependent on (1) lenders’ willingness to refrain from accelerating or demanding repayment on current debt obligations, (2) restructuring of our current debt, (3) securing alternative financing arrangements, and/or (4) asset divestitures. We continue discussions with existing lenders and are seeking alternative financing arrangements and opportunities for asset divestitures. Due to the recent events within the banking industry we are having difficulty securing alternative financing arrangements. There is no assurance the lenders will not call the debt obligation or that we will be able to restructure or refinance our current debt or sell assets in an amount sufficient to remedy our loan defaults.
On October 1, 2008, we received a notice of early termination from BNP with respect to our natural gas and interest rate swap derivatives (the “Early Termination Notice”) in accordance with the 1992 International Swap Dealers Association, Inc. (“ISDA”) master agreement dated August 20, 2007, between us and BNP. The Early Termination Notice references Sections 6(a) and 6(b) of the ISDA master agreement which gives BNP the right to terminate following an event of default. The settlement amount in connection with the Early Termination Notice amounted to approximately $1.6 million for the interest rate swap derivative and $0.6 million for the natural gas derivatives. The total settlement amount due in the approximate amount of $2.2 million was payable on or before October 2, 2008. As of the filing of this Form 10-K we have not paid the $2.2 million liability and instead have included the amount in our debt balance. For the year ended December 31, 2008, the effect of the termination of our natural gas derivatives resulted in a loss of oil and gas revenue in the approximate amount of $1.2 million. If natural gas continues selling at current prices, our oil and gas revenue will be impacted negatively due to the inability to benefit from gains resulting from hedged production. Based on a sales price of $4.50 per mcf, we estimate lost revenues from our terminated natural gas contracts to be $10.8 million, $10.7 million, and $8.0 million for the years ended December 31, 2009, 2010, and 2011, respectively. As a result of the natural gas derivative contracts termination, we are presently exposed to the fluctuation of natural gas prices.
Senior Secured Credit Facility
Our senior secured credit facility is a $100 million senior secured credit facility with BNP. In connection with the second lien term loan, we also agreed to the amendment and restatement of our senior secured credit facility with BNP and other lenders, pursuant to which the borrowing base under the senior secured credit facility was increased from the current authorized borrowing base of $50 million to $70 million. The amount of the borrowing base was based primarily upon the estimated value of our oil and natural gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at our request. The required semiannual reserve report may result in an increase or decrease in credit availability. As noted above, on June 6, 2008, we were notified that our borrowing base was determined to be only $50 million. The security for this facility is substantially all of our oil and natural gas properties; guarantees from all material subsidiaries; and a pledge of 100% of our stock or member interest of all material subsidiaries.
The senior secured credit facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 3.0% (increased range by 1.0% from 2.0% to 3.0% as a result of the First Forbearance and Amendment dated June 12, 2008) depending on the borrowing base utilization, as selected by us. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of December 31, 2008, interest on the borrowings including the Early Termination Notice liability had a weighted average interest rate of 6.5%. The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.
On February 12, 2009, we entered into a forbearance agreement to the senior secured credit facility (the “Second Forbearance Agreement”) with BNP Paribas (“BNP” or the “Administrative Agent”) and the syndication. In accordance with the Second Forbearance Agreement, during the period from December 31, 2008 until April 30, 2009 (the “Second Forbearance Period”), BNP will forbear and refrain from (i) accelerating any loans outstanding and (ii) taking any other enforcement action under the senior secured credit facility at law or otherwise as a result of designated defaults or potential defaults, provided we comply with the forbearance covenants (collectively, the “Second Forbearance Covenants”).
A summary of the Second Forbearance Covenants is as follows: (i) we shall retain and employ a financial advisor, (ii) we shall deliver to the Administrative Agent an initial detailed budget on or before February 20, 2009, and provide subsequent monthly updates, (iii) we shall deliver to the Administrative Agent prior week aggregated cash balances on or before the last business day of the current week, (iv) no later than February 23, 2009, we will execute (or cause to be executed) additional mortgages and no later than February 18, 2009, we will execute (or cause to be executed) other security instruments such that, after giving effect to such additional mortgages and other security instruments, the syndication will have liens on 100% of our oil and gas properties, promissory notes, all significant overriding royalties, and all significant farmout agreements prior to such date, (v) we must obtain prior written approval of the Administrative Agent to farmout any assets or sell any assets for more than $200,000; (vi) we shall provide the Administrative Agent notice of any unwritten or written expressions of interest with respect to the purchase of assets of the Company or any of its subsidiaries for an amount in excess of $2.0 million, (vii) we and the financial advisor shall participate in weekly conference calls with the Administrative Agent and the syndication during which a financial officer of the Company must provide updates on restructuring, sale prospects, and cost reduction efforts, (viii) we must deliver to the Administrative Agent copies of any detailed audit reports, management letters, or recommendations submitted to the board of directors, (ix) no later than February 28, 2009, we must deliver a restructuring plan to resolve the borrowing base deficiency, (x) we must maintain a liquidity position of at least $4.0 million during Second Forbearance Period, and (xi) no later than February 23, 2009, we must obtain the consent of the second lien term loan syndication for us to defer until no earlier than the termination of the Second Forbearance Period, payment of the scheduled interest payment currently payable to the second lien term loan syndication on February 24, 2009.
Our failure to comply with the Second Forbearance Covenants will terminate the Second Forbearance Agreement and allow the syndication to exercise any or all of their rights and remedies purportedly provided to them under the senior secured credit facility.
We recognize that the senior secured credit facility may become due and payable after expiration of the Second Forbearance Period on April 30, 2009. For this reason, the entire outstanding debt has been classified as a current liability on the December 31, 2008 balance sheet.
Second Term Lien Loan
On August 20, 2007, we entered into a second lien term loan agreement with BNP, as the arranger and administrative agent, and several other lenders forming a syndication. During August 2008 we were notified that Laminar Direct Capital, LLC (“Laminar”) succeeded BNP as the arranger and administrative agent for the second term lien loan. The initial term loan is $50 million for a 5-year term which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the second lien term loan were used to payoff our existing mezzanine financing with TCW and for general corporate purposes.
Interest under the second lien term loan is payable at rates based on the London Interbank Offered Rate plus 950 basis points (increased from 700 basis points as a result of the forbearance agreement and amendment no. 1 to the second lien term loan dated June 12, 2008, and by another 2% pursuant to the Term Loan notice of Default dated October 1, 2008).
We continue to engage in discussions with Laminar and the syndication to restructure our second lien term loan debt. We recognize that the second term lien loan is due and payable upon notification from Laminar after the expiration of the 180 days beginning November 24, 2008, and therefore the entire outstanding debt has been classified as a current liability on the December 31, 2008 balance sheet. In addition to discussions with Laminar and the syndication, we are also seeking alternative financing arrangements and opportunities for asset divestitures. There is no assurance that we will be successful in restructuring our debt, finding alternative financing arrangements, or selling company assets in an amount sufficient to remedy our loan defaults.
Cash Flows from Operating Activities
Cash provided by operating activities decreased 59% to $4.1 million in 2008, compared to $10.1 million in 2007. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges such as depreciation, depletion and amortization and stock based compensation decreased by $0.5 million as a result of complete amortization of certain intangibles in January 2008, write-off of debt issuance costs and reduced compensation expense for previously issued stock awards. Non-cash charges of goodwill impairment and ceiling write-down of oil and gas properties increased by $19.4 million and $78.5 million, respectively, due to the write-off of goodwill associated with the Cadence and Bach acquisitions and the carrying amount of oil and gas properties exceeding the full cost limitation. Changes in current operating assets and liabilities decreased cash flow from operations by $1.1 million which is primarily related to a significant amount of collections from joint venture partners during 2007 as opposed to 2008 due to our significant reduction in drilling efforts for 2008.
Cash provided by operating activities increased 84% to $10.1 million in 2007, compared to $5.5 million in 2006. This $4.6 million increase in net cash provided by operating activities was due to an increase in production revenues as well as increases in other service income. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges increased due to higher depreciation, depletion and amortization and a one-time charge on debt extinguishment. Changes in current operating assets and liabilities decreased cash flow from operations by $2.5 million.
Cash Flows used in Investing Activities
Cash flows used in investing activities were $10.7 million in 2008, $61.1 million in 2007, and $89.6 million in 2006. The following table describes our significant investing transactions that we completed in the periods set forth below:
(a) On February 2, 2006, Aurora closed an acquisition of certain New Albany shale acreage located in Indiana, commonly called the Wabash project. Aurora acquired 64,000 acres of oil and natural gas leases from Wabash Energy Partners, L.P. for a purchase price of $11,840,000. We were required to deposit into escrow for the sellers $3.2 million in 2005. Aurora then sold half its interest in a combined 95,000 acre lease position in the Wabash project to New Albany-Indiana, L.L.C., an affiliate of Rex Energy Operating Corporation (“Rex”) for a sale price of $10,500,000. Rex placed $3.5 million in an escrow account in 2005 as a deposit until the closing in February 2006. Internal funds of Aurora were used to pay the net transaction cost of these transactions.
Cash Flows Provided by Financing Activities
Cash flows provided by financing activities were $14.2 million in 2008 compared to $51.7 million in 2007. Cash flows provided in 2008 included: (1) $13.8 million of senior secured borrowing; (2) $0.4 million of capital contributions from minority interest members; and (3) $0.7 million of proceeds received from exercise of common stock options and warrants. Cash flows used in 2008 included: (1) paydown of $0.3 million in mortgage and notes payable obligations; (2) payment of $0.1 million in financing fees; (3) distributions of $0.1 million to minority interest members; and (4) payment of other in the amount of $0.2 million.
Cash flows provided by financing activities were $51.7 million in 2007 compared to $73.9 million in 2006. Cash flows provided in 2007 included: (1) $55.0 million of senior secured credit borrowing; (2) $50.0 million of second lien term loan; and (3) $0.2 million of net proceeds received from exercise of common stock options and warrants. Cash flows used in 2007 included: (1) $40.0 million pay-down of the mezzanine financing; (2) net pay-down of $0.5 million in short-term bank borrowings; (3) $9.0 million pay-down of the senior secured credit facility; (4) pay-down of $0.3 million in mortgage obligations; (5) payment of $1.9 million of prepayment penalties associated with debt extinguishment; and (6) payment of $1.75 million in financing fees.
CRITICAL ACCOUNTING POLICIES
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The reported financial results and disclosures were determined using the significant accounting policies, practices and estimates described in the notes to the consolidated financial statements. We believe that the reported financial results are reliable and the ultimate actual results will not differ materially from those reported. Uncertainties associated with the methods, assumptions and estimates underlying our critical accounting measurements are discussed below.
Use of Estimates
The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates underlying these consolidated financial statements include the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and to evaluate the full cost pool in the ceiling test analysis, the estimated fair value of asset retirement obligations, goodwill impairment, and fair value of stock options.
Oil and Gas Properties
We utilize the full cost method of accounting for oil and natural gas properties. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration, and development activities of oil and natural gas, including costs of unsuccessful exploration and overhead charges directly related to acquisition, exploration, and development activities, are capitalized. We are currently participating in oil and natural gas exploration and development projects in the Antrim shale of Michigan and the New Albany shale of southern Indiana and western Kentucky. Thus, all capitalized costs of oil and natural gas properties considered proven, are amortized on the unit-of-production method using estimates of proven reserves. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and natural gas properties unless the sale represents a significant portion of oil and natural gas properties and the gain or loss significantly alters the relationship between capitalized costs and proven reserves.
Capitalized costs of oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proven reserves plus the lower of cost or fair value of unproven properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year-end prices of oil and natural gas to estimated future production of proved oil and natural gas reserves as of year end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.
Oil and Gas Reserves
Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs, and workover and remedial costs, all of which may, in fact, vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from there may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and natural gas properties and/or the rate of depletion of the oil and natural gas properties. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Many factors will affect actual net cash flows, including the following: the amount and timing of actual production; supply and demand for natural gas; curtailments or increases in consumption by natural gas purchasers; and changes in governmental regulations or taxation.
Income Taxes
We have adopted the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for future tax consequences attributable to the differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. At December 31, 2008, we had approximately $120.0 million of net operating loss carryforwards which expire between 2010 and 2028.
In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of SFAS 109” (“FIN 48”). This interpretation clarifies the application of SFAS 109 by defining the criterion that an individual tax position must meet for any part of the benefit of that position to be recognized in an entity’s financial statements and also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, and disclosure. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We adopted the provisions of FIN 48 on January 1, 2007. No liabilities or assets have been recognized as a result of the implementation of FIN 48.
RECENT ACCOUNTING PRONOUNCEMENTS
On December 31, 2008, the SEC adopted a final rule that amends its oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. The rules are intended to reflect changes in the oil and gas industry since the original disclosures were adopted in 1978. Definitions were updated to be consistent with Petroleum Resource Management System (“PRMS”). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The revised rules will be effective for our annual report on Form 10-K for the fiscal year ending December 31, 2009. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted. We are currently evaluating the effect the new rules will have on our financial reporting and anticipate that the following rule changes could have a significant impact on our results of operations as follows:
·
The price used in calculating reserves will change from a single-day closing price measured on the last day of the company’s fiscal year to a 12-month average price, and will affect our depletion and ceiling test calculations.
·
Several reserve definitions have changed that could revise the types of reserves that will be included in our year-end reserve report.
·
Some of our financial reporting disclosures could change as a result of the new rules.
In December 2008, the FASB issued FASB Staff Position (“FSP”) FAS 140-4 and FIN 46(R)-8, “Disclosure by Public Entities (Enterprises) About Transfers of Financial Assets and Interests in Variable Interest Entities”. The purpose of the FSP is to promptly improve disclosures by public companies until the pending amendments to FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities” (“SFAS 140”), and FIN 46R are finalized and approved by the FASB. The FSP amends SFAS 140 to require public companies to provide additional disclosures about transferor’s continuing involvement with transferred financial assets. It also amends FIN 46R by requiring public companies to provide additional disclosures regarding their involvement with variable interest entities. This FSP is effective December 31, 2008 and has not had a material impact on the consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162 “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. This statement shall be effective 60 days following the Securities Exchange and Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” Management does not expect its adoption will have a material impact on the consolidated financial statements.
In April 2008, the FASB issued FASB Staff Positions (“FSP”) No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other U.S. generally accepted accounting principles. The provisions of FSP No. FAS 142-3 are effective for fiscal years beginning after December 15, 2008. Management does not expect the adoption of FSP No. FAS 142-3 to have a material impact on the consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires enhanced disclosures about an entity’s derivative instruments and hedging activities, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with earlier application encouraged. With the termination of the Company’s derivative instruments more fully disclosed in Note 6 “Risk Management Activities”, management does not expect the adoption to have any impact on the consolidated financial statements.
In November 2007, the FASB issued SFAS 141 (revised 2007), “Business Combination” (“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 141R will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 141R and SFAS 160 are effective for fiscal years beginning on or after December 15, 2008. SFAS 141R will be applied prospectively. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 will be applied prospectively. Early adoption is prohibited for both standards. Management does not expect the adoption of SFAS 141R and SFAS 160 to have a material impact on the consolidated financial statements. However, SFAS 160 will change our reporting of the minority interests in subsidiaries.
On February 15, 2007, the FASB issued SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities”-including an amendment of SFAS Statement No. 115 (“SFAS 115”). SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The FASB believes the statement will improve financial reporting by providing companies the opportunity to mitigate volatility in reported earnings by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Use of the statement will expand the use of fair value measurements for accounting for financial instruments. The provisions of SFAS 159 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We did not elect to apply the fair value option to any of our financial instruments.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which is effective for fiscal years beginning after November 15, 2007, and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. This statement applies under other accounting pronouncements that require or permit fair value measurements. The statement indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. SFAS 157 defines fair value based upon an exit price model.
Relative to SFAS 157, the FASB issued FSP 157-1 and 157-2. FSP 157-1 amends SFAS 157 to exclude SFAS No. 13, “Accounting for Leases” (“SFAS 13”), and its related interpretive accounting pronouncements that address leasing transactions, while FSP 157-2 delays the effective date of the application of SFAS 157 to fiscal years beginning after November 14, 2008, for all nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. In October 2008, the FASB issued FSP No. FAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP No. FAS 157-3”), which clarifies the application of SFAS No. 157 for financial assets in a market that is not active. FSP No. FAS 157-3 was effective upon issuance.
We adopted SFAS 157 as of January 1, 2008, with the exception of the application of the statement to nonrecurring nonfinancial assets and nonfinancial liabilities. Nonrecurring nonfinancial assets and nonfinancial liabilities for which we have not applied the provisions of SFAS 157 include those measured at fair value in goodwill impairment testing, indefinite lived intangible assets measured at fair value for impairment testing, and asset retirement obligations initially measured at fair value. SFAS 157 has not and is not expected to materially affect how we determine fair value, but has resulted and will result in certain additional disclosures.
OFF BALANCE SHEET ARRANGEMENTS
We have no special purpose entities, financing partnerships, guarantees, or off-balance sheet arrangements other than the $0.8 million of outstanding letters of credit discussed in Note 12 “Commitments and Contingencies” to our consolidated financial statements.
CONTRACTUAL OBLIGATIONS
The following summarizes our contractual obligations as of December 31, 2008, and the effect such obligations are expected to have on our liquidity and cash flow in future periods (in thousands):
(a)
Amounts estimated based on current interest rates. If our senior secured credit facility and second lien term loan are held until maturity, interest is estimated at $7.1 million, $6.9 million, and $3.5 million for 2009, 2010, and 2011, respectively.
(b)
Amount represents lease renewal options available to the Company. Renewal options are evaluated on a periodic basis and, based on those evaluations, the amount stated above may be lower.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our results of operations and operating cash flows are impacted by the fluctuations in the market prices of natural gas. To mitigate a portion of the exposure to adverse market changes, we previously entered into various derivative instruments with BNP. The purpose of the derivative instrument was to provide a measure of stability to our cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative instrument reduced our exposure on the hedged production volumes to decreases in commodity prices and limited the benefit we might otherwise have received from any increases in commodity prices on the hedged production volumes. Since BNP has terminated all of our natural gas derivatives, we are presently exposed to the fluctuations of natural gas prices. Based on current production levels, a $0.50 increase or decrease in natural gas prices would have the effect of causing $0.1 million addition or reduction to our monthly oil and gas revenue.
Interest Rate Risk
Our use of debt directly exposes us to interest rate risk. Our policy is to manage interest rate risk through the use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposure when appropriate. On October 1, 2008, we received a letter of termination for our interest rate derivative instrument from BNP. Since BNP has terminated our interest rate derivative, we are presently exposed to the fluctuation of interest rates. Based on current borrowing levels, a 1.0% increase or decrease in current market rates would have the effect of causing $0.1 million additional charge or reduction to our monthly interest expense.
The following table sets forth our principal financing obligation and the related interest rates as of December 31, 2008:
(a) Current default rate as of March 4, 2009.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
It is the responsibility of management of Aurora Oil & Gas Corporation to establish and maintain adequate internal control over the financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (COSO framework) in conducting the required assessment of effectiveness of the Company’s internal control over financial reporting.
Management has performed an assessment of the effectiveness of the Company’s internal control over financial reporting and has determined the Company’s internal control over financial reporting was not effective as of December 31, 2008.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. In the course of auditing our year-end financial statements, our auditors identified a material weakness that resulted from an error made by us during our initial pricing of our reserve report. The Company initially priced its reserve report using the effective price at December 31, 2008, including an adjustment of the price based on a contract that expired on December 31, 2008. Since the contract expired on December 31, 2008, the contract price was incorrectly used to initially price future reserves. The effect of this error resulted in understating impairment of the full cost pool by approximately $20.0 million as a result of the ceiling test at December 31, 2008. An audit adjustment was made to correct the error and is reflected in the December 31, 2008 financial statements. This error had no impact on the December 31, 2007 or 2006 financial statements.
Our management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, has been attested by Weaver and Tidwell, L.L.P., an independent registered public accounting firm, as stated in its report which appears herein.
