Filed Pursuant to Rule 424(b)(3)
Registration No. 333-120659
PROSPECTUS SUPPLEMENT NO. 1,
DATED APRIL 18, 2007
(To Prospectus dated October 11, 2006)
WESTSIDE ENERGY CORPORATION
3131 Turtle Creek Blvd, Suite 1300
Dallas, TX 75219
(214) 522-8990
15,290,205 Shares of Common Stock
-------------------------
This prospectus supplement supplements the prospectus of Westside Energy Corporation (the “Company”) dated October 11, 2006 (the “Prospectus”), and should be read in conjunction with the Prospectus. This prospectus supplement must be delivered with the Prospectus. This prospectus supplement includes the attached Annual Report on Form 10-KSB for the fiscal year ended December 31, 2006 and filed with the U.S. Securities and Exchange Commission on April 17, 2007.
The date of this Prospectus Supplement is April 18, 2007.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934
| For the Fiscal Year Ended December 31, 2006 | Commission File Number 0-49837 |
WESTSIDE ENERGY CORPORATION
(Name of small business issuer in its charter)
Nevada
(State or other jurisdiction of incorporation or organization)
88-0349241
(I.R.S. Employer Identification No.)
3131 Turtle Creek Blvd, Suite 1300
Dallas, TX 75219
214/522-8990
(Address, including zip code, and
telephone number, including area code, of
registrant's principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Name of Each Exchange on which Registered | |
| Common Stock, $0.01 par value | American Stock Exchange |
Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO o
Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES o NO x
The issuer's revenues for the fiscal year ended December 31, 2006 were $3,915,209.
The aggregate market value of the voting stock held by non-affiliates of the registrant on December 31, 2006 was approximately $16,432,063, based on the closing price of such stock on such date. The number of shares outstanding of the registrant's Common Stock, par value $.01 per share, as of April 4, 2007 was 21,458,576.
Transitional Small Business Disclosure format (Check one): YES o NO x
INDEX | ||
Page Number | ||
PART I. | ||
| Items 1. & 2. | 2 | |
| Item 3. | 20 | |
| Item 4. | 20 | |
PART II. | ||
| Item 5. | 20 | |
| Item 6. | 21 | |
| Item 7. | 26 | |
| Item 8. | 26 | |
| Item 8A. | 26 | |
| Item 8B. | 27 | |
PART III. | ||
| Item 9. | 27 | |
| Item 10. | 29 | |
| Item 11. | 32 | |
| Item 12. | 37 | |
| Item 13. | 38 | |
| Item 14. | 40 |
Forward-Looking Statements
This Annual Report on Form 10-KSB contains forward-looking statements within the meaning of Section 24A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements appear in a number of places including “ITEMS 1 AND 2 DESCRIPTION OF BUSINESS AND PROPERTIES." These statements regard:
| * | our belief that our portfolio of large, predominantly undeveloped leasehold interests in the Barnett Shale positions us for significant long-term growth in proved natural gas and oil reserves and production; |
| * | our belief that our remaining undeveloped acreage in the Barnett Shale has substantial current commercial potential, and our plan to exploit that potential through our drilling program; |
| * | our belief that our risk assessments and due diligence reviews are consistent with industry practices; |
| * | our belief that we are well-positioned to pursue selected acquisitions and attract industry joint venture partners due to our asset base and technical expertise; |
| * | our beliefs regarding our key competitive strengths; |
| * | our belief that the current royalty interests, liens and restrictions encumbering our properties do not materially interfere with the use of our properties in the operation of our business; |
| * | our belief that we have satisfactory title to or rights in all of our producing properties; |
| * | our belief that existing regulation or any expected regulatory changes will not affect us in a way that materially differs from the way it will affect our competitors; |
| * | our belief that access to oil and natural gas pipeline services will generally be available to us to the same extent as to our competitors; |
| * | our belief that we are in substantial compliance with current applicable laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations; |
| * | our expectations regarding the increase in our reserves, production and cash flow based on continued drilling success within our acreage position; |
| * | our expectations as to the sources of capital to finance our business and our ability to finance ourselves through any period of time by means of such sources; |
| * | our plan to exploit our properties’ potential through our drilling program, and to pursue further acquisitions of natural gas and oil properties in the Barnett Shale; |
| * | our belief that we will reduce unit costs by greater utilization of our existing infrastructure over a larger number of wells; |
| * | our belief regarding our ability to sell all or most of our production in a manner consistent with industry practices at prevailing rates by means of long-term sales contracts and our ability to find additional sales opportunities; |
| * | our belief regarding compliance with all applicable filing requirements of Section 16(a) of the Securities Exchange Act of 1934; and |
| * | our belief regarding anticipated improved performance of our Audit Committee that would result from a greater number of members serving on such committee. |
Such statements can be identified by the use of forward-looking terminology such as "believes," "expects," "may," "estimates," "will," "should," "plans" or "anticipates" or the negative thereof or other variations thereon or comparable terminology, or by discussions of strategy. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve significant risks and uncertainties, and that actual results could differ materially from those projected in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to, those discussed under "RISK FACTORS" hereinbelow. As a result, these forward-looking statements represent our judgment as of the date of this Annual Report. We do not express any intent or obligation to update these forward-looking statements.
ITEMS 1 and 2. DESCRIPTION OF BUSINESS AND PROPERTIES.
OUR COMPANY
We are an independent natural gas and oil exploration and production company based in Dallas, Texas with operations in the Barnett Shale in the Fort Worth Basin located in north central Texas. We have been successful in identifying and acquiring acreage positions where vertical and horizontal drilling, advanced fracture stimulation and enhanced recovery technologies create the possibility of economically developing and producing natural gas and oil reserves from the Barnett Shale. We have assembled a portfolio of large, predominantly undeveloped leasehold interests in the Barnett Shale, which we believe positions us for significant long-term growth in proved natural gas and oil reserves and production. As of December 31, 2006, we owned natural gas and oil leasehold interests in approximately 76,733 gross (67,184 net) acres, approximately 95% of which are undeveloped. In addition, we own working interests in 44 gross (14.3) net wells in the Barnett Shale.
As of December 31, 2006, we had estimated net proved reserves of 6.7 Bcfe, with a PV-10 value of $9.9 million (calculated using constant prices for natural gas and oil at December 31, 2006). Net proved reserves were 8.9 Bcfe as of March 1, 2007, with a PV-10 value of $16.9 million when calculated using NYMEX forward curve prices on February 28, 2007. We have identified approximately 500 drilling locations on our existing acreage. Our estimated net proved reserves are located on approximately 5% of our net acreage. Based on our drilling results to date and third-party results in adjacent areas, we believe that our remaining undeveloped acreage in the Barnett Shale has substantial commercial potential, and we plan to exploit that potential through our drilling program.
We were incorporated under Nevada law in November 1995 as "Eventemp Corporation," a company related to the automobile industry. Following several years of business inactivity, we entered the natural gas and oil industry in February 2004 and in the following month changed our name to "Westside Energy Corporation."
Our address is 3131 Turtle Creek Blvd., Suite 1300, Dallas, Texas 75219. Our telephone number is (214) 522-8990 and our website address is www.westsideenergy.com.
Certain terms used herein relating to the natural gas and oil industry are defined in "Glossary of Certain Natural Gas and Oil Terms" included as Appendix A hereto.
RISK FACTORS
An investment in shares of our common stock is highly speculative and involves a high degree of risk. You should carefully consider all of the risks discussed below, as well as the other information contained in this Annual Report. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and the trading price of our common stock could decline.
Risks Related to Our Company
We are an early-stage company with limited proved reserves and may not become profitable.
We are an early-stage company, having entered the natural gas and oil industry in February 2004. Although we have acquired leases and undertaken exploratory and other activities on the properties covered by our leases, nearly all of our properties are undeveloped acreage. While we have had exploration success, to date we have established a limited volume of proved reserves on our properties. We have incurred net losses to date and do not expect to generate profits in the short term. To become profitable, we would need to be successful in our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. Unless we sell sufficient volumes of natural gas and oil to cover our expenses, we will not become profitable. Even if we become profitable, we cannot assure you that our profitability will be sustainable or increase on a periodic basis.
Our credit facility, which is secured by a large part of our assets, features limiting operating covenants and requires a substantial future payment, exposes us to certain risks and may adversely affect our ability to operate our business.
During fiscal 2006, we entered into our first credit facility, a $45 million senior secured credit facility provided by GasRock Capital LLC (“GasRock”). During March 2007, we entered into a new loan arrangement to replace the GasRock facility. The new loan arrangement was provided by four private investment funds managed by Wellington Management, LLC, which is the largest beneficial holder of our outstanding common stock. The new loan arrangement:
| * | provided $25 million in funds, which were advanced in their entirety upon completion of the new loan arrangement; |
| * | is secured by a first lien on all of the oil and gas properties comprising our Southeast and Southwest Programs; |
| * | grants to the lenders the right to receive a lien in any and all of the proceeds received upon the sale of a property comprising our North Program or any subsequent property acquired with such proceeds; |
| * | bears annual interest at 10.0%, or (in the case of default) 12.0% annually; |
| * | grants to the lenders a three percent (3.0%) overriding royalty interest (proportionately reduced to our working interest) in all oil and gas produced from the properties now comprising our Southeast and Southwest Programs; |
| * | contains limiting operating covenants; |
| * | contains events of default arising from failure to timely repay principal and interest or comply with certain covenants; and |
| * | requires the repayment of the outstanding balance of the loan in March 2009. |
If we are unable to generate sufficient cash flow from operations, we may have difficulty in paying the outstanding balance of the loan (which could exceed $25 million) in March 2009 when it becomes due. If we were unable to pay this balance at that time, we would be forced to seek an extension to the loan, or alternative debt or equity financing. If we were unable to obtain such an extension or alternative financing, we could default on the loan. If we default on payment or other performance obligations under the loan, the lenders could foreclose on a large part of our assets and exercise other creditor rights, which could result in loss of all or nearly all of the value of our outstanding equity. We may also be required to obtain the lenders’ consent to certain events, such as sales of our assets, and any additional financing, which if secured by our assets would likely need to be junior to our senior lenders’ lien.
Natural gas and oil reserves decline once a property becomes productive, and we may need to find new reserves to sustain revenue growth.
Even if we add natural gas and oil reserves through our exploration activities, our reserves will decline as they are produced. We will be constantly challenged to add new reserves through further exploration or further development of our existing properties. There can be no assurance that our exploration and development activities will be successful in adding new reserves. If we fail to replace reserves, our level of production and cash flows will be adversely impacted.
Our focus on exploration activities exposes us to greater risks than are generally encountered in later-stage natural gas and oil property development businesses.
Much of our current activity involves drilling exploratory test wells on properties with no proved natural gas and oil reserves. While all drilling (whether developmental or exploratory) involves risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of natural gas and oil. The economic success of any project will depend on numerous factors, including the ability to estimate the volumes of recoverable reserves relating to the project, rates of future production, future commodity prices, investment and operating costs and possible environmental liabilities. All of these factors may impact whether a project will generate cash flows sufficient to provide a suitable return on investment. If we experience a series of failed drilling projects, our business, results of operations and financial condition could be materially adversely affected.
We depend on our current management team, the loss of any member of which could delay the further implementation of our business plan or cause business failure. We do not carry key man life insurance and have not required non-competition agreements.
We depend on the services of management to meet our business development objectives. As an early-stage company, we would expect to encounter difficulty replacing any of them. The loss of any person on our management team could materially adversely affect our business and operations. We do not carry key person life insurance for any member of our management team. We have not required that any employee enter into a non-competition agreement.
We may rely on independent experts and technical or operational service providers over whom we may have limited control.
We use independent contractors to assist us in identifying desirable natural gas and oil prospects to acquire and provide us with technical assistance and services. We also may rely upon the services of geologists, geophysicists, chemists, landmen, title attorneys, engineers and scientists to explore and analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. In addition, we intend to rely on the owners and operators of oil rigs and drilling equipment, and on providers of oilfield services, to drill and develop our prospects to production. Moreover, if our properties hold commercial quantities of natural gas and oil, we would need to rely on third-party gathering or pipeline facilities to transport and purchase our production. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.
We do not always undertake a full title review of, or obtain title insurance on, our properties.
Consistent with industry practice, rather than incur the expense of formal title examination on a natural gas or oil property to be placed under lease, we have relied on and plan to continue to rely on the judgment of natural gas and oil lease brokers or landmen who perform the field work in examining government records before placing a mineral interest under lease. Although an operator of a well customarily obtains a preliminary title review to avoid obvious title deficiencies prior to the drilling of a natural gas or oil well, we do not always engage counsel to examine title until just prior to drilling the well. This could result in our having to cure title defects that could affect marketability, which would increase costs. We may conclude from a title examination that a lease was purchased from someone other than the owner, in which case the lease would be worthless to us and prevent us from recovering our expenditures.
Our review of properties cannot assure that all deficiencies or environmental risks may be identified or avoided.
Although we undertake reviews that we believe are consistent with industry practice for our projects, these reviews are often limited in scope and may not reveal all existing or potential problems, or permit us to become sufficiently familiar with the related properties to assess their deficiencies and capabilities. Moreover, we do not perform an inspection on every well, and our inspections may not reveal all structural or environmental problems. Even if our inspections identify problems, the seller or lessor may be unwilling or unable to provide effective contractual protection. We generally do not receive indemnification for environmental liabilities and, accordingly, may have to pursue many projects on an "as is" basis, which could require us to make substantial expenditures to remediate environmental contamination on acquired properties. If a property deficiency or environmental problem cannot be satisfactorily remedied to warrant commencing drilling operations on a property, we could lose our entire investment in the property.
Our properties may be subject to substantial impairment of their recorded value.
The accounting rules for our properties that have proven reserves require us to review periodically their carrying value for possible impairment. If natural gas and oil prices decrease or if the recoverable reserves on a property are revised downward, we may be required to record impairment write-downs, which would result in a negative impact to our financial position. We also may be required to record impairment write-downs for properties lacking economic access to markets and must record impairment write-downs for leases as they expire, both of which could also negatively impact our financial position. We recorded $4.3 million of impairment charges in 2006 to reduce carrying values on developed properties with insufficient reserves to recover all of their remaining book value at constant year-end 2006 natural gas prices that were lower than year-end 2005 prices as well as on undeveloped properties that we expect to allow to expire undeveloped in 2007.