William W. Deneau
Chairman, Director, and Chief Executive Officer
Barbara E. Lawson
Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Aurora Oil & Gas Corporation and Subsidiaries
Traverse City, Michigan
We have audited the accompanying consolidated balance sheets of Aurora Oil & Gas Corporation and Subsidiaries (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity and cash flows for the years then ended. Aurora Oil & Gas Corporation’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 consolidated financial position of Aurora Oil & Gas Corporation at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company has experienced decreased production and significant deficiencies in working capital, which results in existing cash balances being insufficient to support existing debt service requirements. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans regarding those matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Aurora Oil & Gas Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 13, 2009 expressed an adverse opinion.
WEAVER AND TIDWELL, L.L.P.
Fort Worth, Texas
March 13,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Board of Directors and Shareholders
Aurora Oil & Gas Corporation and Subsidiaries
Traverse City, Michigan
We have audited Aurora Oil & Gas Corporation’s (the Company) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Aurora Oil & Gas Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a control deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. The Company’s controls in place did not identify errors in the pricing used to prepare its reserve report. The Company initially priced the natural gas in its reserve report utilizing the effective price at December 31, 2008 including adjustments for a contract that expired on December 31, 2008. Prices used in the reserve report should only be adjusted for fixed and determinable escalations for the term of a contract. The effect of the material weakness resulted in an additional impairment of the full cost pool of approximately $20 million as a result of the ceiling test. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 financial statements, and this report does not affect our report dated March 13, 2009 on those financial statements.
In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Aurora Oil & Gas Corporation has not maintained effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and the related consolidated statements of operations, shareholders’ equity, and cash flows of Aurora Oil & Gas Corporation, and our report dated March 13, 2009 expressed an unqualified opinion.
WEAVER AND TIDWELL, L.L.P.
Fort Worth, Texas
March 13,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Aurora Oil & Gas Corporation and Subsidiaries
Traverse City, Michigan
We have audited the accompanying consolidated statements of operations, shareholders’ equity, and cash flows of Aurora Oil & Gas Corporation and Subsidiaries for the year ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Aurora Oil & Gas Corporation and Subsidiaries for the year ended December 31, 2006, in conformity with accounting principles generally accepted in the United States.
RACHLIN LLP
(formerly known as Rachlin Cohen & Holtz LLP)
Miami, Florida
March 13,
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Supplemental Information
Net loss for the years ended December 31, 2008, 2007, and 2006, included stock-based compensation expense of $1,330,907, $2,222,200, and $2,206,801, respectively, under Statement of Financial Accounting Standards No. 123 (revised 2004). See Note 11 “Common Stock Options” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND NATURE OF BUSINESS
Aurora Oil & Gas Corporation (“AOG”) and its wholly owned subsidiaries (collectively, the “Company”) is an independent energy company focused on the exploration, development, and production of unconventional natural gas reserves. The Company generates most of its revenue from the production and sale of natural gas. The Company is focused on developing operating interests in unconventional drilling programs in the Michigan Antrim shale and the New Albany shale of Indiana and Kentucky. The Company’s drilling program is dependent on access to the credit markets. Due to the current economic events within the banking industry and the Company currently being in default under the senior secured credit facility and second lien term loan more fully described in Note 8 “Debt”, the Company is having difficulty securing the necessary credit to move forward with a development program. The Company is a Utah corporation whose common stock is listed and traded on the American Stock Exchange.
The Company’s revenue, profitability, and future rate of growth are substantially dependent on prevailing prices of natural gas and oil. Historically, the energy markets have been very volatile, and it is likely that oil and natural gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows, access to capital, and the quantities of natural gas and oil reserves that can be economically produced. Prior to the termination of the Company’s natural gas derivatives on October 1, 2008, more fully described in Note 6 “Risk Management Activities”, the Company periodically entered into various derivative instruments with a major financial institution to mitigate a portion of the exposure to adverse market changes. The Company is presently exposed to the fluctuation of natural gas prices.
NOTE 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The accompanying consolidated financial statements of the Company include the accounts of the wholly-owned subsidiaries and other subsidiaries in which the Company holds a controlling financial or management interest of which the Company determined that it is primary beneficiary. The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. The Company also consolidates its pro rata share of oil and natural gas joint ventures. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates underlying these consolidated financial statements include the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and to evaluate the full cost pool in the ceiling test analysis, the estimated fair value of asset retirement obligations, goodwill impairment, and fair value of stock options.
Reclassifications
Certain reclassifications have been made to consolidated financial statements for 2007 and 2006 in order to conform to the presentation used for the 2008 consolidated financial statements. These reclassifications had no effect on net loss or net cash flows as previously reported.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Cash and Cash Equivalents
The Company considers all highly liquid investments with an initial maturity of 3 months or less to be cash equivalents. The Company’s bank accounts are held at four separate financial institutions and periodically exceed federally insured limits. As of December 31, 2008, cash in excess of FDIC limits amounted to approximately $9.7 million. The Company does not anticipate any potential losses from uninsured amounts.
Short-Term Investments
The Company’s short-term investments are comprised of an investment in The Reserve Primary Fund (the “Primary Fund”), a money market fund that has suspended redemptions and is being liquidated. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company records these investments as trading securities at fair value.
In mid-September, the net asset value of the Primary Fund decreased below $1 per share as a result of the Primary Fund’s valuing at zero its holdings of debt securities issued by Lehman Brothers Holdings, Inc., which filed for bankruptcy on September 15, 2008. Management has requested the redemption of the Company’s investment in the Primary Fund. Management expects distributions will occur as the Primary Fund’s assets mature or are sold. While management expects to receive substantially all of the Company’s current holdings in the Primary Fund, management cannot predict when this will occur or the amount that ultimately will be received. Accordingly, management has reclassified the investment from cash and cash equivalents to short-term investments as of December 31, 2008.
Accounts Receivable
Accounts receivable generally consist of amounts due from the sale of oil and natural gas, field service and sales, and from working interest partners for their proportionate share of expenses related to certain oil and natural gas projects. Each customer and/or partner is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Customers and partners are reviewed on a periodic basis throughout the year and when collections of specific amounts due are no longer reasonably assured, an allowance for doubtful accounts is established.
The Company extends credit, primarily in the form of uncollateralized oil and natural gas sales, field service and sales, and joint interest owner's receivables, to various companies in the oil and natural gas industry which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within the industry and may accordingly impact the Company’s overall credit risk. However, the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which the Company extends credit.
Capitalized Interest
The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to the full cost amortization pool. Interest is capitalized only for the period that exploration and development activities are in progress. Interest is capitalized using a weighted average interest rate based on the outstanding borrowing and cost of equity of the Company. Capitalized interest was $4.5 million, $4.5 million, and $3.9 million for the years ended December 31, 2008, 2007, and 2006, respectively.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Oil and Natural Gas Properties
The Company utilizes the full cost method of accounting for oil and natural gas properties. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration, and development activities of oil and natural gas, including costs of unsuccessful exploration and overhead charges directly related to acquisition, exploration, and development activities, are capitalized. The Company is currently participating in oil and natural gas exploration and development projects in the Antrim shale of Michigan, the New Albany shale of southern Indiana and western Kentucky. Thus, all capitalized costs of oil and natural gas properties considered proven, are amortized on the unit-of-production method using estimates of proven reserves. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and natural gas properties unless the sale represents a significant portion of oil and natural gas properties and the gain or loss significantly alters the relationship between capitalized costs and proven reserves.
Capitalized costs of oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proven reserves plus the lower of cost or fair value of unproven properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year-end prices of oil and natural gas to estimated future production of proved oil and natural gas reserves as of year end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. During the year ended December 31, 2008, the Company recognized a ceiling write-down of oil and gas properties in the amount of $78.5 million as a result of the carrying amount of oil and gas properties subject to amortization exceeding the full cost ceiling limitation.
The following table sets forth financial data associated with unproved oil and natural gas properties costs at December 31, 2008 ($ in thousands):
(a) Reduction is as a result of various sales more fully described in Note 7 “Acquisition and Dispositions”.
Interest costs capitalized on unproved properties during the years ended December 31, 2008, 2007, and 2006, totaled $4.5 million, $4.5 million, and $3.9 million, respectively. Capitalized interest costs of $3.2 million, $3.8 million, and $1.8 million are included in the balances above at December 31, 2008, 2007, and 2006, respectively, after transferring $1.3 million, $0.7 million, and $2.1 million from unproved to proven during the years 2008, 2007, and 2006, respectively.
Note Receivable
Note receivable consists of amount due from the sale of our Oak Tree Project more fully described in Note 13 “Related Party Transactions.” Prior to extending credit in the form of a note receivable the Company reviews the customer for credit worthiness and secures collateral when appropriate. Interest income is recognized when earned.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Asset Retirement Obligation
On January 1, 2006, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” which is an interpretation of FASB Statement No. 143 “Accounting for Asset Retirement Obligations.” Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future dismantlement and removal of production equipment and facilities and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction began.
In general, the amount of an Asset Retirement Obligation (“ARO”) and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related full cost pool.
Revisions for the year ended December 31, 2008, are not considered material and primarily relate to changes in working interest on certain properties. Effective January 1, 2007, the accretion of ARO on producing wells was adjusted for a change in estimated life of the wells based on a reserve study prepared by Data & Consulting Services, Division of Schlumberger Technology Corporation, an independent reserve engineering firm. The estimated life of the wells was increased by 10 years to an estimated life of 50 years per well resulting in a reduction of $0.6 million to estimated liabilities. In addition, revisions of estimated liabilities included increases due to the removal of equipment salvage value totaling $0.1 million and a decrease in the estimated well plugging costs for certain non-Antrim wells totaling $0.1 million. Revisions of estimated liabilities for 2006 included reductions in well working interest totaling $0.1 million and increases in the salvage value of equipment totaling $0.1 million.
The change in the ARO for the years ended December 31, 2008, 2007, and 2006 is as follows ($ in thousands):
Other Property and Equipment
Other property and equipment are recorded at original cost and depreciated using the straight-line method over the estimated useful lives. Major improvements, replacements, and renewals are capitalized while ordinary maintenance and repairs are expensed as incurred. Long-lived assets, other than oil and natural gas properties, are evaluated annually for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. During 2008, the Company sold and disposed of various assets resulting in a loss of $12,374. Total proceeds received in connection with the sale amounted to $785. The Company did not recognize any impairment losses for the years ended December 31, 2007 or 2006. A summary of the other property and equipment for the year ended December 31, 2008 and 2007 and the useful lives are as follows ($ in thousands):
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Other Investments
The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. Under the equity method of accounting, the Company’s proportionate share of the investees’ net income or loss is included in the results of operations as other income. During 2008, the Company sold certain properties in GeoPetra Partners, LLC more fully described in Note 7 “Acquisitions and Dispositions”. Investment in GeoPetra Partners, LLC amounted to $0.5 million at December 31, 2007. Investments in mineral properties and other investments amounted to $0.2 million at December 31, 2007 and were written off to general and administrative expense for the year ended December 31, 2008.
Intangible Assets
Acquired intangible assets consist of a noncompete agreement. This asset is recorded at fair value or cost and amortized on a straight-line basis using an estimated useful life of 7 years. A summary of amortization expense over the next 4 years is as follows ($ in thousands):
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During 2008, the Company determined a patent was impaired and recorded an expense to general and administrative expense for the year ended December 31, 2008 in the amount of $250,000.
Revenue Recognition
Oil and natural gas revenue is recognized as income as production is extracted and sold. Field service and sales revenue is recognized as income as services are rendered. Revenues from service contracts are recognized ratably over the term of the contract.
Sales and Major Customers
The Company markets natural gas production on a competitive basis for its operated properties. In most cases, the Company connects to nearby high pressure transmission pipelines and utilizes a gas marketing firm for the sale of production. Effective June 1, 2007, the Company entered into a firm sales contract with Integrys Energy Services, Inc. (formerly WPS) for 5,000 mmbtu per day at MichCon city-gate for the period June 1, 2007, through December 31, 2008. Since the expiration of the firm sales contract on December 31, 2008, the Company has been negotiating 4,500 mmbtu per day on a month by month basis.
Management is currently in discussions about the possibility of entering into a long-term contract. Integrys Energy Services, Inc. is the Company’s primary marketing partner for the majority of Michigan operated properties. In addition, the Company has established other base contracts primarily for future natural gas sales in Indiana and Michigan. The Company sets the firm delivery volume obligation under these contracts on either a monthly or a daily basis with the amount of the obligation varying from month to month or day to day. As new wells come online and production volume increases, new production will be sold under the base contracts on a spot market pricing structure.
For the year ended December 31, 2008, one gas marketing firm accounted for 63% of total oil and natural gas revenues. For the year ended December 31, 2007, two gas marketing firms accounted for 56% of total oil and natural gas revenues. For the year ended December 31, 2006, one gas marketing firm accounted for 62% of total oil and natural gas revenues.
Stock-Based Compensation
On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”), to account for stock-based employee compensation. Among other items, SFAS No. 123R eliminates the use of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and the intrinsic value method of accounting and requires companies to recognize the cost of employee services received in exchange for stock-based awards based on the grant date fair value of those awards in their financial statements. The Company elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options beginning in the first quarter of adoption. For stock-based awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant, will be recognized in the financial statements over the vesting period. The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options. To the extent compensation cost relates to employees directly involved in oil and natural gas exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expense, production and lease operating expenses or pipeline processing operating expenses as appropriate.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
For the years ended December 31, 2008, 2007, and 2006, the Company recorded the following stock-based compensation ($ in thousands):
The following table provides the unrecognized compensation expense related to unvested stock options as of December 31, 2008. The expense is expected to be recognized over the following remaining periods indicated ($ in thousands):
Income Taxes
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. With few exceptions, the Company is no longer subject to U.S. federal, state, and local examinations by tax authorities for years before 2004. The Company is currently not under an examination by any U.S. federal, state, or local tax authorities.
The Company has adopted the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”). Under the asset and liability method of SFAS 109, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized.
In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of SFAS 109” (“FIN 48”). This interpretation clarifies the application of SFAS 109 by defining the criterion that an individual tax position must meet for any part of the benefit of that position to be recognized in an entity’s financial statements and also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, and disclosure. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. The Company adopted the provisions of FIN 48 on January 1, 2007. No liabilities or assets have been recognized as a result of the implementation of FIN 48.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
As of December 31, 2008, the Company had approximately $14.2 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the Company’s significant unutilized tax net operating loss carry-forwards, the disallowance of the shorter deductibility period would not accelerate the payment of cash to the taxing authorities to an earlier period or result in any interest or penalty for tax underpayment. In addition, because of the impact of deferred tax accounting, the disallowance of the shorter deductibility period would not affect the annual effective tax rate of the Company. Accordingly, the Company has not recognized any penalty, interest or tax impact from this uncertain tax position.
Comprehensive Income (Loss)
Comprehensive income (loss) is comprised of net income and other comprehensive income. Other comprehensive income includes income resulting from derivative instruments designated as hedging transactions. More fully described in Note 6 “Risk Management Activities” the Company’s derivative instruments were terminated on October 1, 2008. The details of comprehensive income (loss) are as follows ($ in thousands):
Income (Loss) Per Share
Basic net income (loss) per common share is computed based on the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is computed based on the weighted average number of common shares outstanding plus other dilutive securities, such as stock options, warrants, and redeemable convertible preferred stock. For the years ended December 31, 2008, 2007, and 2006, respectively, options and warrants to purchase 6,560,445, 2,175,280, and 766,500 shares of common stock were not included in the computation of diluted net income (loss) per share as their effect would have been anti-dilutive.
NOTE 3. GOING CONCERN
The Company’s financial statements for the year ended December 31, 2008, have been prepared on a going concern basis which contemplates the realization of assets and the settlement of liabilities in the normal course of business. With the loss of production and significant deficiencies in working capital along with the increase in interest rates and termination of the Company’s natural gas and interest rate derivatives more fully described in Note 6 “Risk Management Activities”, the Company’s operations and existing cash balances are not sufficient to support interest requirements on existing debt balances for longer than one year. The Company is currently in default under the senior secured credit facility and second lien term loan which are more fully described in Note 8 “Debt”. The Company’s continued existence is dependent on (1) the lenders’ willingness to refrain from accelerating or demanding repayment on current debt obligations, (2) restructuring the Company’s current debt and interest payments, (3) securing alternative financing arrangements, and/or (4) asset divestitures. Management continues discussions with existing lenders and is seeking alternative financing arrangements and opportunities for asset divestitures. There is no assurance the lenders will not call the debt obligation or that the Company will be able to restructure or refinance its current debt or sell assets.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
These uncertainties raise substantial doubt about the ability of the Company to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties should the Company be unable to continue as a going concern.
NOTE 4. IMPAIRMENT OF GOODWILL
On January 1, 2008, the Company had goodwill of $16.0 million related to the reverse acquisition of Cadence Resources Corporation (“Cadence”) executed in October 2005 and $3.4 million related to the acquisition of Bach Services & Manufacturing Co., LLC (“Bach”), a subsidiary of the Company, executed in October 2006 and more fully described in Note 7 “Acquisitions and Disposition”.
The Company tests goodwill for impairment annually in accordance with Statement of Financial Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 142 requires goodwill be tested at least annually using a two-step process that begins with identifying potential impairment. Potential impairment is identified if the fair value of the reporting unit to which goodwill applies is less than the recognized or book value of the related reporting entity, including such goodwill. Where the book value of a reporting entity, including related goodwill, is greater than the reporting entity’s fair value, the second step of the goodwill impairment test is performed to measure the amount of impairment loss, if any. Based on the Company’s continued loss in production, management has determined using projected discounted future operating cash flows at a 10% discount rate as a measurement of goodwill impairment for the Cadence acquisition is not appropriate. Accordingly, management measured goodwill impairment using quoted market prices of common stock adjusted for known synergies and other benefits arising from subsidiaries. For the Bach acquisition, the Company measured goodwill using the anticipated sales price of the company derived from internal valuations.
As of December 31, 2008, the Company determined that there was an impairment of goodwill related to Cadence and Bach. Accordingly, the Company recorded a full impairment of goodwill for the Cadence and Bach acquisitions which resulted in a write-down of $19.4 million and has been recorded as an operating expense in the consolidated statements of operations for the year ended December 31, 2008. There were no impairments to goodwill during the years ended December 31, 2007 and 2006.
NOTE 5. RECENT ACCOUNTING PRONOUNCEMENTS
On December 31, 2008, the SEC adopted a final rule that amends its oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. The rules are intended to reflect changes in the oil and gas industry since the original disclosures were adopted in 1978. Definitions were updated to be consistent with Petroleum Resource Management System (“PRMS”). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The revised rules will be effective for the Company’s annual report on Form 10-K for the fiscal year ending December 31, 2009. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted. The Company is currently evaluating the effect the new rules will have on the Company’s financial reporting and anticipate that the following rule changes could have a significant impact on the Company’s results of operations as follows:
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
·
The price used in calculating reserves will change from a single-day closing price measured on the last day of the Company’s fiscal year to a 12-month average price, and will affect the Company’s depletion and ceiling test calculations.
·
Several reserve definitions have changed that could revise the types of reserves that will be included in our year-end reserve report.
·
Some of the Company’s financial reporting disclosures could change as a result of the new rules.
In December 2008, the FASB issued FASB Staff Position (“FSP”) FAS 140-4 and FIN 46(R)-8, “Disclosure by Public Entities (Enterprises) About Transfers of Financial Assets and Interests in Variable Interest Entities”. The purpose of the FSP is to promptly improve disclosures by public companies until the pending amendments to FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities” (“SFAS 140”), and FIN 46R are finalized and approved by the FASB. The FSP amends SFAS 140 to require public companies to provide additional disclosures about transferor’s continuing involvement with transferred financial assets. It also amends FIN 46R by requiring public companies to provide additional disclosures regarding their involvement with variable interest entities. This FSP is effective December 31, 2008 and has not had a material impact on the consolidated financial statements.
In May 2008, the FASB issued SFAS No. 162 “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. This statement shall be effective 60 days following the Securities Exchange and Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” Management does not expect its adoption will have a material impact on the consolidated financial statements.
In April 2008, the FASB issued FASB Staff Positions (“FSP”) No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other U.S. generally accepted accounting principles. The provisions of FSP No. FAS 142-3 are effective for fiscal years beginning after December 15, 2008. Management does not expect the adoption of FSP No. FAS 142-3 to have a material impact on the consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires enhanced disclosures about an entity’s derivative instruments and hedging activities, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with earlier application encouraged. With the termination of the Company’s derivative instruments more fully disclosed in Note 6 “Risk Management Activities”, management does not expect the adoption to have any impact on the consolidated financial statements unless the Company engages in hedge contracts.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In November 2007, the FASB issued SFAS 141 (revised 2007), “Business Combination” (“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 141R will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 141R and SFAS 160 are effective for fiscal years beginning on or after December 15, 2008. SFAS 141R will be applied prospectively. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 will be applied prospectively. Early adoption is prohibited for both standards. Management is currently evaluating the requirements of SFAS 141R and SFAS 160 and has not yet determined the impact on its consolidated financial statements.
On February 15, 2007, the FASB issued SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities”-including an amendment of SFAS Statement No. 115 (“SFAS 115”). SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The FASB believes the statement will improve financial reporting by providing companies the opportunity to mitigate volatility in reported earnings by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Use of the statement will expand the use of fair value measurements for accounting for financial instruments. The provisions of SFAS 159 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We did not elect to apply the fair value option to any of our financial instruments.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which is effective for fiscal years beginning after November 15, 2007, and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. This statement applies under other accounting pronouncements that require or permit fair value measurements. The statement indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. SFAS 157 defines fair value based upon an exit price model.
Relative to SFAS 157, the FASB issued FSP 157-1 and 157-2. FSP 157-1 amends SFAS 157 to exclude SFAS No. 13, “Accounting for Leases” (“SFAS 13”), and its related interpretive accounting pronouncements that address leasing transactions, while FSP 157-2 delays the effective date of the application of SFAS 157 to fiscal years beginning after November 14, 2008, for all nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. In October 2008, the FASB issued FSP No. FAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP No. FAS 157-3”), which clarifies the application of SFAS No. 157 for financial assets in a market that is not active. FSP No. FAS 157-3 was effective upon issuance.
We adopted SFAS 157 as of January 1, 2008, with the exception of the application of the statement to nonrecurring nonfinancial assets and nonfinancial liabilities. As of January 1, 2009, the Company adopted SFAS 157 as it relates to nonrecurring nonfinancial assets and nonfinancial liabilities. Nonrecurring nonfinancial assets and nonfinancial liabilities include those measured at fair value in goodwill impairment testing, indefinite lived intangible assets measured at fair value for impairment testing, and asset retirement obligations initially measured at fair value. SFAS 157 has not materially affected how the Company determines fair value, but has resulted and will result in certain additional disclosures.
NOTE 6. RISK MANAGEMENT ACTIVITIES
Natural Gas Derivative Instruments
The Company’s results of operations and operating cash flows are impacted by the fluctuations in the market prices of natural gas. To mitigate a portion of the exposure to adverse market changes, the Company previously entered into various derivative instruments with a major financial institution. The purpose of the derivative instrument was to provide a measure of stability to the Company’s cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative instrument reduced the Company’s exposure on the hedged production volumes to decreases in commodity prices and limited the benefit the Company might otherwise have received from any increases in commodity prices on the hedged production volumes.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
On October 1, 2008, the Company received a notice of early termination from BNP Paribas (“BNP”) with respect to the Company’s natural gas and interest rate swap derivatives (the “Early Termination Notice”) in accordance with the 1992 International Swap Dealers Association, Inc. (“ISDA”) master agreement dated August 20, 2007, between the Company and BNP. The Early Termination Notice references Sections 6(a) and 6(b) of the ISDA master agreement which gives BNP the right to terminate following an event of default (the Company received a notice of default on October 3, 2008, from BNP which is more fully described in Note 8 “Debt”). The settlement amount in connection with the Early Termination Notice amounted to $0.6 million for the natural gas derivatives and was classified as a liability included with the senior secured credit facility. As a result of the natural gas derivative contracts termination, the Company is presently exposed to the fluctuation of natural gas prices.
For the years ended December 31, 2008, 2007 and 2006, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(5.9) million, $(0.5) million, and $7.9 million, respectively, on the contracts that have been designated as cash flow hedges on forecasted sales of natural gas. See “Comprehensive Income (Loss)” found in Note 2 “Basis of Presentation and Summary of Significant Accounting Policies”. For the year ended December 31, 2008, the Company recognized $3.6 million of net losses from hedging activities included in oil and gas revenues. For the years ended December 31, 2007, and 2006, the Company recognized $3.9 million and $2.7 million, respectively in net gains from hedging activities included in oil and natural gas revenues.
The following table sets forth components of oil and gas sales ($ in thousands):
Interest Rate Derivative Instruments
The Company’s use of debt directly exposes it to interest rate risk. The Company’s policy is to manage interest rate risk through the use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposure when appropriate. These derivatives are used as hedges and are not for speculative purposes. These derivatives involve the exchange of amounts based on variable interest rates and amounts based on a fixed interest rate over the life of the agreement without an exchange of the notional amount upon which payments are based. The interest rate differential to be received or paid on the swaps is recognized over the lives of the swaps as an adjustment to interest expense.
The settlement amount for the interest rate swap derivative in connection with the Early Termination Notice amounted to approximately $1.6 million and was classified as a liability included with the senior secured credit facility. As a result of the interest rate derivative contract termination, the Company is presently exposed to the fluctuation of interest rates.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
For the years ended December 31, 2008, and 2007, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $0.6 million and $(1.2) million, respectively, on the interest rate swap. See “Comprehensive Income (Loss)” found in Note 2 “Basis of Presentation and Summary of Significant Accounting Policies”. For the years ended December 31, 2008, and 2007, the Company recognized $2.1 million in interest expense, which included $1.6 million related to the Early Termination Notice more fully described in the previous paragraph and $0.1 million in interest savings, respectively, related to the hedge activity which is recorded as an adjustment to interest expense.
Financial Instruments
The Company has financial instruments for which the fair value of the financial instruments could be different than that recorded on a historical basis in the accompanying balance sheets. The Company’s financial instruments consist of cash, short-term investments, accounts receivable, note receivable, accounts payable, accrued expenses, and debt. The carrying amounts of the Company’s financial instruments approximate their fair values as of December 31, 2008, due to their short-term nature.
Concentration of Credit Risk
Financial instruments that subject the Company to concentrations of credit risk consist primarily of temporary cash investments, short-term investments, trade receivables, and note receivable. The Company believes it has placed its demand deposits with high credit quality financial institutions. As more fully described in Note 2 “Basis of Presentation and Summary of Significant Accounting Policies,” the Company’s short-term investments are comprised of an investment in the Primary Fund which is a money market fund that decreased below $1 per share and is currently being liquidated. While management recognizes there is increased credit risk associated with this investment, management expects to receive substantially all of the company’s current holdings in the Primary Fund. Concentrations of credit risk with respect to trade receivable are primarily focused on companies involved in the exploration and development of oil and natural gas properties. The concentration is somewhat mitigated by the diversification of customers for which the Company provides services or partners with. As is general industry practice, the Company typically does not require customers or joint venture partners to provide collateral. No significant losses from individual customers or joint venture partners were experienced during the years ended December 31, 2008, 2007, or 2006.
During 2008 we entered into a note receivable as more fully described in Note 13 “Related Party Transactions”. The Company believes the concentration of credit risk associated with this note receivable is sufficiently mitigated based on the collateral secured as part of this agreement.
NOTE 7. ACQUISITIONS AND DISPOSITIONS
New Albany Shale
North Knox
On December 1, 2008, the Company received proceeds of $25,794 in connection with the sale of a 45% working interest in the North Knox project. The project is located in Knox County Indiana and covers approximately 129 net acres.
Release of Oil and Gas Leases
During November 2008, the Company received proceeds amounting to $15,375 and $3,183 for leases released in Spencer County and DeKalb Counties, Indiana respectively and covers approximately 440 net acres.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
New Albany Shale Exchange
On August 12, 2008, the Company exchanged 42,988 net acres located in the Lawrence, Knox, and Sullivan Counties, Indiana for 40,316 net acres located in Owen, Sullivan, Clay, Green, Lawrence, Washington, Jackson, and Orange Counties, Indiana. As part of this transaction, the Company increased reserves by 1,232 mcfe and increased the Company’s working interest by 15.68%.
Other
Dehydration Contactor and Regenerator Sale
On December 18, 2008, the Company sold a dehydration contactor and regenerator to Acadian Energy, LLC (related party more fully disclosed in Note 13 “Related Party Transactions”) for a purchase price of $15,368.
AOK Energy, LLC
As more fully disclosed in Note 13 “Related Party Transactions”, effective September 12, 2008, the Company sold all its membership interest in AOK Energy, LLC to Presidium Energy, LC for $15 million.
GeoPetra
In April 2008, the Company sold a 3.75% interest in the GeoPetra prospect for $79,322. The interest covers approximately 285 net acres in St. Martin and Iberville Counties, Louisiana.
Other
During 2008, the Company received proceeds of $124,720 in connection with the sale of all its interest in five separate prospects. The prospects were located in Benzie, Grand Traverse, Mecosta, Newaygo, and Oscoda Counties, Michigan and cover approximately 6,410 net acres.
Michigan Antrim Shale
GFS and Federated Oil and Gas Properties
On August 31, 2007, the Company entered into two Purchase Letter Agreements to buy GFS Energy, Inc. and Federated Oil & Gas Properties, Inc. non-operated working interests and overriding royalty interests in various developed oil and natural gas properties located in the Antrim shale for approximately $3.0 million. The properties included 93 (33 net) wells, producing approximately 500 mcfe per day, and approximately 4,700 (1,706 net) acres. This transaction had an effective date of September 1, 2007.
New Albany Shale
Rex Energy Exercised Option to Acquire Interest in Oil and Natural Gas Leases
On September 7, 2007, Rex Energy Corporation exercised an option to acquire a 30% working interest in various undeveloped oil and natural gas leases located in the New Albany shale for approximately $1.1 million. The interest in oil and gas leases covers approximately 70,324 (21,097 net) acres in Lawrence, Jackson, Washington, and Orange Counties, Indiana.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Knox County, Indiana
On July 30, 2007, the Company purchased from Horizontal Systems, Inc. its working interest in various undeveloped oil and natural gas leases located in Knox County, Indiana for approximately $1.2 million pursuant to a Sale and Assignment of Oil and Gas Interests Agreement. The properties included 25% working interest in one well and approximately 9,642 net acres.
Other
Mining Claims
On May 15, 2007, the Company sold certain mining claims and mineral leases to U.S. Silver-Idaho, Inc. for $400,000 in cash and 50,000 shares of common stock in U.S. Silver Corporation. This non-core property sale consisted of 14 unpatented and 27 patented mining claims as well as 5 mineral leases located in Idaho. A $418,000 gain was recognized in other income since these non-core properties were being recognized as an investment.
Kansas Project
On February 7, 2007, the Company entered into a Purchase and Sale Letter Agreement to sell to Harvest Energy, LLC all of the Company’s interest in various developed and undeveloped oil and natural gas properties located in Lane and Ness Counties, Kansas for approximately $1.0 million. The properties included two net wells, 98 mmcfe in proven reserves, and approximately 23,110 net acres. This transaction closed on March 9, 2007.
Other Investments
From time to time, the Company has acquired and disposed of legacy Cadence stock investments and non-core working interests. For the year ended December 31, 2007, the Company recognized minor stock investments valued at approximately $290,000 and disposed of non-core working interests and stock investments of approximately $490,000.
New Albany Shale Sales
Wabash Project
On February 2, 2006, Aurora closed on two Purchase and Sale Agreements with respect to certain New Albany Shale acreage located in Indiana, commonly called the Wabash project. Aurora acquired 64,000 acres of oil and natural gas leases from Wabash Energy Partners, L.P. for a purchase price of $11.84 million. The Company was required to deposit into escrow for the seller $3.2 million.
Aurora then sold half its interest in a combined 95,000-acre lease position in the Wabash project to New Albany-Indiana, L.L.C. (“New Albany”), an affiliate of Rex Energy Operating Corporation, for a sale price of $10.5 million. Pursuant to the terms of this sales agreement, $3.5 million was placed in escrow by New Albany on behalf of the Company as a deposit until the closing in February 2006.
Other
Hudson Pipeline and Processing Co., L.L.C.
On January 31, 2006, Aurora Antrim North, L.L.C. (“North”), a wholly-owned subsidiary of Aurora, completed the acquisition of oil and natural gas leases, working interests, and interests in related pipelines and production facilities that are located in the Hudson Township area of the Michigan Antrim shale play. The interests acquired are collectively referred to as the Hudson Properties. In addition, interests in the related pipelines and production facilities were acquired by purchasing additional membership interests in Hudson Pipeline and Processing Co., L.L.C. (“HPPC”). North previously owned a working interest in the properties and a membership interest in HPPC. This acquisition increased North’s working interest in the Hudson Properties from an average of 49% to 96% and increased the membership interest in HPPC from 48.75% to 90.94%.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The total purchase price for the Hudson Properties and HPPC was approximately $27.6 million. North also acquired an additional 2.5% membership interest in HPPC, effective January 1, 2006, which increased the membership interest to 93.60%.
With these increases in membership interest in HPPC, effective January 1, 2006, HPPC was converted from the equity method to being consolidated as a subsidiary in the Company’s accompanying consolidated financial statements.
DeSoto Parish, Louisiana
On July 20, 2006, the Company entered into a Purchase and Sale Agreement with respect to the DeSoto Parish, Louisiana, properties to sell certain assets to BEUSA Energy, Inc. for a purchase price of $4.75 million. BEUSA Energy, Inc. is the current operator and joint interest owner in these properties. The properties included: (1) fourteen gross wells with working interest ranging from 22.5% to 45%; (2) 4,480 (1,657 net) acres; and (3) various pipelines and facilities. The effective date of the sale was July 1, 2006.
Crossroads Project, Henry, Ohio
Effective August 15, 2006, the Company agreed to assign all of its working interests in the Crossroads Project located in Henry County, Ohio to an unrelated party. The 7.06% working interest included 15,519 (1,096 net) leasehold acres, 13 (0.92 net) wells, and pipeline assets. Aurora agreed to pay $251,225 for disposition costs but will receive future pipeline revenue over the life of the project.
Bach
On October 6, 2006, the Company closed on the purchase of all assets of Bach Enterprises, Inc., certain assets owned by Bach Energy, LLC, and a limited liability company known as Kingsley Development LLC, forming Bach Services and Manufacturing Co., LLC (“Bach”). Bach is primarily an oil and natural gas service company. The Company has been working exclusively with Bach as a service business in Michigan for several years. Services they have provided include building compressors, CO2 removal, pipelines, and facility construction. The purchase price included common stock and cash. The common stock issued was subject to a one-year lock-up period. In addition, the Company entered into five-year employment agreements with two principals of Bach who agreed not to compete during their employment and for a period of one year following termination of their employment.
NOTE 8. DEBT
Short-Term Bank Borrowings
The Company had a $5.0 million revolving line of credit agreement with Northwestern Bank for general corporate purposes through October 15, 2007. The Company elected not to request an extension of this revolving line of credit beyond the expiration date of October 15, 2007. Interest expense on the revolving line of credit for the years ended December 31, 2007, and 2006, was $32,873 and $0.3 million, respectively.
Northwestern Bank continues to provide letters of credit for the Company’s drilling program (as described in Note 12 “Commitments and Contingencies”).
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Short-Term Bank Borrowings - Bach Services & Manufacturing Co., L.L.C. (“Bach”), a wholly-owned subsidiary
Effective December 12, 2007, Bach obtained an increase in its borrowing capacity under the revolving line of credit from $0.5 million to $1.0 million with Northwestern Bank. This revolving line of credit agreement is for general company purposes and is secured by all Bach’s personal property owned or hereafter acquired and is non-recourse to the Company. Effective December 8, 2008, Bach extended the expiration maturity date of this revolving line of credit to December 1, 2009. As part of the extension agreement, Bach’s maximum borrowings were reduced to $250,000. The interest rate under the revolving line of credit is Wall Street Prime with a floor of 4.0% (effective rate of 4.0% at December 31, 2008) with interest payable in arrears. Principal is payable at the expiration of the agreement. Interest expense for the years ended December 31, 2008, 2007, and 2006, was $1,523, $3,082, and $2,166, respectively.
Mortgage and Notes Payable - Bach
Bach’s outstanding debt was as follows for the periods indicated:
The obligations above are collateralized by the assets that are financed.
Bach’s interest expense was as follows for the periods indicated:
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Mortgage Payable
On October 4, 2005, the Company entered into a mortgage loan from Northwestern Bank in the amount of $2,925,000 for the purchase of an office condominium and associated interior improvements. The security for this mortgage is the office condominium real estate. Effective February 14, 2008, the Company refinanced the existing loan by extending its maturity date through February 1, 2011. The payment schedule is principal and interest in 36 monthly payments of $21,969 with one principal and interest payment of $2,364,419 on February 1, 2011. The interest rate is 5.95% per year. As of December 31, 2008, the principal amount outstanding was $2.6 million. Interest expense for the years ended December 31, 2008, 2007, and 2006, was $0.2 million, $0.1 million, and $0.1 million, respectively.
Note Payable - Directors and Officers Insurance
On November 13, 2006, the Company entered into a financing agreement with AICCO, Inc. to finance the insurance premium related to director and officer liability insurance coverage in the amount of $184,230. This obligation was paid in full during August 2007. Interest expense for the year ended December 31, 2007, was $2,546.
Senior Secured Credit Facility
On January 31, 2006, the Company entered into a $100 million senior secured credit facility with BNP and other lenders for drilling, development, and acquisitions, as well as other general corporate purposes. In connection with the second term lien loan discussed below, the Company also agreed to the amendment and restatement of the senior secured credit facility, pursuant to which the borrowing base under the senior secured credit facility was increased from the then current authorized borrowing base of $50 million to $70 million effective August 20, 2007. The amount of the borrowing base was based primarily upon the estimated value of the Company’s oil and gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at the Company’s request. The required semi-annual reserve report may result in an increase or decrease in credit availability. The security for this facility is substantially all of the Company’s oil and natural gas properties; guarantees from all material subsidiaries; and a pledge of 100% of the stock or member interest of all material subsidiaries.
The senior secured credit facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 3.0% (increased range by 1.0% from 2.0% to 3.0% as a result of the forbearance agreement and amendment no. 1 to the senior secured credit facility dated June 12, 2008, more fully described in the following paragraphs) depending on the borrowing base utilization, as selected by the Company. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of December 31, 2008, interest on the borrowings including the Early Termination Notice liability more fully described in Note 6 “Risk Management Activities”, had a weighted average interest rate of 6.5%. For the years ended December 31, 2008, 2007, and 2006, interest and fees incurred for the senior secured credit facility including the Early Termination Notice liability were $4.0 million, $2.7 million, and $2.3 million, respectively. All outstanding principal and accrued and unpaid interest under the senior secured facility is due and payable on January 31, 2010. The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitation on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a minimum current ratio, and (ii) maintenance of a minimum interest coverage ratio. Any event of default under the second lien term loan that accelerates the maturing of any indebtedness thereunder is also an event of default under the senior secured credit facility.
On June 6, 2008, BNP notified the Company that the syndication had redetermined the Company’s borrowing base to be $50 million. As a result, there was a potential borrowing base deficiency of as much as $20 million. According to the senior secured credit facility, the Company would be required to repay any deficiency in three equal monthly installments within 90 days following notification, subject to, among other things, the Company’s right to request an interim redetermination of the borrowing base.
On June 12, 2008 (but as of June 2, 2008), the Company and certain subsidiaries, as guarantors, entered into a forbearance agreement and amendment no. 1 to the senior secured credit facility (the “First Forbearance and Amendment Agreement”) with BNP and the syndication to address the Company’s failure to satisfy certain financial and non-financial covenants for the first quarter ended March 31, 2008. In accordance with the First Forbearance and Amendment Agreement, BNP permanently waived any defaults or events of default resulting from the non-compliance with any covenant failures for any date of determination prior to and including March 31, 2008. BNP also agreed to forbear and refrain from (i) accelerating any loans outstanding (including any borrowing base deficiency), (ii) exercising all rights and remedies, and (iii) taking any enforcement action under the senior secured credit facility or otherwise as a result of certain potential covenant defaults during the period from June 2, 2008, until August 15, 2008 (the “Standstill Period”), provided the Company complied with certain forbearance covenants (collectively, the “Forbearance Covenants”). The First Forbearance Covenants were (i) the Company was required to deliver to the syndication on or before the twentieth business day of each month, a detailed monthly financial reporting package for the previous month that shall include account payables aging, working capital, monthly production reports, and lease operating statements, (ii) the Company was required to participate in monthly conference calls with the syndication during which a financial officer of the Company would provide the syndication with an update on restructuring and cost reduction efforts, and (iii) no later than August 14, 2008, the Company was required to execute (or cause to be executed) additional mortgages such that, after giving effect to such additional mortgages, the syndication will have liens on not less that 90% of the PV10 of all proved oil and gas properties evaluated in the reserve report most recently delivered prior to such date. The First Forbearance and Amendment Agreement also increased the additional margin spread from 2.0% to 3.0% when electing a LIBOR-based borrowing rate. From August 14, 2008 until the execution of a second forbearance agreement on February 12, 2009 more fully described in Note 17 “Subsequent Events,” the Company did not comply with a provision of the First Forbearance Covenants which required the Company to execute additional mortgages on not less than 90% of all the Company’s proved oil and gas properties.