Our recent acquisition of two related natural gas and oil companies could expose us to undisclosed liabilities.
In March 2006, we expanded our base of natural gas and oil producing properties through an acquisition of EBS Oil and Gas Partners Production Company, L.P. and an affiliated operations company that were engaged in the drilling and completion of natural gas and oil wells in Texas. Although we have largely integrated their activities into ours and assessed the quality of their properties, we may encounter risks, and possibly incur remediation costs, from existing or potential problems and liabilities that were not disclosed to us, or unknown to the acquired companies, when the transaction was completed.
We have not insured and cannot fully insure against all risks related to our operations, which could result in substantial claims for which we are underinsured or uninsured.
We have not insured and cannot fully insure against all risks and have not attempted to insure fully against risks where coverage is prohibitively expensive. Losses and liabilities arising from uninsured and underinsured events, which could arise from even one catastrophic accident, could materially and adversely affect our business, results of operations and financial condition. We do not carry business interruption insurance coverage. Our exploration, drilling and other activities are subject to risks such as:
| * | fires and explosions; |
| * | environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination; |
| * | abnormally pressured formations; |
| * | mechanical failures of drilling equipment; |
| * | personal injuries and death, including insufficient worker compensation coverage for third-party contractors who provide drilling services; and |
| * | natural disasters, such as adverse weather conditions. |
Our commodity price risk management program, which is currently required by our senior credit facility, may cause us to forego additional future profits or result in our making cash payments.
To reduce our exposure to changes in the prices of natural gas and oil and to comply with a requirement of the senior secured credit facility that was in effect during most of fiscal 2006, we have entered into, and expect in the future to enter into, commodity price risk management agreements for a portion of our natural gas and oil production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future natural gas and oil production over a fixed period of time. Commodity price risk management agreements expose us to the risk of financial loss and may limit our ability to benefit from increases in natural gas and oil prices in some circumstances, including the following:
| * | the counterparty to the commodity price risk management agreement may default on its contractual obligations to us; |
| * | there may be a change in the expected differential between the underlying price in the commodity price risk management agreement and actual prices received; and |
| * | market prices may exceed the prices which we are contracted to receive, resulting in our need to make significant cash payments. |
Our commodity price risk management activities could have the effect of reducing our future revenues and the value of our common stock.
Operational impediments may hinder our access to natural gas and oil markets or delay our production.
The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. For example, there are no existing pipelines in certain areas where we have acreage. Therefore, if drilling results are positive in these areas, new gathering systems would need to be built to deliver any natural gas and oil to markets. There can be no assurance that we would have sufficient liquidity to build such a system or that third parties would build a system that would allow for the economic development of any such production.
We deliver natural gas and oil through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Our ability to produce and market natural gas and oil is affected and also may be harmed by:
| * | the lack of pipeline transmission facilities or carrying capacity; |
| * | federal and state regulation of natural gas and oil production; and |
| * | federal and state transportation, tax and energy policies. |
Any significant change in our arrangements with gathering system or pipeline owners and operators or other market factors affecting the overall infrastructure facilities servicing our properties could adversely impact our ability to deliver the natural gas and oil we produce to markets in an efficient manner. In some cases, we may be required to shut in wells, at least temporarily, for lack of a market because of the inadequacy or unavailability of transportation facilities. If that were to occur, we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.
We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
A substantial portion of our business activities is conducted through joint operating agreements under which we own partial interests in natural gas and oil properties. We do not operate all of the properties in which we have an interest and in some cases we do not have the ability to remove the operator in the event of poor performance. As a result, we may have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our and the operator's control, including:
| * | timing and amount of capital expenditures; |
| * | expertise and financial resources; and |
| * | inclusion of other participants. |
Unless we generate sufficient revenue, we will require additional capital, which may not be available on favorable terms or at all.
If our cash flows from operations are insufficient to fund our expected capital needs, or our needs are greater than anticipated, we will need to raise additional capital through private or public sales of equity securities or the incurrence of additional indebtedness. Additional funding may not be available on favorable terms or at all. We may be required to raise additional capital to fund our operations for the foreseeable future. If we require but cannot secure outside financing, we could be forced to dispose of certain of our assets or curtail our operations substantially or cease business altogether, which could result in a substantial reduction or elimination of the value of our then-outstanding equity. If we raise additional funds through public or private sales of equity securities, the sales may be at prices below the market price of our stock, and our stockholders may suffer significant dilution.
Our competitors include larger, better financed and more experienced companies.
The natural gas and oil industry is intensely competitive and, as an early-stage company, we must compete against larger companies that may have greater financial and technical resources than we have and substantially more experience in our industry. These competitive advantages may better enable our competitors to sustain the impact of higher exploration and production costs, natural gas and oil price volatility, productivity variances among properties, overall industry cycles and other factors related to our industry. Their advantage may also negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital.
Risks Related to the Natural Gas and Oil Business
Natural gas and oil are commodities subject to price volatility based on many factors outside the control of producers, and low prices may make properties uneconomic for future production.
Natural gas and oil are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for natural gas and oil have been volatile. These markets will likely continue to be volatile in the future. The prices a producer may expect and its level of production depend on numerous factors beyond its control, such as:
| * | changes in global supply and demand for natural gas and oil; |
| * | the actions of the Organization of Petroleum Exporting Countries, or OPEC; |
| * | the price and quantity of imports of foreign natural gas and oil; |
| * | political conditions, including embargoes, in natural gas and oil producing regions; |
| * | the level of global natural gas and oil inventories; |
| * | weather conditions; |
| * | technological advances affecting energy consumption; and |
| * | the price and availability of alternative fuels. |
Lower natural gas and oil prices may not only decrease revenues on a per unit basis, but also may reduce the amount of natural gas and oil that can be economically produced. Lower prices will also negatively impact the value of proved reserves.
Natural gas and oil exploration and production present many risks that are difficult to manage.
Our natural gas and oil exploration, development and production activities are subject to many risks that may be unpredictable and are difficult to manage. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs will be charged against earnings as impairments.
Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plan.
If domestic drilling activity increases, particularly in fields where we operate, a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop. As a result, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. From time to time, these costs have sharply increased and could do so again. The demand for and wage rates of qualified drilling rig crews generally rise in response to the increasing number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which could in turn adversely affect our results of operations.
Conducting operations in the natural gas and oil industry subjects us to complex laws and regulations, including environmental regulations, that can have a material adverse effect on the cost, manner or feasibility of doing business.
Companies that explore for and develop, produce and sell natural gas and oil in the United States are subject to extensive federal, state and local laws and regulations, including complex tax laws and environmental laws and regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements to obtain any permits, may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Compliance costs can be significant. Further, these laws and regulations could change in ways that substantially increase our costs and associated liabilities. We cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. For example, matters subject to regulation and the types of permits required include:
| * | water discharge and disposal permits for drilling operations; |
| * | drilling permits; |
| * | reclamation; |
| * | spacing of wells; |
| * | occupational safety and health; |
| * | air quality, noise levels and related permits; |
| * | rights-of-way and easements; |
| * | calculation and payment of royalties; |
| * | gathering, transportation and marketing of natural gas and oil; |
| * | taxation; and |
| * | waste disposal. |
Under these laws and regulations, we could be liable for:
| * | personal injuries; |
| * | property damage; |
| * | oil spills; |
| * | discharge of hazardous materials; |
| * | remediation and clean-up costs; |
| * | fines and penalties; and |
| * | natural resource damages. |
Risks Related to Our Common Stock
Our management team members beneficially own a significant percentage of our common stock and can substantially influence corporate actions.
As of April 12, 2007, our directors and executive officers own about 14% of our outstanding common stock. Their ownership would increase if they exercise the outstanding warrants they own or are issued incentive shares that we must issue if certain performance benchmarks are reached. As a result, our directors and executive officers are able to substantially influence all matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions, such as a recapitalization or other fundamental corporate action. This concentration of ownership may have the effect of facilitating, delaying or preventing a change in control, which may be to the benefit of our directors and executive officers but not in the best interests of our other stockholders. The concentration of ownership could also significantly reduce the capacity of our stockholders to change the Board of Directors if stockholders are dissatisfied or disagree with the Board's oversight of management’s determination of business policy, or the business decisions of officers who are appointed by the Board. This lack of stockholder control could cause investors to lose all or part of their investment in us.
Provisions in our articles of incorporation, our bylaws and Nevada law may make it more difficult to effect a change in control, which could adversely affect the price of our common stock.
Provisions of our articles of incorporation, our bylaws and Nevada law could make it more difficult for a third party to acquire us, even if doing so would be beneficial to our stockholders. We may issue shares of preferred stock in the future without stockholder approval and upon such terms as our Board of Directors may determine. Our issuance of preferred stock could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, a majority of our outstanding stock and potentially prevent the payment of a premium to our stockholders in an acquisition.
Our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:
| * | providing that special meetings of stockholders may only be called by the Board pursuant to a resolution adopted by: |
| (i) | our President; |
| (ii) | our Chairman, or |
| (iii) | a majority of the members of the Board; |
| * | prohibiting cumulative voting in the election of directors. |
These provisions also could discourage proxy contests and make it more difficult for you and our other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and may limit the price that potential investors are willing to pay in the future for shares of our common stock.
We are also subject to provisions of the Nevada corporation law that prohibit business combinations with persons owning 10% or more of the voting shares of a corporation's outstanding stock, unless the combination is approved by the Board of Directors prior to the person owning 10% or more of the stock, for a period of three years, after which the business combination would be subject to special stockholder approval requirements. This provision could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company or may otherwise discourage a potential acquiror from attempting to obtain control from us, which in turn could have a material adverse effect on the market price of our common stock.
Our common stock has a limited trading history and may experience price volatility.
Our common stock has been trading on the American Stock Exchange since June 2005, before which time our common stock was traded in the over-the-counter market on the OTC Electronic Bulletin Board. The volume of trading in our common stock varies greatly and may often be light, resulting in what is known as a "thinly-traded" stock. Until a larger secondary market for our common stock develops, the price of our common stock may fluctuate substantially. The price of our common stock may also be impacted by any of the following, some of which may have little or no relation to our company or industry:
| * | the breadth of our stockholder base and the extent to which securities professionals follow our common stock; |
| * | investor perception of us and the natural gas and oil industry, including industry trends; |
| * | domestic and international economic and capital market conditions, including fluctuations in commodity prices; |
| * | responses to quarter-to-quarter variations in our results of operations; |
| * | announcements of significant acquisitions, strategic alliances, joint ventures or capital commitments by us or our competitors; |
| * | additions or departures of key personnel; |
| * | sales or purchases of our common stock by large stockholders or our insiders; |
| * | accounting pronouncements or changes in accounting rules that affect our financial reporting; and |
| * | changes in legal and regulatory compliance unrelated to our performance. |
We have not paid cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future.
Under the terms of our outstanding loan arrangement, we may not pay dividends on our common stock. We anticipate that we will retain all future earnings and other cash resources for the operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Payment of future dividends, if any, will be at the discretion of the Board of Directors after taking into account various factors, including our financial condition, results of operations, current and anticipated cash needs and plans for expansion.
BUSINESS AND PROPERTIES
Overview
We are an independent natural gas and oil exploration and production company based in Dallas, Texas with operations in the Barnett Shale in the Fort Worth Basin located in north central Texas. We have been successful in identifying and acquiring acreage positions where vertical and horizontal drilling, advanced fracture stimulation and enhanced recovery technologies create the possibility of economically developing and producing natural gas and oil reserves from the Barnett Shale. We have assembled a portfolio of large, predominantly undeveloped leasehold interests in the Barnett Shale, which we believe positions us for significant long-term growth in proved natural gas and oil reserves and production. As of December 31, 2006, we owned natural gas and oil leasehold interests in approximately 76,733 gross (67,184 net) acres, approximately 95% of which are undeveloped. In addition, we own working interests in 44 gross (14.3) net wells in the Barnett Shale. We were incorporated under Nevada law in November 1995 as "Eventemp Corporation," a company with activities related to the automotive industry. Following several years of business inactivity, we entered the natural gas and oil industry in February 2004 and in the following month changed our name to "Westside Energy Corporation."
The Barnett Shale
The Barnett Shale is one of the largest and most active domestic natural gas plays in the United States. The Barnett Shale formation, which can reach a thickness of up to approximately 1,000 feet, is located at depths of 6,500 to 9,000 feet and covers an area that spans approximately 20 counties in north central Texas. The shale formation is characterized by extremely low permeability requiring hydraulic fracturing to enable economic recovery of natural gas and oil reserves. Technological advances in fracturing techniques and horizontal drilling have allowed natural gas production from the Barnett Shale to grow to over 2.2 Bcf/d from more than 6,000 wells according to the Texas Railroad Commission.
Significant Company Events in 2006
The following is a brief description of our most significant events occurring in 2006:
* | In January, we completed a private placement in which we sold 3,278,000 shares of our common stock, at $3.15 per share, to 27 investors resulting in gross proceeds of approximately $10.3 million and net proceeds of approximately $9.5 million after placement-related costs. |
* | In March, we completed the acquisition of EBS Oil and Gas Partners Production Company, L.P. and an affiliated operations company that were engaged in the drilling and completion of natural gas and oil wells in Texas. |
* | In March, we entered into a $45 million senior secured revolving credit facility with GasRock Capital LLC. During March 2007, we entered into a new $25 million loan arrangement to replace the GasRock facility. The new loan arrangement was provided by four private investment funds managed by Wellington Management, LLC, which is the largest beneficial holder of our outstanding common stock. |
| * | In July, we entered into a joint exploration agreement with Forest Oil Corporation covering approximately 17,200 gross acres in Hill County, Texas. For more information regarding matters occurring as a result of this joint exploration agreement, see the discussion of our Southeast Program below. |
| * | In November, we sold our one-sixth interest in Tri-County Gathering, a pipeline system operated by Cimmarron Gathering, LP for an all-cash purchase price of approximately $5.0 million. |
Our Properties
The table below lists and summarizes our acreage by program as of December 31, 2006. This table excludes acreage in which our interests are limited to royalty and overriding royalty interests.
| Program | Developed Acreage | Undeveloped Acreage | Total Acreage | Weighted Average Remaining Lease Term | ||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||
North | 2,180 | 601 | 6,576 | 3,726 | 8,756 | 4,327 | 1.75 years* | |||||||||||||||
Southeast | ---- | ---- | 15,355 | 10,748 | 15,355 | 10,748 | 2.67 years | |||||||||||||||
Southwest | 640 | 127 | 51,982 | 51,982 | 52,622 | 52,109 | 8.24 years | |||||||||||||||
Total | 2,820 | 728 | 73,913 | 66,456 | 76,783 | 67,184 | ||||||||||||||||
* Certain leases in the North Program area have drilling commitments that, if not met, could result in the loss of undrilled acreage.
North Program
The North Program is located in Cooke, Denton, Montague and Wise Counties in Texas and was the primary focus of our drilling and production activities during 2005 and 2006. This region of the Barnett Shale (our North Program area) is defined by the following characteristics:
| · | Our Operated Wells: | 35 gross /approximately 12 net completed 4 gross / 2 net drilling and completing | |
| · | Our Non-Operated Wells: | 8 gross / approximately 1 net completed well (excludes overriding royalty interest wells) | |
| · | Barnett Thickness: | 1,000 feet | |
| · | Drilling Depth: | 7,500 to 9,000 feet | |
| · | Drilling Method: | Vertical and horizontal | |
| · | Production Characteristics: | High Btu natural gas and associated liquids | |
| · | Fracture Stimulation: | 3 to 5 stage, medium volume | |
| · | Key Considerations: | Lower risk drilling, multiple pay zones, high liquid content, operations in high Btu conditions and access to equipment and services |
Southeast Program
The Southeast Program is located in Hill and Ellis Counties in Texas. During fiscal 2005, we completed the processing of a three-dimensional seismic survey of 4.3 square miles that includes property leased by us in northern Hill County (the “Survey”). Based on the Survey, we selected our first site for drilling on the property. During fiscal 2006, we entered into a joint exploration agreement with Forest Oil Corporation covering approximately 17,200 gross acres in Hill County, Texas. The agreement provides that we and Forest Oil will each assign a 50% interest in certain properties to each other. During February 2007, we completed our first well in Hill County, the Primula #1H well. This well tested at a gross initial rate of 2.1 million cubic feet per day from its 1,600' productive horizontal section. The original well design included a 2,400' productive horizontal section, which was reduced due to unsatisfactory rig performance. We believe that the additional length would have enhanced the resulting test rate. We recently finished drilling our second well in Hill County, the Ellison Estate #1H. We plan to fracture stimulate the approximately 2,300' horizontal section of this well in early May 2007. The next well to be drilled is the Primula #2H. Our 2007 budget is primarily focused on activities in Hill County and includes funds to drill 8 gross (3.5 net) wells plus acquire additional acreage and seismic data. The Hill and Ellis Counties region of the Barnett Shale (our Southeast Program area) is defined by the following characteristics:
| · | Our Operated Wells: | 1 gross / 0.5 net drilling and completing | |
| · | Barnett Thickness: | 200 to 400 feet | |
| · | Drilling Depth: | 7,000 to 9,000 feet | |
| · | Drilling Method: | Horizontal | |
| · | Production Characteristics: | Natural gas | |
| · | Fracture Stimulation: | 4 to 6 stage, high volume | |
| · | Key Considerations: | Lower risk drilling, contiguous shale completion, three-dimensional seismic control, cost control and infrastructure access |
Southwest Program
The Southwest Program is located in Comanche, Coryell, Hamilton, Mills and Lampasas Counties in Texas. Drilling in this area by others has been primarily vertical, although horizontal drilling technology has recently been utilized. The terms of the leases covering this area expire sufficiently far enough into the future (especially considering renewal options in our favor) that we are not constrained to drill in this area in the near future. This region of the Barnett Shale (our Southwest Program area) is defined by the following characteristics:
| · | Barnett Thickness: | 130 to 220 feet | |
| · | Drilling Depth: | 3,000 to 4,000 feet | |
| · | Drilling Method: | Vertical and horizontal | |
| · | Production Characteristics: | Natural gas and oil | |
| · | Fracture Stimulation: | 6 to 8 stage, low volume | |
| · | Key Considerations: | Multiple pay zones, expansion area with limited production, associated water production and infrastructure access |
Our Business Strategy
Our goal is to increase shareholder value by finding and developing natural gas and oil reserves at costs that provide an attractive rate of return on our investments. The principal elements of our business strategy are:
| * | Develop Our Existing Properties. We intend to create near-term reserve and production growth from numerous drilling locations identified on our Barnett Shale acreage. The structure and the continuous natural gas and oil accumulation of the Barnett Shale and the expected long-life production and reserves of these properties enhance our opportunities for long-term profitability. |
| * | Pursue Selective Acquisitions and Joint Ventures. Due to our asset base and technical expertise, we believe we are well-positioned to pursue selected acquisitions and attract industry joint venture partners. We expect to pursue additional natural gas and oil properties in the Barnett Shale. |
| * | Reduce Unit Costs Through Economies of Scale and Efficient Operations. As we continue to increase our natural gas and oil production and develop our existing properties, we expect that our unit cost structure will benefit from economies of scale. With respect to our operations in the Barnett Shale, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells. We seek to exert control over costs and timing in our exploration, development and production activities through our operating activities and relationships with our joint venture partners. |
Our Competitive Strengths
We believe that the key competitive strengths of our company include:
| * | Significant Production Growth Opportunities. We have acquired a large acreage position with very favorable lease terms in a region where drilling and production activities by other exploration and production companies continue to increase. Based on continued drilling success within our acreage position, we expect to increase our reserves, production and cash flow. |
| * | Experienced Management Team with Strong Technical Capability. Our senior management team and Board of Directors have considerable public company experience, industry experience and technical expertise in engineering, geoscience and field operations, with an average of more than 20 years of experience in the natural gas and oil industry. Our in-house technical personnel have extensive experience in the Barnett Shale, including horizontal drilling, completion and fracture stimulation techniques and technologies. |
| * | Incentivized Management Ownership. The equity ownership of our directors and executive officers is strongly aligned with that of our stockholders. As of April 12, 2007, our directors and executive officers owned approximately 14% of our outstanding common stock. In addition, the compensation arrangements for our directors and executive officers are heavily weighted toward future performance based equity payments rather than cash. |
Drilling Activity
The following table sets forth the results of our drilling activities during the fiscal years ended December 31, 2005 and 2006:
| Drilling Activity | |||||||||||||||||||
| Gross Wells | Net Wells | ||||||||||||||||||
| Year | Total | Producing | Dry | Total | Producing | Dry | |||||||||||||
| 2005 Exploratory | 5.0 | 5.0 | -- | 2.9 | 2.9 | -- | |||||||||||||
| 2006 Exploratory | 5.0 | 5.0 | -- | 2.8 | 2.8 | -- | |||||||||||||
| 2005 Development | 1.0 | 1.0 | -- | 0.5 | 0.5 | -- | |||||||||||||
| 2006 Development | 4.0 | 4.0 | -- | 2.0 | 2.0 | -- | |||||||||||||
Production Information
Net Production, Average Sales Price and Average Production Costs (Lifting)
The table below sets forth the net quantities of oil and gas production (net of all royalties, overriding royalties and production due to others) attributable to us for the fiscal years ended December 31, 2005 and 2006, and the average sales prices, average production costs and direct lifting costs per unit of production.
Years Ended December 31, | |||||||
2005 | 2006 | ||||||
Net Production | |||||||
| Oil (MBbls) | 4 | 23 | |||||
| Gas (MMcf) | 47 | 360 | |||||
Average Sales Prices | |||||||
| Oil (per Bbl) | $ | 57.94 | $ | 61.93 | |||
| Gas (per Mcf) | $ | 7.35 | $ | 5.92 | |||
Average Production Cost (1) | |||||||
| Per equivalent (Bbl of oil) | $ | 33.35 | $ | 84.92 | |||
Average Lifting Costs (2) | |||||||
| Per equivalent (Bbl of oil) | $ | 9.00 | $ | 21.43 | |||
(1) Production costs include all operating expenses, depreciation, depletion and amortization, lease operating expenses and all associated taxes. Does not include impairment.
(2) Direct lifting costs do not include impairment expense or depreciation, depletion and amortization.
Productive Wells and Acreage
Gross and Net Productive Gas Wells, Developed Acres, and Overriding Royalty Interests
Leasehold Interests - Productive Wells and Developed Acres: The tables below sets forth our leasehold interests in productive and shut-in gas wells, and in developed acres, at December 31, 2006:
Producing and Shut-In | |||||||
Prospect | Gross Gas | Net(1) Gas | |||||
| Barnett Shale | 44 | 14.3 | |||||
| (1) | A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. |
Developed Acreage Table Developed Acres (1) | |||||||
Prospect | Gross (2) | Net (3) | |||||
| Barnett Shale | 2,820 | 728 | |||||
| (1) | Consists of acres spaced or assignable to productive wells. |
| (2) | A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. |
| (3) | A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. |
Undeveloped Acreage
Leasehold Interests Undeveloped Acreage: The following table sets forth our leasehold interest in undeveloped acreage at December 31, 2006:
Undeveloped Acreage Table | |||||||
Prospect | Gross | Net | |||||
| Barnett Shale | 73,913 | 66,456 | |||||
Gas Delivery Commitments
None.
Drilling Commitments
We have an approved drilling budget of $12 million authorizing new projects for the period January 1, 2007 through December 31, 2007.
Reserve Information - Oil and Gas Reserves:
LaRoche Petroleum Consultants, Ltd. evaluated our oil and gas reserves attributable to our properties at December 31, 2006. Reserve calculations by independent petroleum engineers involve the estimation of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Those estimates are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of proved reserves and future net revenues therefrom are affected by oil and gas prices, which have fluctuated widely in recent years. Moreover, these estimates are based on numerous factors, many of which are variable, uncertain and beyond the control of the producer. Reserve estimators are required to make numerous, subjective judgments based upon professional training, experience and educational background. As a result, estimates of different engineers, including those used by us, may vary. The extent and significance of the judgments are sufficient to render reserve estimates inherently imprecise, since reserve revenues and operating expenses may not occur as estimated. Moreover, it is common for the actual production and revenues later received to vary from earlier estimates. Estimates made in the first few years of production from a property are generally not as reliable as later estimates based on a longer production history. Reserve estimates based upon volumetric analysis are inherently less reliable than those based on lengthy production history. Also, potentially productive gas wells may not generate revenue immediately due to lack of pipeline connections and potential development wells may have to be abandoned due to unsuccessful completion activities. Hence, reserve estimates may vary from year to year. Based on the preceding, the reserve data set forth in this Annual Report must be viewed only as estimates and not as exact information.
Estimated Proved/Developed and Undeveloped Reserves: The following tables set forth our estimated proved developed and proved undeveloped oil and gas reserves for the years ended December 31, 2005 and 2006. See Note 14 to the Consolidated Financial Statements and the above discussion.
Developed and Undeveloped Reserves | ||||||||||
Developed | Undeveloped | Total | ||||||||
| Oil (Bbls) | ||||||||||
| December 31, 2005 | 85,206 | 11,200 | 96,406 | |||||||
| December 31, 2006 | 85,385 | 64,230 | 149,615 | |||||||
| Gas (Mcf) | ||||||||||
| December 31, 2005 | 1,191,699 | 272,000 | 1,463,699 | |||||||
| December 31, 2006 | 3,277,562 | 2,557,473 | 5,835,035 | |||||||
For information concerning the standardized measure of discounted future net cash flows, estimated future net cash flows and present values of such cash flows attributable to our proved oil and gas reserves as well as other reserve information, see Note 14 to the Consolidated Financial Statements.
Oil and Gas Reserves Reported to Other Agencies: We did not file any estimates of total proved net oil or gas reserves with, or include such information in reports to, any federal authority or agency since the beginning of the fiscal year ended December 31, 2006.
Title to Properties
Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements and liens for current taxes and other burdens, including mineral encumbrances and restrictions. Our current loan arrangement is also secured by a first lien on a large part of our assets. We do not believe that any of these burdens materially interferes with the use of our properties in the operation of our business.
We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the natural gas and oil industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel or have title reviewed by certified landmen only when we acquire producing properties or before we begin drilling operations.
Sale of Natural Gas and Oil
We do not intend to refine our natural gas or oil production. We expect to sell all or most of our production to a small number of purchasers in a manner consistent with industry practices at prevailing rates by means of long-term sales contracts. We are developing a market with purchasers such as end-users, local distribution companies, and natural gas brokers. We have several long-term purchase contracts, and can readily find other purchasers, if needed. In areas where there is no practical access to pipelines, oil is trucked to storage facilities.
Markets and Marketing
The natural gas and oil industry has experienced rising prices in recent years. As a commodity, global natural gas and oil prices respond to macro-economic factors affecting supply and demand. In particular, world oil prices have risen in response to political unrest and supply uncertainty in Iraq, Venezuela, Nigeria and Iran, and increasing demand for energy in rapidly growing economies, notably India and China. Due to rising world prices and the consequential impact on supply, North American prospects have become more attractive. Escalating conflicts in the Middle East and the ability of OPEC to control supply and pricing are some of the factors negatively impacting the availability of global supply. In contrast, increased costs of steel and other products used to construct drilling rigs and pipeline infrastructure, as well as higher drilling and well-servicing rig rates, negatively impact domestic supply.
Our market is affected by many factors beyond our control, such as the availability of other domestic production, commodity prices, the proximity and capacity of natural gas and oil pipelines, and general fluctuations of global and domestic supply and demand. Although we have entered into few sales contracts at this time, we do not anticipate difficulty in finding additional sales opportunities.
Natural gas and oil sales prices are negotiated based on factors such as the spot price for gas or posted price for oil, price regulations, regional price variations, distances from wells to pipelines, well pressure, and estimated reserves. Many of these factors are outside our control. Natural gas and oil prices have historically experienced high volatility, related in part to ever-changing perceptions within the industry of future supply and demand.
Competition
The natural gas and oil industry is intensely competitive and, as an early-stage company, we must compete against larger companies that may have greater financial and technical resources than we and substantially more experience in our industry. These competitive advantages may better enable our competitors to sustain the impact of higher exploration and production costs, natural gas and oil price volatility, productivity variances between properties, overall industry cycles and other factors related to our industry. Their advantage may also negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital.