On October 3, 2008, the Company received a notice of default from BNP with respect to the senior secured credit facility (the “Notice of Default). The Notice of Default states that an event of default occurred under (1) Section 10.01(a) of the senior secured credit facility due to the Company’s failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million, (2) Section 10.01(g) of the senior secured credit facility due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (3) Section 10.01(f) of the senior secured credit facility due to the Company’s failure to pay the settlement amount of approximately $2.2 million ($0.6 million for natural gas derivatives and $1.6 million for interest rate derivative) by the due date of October 2, 2008, in connection with the Early Termination Notice, and (4) Sections 8.14, 8.18, and 9.01 of the senior secured credit facility and second lien term loan (cross default) due to the Company’s failure to comply with certain financial and non-financial covenants.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Notice of Default informed the Company, as of October 1, 2008, that the interest rate under the senior secured credit facility shall bear interest at the default rate of prime plus 3.0% thereby increasing the Company’s current interest rate under the senior secured credit facility by 2% to approximately 8.0% (6.25% at December 31, 2008).
The Company continues to engage in discussions with BNP and the syndication to restructure the Company’s debt. Management recognizes that subject to the terms of the February 12, 2009 Second Forbearance Agreement more fully described in Note 17 “Subsequent Events,” the senior secured credit facility will be due and payable upon notification from BNP, and therefore the entire outstanding debt has been classified as a current liability on the accompanying December 31, 2008 balance sheet. In addition to discussions with BNP and the syndication, management is also seeking alternative financing arrangements and opportunities for asset divestitures. Upon expiration of the February 12, 2009 Second Forbearance Agreement, there is no assurance that BNP and the syndication will not accelerate or demand repayment of the senior secured credit facility or that management will be successful in restructuring the Company’s debt, finding alternative financing arrangements, or selling Company assets.
The Company has incurred deferred financing fees of $0.7 million with regard to the senior secured credit facility. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the debt obligation. Amortization expense was $0.2 million, $0.2 million, and $0.1 million for the years ended December 31, 2008, 2007, and 2006, respectively. During 2008, the Company also incurred additional financing fees in the amount of $0.3 million in connection with the Forbearance and Amendment Agreement. The additional financing fees were recorded as an increase to general and administrative expense. In addition, the Company incurs various annual fees associated with unused commitment and agency fees which are recorded to interest expense.
Second Lien Term Loan
On August, 20, 2007, the Company entered into a second lien term loan agreement with BNP as the arranger and administrative agent, and several other lenders forming a syndication (the “Term Loan”). During August 2008, the Company was notified that Laminar Direct Capital, LLC (“Laminar”) succeeded BNP as the arranger and administrative agent for the second lien term loan. The initial term loan was $50 million for a 5-year term (expires 8/20/12) which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the second lien term loan were used to repay the outstanding balance under the Company’s mezzanine financing with Trust Company of the West (“TCW”) and for general corporate purposes. Interest under the second lien term loan is payable at rates based on the London Interbank Offered Rate (“LIBOR”) plus 950 basis points (increased from 700 basis points as a result of the forbearance agreement and amendment no. 1 to the second lien term loan dated June 12, 2008, more fully described in the following paragraphs) with a step-down of 25 basis points once the Company’s ratio of total indebtedness to earnings before interest, taxes, depreciation, depletion, amortization, and other non-cash charges is lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis. The Company has the ability to prepay the second lien term loan during the first year at a price equal to 103% of par, during the second year at a price equal to 102% of par, and thereafter at a price equal to 100% of par.
On June 12, 2008 (but as of June 2, 2008), the Company and certain subsidiaries, as guarantors, entered into a forbearance agreement and amendment no. 1 to the Term Loan (the “Term Loan Forbearance and Amendment Agreement”) with BNP and the syndication to address the Company’s failure to satisfy certain financial and non-financial covenants for the first quarter ended March 31, 2008. In accordance with the Term Loan Forbearance and Amendment Agreement, BNP has permanently waived any defaults or events of default resulting form the non-compliance with any covenant failures for any date of determination prior to and including March 31, 2008. BNP also agreed to forbear and refrain from (i) accelerating any loans outstanding, (ii) exercising all rights and remedies, and (iii) taking any enforcement action under the Term Loan or otherwise as a result of certain potential covenant defaults during the Standstill Period, provided the Company complies with the Forbearance Covenants, as applicable to the Term Loan. As of December 31, 2008, the syndication for the Term Loan has liens on less than 90% of all the Company’s proved oil and gas properties, and the Company is therefore not in compliance with a Forbearance Covenant. On August 15, 2008, the Term Loan Forbearance and Amendment Agreement expired without extension and therefore the syndication currently has the ability to exercise any or all of its rights and remedies under Term Loan. The Term Loan Forbearance and Amendment Agreement also increased the interest rate payable from LIBOR-based plus 700 basis points to LIBOR-based plus 950 basis points. The Term Loan Forbearance and Amendment Agreement also provided that in no event shall the LIBOR-based rate be less than 4.0%. In addition, the Term Loan Forbearance and Amendment Agreement instituted a payment-in-kind (“PIK”) arrangement which has resulted in additional liability under the Term Loan amounting to $0.9 million for the year ended December 31, 2008.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
On October 6, 2008, the Company received a notice of default from Laminar with respect to the second lien term Loan (“the “Term Loan Notice of Default”). The Term Loan Notice of Default states that an event of default occurred under (1) Section 10.01(g) of the second lien term loan due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (2) Section 10.01(f) of the second lien term loan due to the Company’s failure to pay the settlement amount of approximately $2.2 million ($0.6 million for natural gas derivatives and $1.6 million for interest rate derivative) by the due date of October 2, 2008, in connection with the Early Termination Notice, (3) Sections 8.14, 8.18, and 9.01 of the second lien term loan and the senior secured credit facility (cross default) due to the Company’s failure to comply with certain financial and non-financial covenants, and (4) Section 10.01(f) and (g) of the Term Loan due to the Company’s failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million under Section 10.01(a) of the senior secured credit facility (cross default). Laminar and the syndication under the second lien term loan cannot take any enforcement or similar actions against the Company or its property for at least 180 days beginning November 24, 2008 pursuant to the terms of the Intercreditor Agreement, dated August 20, 2007, between the second lien term loan syndication and the senior secured credit facility syndication.
The Term Loan Notice of Default also informed the Company, as of October 1, 2008, that the interest rate under the second lien term loan shall bear interest at the default rate thereby increasing the Company’s current interest rate under the Term Loan by 2% to approximately 15.5%.
Since the expiration of the Standstill Period, the Company continues to engage in discussions with Laminar and the syndication to restructure the Company’s debt. The Company recognizes that the term loan is due and payable upon notification from Laminar after the expiration of the 180 days beginning November 24, 2008, and therefore the entire outstanding balance has been classified as a current liability on the accompanying December 31, 2008 balance sheet. In addition to discussions with Laminar and the syndication, management is also seeking alternative financing arrangements and opportunities for asset divestitures. There is no assurance that management will be successful in restructuring the Company’s debt, finding alternative financing arrangements, or selling Company assets in an amount sufficient to remedy the Company’s loan defaults.
For the years ended December 31, 2008 and 2007, interest and fees incurred for the second lien term loan was $6.7 million and $2.2 million, respectively. The Company has also incurred deferred financing fees of $1.3 million with regard to the second lien term loan. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the second lien term loan obligation. Amortization expense for the second lien term loan is estimated to be $0.3 million per year through 2011. Amortization expense was $0.3 million and $0.1 million for the years ended December 31, 2008 and 2007, respectively. During 2008, the Company also incurred additional financing fees in the amount of $0.3 million in connection with the Term Loan Forbearance and Amendment Agreement. The additional financing fees were recorded as an increase to general and administrative expense. In addition, the Company incurred annual agency fees which are recorded to interest expense.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Scheduled principal maturities of long-term debt for each of the years succeeding December 31, 2008, are summarized as follows ($ in thousands):
Mezzanine Financing
Effective August 20, 2007, the Company’s subsidiary Aurora Antrim North, L.L.C. (“North”) terminated its Amended Note Purchase Agreement with TCW which provided $50 million in mezzanine financing. As of the effective date, North had outstanding borrowing of $40 million. The interest rate was fixed at 11.5% per year, compounded quarterly, and payable in arrears. TCW had limited the borrowing base, and the agreement contained a commitment expiration date of August 12, 2007. Under the termination provisions, the Company was required to pay certain fees and prepayment charges associated with early termination.
As part of the mezzanine financing with TCW, North provided an affiliate of TCW an overriding royalty interest of 4% in certain leases to be drilled or developed in the Counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency, and Otsego in the State of Michigan. The overriding royalty interest will also continue on leases, including extensions or renewals, held by the Company and its affiliates at August 20, 2007, that may be developed through September 29, 2009.
For the years ended December 31, 2007, and 2006, interest and fees incurred for the mezzanine credit facility were $3.0 million and $4.7 million, respectively. Since this agreement was terminated in 2007, no interest or fees were incurred during 2008.
NOTE 9. SHAREHOLDERS’ EQUITY
Common Stock
In June 2008, 350,000 shares of the Company’s stock were issued in connection with a stock grant awarded to the Company’s former Chief Financial Officer. The original grant was for 500,000 and the Chief Financial Officer elected to forfeit 150,000 shares in exchange for the Company paying taxes associated with the stock award in the amount of $90,450.
During May 2008, the Board of Directors granted a special common stock award under the 2006 Stock Incentive Plan to each of the five non-employee directors totaling 250,000 shares, or 50,000 each, for past services rendered. In addition, two of the non-employee directors were granted a special common stock award of an additional 15,000 shares each for services rendered on special projects. Of the 280,000 total shares granted, 100,000 were issued during July 2008 and 180,000 were issued during August 2008. Effective October 23, 2008, these awards were rescinded by agreement of the Company and those directors.
In January 2008 and April 2008, 500,000 common stock options were exercised in each month totaling 1,000,000 shares exercised during 2008 by an outside party at an exercise price of $0.625 per share. The Company received $0.6 million in connection with these exercises.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In March 2008, 133,332 common stock options were exercised by two Company directors under the existing stock option plans at an exercise price of $0.375 per share. The Company received $50,000 in connection with these exercises.
In January 2008, 30,000 common stock options were exercised by a Company employee under the existing stock option plans at an exercise price of $0.375 per share. The Company received $11,250 in connection with this exercise.
From February 2007 through December 2007, 210,000 common stock options were exercised by various Company employees under the existing stock option plans at exercise prices ranging from $0.375 to $1.25 per share. The Company received $92,500 in conjunction with these exercises.
In June 2007, 75,000 shares of the Company’s common stock valued at $147,000 were cancelled in order to reconcile with the Company’s transfer agent.
From February through December 2007, 143,332 common stock options were exercised by various Company directors under the existing stock option plans at exercise prices ranging from $0.375 to $1.42 per share. The Company received $106,000 in conjunction with these exercises.
In January 2007, 78,158 shares of the Company’s common stock were issued in connection with the exercise of outstanding warrants by a non-affiliated party in a net issue (cashless) exercise transaction.
From late December 2005 through early February 2006, the Company reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. Each holder who took advantage of the reduced exercise price was required to execute a 6-month lock-up agreement with respect to the shares issued in the exercise. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement and pursuant to other exercises of outstanding options, an additional 20,573,422 shares were issued during the year ended December 31, 2006, representing 15,823,457 shares issued for cash proceeds of $18,301,949, and 4,749,965 shares issued pursuant to cashless exercises of the applicable and other warrants or options. Substantially, all of the options and warrants exercised under the reduced exercise price option were noncompensatory in nature and were accounted for as equity transaction.
In December 2006, three officers of the Company rescinded option exercises for 600,000 shares each. The option exercise price of $249,000 was returned to each of these officers, and in exchange each officer surrendered 600,000 shares of common stock.
In February 2006, a special meeting of the shareholders was held where they voted to increase the number of authorized shares of common stock from 100,000,000 to 250,000,000.
In June 2006, an officer of the Company was issued 30,000 shares for services provided in 2005. Compensation expense related to this activity was recorded in 2005. Additionally, two directors of the Company were issued 30,000 shares each for their services provided to Aurora as Board members prior to the merger with Cadence. Compensation expense related to this activity was recorded in 2005.
In October 2006, upon the acquisition of the assets of Bach Enterprises, Inc. and its affiliates, 1,378,299 of unregistered common shares were issued.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Company closed on the public offering of 16 million shares on November 7, 2006, and received net proceeds of approximately $44.4 million, which were utilized to repay amounts outstanding under the senior secured credit facility. The 30-day over-allotment option granted to the underwriters for the purchase of 3.6 million additional shares was exercised and closed on November 13, 2006, and the Company received net proceeds of approximately $10.2 million.
Common Stock Warrants
The following table provides information related to stock warrant activity for the years ended December 31 ($ in thousands):
As of December 31, 2008, these common stock warrants had an average remaining contractual life of one month and weighted average exercise price per share of $1.74. As the lowest exercise price per share is $0.75, the Company does not expect any of the warrants to be exercised.
NOTE 10. INCOME TAXES
Income tax expense (benefit) for the years ended December 31 consists of the following ($ in thousands):
The effective income tax rate for the years ended December 31 differs from the U.S. federal statutory income tax rate due to the following (in thousands):
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
(a) 2006 adjustment of estimated income tax provision of prior year is due primarily to intangible costs that were expensed in 2005 calculation but capitalized and amortized in actual 2005 tax return. 2007 adjustment of estimated income tax provision of prior year is due primarily to a 2006 revision to the method of tax accounting treatment for stock options which lead to a significant change in the net operating loss carryover. 2008 adjustment of estimated income tax provision of prior year is due primarily to the impairment loss recognized as an expense during 2008 related to goodwill having no tax basis and previously treated as a permanent difference between book and tax amounts, reduced by revisions to the tax basis of oil and gas properties which lead to changes in the net operating loss carryover.
The components of the deferred tax assets and liabilities as of December 31 are as follows (in thousands):
The Company has net operating loss carryforwards available to offset future federal taxable income of approximately $120.0 million, which expire from 2010 through 2028. During October 2005, the Company (formerly Cadence) acquired Aurora Energy, Ltd. (“Aurora”) through the wholly-owned subsidiary with and into Aurora. As a result of the merger, Aurora became a wholly owned subsidiary. Included in this amount is a pre-merger net operating loss carryforward incurred by Cadence of approximately $17.0 million. The valuation allowance increased (decreased) by approximately $5.8 million, $7.9 million, and $(1.9) million as of December 31, 2008, 2007, and 2006, respectively. Due to the net operating loss carryforwards, no federal income tax expense was recorded in 2008, 2007, and 2006.
NOTE 11. COMMON STOCK OPTIONS
Stock Option Plans
In October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it was authorized to issue compensatory options to purchase up to 1,000,000 shares of common stock. The 1997 Stock Option Plan provides that the total number of shares of common stock of Aurora which may be granted as options shall not exceed 10% of the outstanding shares of the Company as of December 31 of each year for the following year. Aurora issued options to purchase a total of 580,000 shares of Aurora's common stock under this plan which, upon closing the merger, converted into the right to acquire up to 1,160,000 shares of common stock. The maximum term of options granted is 10 years. Because of the merger, no further awards will be made under this plan.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In 2001, Aurora's Board of Directors and shareholders approved the adoption of an Equity Compensation Plan for Non-Employee Directors. This plan provided that each non-employee director is entitled to receive options to purchase 100,000 shares of Aurora's common stock, issuable in increments of options to purchase 33,333 shares each year over a period of 3 years, so long as the director continues in office. Prior to the merger closing, Aurora had issued options to purchase a total of 309,997 shares of Aurora common stock under this plan which, upon closing the merger, converted to the right to acquire 619,994 shares of our common stock. Because of the merger, no further awards will be made under this plan.
In 2004, Cadence’s Board of Directors adopted, and the shareholders approved, a 2004 Equity Incentive Plan. This plan provides for the grant of options or restricted shares for compensatory purposes for up to 1,000,000 shares of common stock. The number of shares issued or subject to options issued under this plan total 910,500. The maximum term of options granted is 10 years. The Company does not currently intend to make any further awards under this plan, however, the plan continues to exist, and the Company may decide to use it in the future.
In March 2006, the Company’s Board of Directors adopted, and, in May 2006, shareholders approved, the 2006 Stock Incentive Plan. This Plan provides for the award of options or restricted shares for compensatory purposes for up to 8,000,000 shares. The purpose of the Plan is to promote the interests of the Company by aligning the interests of employees (including directors and officers who are employees) of the Company, consultants, and non-employee directors of the Company and to provide incentives for such persons to exert maximum efforts for the success of the Company and its affiliates. The maximum term for options granted is 10 years.
Activity related to the stock option plans referenced above was as follows (shares in thousands):
The weighted average assumptions used in the Black-Scholes option-pricing model used to determine fair value were as follows:
All Stock Options
In addition, Cadence awarded compensatory options and warrants totaling 30,280 on an individualized basis that was considered outside the awards issued under its 2004 Equity Incentive Plan. Aurora also issued options and warrants totaling 1,400,000 on an individualized basis that was considered outside the awards issued under its 1997 Stock Option Plan and Equity Compensation Plan for Non-Employee Directors. Of the 1,400,000 options and warrants issued, 431,000 shares remain outstanding as of December 31, 2008.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Activity with respect to all stock options is presented below for the years ended December 31, 2008, 2007, and 2006 (shares in thousands):
The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. Since the exercise price of all stock options is greater than the current market value, no intrinsic value exists for options outstanding at December 31, 2008.
The weighted average remaining life by exercise price as of December 31, 2008, is summarized below (shares in thousands):
NOTE 12. COMMITMENTS AND CONTINGENCIES
Environmental Risk
Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company manages its exposure to environmental liabilities for both properties it owns as well as properties to be acquired. Management believes that the Company is in substantial compliance with all currently applicable environmental laws and regulations.
In 2007, the State of Michigan, Department of Environmental Quality (“DEQ”) instituted a water sampling and monitoring requirement for wells north of a line of demarcation that includes most of the Company’s Antrim projects. The drilling permits for new wells in this area require produced water monitoring and reporting of gas and water volume and water quality. If the water produced by a well has levels of chloride or total dissolved solids concentration below specified levels, the Company may be required to shut-in the well. If such wells cannot be remediated so that fresh water is no longer produced, the Company may be required to plug such wells.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In September 2007, the DEQ collected and analyzed water samples from certain wells in the Arrowhead, Blue Chip, and Gaylord Fishing Club projects. On January 31, 2008, management met with the DEQ to review the analyses. Since the water composition in most of the wells fell within the range deemed by the DEQ to be fresh water, the DEQ requested that the Company plug six wells, plug or remediate an additional 15 wells, and collect water samples from the remaining wells that had not been previously sampled. Management agreed to plug five of the six wells requested and collected a new round of water samples from each requested well for additional analysis.
In September 2008, the Company received a notice of violation from the DEQ requesting a proposal from management to plug 25 wells in the Arrowhead and Blue Chip projects. Five of the wells listed on this notice had been agreed to during the January 31, 2008 meeting and were plugged during 2008. In December 2008, management met again with the DEQ to discuss the remaining wells. Management agreed to shut-in three additional wells bringing total shut-in wells to 13, and continue to provide water samples for the remaining wells for further analysis. Management is expected to meet again with the DEQ in March 2009 to discuss the results. There is no assurance that the Company will not be required to plug the remaining wells in the Arrowhead project. If the Company is required to plug the remaining wells, operations are not expected to be materially impacted as most of these wells are uneconomic and plugging costs are estimated to be $12,000 per well.