Governmental Regulation
Natural Gas and Oil Regulation
Regulation of Transportation and Sale of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the Federal Energy Regulatory Commission, or FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act generally removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
Since the mid-1980s, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines' traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage services on an open access basis to others who buy and sell natural gas. Although the FERC's orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 changed FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. We cannot accurately predict whether the FERC's actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
Intrastate natural gas transportation and gathering of natural gas is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and gathering and the degree of regulatory oversight and scrutiny given to intrastate natural gas transportation and gathering rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all shippers on intrastate natural gas pipelines and gatherers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation and gathering in any state in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.
Regulation of Transportation and Sale of Oil. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact (or, in some cases, reenact) price controls in the future.
Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, a common carrier must offer the same terms and rates to all similarly-situated shippers requesting service. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services will generally be available to us to the same extent as to our competitors.
Environmental Regulation
We are subject to stringent federal, state and local laws, that, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous government departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations.
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third-party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.
The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, or RCRA, regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as "hazardous waste." Disposal of such non-hazardous natural gas and oil exploration, development and production wastes usually is regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of "hazardous wastes," thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.
Our operations are also subject to the Clean Air Act, or CAA, and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.
The Federal Water Pollution Control Act of 1972, as amended, or the Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Cost may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In Texas, no underground injection may take place except as authorized by permit or rule.
Statutes that provide protection to animal and plant species and that may apply to our operations include the National Environmental Policy Act, the Oil Pollution Act, the Emergency Planning and Community Right-to-Know Act, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.
Employees
As of April 12, 2007, we had seven full-time employees.
Facilities
Our principal executive offices are located in Dallas, Texas, where we lease approximately 5,000 square feet. This lease terminates in the first quarter of 2008.
ITEM 3. LEGAL PROCEEDINGS
We are not now a party to any material legal proceeding. In the future, we may become involved in various legal proceedings from time to time, either as a plaintiff or as a defendant, and either in or outside the normal course of business. We are not now in a position to determine when (if ever) such a legal proceeding may arise. If we ever become involved in a legal proceeding, our financial condition, operations, or cash flows could be materially and adversely affected, depending on the facts and circumstances relating to such proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Our common stock is listed and trades on the American Stock Exchange under the symbol “WHT.” As of April 4, 2007, we had 198 holders of record. Management believes that we have closer to 1,000 beneficial holders of our stock, although the exact number of these holders cannot be determined. The following table sets forth the high and low reported closing prices for our common stock for the completed quarters over the past two fiscal years. Such quotations represent inter-dealer prices, without retail markup, markdown or commission, and do not necessarily represent the prices of actual transactions for the fiscal quarters indicated.
HIGH | LOW | ||||||
2006 | |||||||
| Fourth Quarter | $ | 2.45 | $ | 1.05 | |||
| Third Quarter | 3.18 | 2.30 | |||||
| Second Quarter | 3.80 | 2.38 | |||||
| First Quarter | 3.98 | 2.94 | |||||
2005 | |||||||
| Fourth Quarter | $ | 4.30 | $ | 3.30 | |||
| Third Quarter | 4.10 | 3.35 | |||||
| Second Quarter | 4.65 | 3.53 | |||||
| First Quarter | 5.50 | 3.05 | |||||
We have never paid cash dividends, and have no intentions of paying cash dividends in the foreseeable future.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report. In addition to historical information, the discussion in this report contains forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those anticipated by these forward-looking statements due to factors including, but not limited to, those factors set forth under "Risk Factors" and elsewhere in this Annual Report.
Overview
We are an independent natural gas and oil exploration and production company based in Dallas, Texas with operations in the Barnett Shale in the Fort Worth Basin located in north central Texas. We have been successful in identifying and acquiring acreage positions where vertical and horizontal drilling, advanced fracture stimulation and enhanced recovery technologies create the possibility of economically developing and producing natural gas and oil reserves from the Barnett Shale. We have assembled a portfolio of large, predominantly undeveloped leasehold interests in the Barnett Shale, which we believe positions us for significant long-term growth in proved natural gas and oil reserves and production. As of December 31, 2006, we owned natural gas and oil leasehold interests in approximately 76,733 gross (67,184 net) acres, approximately 95% of which are undeveloped. In addition, as of December 31, 2006, we owned working interests in 44 gross (14.3) net wells in the Barnett Shale.
As of December 31, 2006, we had estimated net proved reserves of 6.7 Bcfe, with a PV-10 value of $9.9 million (calculated using constant prices for natural gas and oil at December 31, 2006). Net proved reserves were 8.9 Bcfe as of March 1, 2007, with a PV-10 value of $16.9 million when calculated using NYMEX forward curve prices on February 28, 2007. We have identified approximately 500 drilling locations on our existing acreage. Our estimated net proved reserves are located on approximately 5% of our net acreage. Based on our drilling results to date and third-party results in adjacent areas, we believe that our remaining undeveloped acreage in the Barnett Shale has substantial current commercial potential, and we plan to exploit that potential through our drilling program.
Recent Developments
During the first few months of 2007, we have been active in both the initiation of our Hill County development activities and the continued development of our North Program area. In Hill County, we completed our first horizontal well, the Primula No. 1H, which came on at an initial rate in excess of 2.1 MMcfd. We recently finished drilling and casing our second well, the Ellison Estate #1H. We have scheduled the fracture stimulation of the approximately2,300’ horizontal section of this well for early May 2007. The drilling rig will be moved to our next location, the Primula #2H, and an additional drilling location is being prepared. With our new funding in place, we are now able to commit to a longer-term contract for a rig and consequently have obtained the services of an excellent rig and crew to carry out our drilling plans for the rest of the year. This, in conjunction with turning over the drilling portion of the operation to Forest Oil, our fifty percent partner, should help to eliminate the poor drilling performance we experienced on the Primula No. 1H as a result of one-off rigs and third party drilling contractors. The plans for the future locations will include drilling lateral sections in the 2,500 to 3,000 foot range. Although pleased with the Primula No. 1H results, we believe that future wells could produce at higher levels due to having longer lateral lengths and greater exposure to the fracture system. In addition to the drilling activity, we continue to work our land base in the area to high grade our position and ensure the maximum number of additional locations.
In our North Program area, we have been active both drilling new wells and completing those drilled prior to 2007. We have finished drilling our Fortenberry No. 1H horizontal well in the area and recently completed and fracture stimulated the well. It will flow back frac fluid over the next few weeks followed by both oil and gas production into sales. A vertical well, the Hawk Littel No. 1, was drilled in 2005 by the former operator EBS and was recently tied into the gas sales line in order that it could be completed. Since then, it has been fracture stimulated and is waiting on a pump to begin unloading frac fluid. In addition, we have farmed out three additional horizontal locations, to an operator that is active in the area, which will be drilled in 2007. One has completed drilling operations and is waiting on completion and the other two will be drilled over the next few months. Finally, the Smith No. 2 vertical well will be tied into the main gas pipeline allowing us to complete it in the next couple of months.
Although some of this activity has been delayed due to rig issues and pipeline infrastructure delays, the current activity should bring on sufficient production to offset the natural declines from our activity in 2006 and allow for additional production growth in 2007.
Critical Accounting Policies and Estimates
Our discussion of our financial condition and results of operations is based on the information reported in our financial statements. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 1 to our financial statements included in this Annual Report. We have outlined below certain of these policies that have particular importance to the reporting of our financial condition and results of operations and that require the application of significant judgment by our management.
Key Definitions
Proved reserves, as defined by the SEC, are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Valuations include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Prices do not include the effect of derivative instruments, if any, entered into by us.
Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods. Additional oil and gas volumes expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing of a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves are those reserves that are expected to be recovered from new wells on non-drilled acreage, or from existing wells where a relatively major expenditure is required for re-completion. Reserves on non-drilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other non-drilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.
Estimation of Reserves
Volumes of reserves are estimates that, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. There are numerous uncertainties in estimating crude oil and natural gas reserve quantities, projecting future production rates and projecting the timing of future development expenditures. Natural gas and oil reserve engineering must be recognized as a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. Estimates of independent engineers that we use may differ from those of other engineers. The accuracy of any reserve estimate is a function of the quantity and quality of available data and of engineering and geological interpretation and judgment. Accordingly, future estimates are subject to change as additional information becomes available.
Revenue Recognition
We record natural gas and oil revenues using the entitlement method of accounting for production, in which any excess amount received by us above our share of production is treated as a liability. If we receive less than our share of production, the underproduction is recorded as an asset. We did not have an imbalance position relative to volumes or values at December 31, 2006.
Successful Efforts Accounting
We utilize the successful efforts method to account for our natural gas and oil operations. Under this method, all costs associated with natural gas and oil lease acquisitions, successful exploratory wells and all development wells are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves on a lease basis. Unproved leasehold costs are capitalized pending the results of exploration efforts. Exploration costs, including geological and geophysical expenses, exploratory dry holes and delay rentals, are expensed when incurred.
Impairment of Properties
We review our proved properties for potential impairment at the lease level when management determines that events or circumstances indicate that the recorded carrying value of any of the properties may not be recoverable. Such events include a projection of future natural gas and oil reserves that will be produced from a lease, the timing of this future production, future costs to produce the natural gas and oil, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, we recognize impairment expense equal to the difference between the carrying value and the fair market value of the asset, which is estimated to be the expected present value of future net cash flows from proved reserves, without the application of any estimate of risk. We cannot predict the amount of impairment charges that may be recorded in the future. Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired.
Stock-Based Compensation
Compensation expense has been recorded for common stock grants based on the fair value of the common stock on the measurement date. Statement of Financial Accounting Standards No. 123R, "Share-Based Payments," or "SFAS No. 123R," establishes standards for accounting for transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires that the fair value of such equity instruments be recognized as expense in the historical financial statements as services are performed. SFAS No. 123R was effective for us as of the beginning of 2006 and has had no impact on our financial statements, because the only equity compensation that we have previously made is in the form of grants of common stock, which are recorded at fair value.
Results of Operations - Year ended December 31, 2006 compared to the year ended December 31, 2005
Financial results for the year ended December 31, 2006 are not directly comparable to financial results for the year ended December 31, 2005. During 2005, we had limited operations consisting of our first two operated wells (the Lucille Pruett #1 and #2H), two wells operated by EBS (the Kirby #1 and Mitchell #1) and three marginal non-operated wells that were sold in the fourth quarter of 2005. In the first quarter of 2006, we greatly expanded our operations as a result of acquiring EBS in March 2006. Other significant activities that increased operations in 2006 included drilling and completing two additional wells on the Lucille Pruett lease (the Lucille Pruett #3 and #4), drilling and/or completing several additional wells on acreage acquired in the EBS acquisition and commencing drilling operations on our first well in Hill County (the Primula #1H).
Revenues. Revenues from sales of oil and natural gas were $3,915,209 in 2006 as compared to $595,657 in 2005. This increase in revenues reflects the impact of higher sales volumes for both oil and gas and higher oil sales prices. Oil sales volumes increased from an average of 12 to 63 barrels per day, and average oil sales prices increased from $57.94 to $61.93 per barrel. Natural gas sales volumes increased from an average of 128 to 988 thousand cubic feet (MCF) per day while average natural gas sales prices decreased from $7.35 to $5.92 per MCF. Both oil and natural gas sales volume growth resulted from additional well interests acquired in the EBS transaction plus additional wells drilled in 2006. New wells that contributed significantly to this production increase include the Christian #1A and Lucille Pruett #4. The decrease in natural gas prices resulted from historically above average prices in 2005, reflecting the price impact of two severe hurricanes, followed by declining prices in 2006 resulting from a mild winter and below average hurricane activity.
Expenses. Operating expenses increased from $3,231,656 in 2005 to $17,096,540 in 2006. This significant increase reflects the impact of owning interests in a larger number of properties and wells that produced significantly higher volumes and adding staff and services to support this increased activity.
* Production expense was $1,779,192 in 2006 as compared to $108,227 in 2005 reflecting increased production operations activity associated with the well count and produced volumes increases as well as higher oil and gas severance taxes due to both higher volumes and higher oil prices.
* Exploration expense was $360,170 in 2005 reflecting the costs incurred for the three-dimensional seismic acquisition program conducted in Hill County. No exploration expense was incurred in 2006.
* General and Administrative expenses increased from $1,782,184 in 2005 to $5,296,723 in 2006. Approximately 40% of this increase was the result of non-cash stock compensation expense recorded in 2006. The remainder of the increase reflects salaries for additional staff and additional overhead costs resulting from a substantial increase in business support activities as a result of drilling and operating substantially more wells in 2006.
* Depreciation, Depletion and Amortization expenses were $5,710,295 in 2006 versus $344,797 in 2005 reflecting higher produced volumes plus higher property carrying values as a result of additional drilling activities and the EBS acquisition transaction.
* Impairment charges of $636,278 were taken against three producing leases in 2005. In 2006, impairment charges of $4,085,234 were taken against twelve producing leases and $225,096 against undeveloped leases. Impairment tests are conducted on a lease-by-lease basis.
Operating Loss. As a result of the above described revenues and expenses, we incurred an operating loss in 2006 of $13,181,331 as compared to an operating loss of $2,635,999 in 2005.
Other Income (Expense). Other expense of $730,581 in 2006 included $956,000 of interest expense partially offset by $225,619 of interest income. Other income of $696,677 in 2005 included $359,490 of interest income and $339,355 of gain from the sale of our interest in three marginal wells and 467 undeveloped acres. Interest income decreased in 2006 due to lower average cash balances and interest expense increased significantly as a result of three cash draws against the GasRock Credit Facility commencing in March 2006.
Net Loss. We incurred a net loss of $13,911,912, or $.66 per share, for the year ended December 31, 2006 as compared to a net loss of $1,939,322, or $.11 per share, for the year ended December 31, 2005.
Liquidity and Capital Resources
Sales of Equity. In January 2006, we completed a private placement in which we sold 3,278,000 shares of our common stock, at $3.15 per share, to 27 investors resulting in gross proceeds of approximately $10.3 million and net proceeds of approximately $9.5 million after placement-related costs. In May through July 2006, we raised approximately $1.3 million from the sale of approximately 290,000 shares issued upon exercise of warrants by 16 warrant holders at $2.50 per share and the sale of approximately 180,000 shares to two of our executives at $3.15 per share..