Letters of Credit
For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned. For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells. This blanket letter of credit allows the Company to drill an unlimited number of natural gas wells. The majority of existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of setoff against all of the Company’s deposit accounts with Northwestern Bank. At December 31, 2008, letters of credit in the amount of $0.8 million were outstanding with the majority issued to the Michigan Supervisor of Wells.
Employment Agreement
Ronald E. Huff resigned as President, Chief Financial Officer and Director of AOG effective January 21, 2008. The Company had a 2-year Employment Agreement with Mr. Huff, providing for an annual salary of $200,000 per year and an award of a stock bonus in the amount of 500,000 shares of the Company’s common stock on January 1, 2009, so long as he remained employed by the Company through June 18, 2008, which required the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. The Company paid Mr. Huff the compensation provided for in the employment agreement through June 18, 2008. This agreement was modified to accelerate the award of Mr. Huff’s stock bonus in the amount of 500,000 shares of common stock from January 1, 2009, to June 18, 2008. As a result of the acceleration, $0.5 million was recorded as stock-based compensation during the year ended December 31, 2008.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Retention Bonus
On September 19, 2007, the Company announced that it had retained Johnson Rice & Company, L.L.C. to assist the Board of Directors with investigating strategic alternatives for the Company. The Board of Directors of the Company has approved a retention bonus arrangement to encourage certain key officers and employees to remain with the Company through the completion of the Company’s review of potential strategic alternatives. The services of Johnson Rice & Company, L.L.C. were concluded on March 7, 2008. For the year ended December 31, 2008, the Company paid $0.3 million for retention bonuses.
Letter of Intent
On January 10, 2008, the Company signed a non-binding Letter of Intent to acquire Acadian Energy, LLC (“Acadian”). John E. McDevitt (former President and Chief Operating Officer, through a controlled entity) and Gilbert A. Smith (current President) are the only members of Acadian (60% and 40%, respectively). The Letter of Intent was terminated on October 1, 2008, and as a result Acadian acquisition costs initially capitalized in the amount of $0.2 million were recorded as a general and administrative expense as of December 31, 2008. In addition, all amounts paid on behalf of Acadian by the Company pursuant to the operating agreements more fully described in Note 13 “Related Party Transactions” have been repaid to the Company with the exception of $21,899 which has been recorded as a receivable at December 31, 2008.
Oak Tree Joint Venture
In March 2006, the Company entered into a Joint Venture Agreement covering the acquisition and development of oil and gas leases in an Area of Mutual Interest (“AMI”) in Oklahoma. The Company’s joint venture partner is the manager of the leasing program and is designated as Operator for the AMI. In March 2008, the Company’s joint venture partner filed a complaint alleging breach of contract and unjust enrichment, seeking a declaratory judgment to terminate the Joint Venture Agreement and to rescind the assignment of leases to the Company’s subsidiary, AOK Energy, LLC. As a result of the Company’s Purchase and Sale Agreement more fully described in Note 13 “Related Party Transactions,” on September 23, 2008, the joint venture partner dismissed all claims associated with this complaint.
General Legal Matters
The Company is currently involved in various disputes incidental to its business operations. Management, after consultation with legal counsel, is of the opinion that the final resolution of all currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position results of operations, or cash flows.
South Knox Loss
The Company operates various wells located in the South Knox project. During August 2008, the facility located in the South Knox project experienced a fire which incurred approximately $0.4 million in damages. Insurance claims have been submitted for the entire $0.4 million. The Company has a $25,000 deductible and has received full reimbursement of the amount of damages net of the deductible with the exception of $18,000. The Company anticipates receipt of the outstanding $18,000 in 2009.
Equipment Sale - Leaseback Agreement
Effective June 21, 2007, the Company entered into an agreement with Fifth Third Bank to sell and leaseback three natural gas compressors, which were accounted for as an operating lease. The net carrying value of the natural gas compressors sold was $1.2 million. Because the net carrying value of the natural gas compressors was equal to the sales price, there was no gain or loss recognized on the sale. The lease agreement has a base lease term of 84 months with a monthly rental fee of $13,610 beginning July 1, 2007. Effective June 26, 2008, Fifth Third Bank sold one of the compressors and released the Company of its obligation for this compressor. As a result of the sale and release, the monthly rental fee was adjusted to $8,713. For the year ended December 31, 2008, total rental expense incurred by the Company under this lease was $0.1 million.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Effective December 19, 2007, the Company entered into an agreement with Fifth Third Bank to sell and leaseback eleven natural gas compressors for $2.7 million. Under the agreement, the Company is leasing back the property over a base lease term of 60 months with a monthly rental fee of $37,110 beginning January 1, 2008. The Company is accounting for the leaseback as an operating lease. The gain of $0.7 million realized in this transaction has been deferred and will be amortized to income in proportion to rent charged over the term of the lease. At December 31, 2008, the long-term portion of the deferred gain is shown on the Company’s Balance Sheet as “Other long-term liabilities” in the amount of $0.4 million and as “Accounts payable and accrued liabilities” for the short-term portion of $0.1 million. For the year ended December 31, 2008, total rental expense incurred by the Company under this lease was $0.4 million.
The minimum lease payments required by both leases are as follows ($ in thousands):
NOTE 13. RELATED PARTY TRANSACTIONS
Presidium Energy, LC
AOK Energy LLC Purchase and Sale Agreement
In March 2006, the Company entered into a joint venture agreement with certain unrelated parties. The joint venture covered the acquisition and development of oil and gas leases in various counties located in Oklahoma. The joint venture project was known as the “Oak Tree Project.” The Company participated in the joint venture through a wholly owned subsidiary, AOK Energy, LLC (“AOK”). Effective March 28, 2008, the Company entered into an Agreement for the Purchase and Sale of Limited Liability Company Memberships with Presidium, which is wholly owned and operated by John V. Miller, who served as the Company’s Vice President from November 1, 2005, until he resigned on February 29, 2008. Under the terms of the agreement, the Company would sell to Presidium all of the outstanding member interests in AOK for a purchase price that included the payment by Presidium of certain liabilities that the operator alleged were owed by the Company to other participants in the joint venture, a cash payment to the Company in the amount of $10,500,000, and an assignment to the Company of a 3% overriding royalty in certain leases in the Oak Tree Project.
Effective July 21, 2008, the Company amended the Purchase and Sale of Limited Liability Company Memberships with Presidium (the “First Amendment”) to extend Presidium’s exclusive right to purchase all of the outstanding member interests in AOK until September 15, 2008. In exchange for the extension, Presidium made a $2.0 million non-refundable payment to the Company.
Effective on September 12, 2008, the Company amended the Purchase and Sale of Limited Liability Company Memberships with Presidium (the “Second Amendment”) increasing the purchase price to $15,000,000. The Second Amendment also required Presidium to pay another $1,000,000 in cash and execute a promissory note in the amount of $12,000,000 (“Promissory Note”). In order to induce the Company to enter into the Second Amendment, Mr. Miller granted the Company an option to buy up to one million membership units in Presidium for the sum of $0.50 per unit during the period from six months to five years after closing. If the Promissory Note is repaid in full within the first six months after closing, the Company’s option to purchase units in Presidium is null and void. The sale of the membership interest closed effective September 15, 2008.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Under the terms of the Promissory Note, Presidium is required to make monthly interest only payments calculated at the lesser of the maximum rate allowed by law or 9.0%. As security for repayment of the Promissory Note, Presidium granted a first priority security interest in all of AOK interests and delivered mortgages on all oil and gas leases Presidium holds or will acquire in the Oak Tree Project. In the event Presidium plans to drill a well in the Oak Tree Project, a principal payment on the Promissory Note equal to the amount of $400 per net acre of leases to be included in the drilling unit must be submitted to the Company in order for the Company to subordinate any mortgages held on leases that fall within the drilling unit. Presidium shall be entitled to have outstanding mortgage subordinations for no more than five undrilled well sites at any one time. The entire outstanding principal balance along with all accrued interest is due September 10, 2010. For the year ended December 31, 2008, the Company recorded $0.3 million of interest income related to the Promissory Note.
Consulting Agreement and Other
Effective May 20, 2008, the Company entered into a consulting agreement with Presidium in which the Company agreed to provide Presidium services in connection with certain oil and gas leasing, exploration, development, and business projects. This agreement expired December 31, 2008. For the year ended December 31, 2008, the Company billed Presidium $0.1 million for services rendered.
In the normal course of business the Company engages in certain operational transactions with Presidium. For the year ended December 31, 2008, the Company sold inventory to Presidium in the amount of $0.1 million and billed Presidium for lease bonus extensions in the amount of $0.1 million.
Acadian Energy, LLC
Operating Agreements
Subsequent to the Company executing a Letter of Intent with Acadian as more fully described in Note 12 “Commitment and Contingencies”, on June 24, 2008, the Company entered into an agreement with Acadian to provide funding to maintain and preserve the value of Acadian’s properties located in the State of Indiana pending the Company’s acquisition of Acadian. The Company agreed to advance approximately $83,000 pursuant to an authority for expenditure to be used for the purpose of bringing wells into compliance with the requirements of the State of Indiana and if practical, into production. The Company also agreed to pay certain legal expenses on behalf of Acadian in connection with the proposed acquisition of Acadian. The agreement also stated if the Company did not acquire Acadian or its assets by October 1, 2008, Acadian would be required to reimburse the Company for the entire amount advanced no later than October 1, 2009.
Effective April 1, 2008, the Company entered into an agreement with Acadian to provide oil and gas operating services on properties located in the State of Indiana. This agreement expired December 31, 2008. Under the terms of the agreement, the Company was not entitled to monetary consideration. Services were performed to maintain the value of the properties prior to transfer of ownership from Acadian to the Company.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
For the year ended December 31, 2008, the Company incurred expenses in the amount of $0.1 million under the operating agreements with Acadian. Due to the termination of the Letter of Intent agreement with Acadian more fully described in Note 12 “Commitments and Contingencies”, amounts incurred on behalf of Acadian in the amount of $0.1 million were reimbursed at December 31, 2008 with the exception of $21,899 which has been recorded as a receivable at December 31, 2008.
Simple Financial Solutions, Inc.
Consulting Agreements
Effective January 22, 2008, Barbara E. Lawson was named Chief Financial Officer of the Company. Simple Financial Solutions, Inc., which is owned and operated by Ms. Lawson’s spouse, provides consulting services on a continuous basis to the Company including Bach Services and Manufacturing Co., LLC, a Company subsidiary. For the year ended December 31, 2008, Simple Financial Solutions, Inc. billed the Company $0.1 million for services rendered.
Effective May 1, 2008, the Company entered into a month-to-month agreement with Simple Financial Solutions, Inc. to provide professional services for a subsidiary of the Company, Hudson Pipeline & Processing CO., LLC (“HPPC”). On a monthly basis, Simple Financial Solutions, Inc. will be paid 2% of the gross revenues of HPPC and 3.5% of the net income to HPPC before compensation. Certain revenue resulting from gas transportation will be excluded from the calculations. For the year ended December 31, 2008, the Company paid $0.1 million for services received from Simple Financial Solutions, Inc. pursuant to this HPPC agreement.
Disposition of Membership Interest
Effective June 28, 2008, Lawson & Kidd, LLC purchased a 2.5% membership interest in HPPC for $0.1 million. Lawson & Kidd, LLC is solely owned by Barbara E. Lawson who is the Company’s Chief Financial Officer and Ms. Lawson’s spouse. Lawson & Kidd, LLC’s interest will increase to 5% upon HPPC receiving income equal to 125% of total costs spent on construction of the pipelines owned and operated by HPPC. For the year ended December 31, 2008, the Company received $0.1 million in capital call contributions from Lawson & Kidd, LLC and paid Lawson & Kidd, LLC total distributions in the amount of $20,002. As more fully described in Note 17 “Subsequent Events,” the Company repurchased the 2.5% membership interest in HPPC from Lawson & Kidd, LLC during March 2009.
Other
Consulting Agreements
Effective August 15, 2008, the Company entered into a consulting agreement with Richard M. Deneau to provide advice and services at an hourly rate of $125 (not to exceed $1,000 per day) in connection with management’s negotiations with the Company’s existing bankers and the creation and maintenance of new banking relationships. Mr. Deneau is the brother of the Company’s Chief Executive Officer and has served as an affiliated director of the Company since 2005. For the year ended December 31, 2008, the Company paid $45,500 for consulting services received from Mr. Deneau.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Working Interest in Certain Projects
Effective May 30, 2007, the Board of Directors named John C. Hunter as Vice President of Exploration and Production. He has worked for AOG since 2005 as Senior Petroleum Engineer. Prior to that, Mr. Hunter was instrumental in certain projects associated with the Company’s New Albany shale play. Over a series of agreements with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has acquired 1.25% working interest in certain leases. The leases cover approximately 132,600 acres (1,658) net in certain counties located in Indiana. The 1.25% carried working interest shall be effective until development costs exceed $30 million. Thereafter, participation may continue as a standard 1.25% working interest owner. The Company is entitled to recovery of 100% of development costs (plus interest at a rate of 6.75% per annum compounded annually) from 85% of the net operating revenue generated from oil and gas production developed directly or indirectly in the area of mutual interest covered by the agreement. As of December 31, 2008, there is no production associated with this working interest, and development costs were approximately $13.3 million.
Effective July 1, 2004, Aurora Energy, Ltd., (“AEL”), entered into a Fee Sharing Agreement with Mr. Hunter as compensation for bringing Bluegrass Energy Enhancement Fund, LLC (“Bluegrass”) and AEL together for the development of the 1500 Antrim and Red Run projects in Michigan. At this time, AEL (which has since merged into the Company) and Bluegrass have discontinued leasing activities in both projects. In the 1500 Antrim project there are 23,989.41 acres. Mr. Hunter’s carried working interest share of 0.8333% is approximately 199.95 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are no producing wells. The Red Run project contains 12,893.64 acres. Mr. Hunter’s carried working interest share of 0.8333% is approximately 107.44 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are three wells permitted for the Red Run project and one well was temporarily abandoned.
NOTE 14. RETIREMENT BENEFITS
401(k) Plan
Effective May 1, 2006, the Company established a qualified retirement plan referred to as the Aurora 401(k) Plan (the “Plan”). The Plan is available to all employees who have completed at least 1,000 hours of service over their first 12 consecutive months of employment and are at least 21 years of age. Effective July 1, 2006, the Company waived the age and service requirements for any employee employed by the Company on or before July 1, 2006. The Company may provide: (1) discretionary matching of employee contributions; (2) discretionary profit-sharing contributions; and (3) qualified nonelective contributions to the Plan. Company-provided contributions are subject to certain vesting schedules. For the years ended December 31, 2008, 2007, and 2006, the Company contributed $53,148, $66,211, and $42,350, respectively, as a discretionary matching contribution. Of the $53,148 discretionary matching contribution for 2008, $10,478 is attributable to forfeitures and $42,670 is attributable to cash contributions by the Company. No forfeitures occurred during 2007 or 2006.
NOTE 15. FOURTH QUARTER ADJUSTMENTS-2006
During the fourth quarter of 2006, the Company modified its approach to estimating capitalized interest. The Company’s original approach to capitalization of interest cost was to relate the specific exploration and development activities in progress that were allowed under the mezzanine credit facility to specific mezzanine credit facility borrowings. If there were no such borrowings in a month that matched the drilling activities, then no interest was capitalized. On January 31, 2006, the Company entered into a new senior secured revolving credit facility for drilling, development, and acquisitions, which was not limited to certain exploration and development activities. In this connection, the mezzanine credit facility was subordinated to the new senior credit facility, and no further borrowings occurred under the mezzanine facility. The Company reviewed its approach to capitalized interest and began treating all oil and gas properties that were not being depreciated, depleted, or amortized, as well as any exploration and development activities that were in progress of being developed as qualifying assets under SFAS No. 34. The Company identified all its long-term debt borrowings to be included in the weighted average rate calculation for capitalized interest. This change resulted in additional $3.2 million of capitalized interest for the entire fiscal year of 2006 which was recorded in the fourth quarter; of this amount, $1.9 million related to prior quarters.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During the fourth quarter of 2006, the Company modified its approach to estimating oil and natural gas depreciation, depletion and amortization (“DD&A”). The Company’s original accounting approach was to amortize all capitalized costs of oil and natural gas properties considered proven developed, on the unit-of-production method using estimates of proven developed reserves. However, applicable accounting principles and related guidance provides that capitalized costs of oil and natural gas properties can be amortized on a unit-of-production method based on all proved oil and natural gas reserves. As of December 31, 2006, all of the Company’s proven reserves were evaluated by an independent petroleum engineering group which resulted in an 89 bcfe increase in proved reserves associated with the full cost pool. This change in estimate from proven developed reserves to proven reserves as well as an updated reserve report resulted in a reduction of $2.7 million in oil and natural gas depreciation, depletion and amortization.
NOTE 16. SELECTED QUARTERLY DATA (Unaudited)
The following table shows financial data for 2008, 2007, and 2006 ($ in thousands except for share data):
(a)
Includes oil and natural gas sales, pipeline transportation and processing, and field services and sales.
(b)
Includes production taxes, production and processing operating expenses, field services expenses, and general and administrative expenses.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
NOTE 17. SUBSEQUENT EVENTS
On February 12, 2009, the Company and certain subsidiaries, as guarantors, entered into a forbearance agreement to the senior secured credit facility (the “Second Forbearance Agreement”) with BNP Paribas (“BNP” or the “Administrative Agent”) and the syndication. In accordance with the Second Forbearance Agreement, during the period from December 31, 2008 until April 30, 2009 (the “Second Forbearance Period”), BNP will forbear and refrain from (i) accelerating any loans outstanding and (ii) taking any other enforcement action under the senior secured credit facility at law or otherwise as a result of designated defaults or potential defaults, provided the Company complies with the forbearance covenants (collectively, the “Second Forbearance Covenants”).
A summary of the Second Forbearance Covenants is as follows: (i) the Company shall retain and employ a financial advisor, (ii) the Company shall deliver to the Administrative Agent an initial detailed budget on or before February 20, 2009, and provide subsequent monthly updates, (iii) the Company shall deliver to the Administrative Agent prior week aggregated cash balances on or before the last business day of the current week, (iv) no later than February 23, 2009, the Company will execute (or cause to be executed) additional mortgages and no later than February 18, 2009, the Company will execute (or cause to be executed) other security instruments such that, after giving effect to such additional mortgages and other security instruments, the syndication will have liens on 100% of all oil and gas properties, promissory notes, all significant overriding royalties, and all significant farmout agreements prior to such date, (v) the Company must obtain prior written approval of the Administrative Agent to farmout any assets or sell any assets for more than $200,000; (vi) the Company shall provide the Administrative Agent notice of any unwritten or written expressions of interest with respect to the purchase of assets of the Company or any of its subsidiaries for an amount in excess of $2.0 million, (vii) the Company and its financial advisor shall participate in weekly conference calls with the Administrative Agent and the syndication during which a financial officer of the Company must provide updates on restructuring, sale prospects, and cost reduction efforts, (viii) the Company must deliver to the Administrative Agent copies of any detailed audit reports, management letters, or recommendations submitted to the board of directors, (ix) no later than February 28, 2009, the Company must deliver a restructuring plan to resolve the borrowing base deficiency, (x) the Company must maintain a liquidity position of at least $4.0 million during Second Forbearance Period, and (xi) no later than February 23, 2009, the Company must obtain the consent of the second lien term loan syndication for the Company to defer until no earlier than the termination of the Second Forbearance Period, payment of the scheduled interest payment currently payable to the second lien term loan syndication on February 24, 2009.
The Company’s failure to comply with the Second Forbearance Covenants will terminate the Second Forbearance Agreement and allow the syndication to exercise any or all of their rights and remedies purportedly provided to them under the senior secured credit facility.
On February 18, 2009, the Company executed the mortgages, security agreement and pledge agreements necessary to provide the senior secured credit facility lenders a first secured lien on substantially all of the Company’s oil and gas properties not previously pledged to them. The Company has also complied with the other Second Forbearance Covenants, except that the Company has not obtained the consent of the second lien lenders to defer payment of the $1.6 million interest payment scheduled to be paid by the Company on the second lien term loan on February 24, 2009. The Company has received correspondence from BNP dated February 27, 2009 indicating that the first lien lenders agree not to declare a forbearance termination event as a result of the Company’s failure to obtain the consent of the second lien lenders to defer payment of the interest scheduled to be paid on February 24, 2009, as long as the Company does not actually make the interest payment during the Second Forbearance Period. The Company has recorded the $1.6 million interest payment owed to the second lien lenders as a liability included with the second lien term loan obligation. As more fully described above, Laminar and the second lien term loan syndication cannot take any enforcement or similar actions against the company’s property for at least 180 days beginning November 24, 2008.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During March 2009, the Company repurchased a 2.5% membership interest in HPPC from Lawson & Kidd, LLC for $0.1 million and is pursuing the repurchase of the remaining outside interest in HPPC.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited)
Supplemental Reserve Information. The information set forth below on our proved oil and natural gas reserves is presented in accordance with regulations prescribed by the Securities and Exchange Commission. The Company retained the service of an independent petroleum consultant, Data & Consulting Services, Division of Schlumberger Technology Corporation (“Schlumberger”), to estimate its proved natural gas reserves at December 31, 2008, 2007, and 2006. Included in the tables set forth below are proved oil and natural gas reserves located in Michigan that were acquired as a separate property acquisition early in 2006 which were estimated by Netherland, Sewell & Associates, Inc.
The Company emphasizes that reserve estimates are inherently imprecise and strictly technical judgments. The accuracy of any reserve estimate is a function of the quality of data available and of the engineering and geological interpretations. The reserve estimates presented below are believed reasonable, however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision as future information becomes available. Accordingly, these estimates are expected to change and such changes could be material and occur in the near term as future information becomes available.
Reserves were assigned to the proved developed producing, proved non-producing, and proved undeveloped reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories of producing and non-producing. The reserves and income attributable to the various reserve categories below have not been adjusted to reflect the varying degrees of risk associated with them.
A majority of the undeveloped properties in the proved category are within fields containing complete infrastructure (including a central production facility and gathering system), an existing gas market and a demonstrated history of production and sales. All estimates of capital expenditures were supplied by the Company. A formal inspection of the Company’s financial status was not made by Schlumberger and Schlumberger assumes that the Company’s capital expenditures will proceed as planned. The Company’s capital expenditures are dependent on restructuring its current debt or securing alternative financing arrangements. There can be no assurance that the Company will be able to restructure its current debt or secure alternative financing arrangements.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited-continued)
The following table sets forth a summary of changes in estimated reserves for 2008, 2007 and 2006:
(a) Production for both 2007 and 2006 does not reflect 5 mcfe and 4 mcfe, respectively, of production the Company received in association with certain non-operated wells excluded in the year end reserve report.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited-continued)
During 2008, the Company recorded upward revisions of 1.0 bcfe from our New Albany properties and downward revisions to certain Antrim properties of 69.3 bcfe to the December 31, 2007 estimates of our reserves. The downward revision to certain Antrim properties was due to the following developments:
·
Reserves were reduced by 3.0 bcfe due to production during the year.
·
A reduction in natural gas prices (from an average of $7.18 per mcf on December 31, 2007, to an average of $6.07 per mcf on December 31, 2008) has caused a reduction in the volume of natural gas that can be economically produced. The Company attributes approximately 7.9 bcfe of the reduction in Antrim shale proved reserves to be attributable to lower natural gas prices.
·
As a result of changes in regulatory criteria, the Michigan Department of Environmental Quality (“DEQ”) forced the Company to plug 5 wells and shut in 13 wells during 2008 due to water quality issues, resulting in a setback in the Company’s efforts to dewater the Antrim shale in the Arrowhead project. Furthermore, the DEQ blocked the Company’s efforts to drill additional wells needed for dewatering. With no means to effectively dewater the project area, performance of the existing wells resulted in net reserve reduction of 7.1 bcfe on the three producing units in the project.
·
Due to the DEQ issues cited above, the absence of available capital needed to install infrastructure for existing wells and drill additional wells, and lack of performance of wells in the Arrowhead project, the proved reserves associated with the Blue Lakes Unit, Tomahawk 26 Unit, Tomahawk 27 Unit and Tomahawk 35 Unit were eliminated, resulting in a reduction of 12.8 bcfe.
·
The Company’s Antrim shale proved reserves have historically been determined by the Company’s third party reserve engineers using type curves derived from a combination of reservoir simulation and production performance from nearby more mature Antrim shale units operated by others. At the end of 2007, the type curves were modified to conform to our historical production history to date, but the Company had an insufficient amount of production on our working interest units to significantly alter the type curves. Now that the Company has sufficient data to develop decline curves for its wells, the Company’s engineers have based their projections of future production volumes on actual historical data from the Company’s own wells instead of representative data from other wells in the Antrim play. Not only did this affect the proved developed producing reserves, but the type curves for proved undeveloped reserves were modified accordingly. This resulted in type curves projecting lower reserves, and certain future drilling locations with proved undeveloped reserves were eliminated due to unacceptable economics. The Company estimates that approximately 41.3 bcfe of the reduction in Antrim shale proved reserves is attributable to this change.
·
The Company added 2.8 bcfe in extensions to proved reserves due to drilling activities in various areas.
During 2007, the Company recorded downward revisions to certain Antrim properties of 34.5 bcfe to the December 31, 2006, estimates of our reserves. This was due primarily to the 2007 lower realized production levels from certain project areas. The production curves used in the reserve report were adjusted to reflect lower future production to be consistent with the 2007 actual experience. This decrease was net of the upward adjustments caused by higher natural gas prices at December 31, 2007. Increase in pricing extends the economic lives of the properties which subsequently increases the reserves.
The Company recorded an increase in extensions and discoveries of 48 bcfe which was due to positive results from our 2007 drilling activity. Positive drilling results in the New Albany Shale added nearly 24 bcfe, while positive drilling results in the Antrim added 24 bcfe. Increases in the number of identifiable offsets also moved certain probable reserves to proved reserves. The Company also acquired 2.9 bcfe of proved reserves through the purchase of certain Antrim working interests for $3 million and sold 0.11 bcfe of proved reserves for approximately $1 million.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited-continued)
During 2006, the Company experienced significant changes in reserves due to extensions and discoveries associated with drilling activities conducted by both the Company and by third parties. Approximately 99.6% of the 65.4 bcfe of reserves attributable to extensions and discoveries are associated with the following:
The drilling of 16 gross (0.9 net) New Albany shale wells in Daviess and Greene Counties, Indiana, resulted in two field discoveries and reserves of 2.3 bcfe associated with 40 gross (2.4 net) wells. Approximately 67% of the reserves are undeveloped and are expected to be developed in 2007 and 2008.
The drilling of 196 gross (90.1 net) Antrim shale wells in Alcona, Alpena, Antrim, Charlevoix, Cheboygan, Montmorency, and Otsego Counties, Michigan, resulted in reserve extensions of 62.8 bcfe associated with 257 gross (138.1 net) wells. Approximately 59% of the reserve extensions are undeveloped and are expected to be developed in 2007 and 2008. The Company also acquired approximately 23 bcfe of proved reserves through purchases of natural gas properties for approximately $24.0 million and sold 0.7 bcfe of proved reserves for approximately $4.75 million.
During 2006, the Company recorded upward revisions of 5.1 bcfe to the December 31, 2005, estimates of our reserves. This was due primarily to the increase in the lives of the wells from 40 years to 50 years. Our reserve report for 2005 recognized a maximum well life of 40 years for Antrim shale wells. Schlumberger Data & Consulting Services, the preparer of the Company’s reserve reports, extended the maximum well life for the Antrim shale by an additional 10 years in the 2006 reserve report, and they also recognized a 50-year maximum life for the New Albany shale for several reasons. First, a number of Antrim shale properties operated by third parties have exhibited extended lives that suggest that a 50-year life is a reasonable expectation. Second, in most cases, our properties are projected to still be economic to produce after 50 years of production. Third, the casing in our wells is expected to maintain its integrity for 50+ years. Finally, we noted that at least one of the leading Antrim shale and New Albany shale producing companies projects their Antrim shale reserves and New Albany shale reserves using a 50-year maximum well life. The New Albany shale properties were included for the first time in our 2006 reserve report. The New Albany shale reservoir is comparable to the Antrim shale in its age, depth, pay thickness, gas content, gas origin, and production characteristics, so it is our belief that the maximum well life will be comparable. This increase was net of the downward adjustments caused by lower natural gas prices at December 31, 2006. A decrease in pricing reduces the economic lives of the properties which subsequently reduces the reserves.
Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Natural Gas Reserves
The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on oil and natural gas reserve and production volumes estimated by the Company’s independent reserve engineers. It may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The future cash flows presented below are computed by applying year-end prices to year-end quantities of proved oil and natural gas reserves. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves based on year-end costs and assuming continuation of existing economic conditions. It is expected that material revisions to some estimates of oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Additionally, certain capital funding constraints may impact the Company’s ability to develop the properties.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited-continued)
Management does not rely upon the following information in making investment and operating decisions. Such decision are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions are considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed in SFAS 69:
The standardized measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:
1.
An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.
2.
In accordance with SEC guidelines, the engineers’ estimates of future net revenues from our proved properties and the present value thereof are made using oil and gas sales prices in effect at December 31 of the year presented and are held constant throughout the life of the properties. The overall average year-end sales prices used in the reserve reports were supplied to Schlumberger by the Company as of December 31, 2008, 2007, and 2006 are summarized as follows:
3.
The future gross revenue streams were reduced by estimated future operating costs (including production and severance taxes) and future development and abandonment costs, all of which were based on current costs in effect at December 31 of the year presented and held constant throughout the life of the prosperities.
4.
Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited-continued)
Changes in Standardized Measure of Discounted Future Cash Flows
The following table sets forth the principal sources of change in the standardized measure of discounted future net cash flows:
(a) “Net changes in prices and production costs” - Our reserves consist primarily of natural gas. A significant change in natural gas price between reporting periods resulted in differences between 2006, 2007 and 2008. These price fluctuations were offset by changes in production costs. A summary of the changes is as follows:
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited-continued)
(b) “Revisions in quantity estimates” - The quantity estimates varied significantly between 2006, 2007 and 2008. The significant reduction reflected in 2008 resulted when a reduction of year end prices were applied to the downward adjustments of 63 bcfe to the 12/31/2007, reserves for certain Antrim properties, then discounted back to present value. The large reduction reflected in 2007 resulted when year end prices were applied to the downward adjustments of 34 bcfe to the 12/31/06 reserves for certain Antrim properties, then discounted back to present value. Certain fluctuations occurred in 2006 versus 2005 due to the classification of additional wells being added to the proved undeveloped category from the 12/31/05 report versus the 12/31/06 report.
(c) “Accretion of the discount” - In 2006, 2007, and 2008, this line item was computed using the industry-recognized method as a computation of the 10% of the pre-tax present value of the prior year reserve report.
(d) “Other” - This line item reflects reconciling amounts which is made available to capture those timing and other differences, including modifications to the methodology applied from 2006, 2007, and 2008.
Capitalized Costs Related to Oil and Natural Gas Producing Activities
The following table sets forth the capitalized costs relating to the Company’s oil and natural gas producing activities:
Costs Incurred in Oil and Natural Gas Producing Activities
The acquisition, exploration, and development costs disclosed in the following table are in accordance with definitions in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Exploration costs include exploration expenses, additions to exploration wells in progress, and depreciation of support equipment used in exploration activities. Development costs include additions to production facilities and equipment, additions to development wells in progress and related facilities, and depreciation of support equipment and related facilities used in development activities.
The following table sets forth capitalized costs incurred related to the Company’s oil and natural gas activities:
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL
GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
(Unaudited-continued)
(a) Total costs incurred includes (a) capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $0.6 million, $1.3 million, and $1.3 million for years ended December 31, 2008, 2007, and 2006, respectively, and (b) capitalized interest on unproven properties of $4.5 million, $4.5 million, and $3.9 million for years ended December 31, 2008, 2007, and 2006, respectively. Certain non-cash transactions are included as follows: (a) 2008, 2007, and 2006 asset retirement obligation of $0.1 million, $0.1 million, and $0.2 million, respectively, (b) 2008, 2007, and 2006 capitalized stock based compensation of $0.6 million, $1.3 million, and $0.5 million, respectively, (c) 2008 sale proceeds of $12.0 million, and (d) net transfer of $0.3 million from 2005 deposits to 2006 oil and natural gas properties.
Results of Operations
The Company’s results of operations related to oil and natural gas activities are set forth below. The following table includes revenues and expenses associated directly with our oil and natural gas producing activities. It does not include any interest costs, general and administrative costs, ceiling write-down of oil and gas properties, or provision for income taxes due to the net operating loss carryforward, and therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil and natural gas operations.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On March 23, 2007, after the completion of the audit of our financial statements for the years ended December 31, 2006 and 2005, we dismissed Rachlin Cohen & Holtz LLP (now known as Rachlin LLP) (“Rachlin”) as our independent auditors. The report of Rachlin on our financial statements for the years ended December 31, 2006 and 2005, contained no adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope, or accounting principles. In connection with its audit for the years ended December 31, 2006 and 2005, there have been no disagreements with Rachlin on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Rachlin, would have caused them to make reference thereto in their report on the financial statements for such years except as described in the following paragraph:
As described under Item 3 of our Form 10-QSB/A for the quarter ended March 31, 2006 (as filed on October 31, 2006), Rachlin advised us and we disclosed that we had a material weakness resulting from a deficiency in internal controls relating to the lack of accounting recognition given to the stock option grants authorized and approved by the Board of Directors in March 2006, which resulted in (a) the financial statements being modified to account for all of the stock option grants in accordance with the applicable provisions of Statement of Financial Accounting Standards No. 123(R) and (b) remedial actions being taken by us. In addition, as described under Item 3 of our Form 10-QSB/A for the quarter ended June 30, 2006 (as filed on October 31, 2006), we validated the remedial actions taken to correct the material weakness in connection with the reporting of stock option compensation.
The decision to change firms was approved by our Audit Committee of the Board of Directors.
We engaged Weaver and Tidwell, L.L.P. as our new independent auditors effective March 23, 2007, and we have relied upon Weaver and Tidwell, L.L.P. as an expert in auditing and accounting from that date.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management has responsibility for establishing and maintaining adequate internal control over our financial reporting. Management utilized the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (“COSO framework”) in conducting the required assessment of effectiveness of our internal control over financial reporting.
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by the Company is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the Securities and Exchange Commission. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in our periodic filings under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure.
Our management, including our CEO and CFO, do not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met with respect to financial statement preparation and presentation. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or because the degree of compliance with the policies or procedures deteriorates.
Our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended) as of December 31, 2008. Based on the evaluation and considering the material weakness in internal control over financial reporting described below, our CEO and CFO concluded that the Company’s reserve reporting controls were not effective.
Changes in Internal Controls over Financial Reporting
Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
·
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the issuer;
·
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and
·
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. In the course of auditing our year-end financial statements, our auditors identified a material weakness that resulted from an error made by us during our initial pricing of our reserve report. We initially priced our reserve report using the effective price at December 31, 2008, including an adjustment of the price based on a contract that expired on December 31, 2008. Since the contract expired on December 31, 2008, the contract price was incorrectly used to initially price future reserves. Prior to the audit of our December 31, 2008 financial statements, the effect of this error was recorded and resulted in understating impairment of the full cost pool by approximately $20.0 million as a result of the ceiling test at December 31, 2008. An audit adjustment was made to correct the error and is reflected in the December 31, 2008 financial statements. This error had no impact on the December 31, 2007 or 2006 financial statements.
As a result of the error in initially pricing our reserves, we are currently formulating a remediation plan to address this material weakness. We will have this plan in place prior to commencing preparation procedures for the next reserve report. This remediation plan is expected to include certain checklists, additional education and training for those employees involved in the reserve reporting process, expanded reserve planning and assumption meetings, and require supporting documentation for the prices to be used in calculating reserve values and any other assumptions that have a material impact in the reserve evaluation.
Since the above error was a failure in a one-time annual control historically occurring during the first quarter, there have been no changes in our internal controls over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. As noted above, we are currently formulating a remediation plan to address this material weakness which will result in changes to our internal controls during 2009.
Management’s Report on Internal Control Over Financial Reporting
Management’s report on internal control over financial reporting and the attestation report of our independent registered public accounting firm are included in Item 8 of this report.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The following table sets forth the name, age, and position of each of our executive officers and directors.
Name
Age
Position(s) with the Company
William W. Deneau
Director, Chairman and Chief Executive Officer
Gilbert A. Smith
President and Vice President, Business Development
John C. Hunter
Vice President, Exploration and Production
Barbara E. Lawson
Chief Financial Officer
Richard M. Deneau
Director
John E. McDevitt
Director
Gary J. Myles
Director
Wayne G. Schaeffer
Director
Kevin D. Stulp
Director
Earl V. Young
Director
Under the Company’s by-laws, the authorized number of directors is set at no fewer than three and no more than ten directors. The Board of Directors currently has seven members. Each member of the Board of Directors serves for a term of one year that expires at the following annual shareholders’ meeting. Each officer serves at the pleasure of the Board of Directors and until a successor has been qualified and appointed.
To the best of our knowledge, none of our Directors has been convicted in a criminal proceeding, excluding traffic violations or similar misdemeanors, or has been a party to any judicial or administrative proceeding during the past five years, except for matters that were dismissed without sanction or settlement, that resulted in a judgment, decree, or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.
Set forth below is certain biographical information regarding each of our directors and executive officers:
William W. Deneau has served on our Board of Directors and as Chief Executive Officer and Chairman of the Board of Directors since November 1, 2005. Mr. Deneau also served as President until May 30, 2007. Mr. Deneau became an employee of Aurora Energy, Ltd. (“AEL”) on April 22, 1997, when he sold his interest in Jet/LaVanway Exploration, L.L.C. to AEL in exchange for AEL’s stock. On June 25, 1997, and July 17, 1997, respectively, Mr. Deneau became a Director and President of AEL, which became a wholly-owned subsidiary of the Company on October 31, 2005. Mr. Deneau continued to manage the affairs of AEL through January 1, 2008, when it was merged with the Company. William W. Deneau is the brother of Richard M. Deneau, another one of our Directors.
Gilbert A. Smith has served as our President since November 15, 2008, and as a Vice President since February 1, 2008. Since January 2007, Mr. Smith has been a Manager and Chief Operating Officer of Acadian Energy, LLC, a position he continues to hold. From 2002 to 2006, Mr. Smith was Vice President of Land and Contract Administration for CDX Gas, LLC. From 1999 to 2001, Mr. Smith worked as an independent consultant, performing international strategic contract negotiation and business development. Mr. Smith worked for Sun Exploration and Production Company (subsequently named Oryx Energy Company) from 1978 through 1999 where he served in various senior management positions.
John C. Hunter has served as a Vice President since May 30, 2007. He has worked for us since 2005 as Senior Petroleum Engineer. From 2004 to 2005, Mr. Hunter was Executive Vice President of Wellstream Energy Services providing petroleum engineering consulting services. From 2000 to 2004, Mr. Hunter was President of Terra Drilling Services, LLC and TerraFluids, LLC, which provides short radius horizontal drilling services, as well as drilling and completion fluids in the United States. From 1995 to 2004, Mr. Hunter was Director of Exploitation of Torch Energy Advisors, Inc. located in Houston, Texas, where he managed a staff of 15 employees dedicated to the development of oil and natural gas properties.
Barbara E. Lawson has served as our Chief Financial Officer since January 22, 2008. From March 2006 until she became our Chief Financial Officer, Ms. Lawson worked for us as SEC Reporting Manager. From 2005 to 2006, Ms. Lawson was Vice President of Simple Financial Solutions, Inc. providing consulting services that covered public equity offerings and Sarbanes-Oxley Section 404 implementation. From 1988 to 2004, Ms. Lawson was employed with Midland Cogeneration Venture, LLP, an independent power producer, where her last position was Treasurer and Manager of Internal Audit. Ms. Lawson managed up to $450 million investment portfolio, administered compliance on $1.7 billion of bond debt, implemented Sarbanes-Oxley compliance requirements, and managed at least 12 internal audits annually.