Cash and Cash Equivalents. As of December 31, 2006, we had cash, cash equivalents and marketable securities of approximately $5.5 million, representing an increase of $3.8 million from December 31, 2005.
Hedging. Under our senior secured credit facility that was in effect during most of fiscal 2006, we were required to hedge a substantial portion of our reserves. As of December 31, 2006, we had entered into swap contracts covering 75% of our projected production through March 2008 from our proved developed producing reserves estimated as of December 31, 2005 based on a report prepared by LaRoche Petroleum Consultants, Ltd., a third-party engineering firm. The prices stated in the swap contracts were $8.05 per MMBtu for natural gas and $66.15 per barrel for oil. In the first quarter of 2007, we added additional gas hedges, extending from February 2007 to December 2008. The price in these swap contracts was $7.45 per MMBtu of natural gas.
Senior Secured Financing. In March 2006, we entered into a $45 million senior secured revolving credit facility with GasRock Capital LLC (“GasRock”). In connection with our acquisition of EBS Oil and Gas Partners Production Company L.P. and its affiliated operations company, we borrowed approximately $5.3 million under the GasRock credit facility for payments at closing, approximately $1.6 million to discharge certain of the acquired companies' indebtedness, and amounts for reimbursement of costs related to previous drilling and future development drilling. Subsequently, we borrowed an additional amount of approximately $10 million under the GasRock credit facility. During March 2007, we entered into a new loan arrangement to replace the GasRock facility, which was paid off and terminated. The new loan arrangement was provided by four private investment funds managed by Wellington Management, LLC, which is the largest beneficial holder of our outstanding common stock. The new loan arrangement:
| * | provided $25 million in funds, which were advanced in their entirety upon completion of the new loan arrangement; |
| * | is secured by a first lien on all of the oil and gas properties comprising our Southeast and Southwest Programs; |
| * | grants to the lenders the right to receive a lien in any and all of the proceeds received upon the sale of a property comprising our North Program or any subsequent property acquired with such proceeds; |
| * | bears annual interest at 10.0%, or (in the case of default) 12.0% annually; |
| * | grants to the lenders a three percent (3.0%) overriding royalty interest (proportionately reduced to our working interest) in all oil and gas produced from the properties now comprising our Southeast and Southwest Programs; |
| * | contains limiting operating covenants; |
| * | contains events of default arising from failure to timely repay principal and interest or comply with certain covenants; and |
| * | requires the repayment of the outstanding balance of the loan in March 2009. |
We continually evaluate our capital needs and compare them to our capital resources. Our budgeted project expenditures for 2007 are approximately $15.0 million and are to be used primarily for drilling and development of our properties. We expect to fund these expenditures from available cash and revenue generated during 2007 and, if necessary, from additional borrowings. The level of project expenditures is largely discretionary and the amount of funds devoted to any activity may increase or decrease depending on available opportunities, commodity prices, cash flows, development results and other considerations.
We believe that our available cash will be sufficient to enable us to pursue our business plans for the next 12 months.
ITEM 7. FINANCIAL STATEMENTS.
The report of our Independent Auditors appears at Page F-1 hereof, and our Financial Statements appear at Page F-2 through F-20 hereof.
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not applicable.
ITEM 8A. CONTROLS AND PROCEDURES.
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure based closely on the definition of "disclosure controls and procedures" in Rule 13a-14(c). In designing and evaluating the disclosure controls and procedures, management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures..
We conducted an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 as amended (the "Exchange Act")). Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of the end of the fiscal year covered by this Annual Report on Form 10-KSB were effective at a reasonable assurance level to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Our internal controls over financial reporting (as defined in Rule 13a-15(f) or Rule 15d-15(f) under the Exchange Act) have improved significantly during the last 21 months. The improvements include the expansion of the Board of Director's on March 31, 2005 to include three independent directors, each of whom was appointed a member of the Audit Committee, and the addition to staff of a Chief Financial Officer /Principal Accounting Officer and a Controller. Systems improvements include the installation of a more robust accounting system specifically designed to meet the needs of an oil and gas company. The Audit Committee members were actively involved in reviews of the financial statements for each of the quarters in 2005 and in 2006. The Chairman of the Audit Committee met with our independent auditors in May 2005, and the independent auditors met with the full Audit Committee on March 29, 2006. The addition of a Chief Financial Officer has allowed us to enhance controls over the authorization, recording, processing and reporting of transactions. Additional accounting staff, including a Controller, joined us as a result of the EBS transaction, enhancing our ability to segregate duties and improve internal controls. Management does not expect that our controls and procedures will prevent or detect all errors or fraud. Any control system, no matter how well designed and operated, is based upon certain assumptions and can provide only reasonable, but not absolute, assurance that its objectives will be met. Further, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur.
There have been no significant changes in our internal controls or in other factors that could significantly affect the internal controls subsequent to the date that we completed our evaluation.
ITEM 8B. OTHER INFORMATION
Not applicable.
PART III.
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS, CONTROL PERSONS AND CORPORATE GOVERNANCE; COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
DIRECTORS AND OFFICERS
Our Board of Directors has five members. Each director serves a one-year term that expires at the following annual meeting of stockholders. Executive officers are appointed by the Board of Directors and serve until their successors are appointed. There are no family relationships among our directors or executive officers.
The members of the Audit Committee of our Board of Directors are Herbert C. Williamson, Keith D. Spickelmier and John T. Raymond. Our Board of Directors has determined that each member of this committee qualifies as an “audit committee financial expert,” as defined by SEC rules.
Our directors, executive officers and control persons are listed below with information about their respective backgrounds:
| Name | Age | Positions | ||
| Keith D. Spickelmier | 45 | Chairman of the Board | ||
| Douglas G. Manner | 51 | Chief Executive Officer, President, Chief Operating Officer and Director | ||
| Sean J. Austin | 54 | Vice President and Chief Financial Officer | ||
| Craig S. Glick | 47 | Director | ||
| John T. Raymond | 36 | Director | ||
| Herbert C. Williamson | 58 | Director |
______________________
The backgrounds of our directors, executive officers and control persons are as follows:
Keith D. Spickelmier - Chairman of the Board. Mr. Spickelmier is a Director and has served as Chairman of the Board since May 2002, and was President, Treasurer and Secretary until February 2004. Prior to joining Westside Energy, he was a partner with the law firm Verner, Liipfert, Bernhard, McPherson and Hand. From April 2001 through July 2003, Mr. Spickelmier was of counsel with the law firm Haynes and Boone, LLP. Mr. Spickelmier holds a B.A. from the University of Nebraska at Kearney and a J.D. from the University of Houston. Mr. Spickelmier is also a Director of JK Acquisition Corp.
Douglas G. Manner - Chief Executive Officer, President, Chief Operating Officer and Director. Mr. Manner has been a Director since March 2005. In June 2006 became our Chief Executive Officer, and in April 2007 he became our President and resumed his former duties as Chief Operating Officer. >From January 2006 to May 2006, he was our Chief Operating Officer. From January 2004 to December 2005, Mr. Manner was Senior Vice President and Chief Operating Officer of Kosmos Energy, LLC, a private energy company engaged in oil and gas exploration offshore West Africa. From August 2002 through December 2003, he was President and Chief Operating Officer of White Stone Energy, LLC, a Houston-based oil and gas advisory firm. From May 2001 to June 2002, Mr. Manner was Chairman and Chief Executive Officer of Mission Resources Corporation, a Houston-based oil and gas exploration company. He was Chief Executive Officer and President of Bellwether Exploration, a Houston-based oil and gas exploration company, from June 2000 until May 2001 and became its Chairman of the Board in December 2000. From July 1998 until May 2000, Mr. Manner was Vice President and Chief Operating Officer of Gulf Canada Resources Limited. Mr. Manner began his career with Amoco Petroleum Company in 1977, and from 1981 to 1998, was a reservoir engineering consultant with Ryder Scott Petroleum Engineers, an international reservoir engineering firm. Mr. Manner received a B.S. in mechanical engineering from Rice University in 1977, and is a professional engineer certified by the Texas Board of Professional Engineers and a member of the Society of Petroleum Engineers. Mr. Manner was previously a member of the Board of Directors of Gulf Midstream Service, ROC Oil and Petrovera Energy Company and is currently a member of the Board of Directors of Cordero Energy Inc., Irvine Energy PLC, and Rio Vista Energy Partners, L.P.
Sean J. Austin - Vice President and Chief Financial Officer. Mr. Austin became our Chief Financial Officer in June 2006 and, since May 2005, has served as our Vice President and Corporate Controller. Prior to joining us, he was employed by Hess Corporation (formerly known as Amerada Hess) for 23 years, holding senior management positions in the company’s New York and Houston offices. From 1995 to 1999, he was Vice President and Corporate Controller in the New York office of Hess and, from 1999 until 2004, was Vice President of Finance and Administration, Exploration and Production in the Houston office of Hess. Mr. Austin served as an officer in the United States Navy from 1974 to 1979. Mr. Austin received a B.B.A. in accounting from the University of Notre Dame and an M.B.A. from the Amos Tuck School of Business at Dartmouth College.
Craig S. Glick - Director. Mr. Glick has been a Director since January 2006. Since November 2006, Mr. Glick has served as Managing Director and General Counsel of NGP Midstream & Resources. From August 2006 to November 2006, he served as our Executive Vice President and General Counsel. Mr. Glick co-founded Kosmos Energy, LLC in 2003 and was a partner at Kosmos Energy. From 1999 to 2003, he was President of Hunt Resources, Inc. and Senior Vice President of Hunt Oil Company. Mr. Glick was General Counsel and Chief Financial Officer of Gulf Canada Resources Ltd. from 1994 to 1999. Mr. Glick was in charge of acquisitions for Torch Energy Advisers in 1994. Previously, Mr. Glick was an attorney with Vinson & Elkins, LLP, where he became a partner in 1993. Mr. Glick received a B.A. in political science from Tulane University and holds a J.D. from the University of Texas School of Law.
John T. Raymond - Director. Mr. Raymond became a Director in March 2005 and is Chairman of the Nominating Committee of the Board of Directors. He has been a Director of Vulcan Energy Corporation since July 2004 and was its Chief Executive Officer from July 2004 to April 2005. From December 2002 to March 2004, he was President and Chief Operating Officer of Plains Exploration and Production Company. From June 2001 to April 2005, Mr. Raymond was a Director of Plains All American Pipeline, LP. He was Executive Vice President and Chief Operating Officer of Plains Resources Inc. from May 2001 to November 2001 and its President and Chief Operating Officer from November 2001 to April 2005. From January 2000 to May 2001, he was Director of Corporate Development for Kinder Morgan, Inc. He was Vice President of Corporate Development for Ocean Energy, Inc. from April 1998 to January 2000 and was a Vice President with Howard Weil Labouisse Friedrichs, Inc. from 1992 to April 1998. He currently manages various investments through Lynx Holdings, a company he owns. Mr. Raymond received a B.A. in management from the A.B. Freeman School of Business at Tulane University.
Herbert C. Williamson - Director. Mr. Williamson became a Director in March 2005 and is Chairman of the Audit and Compensation Committees of the Board of Directors. From September 2000 through March 2003, he was a Director of Southwest Royalties, Inc. and chaired the independent directors committee for its acquisition by Clayton Williams Energy. From April 1997 to February 2002, Mr. Williamson was a Director of Pure Resources, Inc. and its predecessor, and served as Chairman of the special committee in connection with the tender offer for Pure Resources made by Unocal. Mr. Williamson was an investment banker with Petrie Parkman & Company from 1995 through May 1999, was Chief Financial Officer for Seven Seas Petroleum Incorporated from October 1998 to April 1999 and was Vice Chairman and Executive Vice President for Parker & Parsley Petroleum Company (now Pioneer Natural Resources Company) from April 1985 to April 1995. Since November 2002, Mr. Williamson has served as a Director in the energy group at CS First Boston, and is currently a Director of JK Acquisition Corp. Since 1996, Mr. Williamson has been a Director of Merlon Petroleum Company, a privately owned oil and gas company engaged in the exploration and production of oil reserves in East Texas and Egypt, where for a period he was also its Chief Financial Officer. He has over 30 years of experience in the oil and gas industry and investment banking business. Mr. Williamson holds a B.A. from Ohio Wesleyan University and an M.B.A. from Harvard University.
CODE OF ETHICS
On March 31, 2004, we adopted a Code of Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, as well as others working on our behalf. The Code of Ethics is posted on our website, and anyone can obtain a copy of the Code of Ethics by contacting us at the following address: 3131 Turtle Creek Blvd, Suite 1300, Dallas, Texas 75219, attention: Chief Executive Officer, telephone: (214) 522-8990. The first such copy will be provided without charge. We will post on our website any amendments to the Code of Ethics, as well as any waivers that are required to be disclosed by the rules of either the Securities and Exchange Commission or the National Association of Securities Dealers.
SECTION 16(A) OF THE EXCHANGE ACT
Section 16(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), requires that our officers and directors, and persons who own more than ten percent of a registered class of our equity securities, file reports of ownership and changes in ownership with the Securities and Exchange Commission and furnish us with copies of all such Section 16(a) forms. Each of Keith D. Spickelmier, Chairman of our Board of Directors, and Westside Resources, L.P. (formerly known as Westside Energy, L.P.), which is wholly-owned by Jimmy D. Wright, formerly a Director and President and Chief Operating Officer, filed several weeks late a Form 4 regarding their separate exercises of warrants to purchase 37,500 shares each, for an aggregate of 75,000 shares. We believe that, during fiscal 2005, each of our officers, directors and greater than ten percent stockholders otherwise complied with all applicable filing requirements of Section 16(a).
ITEM 10. EXECUTIVE COMPENSATION.
Summary Compensation Table
The following table sets forth the compensation we paid during the fiscal years ended December 31, 2006 and 2005 to our executive officers whose total compensation exceeded $100,000. For the purpose of this Annual Report, the executive officers listed in the table below are referred to as the “Named Executive Officers.”
SUMMARY COMPENSATION TABLE (1)
Name and principal position (a) | Year (b) | Salary ($) (c) | Bonus ($) (d) | Stock Awards ($) (e) | Total ($) (j) | |||||||||||
Douglas G. Manner, Chief Executive Officer (2) | 2006 | $ | 175,000 | $ | 262,500(3) | $ | 525,000(4) | $ | 962,500 | |||||||
| Jimmy D. Wright, | 2005 | $ | 150,000 | 0 | 0 | $ | 150,000 | |||||||||
| President & Chief Operating Officer (5) | 2006 | $ | 163,123 | 0 | 0 | $ | 163,123 | |||||||||
| Sean J. Austin, | 2006 | $ | 154,500 | 0 | 0 | $ | 154,500 | |||||||||
Vice President & Chief Financial Officer | 2005 (6) | $ | 92,167 | $ | 20,000(7) | $ | 80,000(8) | $ | 192,167 | |||||||
| (1) | The Columns designated by the Securities and Exchange Commission for the reporting of certain option awards, non-equity incentive plan compensation, nonqualified deferred compensation earnings or all other compensation have been eliminated as no such awards, compensation or earnings were made to, earned by, or paid to or with respect to any person named in the table during any fiscal year covered by the table. |
| (2) | Mr. Manner assumed the office of Chief Executive Officer effective June 1, 2006. Prior to that time, he had served as Chief Operating Officer since January 1, 2006. |
| (3) | Represents 75,000 shares granted as an employment sign-on bonus and valued at $3.50 per share based on the closing price of our stock just prior to the date of grant. |
| (4) | Represents 150,000 restricted shares valued at $3.50 per share based on the closing price of our stock on the date of grant, 75,000 of which have not vested. Based on the $1.45 value per share of our common stock at the close of our last fiscal year, the value of Mr. Manner’s 150,000 restricted shares was $217,500 on December 31, 2006. |
| (5) | Mr. Wright served as Chief Executive Officer throughout all of fiscal 2005 and from January 1, 2006 until June 1, 2006. Effective June 1, 2006, he began serving as Chief Operating Officer. Mr. Wright served as President throughout all of fiscal 2005 and fiscal 2006. Mr. Wright resigned from all of his offices with us in April 2007. |
| (6) | Mr. Austin’s employment began in May 2005. |
| (7) | Represents 5,000 shares granted as an employment sign-on bonus and valued at $4.00 per share based on the closing price of our stock just prior to the date of grant. |
| (8) | Represents 20,000 restricted shares valued at $4.00 per share based on the closing price of our stock on the date of grant, 10,000 of which have not vested. Based on the $1.45 value per share of our common stock at the close of our last fiscal year, the value of Mr. Austin’s 20,000 restricted shares was $29,000 on December 31, 2006. |
Outstanding Equity Awards
The table below set forth information pertaining to outstanding stock awards granted to the Named Executive Officers as of December 31, 2006. No options of any kind have been granted; accordingly, the Columns designated by the Securities and Exchange Commission for the reporting of certain option awards, non-equity incentive plan compensation, nonqualified deferred compensation earnings or all other compensation have been eliminated.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
STOCK AWARDS
Name (a) | Number of Shares or Units of Stock That Have Not Vested (#) (g) | Market Value of Shares or Units of Stock That Have Not Vested ($) (h) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (i) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (#) (j) | |||||||||
Douglas G. Manner, Chief Executive Officer | 150,000 (1) | $ | 217,500 (2) | 600,000 | $ | 870,000 (2) | |||||||
Sean J. Austin, Vice President & Chief Financial Officer | 10,000 | $ | 14,500 (2) | 120,000 | $ | 174,000 (2) | |||||||
| (1) | Of these shares, 75,000 vested on January 1, 2007. |
| (2) | Based on the $1.45 per-share market price of our common stock at the close of our last fiscal year |
Compensation Agreements with Key Personnel
We have a two-year employment agreement with Douglas G. Manner, our Chief Executive Officer, President and Chief Operating Officer, that became effective on January 1, 2006 and may be terminated before January 1, 2008 upon a change of control of the company. The agreement (as amended) currently provides for an annual salary of $275,000 and a sign-on bonus payable in our shares, the number of which, up to a maximum of 225,000 shares (and subject to vesting by thirds), equals 150% of the number of our shares that he purchased from us in cash before June 1, 2006. Mr. Manner timely purchased 150,000 shares and, accordingly, one-third or 75,000 of the bonus shares immediately vested, 75,000 of which vested on January 1, 2007, and 75,000 of the bonus shares are deemed restricted shares and shall vest on January 1, 2008 if he is then employed by us. The agreement also provides for grants of incentive shares in increments of 100,000 shares of our common stock (for a total of 600,000 shares) each time that the 30-day trailing average of our stock’s closing price equals or exceeds in succession $5.00, $6.00, $7.00, $8.00, $9.00 and $10.00 for the first time. If a change of control of the company occurs, Mr. Manner has the right to terminate his employment, in which case (or upon termination by us) Mr. Manner’s right to all of the remaining incentive shares shall immediately vest. Provided he meets eligibility criteria, Mr. Manner may also participate in any employee benefit plans that we have or later establish for our employees.
We have an employment agreement, effective as of May 4, 2005, with Sean J. Austin, our Chief Financial Officer. Mr. Austin’s employment agreement does not have a stated term. His agreement (as amended) currently provides for an annual salary of $200,000, subject to annual review, and a grant of 25,000 shares of our common stock, 5,000 of which vested on signing, 10,000 of which vested on May 4, 2006 and 10,000 of which are deemed restricted shares and shall vest on May 4, 2007 if he is then employed by us. The agreement also provides for grants of incentive shares in increments of 20,000 shares of our common stock (for a total of 120,000 shares) each time that the 30-day trailing average of our common stock’s closing price equals or exceeds in succession $5.00, $6.00, $7.00, $8.00, $9.00 and $10.00 for the first time. If a change of control of the company occurs, Mr. Austin has the right to terminate his employment, in which case (or upon termination by us) Mr. Austin’s right to all of the remaining incentive shares shall immediately vest. Provided he meets eligibility criteria, Mr. Austin may also participate in any employee benefit plans that we have or later establish for our employees.
Director Compensation
Each member of our Board of Directors who is not employed by us receives an annual fee of $7,500 for service on the Board and $1,000 for each meeting attended. In lieu of any cash or equity compensation, we pay the Chairman of the Board a $6,000 monthly fee for his services. We pay the Chairman of the Audit Committee of the Board an additional $3,750 annually for service as committee chair, and we pay $1,875 annually to each other member of this committee. We pay the Chairman of the Compensation Committee an annual fee of $2,500 for service as chair of this committee. We also reimburse our non-employee directors for their reasonable expenses to attend Board and committee meetings.
Each non-employee director, other than the Chairman, is eligible for awards of our common stock under our 2005 Director Stock Plan. We award each non-employee director 12,666 shares of our common stock when he or she first becomes a director. The initial award is comprised of 4,222 unrestricted shares and 8,444 restricted shares of our common, one-half of which will vest, if the director is then a member of the Board, on each of the first and second anniversaries of the award date. We also award each non-employee director 2,650 shares of our common stock for annual service on the Board, of which 884 shares are unrestricted, and 1,766 are restricted, one-half of which will vest, if the director is then a member of the Board, on the first and second anniversaries of the award date.
The following table sets forth the compensation we paid during the fiscal year ended December 31, 2006 to our directors.
DIRECTOR COMPENSATION (1)
Name (a) | Fees Earned or Paid in Cash ($) (b) | Stock Awards ($) (c) | Total ($) (j) | |||||||
| Keith D. Spickelmier | $ | 72,000 | -0- | $ | 72,000 | |||||
| Craig S. Glick | $ | 16,250 | $ | 47,497 (2 | ) | $ | 63,747 | |||
| John T. Raymond | $ | 17,875 | $ | 9,355 (3 | ) | $ | 27,230 | |||
| Herbert C. Williamson | $ | 16,375 | $ | 9,355 (3 | ) | $ | 25,730 | |||
| (1) | The Columns designated by the Securities and Exchange Commission for the reporting of certain option awards, non-equity incentive plan compensation, nonqualified deferred compensation earnings or all other compensation have been eliminated as no such awards, compensation or earnings were made to, earned by, or paid to or with respect to any person named in the table during fiscal 2006. |
| (2) | Represents the aggregate grant date fair value of 12,666 shares, computed in accordance with FAS 123R. As of December 31, 2006, Mr. Glick had been granted an aggregate of 12,666 shares for his services as a director. |
| (3) | Represents the aggregate grant date fair value of 2,650 shares, computed in accordance with FAS 123R. As of December 31, 2006, each of Messrs. Raymond and Williamson had been granted an aggregate of 15,316 shares for their services as directors. |
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table sets forth, as of April 5, 2007, the number of shares of our common stock beneficially owned by (i) each director and each executive officer; (ii) each person known to us to own beneficially more than 5% of the outstanding shares of our common stock; and (iii) all directors and executive officers as a group. Unless otherwise indicated, each person has sole voting and dispositive power over such shares. Shares not outstanding but deemed beneficially owned by virtue of the right of a person or member of a group to acquire them within 60 days of April 5, 2007 are treated as outstanding only for determination of the amount and percent owned by such group or person. Unless otherwise indicated, the address for each person named in the table is care of our company, 3131 Turtle Creek Boulevard, Suite 1300, Dallas, Texas 75219.
Shares of Common Stock Beneficially Owned | |||||||
Name and Address of Beneficial Owner | |||||||
Directors and Executive Officers | Number | Percent | |||||
| Keith D. Spickelmier | 2,626,443 (1) | 12.1 | % | ||||
| Douglas G. Manner | 437,666 | 2.0 | % | ||||
| John T. Raymond | 65,316 | * | |||||
| Herbert C. Williamson | 15,316 | * | |||||
| Craig S. Glick | 42,666 | * | |||||
| Sean J. Austin | 54,972 | * | |||||
| All directors and executive officers as a group (6 persons) | 3,242,379 (2) | 14.9 | % | ||||
Non-management 5% Stockholders | |||||||
| Wellington Management Company, LLP | 3,971,380(3) | 18.5 | % | ||||
| Jimmy D. Wright | 3,435,693(4) | 15.8 | % | ||||
| Westside Resources, L.P. | 3,435,693(5) | 15.8 | % | ||||
| Spindrift Investors (Bermuda) L.P. | 1,616,480(6) | 7.5 | % | ||||
| Spindrift Partners, L.P. | 1,376,200(7) | 6.4 | % | ||||
| Dynamis Advisors, LLC | 1,788,480(8) | 8.3 | % | ||||
| Dynamis Fund, LP | 1,451,921(8) | 6.8 | % | ||||
_______________________________________
* Represents less than one percent.
(1) | Includes 2,360,051 shares held directly and 266,392 shares underlying currently exercisable warrants. Excludes 95,000 shares held by his wife and 70,300 shares held by two family trusts as to which Mr. Spickelmier disclaims ownership. |
(2) | Includes 266,392 shares underlying currently exercisable warrants |
(3) | Wellington Management, LLC, or WML, in its capacity as investment adviser to Spindrift Partners, L.P., Spindrift Investors (Bermuda) L.P. and Wellington Trust Company, NA may be deemed to beneficially own an aggregate of 3,971,380 shares, which are held of record by such clients. The address for WML is 75 State Street, Boston, Massachusetts 02109. . |
(4) | Represents shares held by Westside Resources, L.P., which is controlled by Mr. Wright who has sole voting and investment power over these shares. |
(5) | Includes 3,182,085 shares held directly and indirectly and 253,608 shares underlying currently exercisable warrants. Jimmy D. Wright has sole voting and investment power over these shares. |
(6) | Wellington Hedge Management, LLC, or WHML, is the sole general partner of Spindrift Partners, L.P. and Wellington Hedge Management, Inc., or WHMI, is the managing member of WHML. Each of WHML and WHMI share voting and dispositive power over the shares held by Spindrift Partners, L.P. The address for each of Spindrift Partners, L.P., WHML, and WHMI is c/o Wellington Management, LLC, 75 State Street, Boston, Massachusetts 02109. |
(7) | Wellington Global Holdings, Ltd. is the investment general partner of Spindrift Investors (Bermuda) L.P., and has the power to vote and dispose of the shares held by Spindrift Investors (Bermuda) L.P. The address for each of Spindrift Investors (Bermuda) L.P. and Wellington Global Holdings, Ltd. is c/o Wellington Management, LLC, 75 State Street, Boston, Massachusetts 02109. |
| (8) | Dynamis Advisors, LLC is the general partner of Dynamis Fund, LP and thus has voting power and shared investment power over the 1,451,921 shares owned by Dynamis Fund, LP. Dynamis Advisors, LLC is also the investment advisor of Dynamis Energy Fund Ltd and thus has voting power and shared investment power over the 296,559 shares owned by Dynamis Energy Fund Ltd. We have been advised that Alex Bocock, Frederic Bocock and John H. Bocock have shared voting power and shared investment power over these shares. Frederic S. Bocock, a Member/General Partner and control person of Dynamis Advisors, LLC, owns outright 40,000 of the shares disclosed in the table as being beneficially owned by Dynamis Advisors, LLC. He has sole voting power and sole investment power over these 40,000 shares. The address for each of Dynamis Advisors, LLC and Dynamis Fund, LP is 310 Fourth Street NE, Suite 101, Charlottesville, Virginia 22902. |
EQUITY COMPENSATION PLANS
We have two equity compensation plans for our directors and consultants pursuant to which options, rights or shares may be granted or issued. These plans include our 2004 Consultant Compensation Plan (the “Consultant Plan”) and our 2005 Director Stock Plan (the “Director Plan”). In accordance with requirements of the U.S. Securities and Exchange Commission, further information on the material terms of the Consultant Compensation is given below.
The following table provides information as of December 31, 2006 with respect to our compensation plans (including individual compensation arrangements), under which securities are authorized for issuance aggregated as to (i) compensation plans previously approved by stockholders, and (ii) compensation plans not previously approved by stockholders:
Equity Compensation Plan Information
Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options,warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||||
Plan category | (a) | (b) | (c) | |||||||
| Equity compensation plans approved by security holders | -0- | -0- | -0- | |||||||
| Equity compensation plans not approved by security holders | -0- | -0- | 3,035,875 | |||||||
Total | -0- | -0- | 3,035,875 (1) | |||||||
| (1) | Of these shares, 2,591,839 shares and 444,036 shares remain available for issuance under our 2004 Consultant Compensation Plan and our 2005 Director Stock Plan, respectively. |
Our 2004 Consultant Compensation Plan
The following is a description of the material features of the Consultant Plan
General. On April 14, 2004, our Board of Directors approved the Consultant Plan. The Consultant Plan provides for the grant of shares of our Common Stock to certain outside consultants of ours who assist in the development and success of our business to reward them for their services and to encourage them to continue to provide services to us.