Richard M. Deneau has served on our Board of Directors since November 21, 2005. Mr. Deneau served as a Director and President of Anchor Glass Container Corporation (“Anchor”) from 1997 until his retirement in 2004. He was also the Chief Operating Officer of Anchor from 1997 to 2002, and the Chief Executive Officer of Anchor from 2002 until his retirement. Anchor, which was publicly traded and listed on NASDAQ, is the third largest glass container manufacturer in the United States, with annual revenues of about $750 million. Mr. Deneau is the brother of William W. Deneau, who is also a director and is our Chief Executive Officer and Chairman of the Board.
John E. McDevitt has served as a Director since January 22, 2008. Mr. McDevitt also served as our President and Chief Operating Officer from January 22, 2008, until his resignation on November 15, 2008. Since 2006, Mr. McDevitt has been a Manager and President of Acadian Energy, LLC, a private company focused on unconventional natural gas exploration and production in the New Albany Shale. From 2003 to 2007, Mr. McDevitt was President of CDX Resources, a rig fleet and directional services company that was owned by CDX Gas, LLC. Prior to that, he held positions with CDX Gas, LLC as CFO and Senior Vice President of Strategic Planning. CDX Gas, LLC was an independent oil and gas company focused on the onshore exploration and production of unconventional natural gas, which was sold in 2006.
Gary J. Myles has served on our Board of Directors since November 21, 2005. Mr. Myles also served as a Director of AEL (which became a wholly-owned subsidiary of the Company on October 31, 2005) from June 1997 until January 1, 2008, when AEL was merged into the Company. He is currently retired from his primary employment. Prior to his retirement, Mr. Myles served as Vice President and Consumer Loan Manager for Fifth Third Bank of Northern Michigan (previously Old Kent Mortgage Company), a wholly owned subsidiary of Fifth Third Bank (previously Old Kent Financial Corporation). Mr. Myles had been with Fifth Third Bank and its predecessor, Old Kent Mortgage Company, since July 1988 and retired on October 14, 2005.
Wayne G. Schaeffer joined our Board of Directors on January 19, 2007. Mr. Schaeffer was employed by Citizens Banking Corporation from 1983 until his retirement in June 2005. Positions held with Citizens Banking Corporation include Executive Vice President, Head of Consumer Banking (June 2002 - June 2005) and Executive Vice President of Citizens Banking Corporation and President, Citizens Bank-Southeast Michigan (June 1996 - June 2002).
Kevin D. Stulp has served on our Board of Directors since March 1997. Since August 1995, Mr. Stulp has worked as a consultant with Forte Group, on the board of the Bible League, and is active with various other non-profit organizations and is currently a director of U.S. Silver Corporation, a publicly-traded silver mining company with operations in Wallace, Idaho. From December 1983 to July 1995, Mr. Stulp held various positions with Compaq Computer Corporation, including industrial engineer, new products planner, manufacturing manager, director of manufacturing, and director of worldwide manufacturing reengineering.
Earl V. Young has served on our Board of Directors since November 21, 2005. Mr. Young has also served as a Director of AEL (which became a wholly-owned subsidiary of the Company on October 31, 2005) from June 1997 until January 1, 2008, when AEL was merged into the Company. He is currently President of Earl Young & Associates of Dallas, Texas, which he founded in 1999. Mr. Young is also a Director and chair of the Audit Committee for Diamond Fields International, a Canadian company that is listed on the Toronto Stock Exchange and is a producer of offshore diamonds in Nambia with exploration activity in Sierra Leone and Liberia. Mr. Young is a Director of Madagascar Resources, an Australian public company that is engaged in mineral exploration in Madagascar.
More detailed biographical information about our directors and executive officers may be found on our website at www.auroraogc.com.
To our knowledge, no director, officer or affiliate of the Company, and no owner of record or beneficial owner of more than five percent (5%) of our securities, or any associate of any such director, officer or security holder is a party adverse to us or has a material interest adverse to us in reference to pending litigation.
THE BOARD OF DIRECTORS AND STANDING
COMMITTEES OF DIRECTORS
A majority of our seven member Board of Directors qualify as independent directors. The following directors are independent directors as defined in Section 121A of the American Stock Exchange Corporate Governance Rules, a non-employee director as defined in Rule 16b-3 under the Securities Exchange Act of 1934, and an outside director as defined under Section 162(m) of the Internal Revenue Code: Gary J. Myles, Wayne G. Schaeffer, Kevin D. Stulp, and Earl V. Young.
We require that all members of our standing Board committees be independent directors. Our Board committees are as follows:
Audit Committee: Wayne G. Schaeffer (chairman), Earl V. Young, and Gary J. Myles.
Compensation Committee: Gary J. Myles (chairman), Kevin D. Stulp, and Wayne G. Schaeffer.
Corporate Governance Committee: Earl V. Young (chairman), Kevin D. Stulp, and Wayne G. Schaeffer.
Nominating Committee: Kevin D. Stulp (chairman), Gary J. Myles, and Earl V. Young.
We have adopted a Code of Conduct and Ethics, a copy of which is available on our website at www.auroraogc.com. This Code applies to all Directors, officers, and employees.
Audit Committee
We have a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934, as amended (“Exchange Act”). Members of the Audit Committee currently include Wayne G. Schaeffer, Earl V. Young, and Gary J. Myles. Each of them is an independent outside director. Wayne G. Schaeffer was designated by the Board as a financial expert. We have included in the biographical information above a brief summary of his relevant experience.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
General Objectives of Compensation Program
Our Compensation Committee Charter states that the Committee’s objective is to develop a compensation system that is competitive with our peers and encourages both short-term and long-term performance in a manner beneficial to us and our operations. Our compensation philosophy will vary among the executive officers, depending upon variables such as previous history with the company, number of shares of company stock owned, the impact of peer group comparison, and whether recruitment is a factor under the circumstances. We do not believe that a single approach or even a single objective is appropriate with respect to all executive officers. Furthermore, our financial condition has an impact on what we can and should do in the realm of executive compensation. Nonetheless, our philosophy at this time is to maintain a fairly simple executive compensation structure. If an executive officer is also a director, it is our practice to compensate him only as an executive officer. He will not participate in the compensation awarded to the non-employee directors.
Process
Our executive officers may from time to time make recommendations to the Compensation Committee regarding executive compensation. The Compensation Committee may accept or reject these recommendations. If they are accepted, the Compensation Committee presents them as recommendations to the Board of Directors. Our Board of Directors has ultimate authority over executive compensation and may follow or disregard the recommendations of the Compensation Committee. Executive officers are excused from Board deliberations on executive compensation, and executive officers who are also directors do not vote on any matters that affect their own compensation.
Compensation of our Executive Officers
Objectives
As we entered 2008, our primary objective for the year 2008 was to maintain a fair compensation level while we continued to work on developing a more comprehensive compensation philosophy. At that time, we were working with an investment banker to evaluate strategic alternatives, and we thought it best to defer work on a comprehensive compensation philosophy until our strategic direction was clearer. In July 2008, we identified a compensation consultant who we were interested in engaging to help us develop our executive compensation strategy. However, in light of our deteriorating financial condition, we decided to defer any strategic planning for executive compensation and focus instead on retaining the management team we need to lead us through these rough economic times. Once our financial condition is less precarious, we intend to return to work on our executive compensation plan. In the meantime, our interim approach is described below.
Elements of Executive Compensation
Base Salary. It is our practice to re-evaluate base salary for our executive officers each year. In general, our philosophy is to pay a base salary that is fair in the sense of being competitive enough in the market place to attract and retain our executive officers, given the circumstances of each individual involved, but no more. Our philosophy is not to match the base salary paid by our peers, but to determine what is fair and competitive overall compensation under the circumstances. In 2006, we retained the services of a compensation consulting firm that provided us with data regarding compensation for peer executive officers within our industry.
With the exception of our CEO, by the end of the first quarter of 2008, our executive management team was completely different than the team we had in place during the first quarter of 2007. Accordingly, as new executive officers were hired, their salaries were set at a level that we believed would be sufficient to attract, retain and motivate competent employees. We awarded our CEO a modest salary increase in 2008.
We generally do not make material changes in base salary compensation levels unless there is a significant change in job responsibilities or if the present level of an incumbent's compensation is substantially below competitive levels. We will generally look at modest annual increases as a means of making up for inflationary cost of living increases and to provide some modest merit-based increase for work done during the prior year.
Annual Performance Bonus. Our approach to the use of annual performance bonuses will vary from year to year. During the year 2009, we hope to develop bonus-based compensation for our executive officers tied to their achievement of performance metrics or the character of their assigned duties. Although we do not yet have our anticipated bonus plans in place, it is the goal of the Compensation Committee to significantly increase the proportion of the compensation we pay to our executive officers that is based on performance bonuses. Annual bonuses will be used to align compensation with performance based upon performance metrics. However, this work will be deferred until our financial condition is more stable.
Special Purpose Bonuses. In 2007, we implemented three special purpose bonuses, as described in our December 31, 2007 Form 10-K. During 2008, these bonuses were modified as described below.
•
Stay Bonus - the Stay Bonus Arrangement was adopted in 2007 to encourage employees to remain employed by us through any possible change-in-control. For purposes of this arrangement, "change-in-control" was defined to mean any transaction or occurrence (including a sale of stock or merger) where our shareholders before the transaction or occurrence owned less than 50% of our voting shares after the transaction or occurrence, or a sale or disposition of a majority of our assets. Under the Stay Bonus Arrangement, if a change-in-control occurred on or before September 1, 2008, and the employees who received this benefit remained continuously employed by us through a change-in-control, the employees who participated in the Stay Bonus Arrangement would have been eligible for a stay bonus in the amount of 50% of their then current annual salary.
During 2008, the Stay Bonus Arrangement was extended to changes in control that occurred by December 31, 2008. Because we did not undergo a change-in-control by December 31, 2008, the Stay Bonus Arrangement that we adopted in 2007 expired without the award of any bonuses.
•
Change-in-Control Agreements - the Change-in-Control Agreements were adopted in 2007 to encourage certain key officers and employees to remain employed with us through any potential change-in-control. The Change-in-Control Agreements provide that during a two-year period following a change-in-control, the employees who were provided these agreements would: (i) have a position and duties commensurate to those the employee had prior to the change-in-control; (ii) perform his or her services at a location within a 35-mile radius from his or her previous worksite before the change-in-control; and (iii) receive an annual base salary at least equal to the employee's annual base salary prior to the change-in-control unless a reduction in salary occurs on a proportional basis simultaneously with a Company-wide reduction in senior management salaries. If any of the foregoing commitments are not met, a "covered termination" is deemed to have occurred. In the event of a covered termination during the two-year period following a change-in-control, the arrangement provides for the payment of an amount equal to either one or two times the employee's annual salary, the provision of medical and dental benefits for up to 24 months following the date of termination, and benefits continuation substantially similar to those to which the employee was entitled prior to the date of termination.
In 2008, we modified which executive officers were entitled to receive Change-in-Control Agreements and the multiplier of annual salary some of the executives are entitled to receive. The executive officers who are currently covered by these Change-in-Control Agreements are: William W. Deneau, our current Chief Executive Officer, who would receive two times his annual salary in the event of an applicable post change-in-control termination; Gilbert A. Smith, our President and Vice President of Business Development, who would receive one times his annual salary in the event of an applicable post change-in-control termination; John C. Hunter, our Vice President of Exploration and Production, who would receive two times his annual salary in the event of an applicable post change-in-control termination; and Barbara E. Lawson, our Chief Financial Officer, who would receive two times her annual salary in the event of an applicable post change-in-control termination.
•
Retention Bonus - The Retention Bonus Arrangement was adopted in 2007 to encourage certain key officers and employees to remain employed by us through any possible changes in control. The Compensation Committee and Board of Directors recognized that certain key officers and employees would have increased responsibilities and duties during the evaluation of strategic alternatives, and that they would also contribute significantly to the process. The Retention Bonus Arrangement consisted of equal payments to be made on October 26, 2007, December 26, 2007, February 26, 2008 and April 28, 2008. The participating officers and employees were required to remain continuously employed through each of the scheduled payment dates. The final payment was made in April 2008 to those employees actively participating in the strategic alternative process at that time.
Executive officers who participated in the Retention Bonus Arrangement included Ronald E. Huff, our former President and Chief Financial Officer in the aggregate amount of $100,000; John C. Hunter, one of our Vice Presidents, in the aggregate amount of $80,000; John V. Miller, one of our former Vice Presidents, in the aggregate amount of $40,000; and Barbara E. Lawson, our current Chief Financial Officer, in the aggregate amount of $40,000. In each case, one quarter of the dollar amount specified was payable on each bonus date based upon active employment.
Stock Options. We use stock options from time to time to serve as a long-term incentive to keep our employees' performance aligned with our overall corporate goals. Because of the tax preferred treatment of incentive stock options, we evaluate the tax benefits of incentive stock options when evaluating compensation for our executive officers.
Philosophically, the Compensation Committee has agreed that stock options and other equity incentive awards should be reserved for situations in which the executive officer meets stated goals or to incentivize desired outcomes. Stock options may also be used as a signing bonus.
In 2008, we awarded stock options to executive officers and other management employees, with a goal of incentivizing them through our difficult financial circumstances. Each stock option has a 10-year term and vests over 3 years. The awards to executive officers were as follows:
Stock Awards. In addition to the issuance of stock options, we also have used, and from time to time expect to continue to use, stock awards as an element of executive compensation. This determination will be made on a case-by-case basis. We did not provide any stock awards to our executive officers during 2008.
In the future, we anticipate that stock awards will be reserved for use in the context of a signing bonus or, in some cases, if certain performance goals are satisfied.
Other Types of Compensation. We do not have in place at this time any other types of long-term incentive compensation or special executive benefits not provided to all of our employees on the same terms.
Equity Ownership Guidelines and Requirements
We do not require non-director executive management to own our equity. As described below, Directors are required to own a nominal amount of our stock within a specified period of time. This requirement applies to executive officers who are also Directors.
Our Insider Trading Policy prohibits all insiders, including executive officers and directors, from trading in any interest or position relating to our future stock prices, such as puts, calls and short sales. We have encouraged our executive officers who desire to trade in our stock to establish 10b5-1 Plans in order to minimize the risk of trading on non-public information.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the foregoing Compensation Discussion and Analysis with management, and based on this review and discussions, the Compensation Committee recommended to the Board of Directors that the foregoing Compensation Discussion and Analysis be included in this Form 10-K. This report is submitted by the members of the Compensation Committee.
Gary J. Myles, Chairman
Wayne G. Schaeffer
Kevin D. Stulp
Compensation Committee Interlocks And Insider Participation
None of our Compensation Committee members were, during our fiscal year ending December 31, 2008, or at any prior time, employed as an officer or employee of the Company. There are no relationships between the members of our Compensation Committee and the Company that require disclosure.
The following four tables set forth information regarding our Chief Executive Officer, Chief Financial Officer, and our remaining executive officer of the Company.
SUMMARY COMPENSATION TABLE
(a)
The assumptions used to calculate value in accordance with FAS 123R may be found in Note 11 “Common Stock Options” of our financial statements provided above.
(b)
These reflect our company match to a 401(K) defined contribution plan.
(c)
We paid Mr. Hunter $12,500 for a housing allowance and made 401(k) matching contributions of $3,630.
(d)
Mr. Huff became our chief financial officer on June 19, 2006. We paid him a salary in the amount of $90,900 (annual salary of $200,000 per year) for services rendered from the period June 19, 2006, through December 31, 2006. Mr. Huff served as a director throughout the entire year of 2006. We paid him $14,500 for director services through June 18, 2006, including compensation for his services as chairman of our audit committee. We do not pay our executive officers separate compensation for serving as a director. Accordingly, Mr. Huff did not receive separate compensation for his service as a director from June 19, 2006, through the end of 2006.
(e)
Ronald E. Huff resigned as President, Chief Financial Officer and Director of AOG effective January 21, 2008. The Company had a 2-year Employment Agreement with Mr. Huff, providing for an annual salary and an award of a stock bonus in the amount of 500,000 shares of the Company’s common stock on January 1, 2009, so long as he remained employed by the Company through June 18, 2008, which requires the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. Mr. Huff’s employment agreement was honored by the Company through its June 18, 2008 termination date. This agreement was modified to accelerate the award of Mr. Huff’s stock bonus in the amount of 500,000 shares of common stock from January 1, 2009, to June 18, 2008. In June 2008, 350,000 shares of the Company’s stock were issued in connection with Mr. Huff’s stock bonus. Mr. Huff forfeited 150,000 shares in exchange for us paying taxes associated with the stock bonus in the amount of $90,450.
(f)
Due to our change in frequency of pay during 2008 from monthly to bi-weekly, there is one additional pay date included in the 2008 totals.
(g)
Mr. Smith became a Vice President on February 1, 2008, and became President on November 15, 2008.
(h)
Ms. Lawson was appointed CFO effective January 21, 2008. Before that, she served as our SEC Reporting Manager.
(i)
Mr. McDevitt was appointed President and Chief Operating Officer effective January 21, 2008 and resigned effective November 15, 2008.
(j)
Mr. Miller resigned effective February 29, 2008.
The following table sets forth information on grants of equity-based awards to executive officers during 2008.
GRANTS OF PLAN-BASED AWARDS
Options awarded during 2008 vest one-third annually over a three year period. The options expire on May 30, 2018.
(a) Mr. McDevitt resigned before any of these options vested.
The following table sets forth information on exercised options and unvested stock awards held by our executive officers as of December 31, 2008.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
POTENTIAL PAYMENTS UPON CHANGE IN CONTROL
Had a change of control taken place on December 31, 2008, and certain other provisions of the change in control agreement been triggered, the following executive officers would have been paid in accordance with the change of control agreement referenced above.
COMPENSATION OF DIRECTORS
The table below sets forth the compensation we paid to our non-employee directors during 2008.
DIRECTOR COMPENSATION TABLE
(a)
At December 31, 2008, Richard M. Deneau owned options to purchase an aggregate of 300,000 shares of our common stock, 130,000 of which are vested and 170,000 of which are unvested.
(b)
At December 31, 2008, Gary J. Myles owned options to purchase an aggregate of 366,666 shares of our common stock, 196,666 of which are vested, and 170,000 of which are unvested.
(c)
At December 31, 2008, Wayne G. Schaeffer owned options to purchase an aggregate of 240,000 shares of our common stock, 70,000 of which are vested, and 170,000 of which are unvested.
(d)
At December 31, 2008, Kevin D. Stulp owned options to purchase an aggregate of 300,000 shares of our common stock, 130,000 of which are vested, and 170,000 of which are unvested.
(e)
At December 31, 2008, Earl V. Young owned options to purchase an aggregate of 366,666 shares of our common stock, 196,666 of which are vested, and 170,000 of which are unvested.
(f)
Mr. Deneau’s compensation does not include $45,500 related to consulting services performed for us during 2008 more fully described in Item 13 of this report.
For 2008, our standard compensation arrangement for service as a non-employee director was as follows:
§
Annual retainer of $25,000.
§
Cash fee of $1,000 per Board of Directors meeting attended in person, with additional payments of $1,000 per day for each travel day from the Director’s place of residence to the location of the Board of Directors meeting, up to a total of two additional days in addition to the date of the meeting.
§
Cash fee of $500 for participation in each telephonic Board of Directors meeting.
§
Cash fee of $1,000 for each committee meeting attended in person.
§
Cash fee of $500 for participating in each telephonic committee meeting.
§
Compensation for meetings is a daily aggregate fee without regard to the number of meetings held in proximity to each other and, for purposes hereof, Board meetings and Committee meetings shall be considered together and shall be covered by a single aggregate daily fee.
Our Board of Directors has adopted a policy requiring each director to own at least 20,000 shares of our common stock. For new directors, this requirement must be satisfied within one year of joining our Board of Directors. This requirement applies to all directors, including those who are employees and those who are not employees.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth, as of March 4, 2009, certain information regarding the ownership of voting securities of the Company by each shareholder known by the management of the Company to be (i) the beneficial owner of more than 5% of our outstanding common stock, (ii) our directors, (iii) our current executive officers and (iv) all executive officers and directors as a group. Except as otherwise reflected in the notes below, the Company believes that the beneficial owners of the common stock listed below, based on information furnished by such owners, have sole investment and voting power with respect to such shares.
Unless otherwise specified, the address of each of the persons set forth below is in care of Aurora Oil & Gas Corporation, 4110 Copper Ridge Drive, Suite 100, Traverse City, Michigan 49684.