Administration. Our Board of Directors administers the Consultant Plan.
Eligibility. The Board of Directors has substantial discretion pursuant to the Consultant Plan to determine the persons to whom shares of Common Stock are awarded and the amounts and restrictions imposed in connection therewith. Under the Consultant Plan, awards may be made only to individuals who are outside consultants, or directors, officers, partners or employees of outside consultants, of us or a subsidiary. The number of consultants employed by us varies.
Shares Subject to the Consultant Plan. Three million (3,000,000) shares of Common Stock are authorized to be awarded pursuant to the Consultant Plan, 500,000 of which were registered with the Securities and Exchange Commission. Any shares awarded and later forfeited are again subject to award or sale under the Consultant Plan. Awards may be made pursuant to the Consultant Plan until no further shares are available for issuance or until April 15, 2014, whichever occurs first.
Previous Awards. We have awarded 408,161 shares of Common Stock pursuant to the Consultant Plan as of December 31, 2006.
Restrictions. The Board may, in its discretion, place restrictions and conditions in connection with any particular award of shares pursuant to the Consultant Plan. Shares awarded subject to a condition are, in general, non-assignable until the condition is satisfied.
Anti-dilution. The Consultant Plan carries certain anti-dilution provisions concerning stock dividends, stock splits, consolidations, mergers, recapitalizations and reorganizations.
Amendment and Termination. Our Board of Directors may terminate or amend the Consultant Plan in any respect at any time, except no action of our Board of Directors, or our stockholders, may, without the consent of a participant, alter or impair such participant's rights under any restricted shares previously granted.
Term. The Consultant Plan shall expire on April 15, 2014 unless sooner terminated except as to restricted share grants outstanding on that date.
Federal Income Tax Consequences. The following brief summary of the principal Federal income tax consequences of transactions under the Consultant Plan is based on current Federal income tax laws. This summary is not intended to constitute tax advice and, among other things, does not address possible state or local tax consequences. Accordingly, a participant in the Consultant Plan should consult a tax advisor with respect to the tax aspects of transactions under the Consultant Plan.
Unrestricted Stock Grants. The tax consequences of unrestricted stock awards will depend on the specific terms of each award.
Restricted Stock Grants. Upon receipt of restricted stock, a participant generally will recognize taxable ordinary income when the shares cease to be subject to restrictions in an amount equal to the fair market value of the shares at such time. However, no later than 30 days after a participant receives the restricted stock, the participant may elect to recognize taxable ordinary income in an amount equal to the fair market value of the shares at the time of receipt. Provided that the election is made in a timely manner, when the restrictions on the shares lapse, the participant will not recognize any additional income. If the participant forfeits the shares to us (e.g., upon the participant's termination prior to expiration of the restriction period), the participant may not claim a deduction with respect to the income recognized as a result of the election. Dividends paid with respect to shares of restricted stock generally will be taxable as ordinary income to the participant at the time the dividends are received.
Tax Consequences to Us. We generally will be entitled to a deduction at the same time and in the same amount as a participant recognizes ordinary income, subject to the limitations imposed under Section 162(m).
Tax Withholding. We have the right to deduct withholding taxes from any payments made pursuant to the Consultant Plan or to make such other provisions as it deems necessary or appropriate to satisfy our obligations to withhold federal, state or local income or other taxes incurred by reason of payment or the issuance of Common Stock under the Consultant Plan or the lapse of restrictions on grants upon which restrictions have been placed.
Our 2005 Director Stock Plan
The following is a description of the material features of the Director Plan.
General. Effective March 30, 2005, our Board of Directors adopted the Director Plan. The Director Plan provides for the grant of shares of our Common Stock to non-employee members of the Board of Directors to provide them with incentives to work hard for our success.
Administration. Our Board of Directors administers the Director Plan.
Eligibility. Under the Director Plan, awards may be made only to members of our Board of Directors who are not employees of us or any of our affiliates (“Non-Employee Directors”).
Shares Subject to the Director Plan. Five hundred thousand (500,000) shares of Common Stock are authorized to be awarded pursuant to the Director Plan. Awards may be made pursuant to the Director Plan until no further shares are available for issuance or until March 30, 2015, whichever occurs first.
Awards. Each Non-Employee Director receives an award of 12,666 shares of Common Stock when he or she first becomes a director. Of these shares, 4,222 are unrestricted, and the remaining 8,444 shares are restricted, with one-half of them vesting one year after the award and with one-half of them vesting two years after the award, provided, in both cases, that the related person is still a director of ours on the vesting dates. In addition to the initial grant, each Non-Employee Director receives an annual award of 2,650 shares of our Common Stock. Of these shares, 884 are unrestricted, and the remaining 1,766 are restricted, with one-half of them vesting one year after the award and with one-half of them vesting two years after the award, provided, in both cases, that the related person is still a director of ours on the vesting dates. We have awarded 55,964 shares of Common Stock pursuant to the Director Plan as of December 31, 2006.
Restrictions. The restricted shares comprising a grant are non-assignable until such shares are vested and no longer subject to forfeiture.
Anti-dilution. The Director Plan carries certain anti-dilution provisions concerning stock dividends, stock splits, consolidations, mergers, recapitalizations and reorganizations.
Amendment and Termination. Our Board of Directors may terminate or amend the Director Plan in any respect at any time, provided that no alteration or amendment may be made without the approval of stockholders if such approval is required by applicable law or stock exchange rule.
Term. The Director Plan shall expire on March 30, 2015 unless sooner terminated except as to restricted share grants outstanding on that date.
Federal Income Tax Consequences. The following brief summary of the principal Federal income tax consequences of transactions under the Director Plan is based on current Federal income tax laws. This summary is not intended to constitute tax advice and, among other things, does not address possible state or local tax consequences. Accordingly, a participant in the Director Plan should consult a tax advisor with respect to the tax aspects of transactions under the Director Plan.
Unrestricted Stock Grants. The tax consequences of the unrestricted shares comprising a grant will depend on the specific terms of each award.
Restricted Stock Grants. With regard to the restricted shares, a participant generally will recognize taxable ordinary income when the shares cease to be subject to restrictions in an amount equal to the fair market value of the shares at such time. However, no later than 30 days after a participant receives the restricted shares, the participant may elect to recognize taxable ordinary income in an amount equal to the fair market value of the shares at the time of receipt. Provided that the election is made in a timely manner, when the restrictions on the shares lapse, the participant will not recognize any additional income. If the participant forfeits the shares (e.g., upon the participant's termination prior to expiration of the restriction period), the participant may not claim a deduction with respect to the income recognized as a result of the election. Dividends paid with respect to shares of restricted shares generally will be taxable as ordinary income to the participant at the time the dividends are received.
Tax Consequences to Us. We generally will be entitled to a deduction at the same time and in the same amount as a participant recognizes ordinary income, subject to the limitations imposed under Section 162(m).
Tax Withholding. We have the right to deduct withholding taxes from any payments made pursuant to the Director Plan or to make such other provisions as it deems necessary or appropriate to satisfy our obligations to withhold federal, state or local income or other taxes incurred by reason of payment or the issuance of Common Stock under the Director Plan or the lapse of restrictions on grants upon which restrictions have been place.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
CERTAIN RELATED TRANSACTIONS
In March 2007, we entered into a $25 million two-year Credit Agreement with a syndicate of four private investment funds including Spindrift Partners, L.P., Spindrift Investors (Bermuda) L.P., Placer Creek Partners, L.P. and Placer Creek Investors (Bermuda) L.P. Wellington Management, LLC (“Wellington”), which beneficially owns approximately 18.5% of our outstanding common stock, serves as the investment adviser to each of these lenders, and arranged for the loan. At the time of the loan, Spindrift Investors (Bermuda) L.P. beneficially owned approximately 7.5% of our outstanding common stock, while Spindrift Partners, L.P. beneficially owned approximately 6.4% of our outstanding common stock (all of the shares comprising these preceding two percentage figures below are attributed to Wellington in computing its 18.5% ownership percentage). For more information regarding this loan transaction, see "ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Senior Secured Financing." In addition, in January 2006, we privately sold 3,278,000 shares of our common stock at a price of $3.15 per share to 27 investors. In this private placement, Spindrift Partners, L.P. acquired 402,500 shares for $1,267,875, while Spindrift Investors (Bermuda) L.P. acquired 469,300 shares for $1,478,295.
In the January 2006 private placement described above, one investor was the wife of Keith D. Spickelmier, Chairman of our Board of Directors, who acquired 95,000 shares for $299,250, and two of the investors were trusts for the benefit of his wife’s sons, which together acquired 46,000 shares for $144,900.
In May 2006, we sold 150,000 shares of our common stock at $3.15 per share to Douglas G. Manner, a Director and our Chief Executive Officer, and 29,972 shares at $3.15 per share to Sean J. Austin, our Chief Financial Officer.
In June 2006, each of Mr. Spickelmier and Westside Resources, L.P. (formerly known as Westside Energy, L.P.), which is wholly-owned by Jimmy D. Wright, at the time a Director and our President and Chief Operating Officer, exercised warrants to purchase 37,500 shares of our common stock at a per share price of $2.50.
DIRECTOR INDEPENDENCE
Our common stock is listed for trading on the American Stock Exchange (the “AMEX”). Accordingly, we use the standards established by the AMEX for determining whether or not each of our directors is “independent.” We have determined that, as of March 31, 2007, each of Keith D. Spickelmier, John T. Raymond and Herbert C. Williamson are “independent” directors in accordance with the AMEX independence standards, although Mr. Spickelmier did not meet these standards of independence during any portion of fiscal 2006. The AMEX rules generally require that a listed company’s Board of Directors be composed of a majority of independent directors. However, these rules provide that a “small business issuer” need only maintain a Board of Directors comprised of at least 50% independent directors. Based on our current “small business issuer” status and the preceding exemption, we maintained a Board of Directors comprised of 50% independent directors, until the time that Jimmy D. Wright resigned from his seat on the Board in April 2007. Since the time of Mr. Wright’s resignation, we have maintained a Board of Directors comprised of a majority of independent directors.
Mr. Spickelmier also served on our Audit Committee during a portion of fiscal 2006 at a time when he did not meet the AMEX independence standards. The AMEX rules generally require that a listed company’s Audit Committee be composed of at least three members, each of whom must be independent. However, these rules provide that one director who is not independent but meets certain other requirements may be appointed to the Audit Committee, if the Board of Directors, under exceptional and limited circumstances, determines that membership on the committee by the individual is required by the best interests of the issuer and its stockholders. Mr. Spickelmier was appointed to our Audit Committee on the basis of the preceding exemption. In determining that Mr. Spickelmier’s appointment to our Audit Committee was required by our and our stockholders’ best interests, the Board of Directors considered Mr. Spickelmier's background and expertise, the fact that Mr. Spickelmier would soon again meet the AMEX’s standards of independence, and the anticipated improved performance of our Audit Committee that would result from a greater number of members serving on such committee.
In addressing the question as to Mr. Spickelmier’s independence in view of AMEX standards, the Board of Directors considered the $72,000 in annual fees paid to Mr. Spickelmier for serving as our Chairman of the Board, and the Board of Directors determined that such fees did not create a material relationship that would interfere with Mr. Spickelmier’s exercise of independent judgment.
PART IV.
ITEM 13. EXHIBITS.