* Less than 1%
(a)
Addresses are only given for holders of more than 5% of outstanding common stock who are not executive officers or directors.
(b)
A person is deemed to be the beneficial owner of a security if such person has or shares the power to vote or direct the voting of such security or the power to dispose or direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities if that person has the right to acquire beneficial ownership within 60 days of the date of this chart.
(c)
Based on Schedule 13D/A filed with the SEC on February 27, 2006, Nathan A. Low has the sole power to vote or direct the vote of, and the sole power to direct the disposition of, the shares held by the Nathan A. Low Roth IRAs and the shares held by him individually. Although Nathan A. Low has no direct voting or dispositive power over the 828,643 shares of common stock held by the Nathan A. Low Family Trust or the 100,000 shares of common stock held in individual trusts for the Neufeld children, he may be deemed to beneficially own those shares because his wife, Lisa Low, is the trustee of the Nathan A. Low Family Trust and custodian for the Neufeld children. Therefore, Nathan A. Low reports shared voting and dispositive power over 928,643 shares of common stock.
(d)
Includes options currently exercisable for 200,000 shares of common stock; 3,272,000 shares of common stock held by the Patricia A. Deneau Trust; 360,146 shares of common stock held by the Denthorn Trust; 20,000 shares of common stock held by White Pine Land Services, Inc.; and 2,668 shares of common stock held by Circle D, Ltd. (shared investment interest). Does not include options to purchase 250,000 shares of common stock vesting as follows: 83,333 shares on May 30, 2009; 83,333 shares on May 30, 2010; and 83,334 shares on May 30, 2011.
(e)
Includes options currently exercisable for 200,000 shares of common stock; 2,750 shares of common stock owned by the Kevin Dale Stulp IRA; and 1,750 shares of common stock owned by the Kevin and Marie Stulp Charitable Remainder Unitrust of which Mr. Stulp is a co-trustee. Does not include options to purchase 100,000 shares of common stock vesting as follows: 33,333 shares on May 30, 2009; 33,333 shares on May 30, 2010; and 33,334 shares on May 30, 2011.
(f)
Includes options currently exercisable for 266,666 shares of common stock. Does not include options to purchase 100,000 shares of common stock vesting as follows: 33,333 on May 30, 2009; 33,333 on May 30, 2010; and 33,334 on May 30, 2011.
(g)
Includes 211,132 shares of common stock held by the Gary J. Myles & Rosemary Myles Inter Vivos Trust and options currently exercisable for 266,666 shares of common stock. Does not include options to purchase 100,000 shares of common stock vesting as follows: 33,333 shares on May 30, 2009; 33,333 shares on May 30, 2010, and 33,334 shares on May 30, 2011.
(h)
Includes options currently exercisable for 200,000 shares of common stock. Does not include options to purchase 100,000 shares of common stock vesting as follows: 33,333 shares on May 30, 2009; 33,333 shares on May 30, 2010; and 33,334 shares on May 30, 2011.
(i)
Includes 2,000 shares of common stock held by his minor son and options currently exercisable for 100,000 shares of common stock. Does not include options to purchase 230,000 shares of common stock vesting as follows: 5,000 shares on May 19, 2009; 75,000 shares on May 30, 2009; 75,000 shares on May 30, 2010; and 75,000 on May 30, 2011.
(j)
Includes options currently exercisable for 140,000 shares of common stock. Does not include options to purchase 100,000 shares of common stock vesting as follows: 33,333 shares on May 30, 2009; 33,333 shares on May 30, 2010; and 33,334 shares on May 30, 2011.
(k)
Includes 12,000 shares held by her spouse and options currently exercisable for 45,000 shares of common stock. Does not include options to purchase 225,000 shares of common stock vesting as follows: 75,000 shares on May 30, 2009; 75,000 shares on May 30, 2010; and 75,000 shares on May 30, 2011.
(l)
Includes 30,000 shares of common stock by Financial Intermediaries, Ltd.; 100,000 shares of common stock owned by the John E. McDevitt IRA.
(m)
Does not include options to purchase 225,000 shares vesting as follows: 75,000 shares on May 30, 2009; 75,000 shares on May 30, 2010; and 75,000 shares on May 30, 2011.
(n)
Includes options currently exercisable for a total of 1,418,332 shares of common stock.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act (“Section 16(a)”) requires certain defined persons to file reports of and changes in beneficial ownership of a security registered with the Securities and Exchange Commission (the “Commission”) in accordance with the rules and regulations promulgated by the Commission to implement the provisions of Section 16. Under the regulatory procedure, officers, directors, and persons who own more than ten percent of a registered class of a company’s equity securities are also required to furnish the Company with copies of all Section 16(a) forms they file.
To the Company’s knowledge, based solely on a review of the copies of Forms 3, 4 and 5, and all amendments thereto, furnished to the Company with respect to its fiscal year ending December 31, 2008, the Company’s officers, directors and greater than 10% beneficial owners complied with all Section 16(a) filing requirements, except as follows: All five non-employee directors filed a late Form 4 for the October 23, 2008 regarding rescission of a prior stock award.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
CERTAIN RELATIONSHIPS OR RELATED TRANSACTIONS
Presidium Energy, LC
AOK Energy LLC Purchase and Sale Agreement
In March 2006, we entered into a joint venture agreement with certain unrelated parties. The joint venture covered the acquisition and development of oil and gas leases in various counties located in Oklahoma. The joint venture project was known as the “Oak Tree Project.” We participated in the joint venture through a wholly owned subsidiary, AOK Energy, LLC (“AOK”). Effective March 28, 2008, we entered into an Agreement for the Purchase and Sale of Limited Liability Company Memberships with Presidium, which is wholly owned and operated by John V. Miller, who served as our Vice President from November 1, 2005, until he resigned on February 29, 2008. Under the terms of the agreement, we would sell to Presidium all of the outstanding member interests in AOK for a purchase price that included the payment by Presidium of certain liabilities that the operator alleged were owed by us to other participants in the joint venture, a cash payment to us in the amount of $10,500,000, and an assignment to us of a 3% overriding royalty in certain leases in the Oak Tree Project.
Effective July 21, 2008, we amended the Purchase and Sale of Limited Liability Company Memberships with Presidium (the “First Amendment”) to extend Presidium’s exclusive right to purchase all of the outstanding member interests in AOK until September 15, 2008. In exchange for the extension, Presidium made a $2.0 million non-refundable payment to us.
Effective September 12, 2008, we amended the Purchase and Sale of Limited Liability Company Memberships with Presidium (the “Second Amendment”) increasing the purchase price to $15,000,000. The Second Amendment also required Presidium to pay us another $1,000,000 in cash and execute a promissory note in the amount of $12,000,000 (“Promissory Note”). In order to induce us to enter into the Second Amendment, Mr. Miller granted us an option to buy up to one million membership units in Presidium for the sum of $0.50 per unit during the period from six months to five years after closing. If the Promissory Note is repaid in full within the first six months after closing, our option to purchase units in Presidium is null and void. The sale of the membership to Presidium closed effective September 15, 2008.
Under the terms of the Promissory Note, Presidium is required to make monthly interest only payments calculated at the lesser of the maximum rate allowed by law or 9.0%. As security for repayment of the Promissory Note, Presidium granted a first priority security interest in all of AOK interests and delivered mortgages on all oil and gas leases Presidium holds or will acquire in the Oak Tree Project. In the event Presidium plans to drill a well in the Oak Tree Project, a principal payment on the Promissory Note equal to the amount of $400 per net acre of leases to be included in the drilling unit must be submitted to us in order for us to subordinate any mortgages held on leases that fall within the drilling unit. Presidium shall be entitled to have outstanding mortgage subordinations for no more than five undrilled well sites at any one time. The entire outstanding principal balance along with all accrued interest is due September 10, 2010. For the year ended December 31, 2008, we recorded $0.3 million of interest income related to the Promissory Note.
Consulting Agreement and Other
Effective May 20, 2008, we entered into a consulting agreement with Presidium in which we agreed to provide Presidium services in connection with certain oil and gas leasing, exploration, development, and business projects. This agreement expired December 31, 2008. For the year ended December 31, 2008, we billed Presidium $0.1 million for services rendered.
In the normal course of business we engage in certain operational transactions with Presidium. For the year ended December 31, 2008, we sold inventory to Presidium in the amount of $0.1 million and billed Presidium for lease bonus extensions in the amount of $0.1 million.
Acadian Energy, LLC
On January 25, 2008, we announced the signing of a non-binding Letter of Intent to acquire Acadian Energy, LLC (“Acadian”). Acadian is jointly owned and operated by John E. McDevitt and Gilbert A. Smith (60% and 40% beneficial ownership, respectively). The Letter of Intent was terminated on October 1, 2008.
Operating Agreements
Subsequent to us executing a Letter of Intent with Acadian on June 24, 2008, we entered into an agreement with Acadian to provide funding to maintain and preserve the value of Acadian’s properties located in the State of Indiana pending our acquisition of Acadian. We agreed to advance approximately $83,000 pursuant to an authority for expenditure to be used for the purpose of bringing wells into compliance with the requirements of the State of Indiana and if practical, into production. We also agreed to pay certain legal expenses on behalf of Acadian in connection with the proposed acquisition of Acadian. The agreement also stated if we did not acquire Acadian or its assets by October 1, 2008, Acadian would be required to reimburse us for the entire amount advanced no later than October 1, 2009.
Effective April 1, 2008, we entered into an agreement with Acadian to provide oil and gas operating services on properties located in the State of Indiana. This agreement expired December 31, 2008. Under the terms of the agreement, we were not entitled to monetary consideration. Services were performed to maintain the value of the properties prior to transfer of ownership from Acadian to us.
For the year ended December 31, 2008, we incurred expenses in the amount of $0.1 million under the operating agreements with Acadian. Due to the termination of the Letter of Intent agreement with Acadian, amounts we incurred on behalf of Acadian in the amount of $0.1 million were reimbursed to us at December 31, 2008, with the exception of $21,899 which has been recorded as a receivable at December 31, 2008.
Simple Financial Solutions, Inc.
Consulting Agreements
Effective January 22, 2008, Barbara E. Lawson was named Chief Financial Officer of the Company. Simple Financial Solutions, Inc., which is owned and operated by Ms. Lawson’s spouse, provides consulting services on a continuous basis including to Bach Services and Manufacturing Co., LLC, one of our subsidiaries. For the year ended December 31, 2008, Simple Financial Solutions, Inc. billed us $0.1 million for services rendered.
Effective May 1, 2008, we entered into a month-to-month agreement with Simple Financial Solutions, Inc. to provide professional services for a subsidiary of the Company, Hudson Pipeline & Processing Co., LLC (“HPPC”). On a monthly basis, Simple Financial Solutions, Inc. will be paid 2% of the gross revenues of HPPC and 3.5% of the net income to HPPC before compensation. Certain revenue resulting from gas transportation will be excluded from the calculations. For the year ended December 31, 2008, we paid $0.1 million for services received from Simple Financial Solutions, Inc. pursuant to this HPPC agreement.
Disposition of Membership Interest
Effective June 28, 2008, Lawson & Kidd, LLC purchased a 2.5% membership interest in HPPC for $0.1 million. Lawson & Kidd, LLC is solely owned by Barbara E. Lawson who is our Chief Financial Officer and Ms. Lawson’s spouse. Lawson & Kidd, LLC’s interest will increase to 5% upon HPPC receiving income equal to 125% of total costs spent on construction of the pipelines owned and operated by HPPC. For the year ended December 31, 2008, we received $0.1 million in capital call contributions from Lawson & Kidd, LLC and paid Lawson & Kidd, LLC total distributions in the amount of $20,002. During March 2009, we repurchased the 2.5% membership interest in HPPC from Lawson & Kidd, LLC for $0.1 million and we are pursuing the repurchase of the remaining outside interest in HPPC.
Other
Consulting Agreements
Effective August 15, 2008, we entered into a consulting agreement with Richard M. Deneau to provide advice and services at an hourly rate of $125 (not to exceed $1,000 per day) in connection with management’s negotiations with our existing bankers and the creation and maintenance of new banking relationships. For the year ended December 31, 2008, we paid $45,500 for consulting services received from Mr. Deneau.
Interests in Certain Properties
Effective May 30, 2007, the Board of Directors named John C. Hunter as Vice President of Exploration and Production. He has worked for us since 2005 as Senior Petroleum Engineer. Prior to that, Mr. Hunter was instrumental in certain projects associated with our New Albany shale play. Over a series of agreements with us, Mr. Hunter (controlling member of Venator Energy, LLC) has acquired 1.25% working interest in certain leases. The leases cover approximately 132,600 acres (1,658 net) in certain counties located in Indiana. The 1.25% carried working interest shall be effective until development costs exceed $30 million. Thereafter, participation may continue as a standard 1.25% working interest owner. We are entitled to recovery of 100% of development costs (plus interest at a rate of 6.75% per annum compounded annually) from 85% of the net operating revenue generated from oil and gas production developed directly or indirectly in the area of mutual interest covered by the agreement. As of December 31, 2008, there is no production associated with this working interest and development costs were approximately $13.3 million.
Effective July 1, 2004, Aurora Energy, Ltd., (“AEL”), entered into a Fee Sharing Agreement with Mr. Hunter as compensation for bringing Bluegrass Energy Enhancement Fund, LLC (“Bluegrass”) and AEL together for the development of the 1500 Antrim and Red Run Projects in Michigan. At this time, AEL (which has since merged into the Company) and Bluegrass have discontinued leasing activities in both projects. In the 1500 Antrim project, there are 23,989.41 acres. Mr. Hunter's carried working interest share of 0.8333% is approximately 199.95 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are no producing wells. The Red Run project contains 12,893.64 acres. Mr. Hunter's carried working interest share of 0.8333% is approximately 107.44 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are 3 wells permitted for the Red Run project and one well was temporarily abandoned.
William Deneau, our CEO, and John Miller, who was an officer during the reporting period, are involved as equity owners in numerous corporations and limited liability companies that are active in the oil and natural gas business. They also own miscellaneous overriding royalty interests in wells in which we have an interest but are operated by unrelated third parties. During 2006, these officers divested themselves of all interests for which we served as operator.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Audit Fees
The aggregate fees billed by Weaver for professional services rendered for the audit of our 2008 financial statements and for review of our quarterly financial statements for fiscal year 2008 were $201,500. The aggregate fees billed by Weaver for professional services rendered for the audit of our 2007 financial statements and for reviews of our quarterly financial statements for fiscal year 2007 included in one post-effective amendment of two different SB-2 registration statements and two different S-3 registration statements were $190,800.
Audit Related Fees
There were no other fees billed by Weaver during the last two fiscal years for assurance and related services that were reasonably related to the performance of the auditor review of our financial statements and not reported under “Audit Fees” above.
Tax Fees
There were no fees billed by Weaver during the last two fiscal years for professional services rendered for tax compliance, tax advice, and tax planning.
All Other Fees
There were no other fees billed by Weaver during 2008.
Audit Committee Process
Our Audit Committee Charter requires our Audit Committee to pre-approve all audit services provided by our independent auditors and all non-audit services provided by our independent auditors that are not eligible for the de minimus exception contained in Section 10A of the Securities Exchange Act of 1934, as amended. Our engagement of Weaver to perform our audit for the fiscal year ending December 31, 2008, was pre-approved by our Audit Committee consistent with the requirements of the Charter.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1)
Financial Statements
The following financial statements are filed as a part of this report:
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firms
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2008, and 2007
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007, and
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2008, 2007, and 2006
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007, and
Notes to Consolidated Financial Statements
(a)(2)
Supplemental Information on Oil and Natural Gas Exploration, Development and Production Activities (unaudited)
(a)(3)
Exhibit Index:
3.1(1)
Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
3.2
By-Laws of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.1
Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on February 2, 2005, and incorporated herein by reference.)
10.2(2)
Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.
10.3
First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to our report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.)
10.4(2)
First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006.
10.5
Amended and Restated Credit Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.7 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.6(2)
Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment.
10.7
Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration Statement filed with the SEC on May 15, 2006 and incorporated herein by reference.)
10.8(1)
Employment Agreement with Ronald E. Huff dated June 19, 2006.
10.9(1)
Letter Agreement with Bach Enterprises dated July 10, 2006. (A redacted copy is filed as an exhibit to Amendment No. 4 to our Form 10`-QSB/A filed on January 30, 2008.)
10.10(1)
First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.
10.11(3)
LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
10.12(3)
Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.
10.13(3)
Form of indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
10.14
Second Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24 to our report on Form 10-KSB for the fiscal year ended December 31, 2006, filed with the SEC on March 15, 2007 and incorporated herein by reference.)
10.15
Third Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25 to our Form 10-Q for the period ended June 30, 2007, filed with the SEC on August 9, 2007 and incorporated herein by reference.)
10.16
Intercreditor Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit 10.26 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.17
Second Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.18
Promissory Note from Aurora Oil & Gas Corporation to Northwestern Bank dated February 14, 2008 (filed as Exhibit 10.18 to our Form 10-K as originally filed with the SEC on March 7, 2008, and incorporated herein by reference).
10.19
Forbearance Agreement and Amendment No. 1 to Credit Agreement dated June 2, 2008, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent for the Lenders, the Lenders and the Secured Swap Providers. (filed as Exhibit 10.19 to our Form 8-K dated June 6, 2008, filed with the SEC on June 12, 2008, and incorporated herein by reference.)
10.20
Forbearance Agreement and Amendment No. 1 to Second Lien Term Loan Agreement dated June 2, 2008, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent for the Lenders, and the Lenders (filed as Exhibit 10.20 to our Form 8-K dated June 6, 2008, filed with the SEC on June 12, 2008, and incorporated herein by reference.)
10.21
Forbearance Agreement dated February 12, 2009, among Aurora Oil & Gas Corporation, as Borrower, BNP Paribas, as Administrative Agent for the Lenders, and the Lenders. (filed as Exhibit 10.21 to our Form 8-K dated February 12, 2009, filed with the SEC on February 18, 2009, and incorporated herein by reference.)
14.1
Code of Conduct and Ethics (updated 2/1/08) (filed as Exhibit 14.1 to our Form 10-K as originally filed with the SEC on March 7, 2008, and incorporated herein by reference).
16.1
Letter concerning change of certifying accountant from Rachlin Cohen & Holtz, LLP (included in Exhibit 23.1)
*21.1
List of Subsidiaries.
*23.1
Consent of Rachlin Cohen & Holtz LLP.
*23.2
Consent of Weaver & Tidwell, L.L.P.
*23.3
Consent of Schlumberger Technology Corporation.
*23.4
Consent of Netherland, Sewell & Associates, Inc.
*31.1
Rule 13a-14(a) Certification of Principal Executive Officer.
*31.2
Rule 13a-14(a) Certification of Principal Financial and Accounting Officer.
*32.1
Section 1350 Certification of Principal Executive Officer.
*32.2
Section 1350 Certification of Principal Financial and Accounting Officer.
(1)
Filed as an exhibit to our Form 10-QSB for the period ended June 30, 2006, filed with the SEC on August 7, 2006, and incorporated herein by reference.
(2)
Filed as an exhibit to our Form 10-KSB for the fiscal year ended December 31, 2005, filed with the SEC on March 31, 2006, and incorporated herein by reference.
(3)
Filed on October 27, 2006, with our Amendment No. 3 to Form SB-2 registration statement filing, registration no. 333-137176, and incorporated herein by reference.
* Filed with this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE
OFFICE
DATE
/s/ William W. Deneau
Chairman, Chief Executive Officer, and
March 13, 2009
William W. Deneau
Director (Principal Executive Officer)
/s/ Barbara E. Lawson
Chief Financial Officer
March 13, 2009
Barbara E. Lawson
(Principal Financial Officer and
Principal Accounting Officer)
/s/ Gilbert A. Smith
President
March 13, 2009
Gilbert A. Smith
/s/ Richard M. Deneau
Director
March 13, 2009
Richard M. Deneau
/s/ Gary J. Myles
Director
March 13, 2009
Gary J. Myles
/s/ Wayne G. Schaeffer
Director
March 13, 2009
Wayne G. Schaeffer
/s/ Kevin D. Stulp
Director
March 13, 2009
Kevin D. Stulp
/s/ Earl V. Young
Director
March 13, 2009
Earl V. Young
/s/ John E. McDevitt
Director
March 13, 2009
John E. McDevitt