The following exhibits are filed with this Annual Report or are incorporated herein by reference:
| Exhibit No. | Description |
| 3.01 | Our Restated Articles of Incorporation is incorporated herein by reference from our Quarterly Report on Form 10-QSB for the quarter ended June 30, 2004 (SEC File No. 0-49837), Exhibit 3.01. |
| 3.02 | Our Amended and Restated Bylaws are incorporated herein by reference from our Form 10-SB (SEC File No. 0-49837) filed with the SEC on May 28, 2002, Part III, Item 1, Exhibit 3.02. |
| 3.03 | First Amendment to our Amended and Restated Bylaws is incorporated herein by reference from our Form 10-QSB (SEC File No. 0-49837) filed with the SEC on August 21, 2006, Part II, Item 6, Exhibit 3.01. |
| 3.04 | Article of Merger of Westside Energy Subsidiary Corporation with and into us, whereby we changed our corporate name to "Westside Energy Corporation" is incorporated herein by reference from our Annual Report on Form 10-KSB for the year ended December 31, 2003 (SEC File No. 0-49837), Exhibit 3.04 |
| 4.01 | Specimen Common Stock Certificate is incorporated herein by reference from Pre-effective Amendment No. 1 to our Registration Statement on Form SB-2 (SEC File No. 333-120659) filed December 23, 2004, Exhibit 4.01. |
| 10.01 | Warrant to Purchase our common stock issued in the name of Westside Energy, L.P. is incorporated herein by reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on March 1, 2004, Exhibit 10.03 |
| 10.02 | Warrant to Purchase our common stock issued in the name of Keith D. Spickelmier is incorporated herein by reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on March 1, 2004, Exhibit 10.04 |
| 10.03 | Warrant to Purchase our common stock issued in the name of Westside Resources, L.P. is incorporated herein by reference from our Registration Statement on Form SB-2 (SEC File No. 333-120659) filed November 22, 2004, Exhibit 10.09. |
| 10.04 | Warrant to Purchase our common stock issued in the name of Keith D. Spickelmier is incorporated herein by reference from our Registration Statement on Form SB-2 (SEC File No. 333-120659) filed November 22, 2004, Exhibit 10.10. |
| 10.05 | Warrant to Purchase our common stock issued in the name of Sterne, Agee & Leach, Inc. is incorporated herein by reference from our Registration Statement on Form SB-2 (SEC File No. 333-120659) filed November 22, 2004, Exhibit 10.16. |
| 10.06 | Agreement dated April 12, 2005 between us and EBS Oil and Gas Partners Production Company, L.P. is incorporated herein by reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on April 22, 2005, Exhibit 10.01 |
| 10.07 | Agreement dated May 3, 2005 between us and Sean J. Austin is incorporated herein by reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on May 19, 2005, Exhibit 10.01 |
| 10.08 | Employment Agreement dated December 8, 2005 between us and Douglas G. Manner is incorporated herein by reference from our Current Report on Form 8-K (SEC File No. 0-49837) filed with the SEC on December 8, 2005, Exhibit 10.01 |
| 10.09 | First Amendment dated effective January 1, 2006 to Employment Agreement with Sean J. Austin |
| 10.10 | Form of Indemnification Agreements separately entered into by us, on the one hand, and Keith D. Spickelmier, Douglas G. Manner, Craig S. Glick, John T. Raymond, Herbert C. Williamson and Sean J. Austin, on the other hand |
| 10.11 | Purchase and Sale Agreement dated November 30, 2005 between us, on the one hand, and Kelly K. Buster, James I. Staley, Enexco, Inc., the Class B Limited Partners of EBS, and EBS Oil & Gas Partners Production GP, LLC, on the other hand |
| 10.12 | Omitted |
| 10.13 | Advancing Term Credit Agreement date March 15, 2006 between us, Westside Energy Production Company, LP, and Westside Energy Operating Company, LP, on the one hand, and GasRock Capital LLC, on the other hand |
| 10.14 | Joint Exploration Agreement dated June 26, 2006 between us and Forest Oil Corporation |
| 10.15 | Purchase and Sale Agreement dated November 9, 2006, between Westside Energy Production Company, L.P. and Cimmarron Gathering, LP |
| 10.16 | Second Amendment dated April 4, 2007 but effective as of January 1, 2007 to Employment Agreement with Douglas G. Manner |
| 10.17 | Third Amendment dated April 4, 2007 but effective as of January 1, 2007 to Employment Agreement with Sean J. Austin |
| 10.18 | Letter Amendment dated April 4, 2007 to Joint Exploration Agreement with Forest Oil Corporation |
| 10.19 | Consulting Agreement dated April 4, 2007 but effective as of May 1, 2007 between us and Jimmy D. Wright |
| 23.01 | Consent of Malone & Bailey, PC - filed herewith |
| 23.02 | Consent of LaRoche Petroleum Consultants, Ltd. - filed herewith |
| 31.1 | Sarbanes Oxley Section 302 Certifications |
| 32.1 | Sarbanes Oxley Section 906 Certifications |
| 99.01 | Our 2004 Consultant Compensation Plan (filed as Exhibit 4.1 to our Registration Statement on Form S-8 (SEC File No. 333-114686) filed April 21, 2004. |
| 99.02 | Our 2005 Director Stock Plan (filed as Exhibit 4.2 to our Registration Statement on Form S-8 (SEC File No. 333-124890) filed May 13, 2005. |
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
During 2006 and 2005, the aggregate fees that we paid to Malone & Bailey, PC, our independent auditors, for professional services were as follows:
| Year Ended December 31, | |||||||
| 2006 | 2005 | ||||||
| Audit Fees (1) | $ | 115,485 | $ | 51,267 | |||
| Audit-Related Fees (2) | $ | 41,681 | N/A | ||||
| Tax Fees (3) | $ | 6,580 | N/A | ||||
| All Other Fees | N/A | N/A | |||||
| (1) | Fees for audit services include fees associated with the annual audit and the review of our quarterly reports on Form 10-QSB. |
| (2) | Fees for the audits in connection with the acquisition of EBS Oil and Gas Partners Production Company, L.P. and EBS Oil and Gas Partners Operating Company, L.P. |
| (3) | Consist primarily of professional services rendered for tax compliance, tax advice and tax planning. |
Audit Committee Pre-Approval of Audit and Permissible
Non-Audit Services of Independent Registered Public Accounting Firm.
The Audit Committee pre-approves the engagement of Malone & Bailey, PC for all audit and permissible non-audit services. The Audit Committee annually reviews the audit and permissible non-audit services performed by Malone & Bailey, PC, and reviews and approves the fees charged by Malone & Bailey, PC. The Audit Committee has considered the role of Malone & Bailey, PC in providing tax and audit services and other permissible non-audit services to us and has concluded that the provision of such services was compatible with the maintenance of Malone & Bailey, PC’s independence in the conduct of its auditing functions.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Westside Energy Corporation, Inc.
Dallas, Texas
We have audited the accompanying consolidated balance sheets of Westside Energy Corporation, Inc. (“Westside”) and its subsidiaries as of December 31, 2006 and 2005 and the related consolidated statements of operations, cash flows and changes in stockholders’ equity for the two year period then ended. These financial statements are the responsibility of Westside’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westside as of December 31, 2006 and 2005 and the results of its operations and its cash flows for the periods described in conformity with accounting principles generally accepted in the United States of America.
/s/ Malone & Bailey, PC
Malone & Bailey, PC
www.malone-bailey.com
Houston, Texas
April 16, 2007
F-1
| WESTSIDE ENERGY COPORATION | |||||||
| CONSOLIDATED BALANCE SHEETS | |||||||
| December 31, | December 31, | ||||||
| 2006 | 2005 | ||||||
| ASSETS | |||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | 5,003,803 | $ | 604,411 | |||
| Certificate of deposit and escrow account | 27,887 | 27,693 | |||||
| Marketable securities | 425,000 | 1,050,000 | |||||
| Accounts receivable | 5,189,504 | 492,349 | |||||
| Derivative asset | 169,885 | - | |||||
| Prepaid assets | 122,914 | 1,770 | |||||
| Deferred acquisition charges | - | 289,367 | |||||
| Total current assets | 10,938,993 | 2,465,590 | |||||
| Oil & gas properties, using successful efforts accounting | |||||||
| Proved properties | 23,681,084 | 8,513,598 | |||||
| Unproved properties | 10,319,150 | 4,282,036 | |||||
| Accumulated depreciation, depletion, amortization & impairment | (10,851,176 | ) | (1,293,895 | ) | |||
| Net oil & gas properties | 23,149,058 | 11,501,739 | |||||
| Deferred financing costs, net of accumulated amortization of $66,593 | 265,907 | - | |||||
| Loan receivable from EBS | - | 4,100,000 | |||||
| Property and equipment, net of accumulated depreciation of $92,656 | 150,322 | - | |||||
| TOTAL ASSETS | $ | 34,504,280 | $ | 18,067,329 | |||
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
| Current liabilities | |||||||
| Accounts payable and accrued expenses | $ | 7,171,069 | $ | 529,446 | |||
| Current portion of long-term debt | 3,997,500 | - | |||||
| Total current liabilities | 11,168,569 | 529,446 | |||||
| Non-current liabilities | |||||||
| Asset retirement obligations | 153,487 | 27,880 | |||||
| Long-term portion of debt | 7,609,057 | - | |||||
| TOTAL LIABILITIES | 18,931,113 | 557,326 | |||||
| STOCKHOLDERS’ EQUITY | |||||||
| Preferred stock, $.01 par value, 10,000,000 shares authorized, none issued and outstanding | - | - | |||||
| Common stock, $.01 par value, 50,000,000 shares authorized, 21,461,909 and 17,376,745 shares issued and outstanding | 214,619 | 173,767 | |||||
| Additional paid in capital | 34,501,241 | 22,736,902 | |||||
| Accumulated other comprehensive income | 169,885 | - | |||||
| Accumulated deficit | (19,312,578 | ) | (5,400,666 | ) | |||
| TOTAL STOCKHOLDERS’ EQUITY | 15,573,167 | 17,510,003 | |||||
| TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 34,504,280 | $ | 18,067,329 | |||
See accompanying notes to consolidated financial statements.
F-2
| WESTSIDE ENERGY CORPORATION | |||||||
| CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||
| Years Ended December 31, 2006 and 2005 | |||||||
| 2006 | 2005 | ||||||
| Revenues | |||||||
| Oil and gas sales | $ | 3,915,209 | $ | 595,657 | |||
| Expenses | |||||||
| Production | 1,779,192 | 108,227 | |||||
| Exploration | - | 360,170 | |||||
| General and administrative | 5,296,723 | 1,782,184 | |||||
| Depreciation, depletion and amortization | 5,710,295 | 344,797 | |||||
| Impairment | 4,310,330 | 636,278 | |||||
| Total Expenses | 17,096,540 | 3,231,656 | |||||
| Loss from Operations | (13,181,331 | ) | (2,635,999 | ) | |||
| Other Income (Expense) | |||||||
| Interest income | 225,619 | 359,490 | |||||
| Interest expense | (956,200 | ) | (2,070 | ) | |||
| Gain (loss) on marketable securities | - | (98 | ) | ||||
| Gain (loss) on sale of oil and gas properties | - | 339,355 | |||||
| Total Other Income (Expense) | (730,581 | ) | 696,677 | ||||
| NET LOSS | $ | (13,911,912 | ) | $ | (1,939,322 | ) | |
| Basic and diluted loss per common share | $ | (0.66 | ) | $ | (0.11 | ) | |
| Weighted average common shares outstanding | 21,041,220 | 17,273,205 | |||||
See accompanying notes to consolidated financial statements.
F-3
| WESTSIDE ENERGY CORPORATION | |||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
| Years Ended December 31, 2006 and 2005 | |||||||
| 2006 | 2005 | ||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||
| Net loss | $ | (13,911,912 | ) | $ | (1,939,322 | ) | |
| Adjustments to reconcile net loss to net cash used in operating activities: | |||||||
| Stock for services | 764,985 | 243,646 | |||||
| Impairment | 4,310,330 | �� | 636,278 | ||||
| Depreciation, depletion and amortization | 5,710,295 | 344,797 | |||||
| Amortization of discount on note payable | 82,076 | - | |||||
| Amortization of deferred financing costs | 66,593 | - | |||||
| Gain on sale of properties | - | (339,355 | ) | ||||
| Loss on marketable securities | - | 98 | |||||
| Changes in: | |||||||
| Accounts receivable | 2,439,095 | (377,414 | ) | ||||
| Prepaid assets and other | (553,330 | ) | 28,505 | ||||
| Deferred acquisition charges | - | (289,367 | ) | ||||
| Accounts payable and accrued expenses | (6,418,551 | ) | 111,924 | ||||
| NET CASH USED IN OPERATING ACTIVITIES | (7,510,419 | ) | (1,580,210 | ) | |||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||
| Acquisition of EBS, net of cash acquired | 955,574 | - | |||||
| Purchase of marketable securities | - | (3,575,000 | ) | ||||
| Proceeds from sale of marketable securities | 625,000 | 2,524,902 | |||||
| Purchase of certificate of deposit | - | (27,500 | ) | ||||
| Purchase of office equipment | (75,938 | ) | (27,220 | ) | |||
| Advances to EBS | (3,644,754 | ) | (4,100,000 | ) | |||
| Capital expenditures for oil and gas properties | (13,306,243 | ) | (9,277,131 | ) | |||
| Proceeds from sale of properties | 4,941,985 | 448,000 | |||||
| NET CASH USED IN INVESTING ACTIVITIES | (10,504,376 | ) | (14,033,949 | ) | |||
| CASH FLOWS FROM FINANCING ACTIVIIES | |||||||
| Proceeds from notes payable, net of financing costs | 14,887,500 | - | |||||
| Payments for fundraising | - | (2,121 | ) | ||||
| Proceeds from exercise of warrants | 813,750 | 225,000 | |||||
| Proceeds from sale of common stock, net | 10,226,456 | - | |||||
| Payments on notes | (3,513,519 | ) | - | ||||
| NET CASH PROVIDED FROM FINANCING ACTIVITIES | 22,414,187 | 222,879 | |||||
| NET CHANGE IN CASH | 4,399,392 | (15,391,280 | ) | ||||
| CASH BALANCES | |||||||
| Beginning of period | 604,411 | 15,995,691 | |||||
| End of period | $ | 5,003,803 | $ | 604,411 | |||
See accompanying notes to consolidated financial statements.
F-4
| WESTSIDE ENERGY CORPORATION | |||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||
| Years Ended December 31, 2006 and 2005 | |||||||
| 2006 | 2005 | ||||||
| SUPPLEMENTAL CASH FLOW DISCLOSURES: | |||||||
| Interest paid | $ | 956,200 | $ | - | |||
| Taxes paid | $ | - | $ | - | |||
| NON-CASH DISCLOSURES: | |||||||
| Discount on note payable | $ | 182,000 | $ | - | |||
| Change in derivative asset | $ | 169,885 | $ | - | |||
| Amortized loss on marketable securities | $ | - | $ | 81 | |||
See accompanying notes to consolidated financial statements.
F-5
Westside Energy Corporation
Consolidated Statements of Changes in Stockholders' Equity
Years Ended December 31, 2005 and 2006
| Common Stock | |||||||||||||||||||
| Shares | Par Value | Additional Paid-in Capital | Retained Deficit | Other Comprehensive Income | Total | ||||||||||||||
| Balance at December 31, 2004 | 17,048,331 | $ | 170,483 | $ | 22,273,661 | $ | (3,461,344 | ) | $ | - | $ | 18,982,800 | |||||||
| Stock issued for warrants exercised | 218,000 | 2,180 | 222,820 | - | - | 225,000 | |||||||||||||
| Fundraising costs | - | - | (2,121 | ) | - | - | (2,121 | ) | |||||||||||
| Stock issued for services | 33,972 | 340 | 128,138 | - | - | 128,478 | |||||||||||||
| Deferred compensation | 76,442 | 764 | (764 | ) | - | - | - | ||||||||||||
| Amortization of deferred compensation | - | - | 115,168 | - | - | 115,168 | |||||||||||||
| Net loss | (1,939,322 | ) | (1,939,322 | ) | |||||||||||||||
| Balance at December 31, 2005 | 17,376,745 | 173,767 | 22,736,902 | (5,400,666 | ) | - | 17,510,003 | ||||||||||||
| Stock issued for warrants exercised | 357,500 | 3,575 | 810,175 | - | - | 813,750 | |||||||||||||
| Stock issued for services | 94,384 | 944 | 326,204 | - | - | 327,148 | |||||||||||||
| Shares sold for cash | 3,457,972 | 34,580 | 10,191,876 | - | - | 10,226,456 | |||||||||||||
| Deferred compensation | 175,308 | 1,753 | (1,753 | ) | - | - | - | ||||||||||||
| Amortization of deferred compensation | - | - | 437,837 | - | - | 437,837 | |||||||||||||
| Unrealized gain on derivative instruments | - | - | - | - | 169,885 | 169,885 | |||||||||||||
| Net Loss | - | - | - | (13,911,912 | ) | - | (13,911,912 | ) | |||||||||||
| Balance at December 31, 2006 | 21,461,909 | $ | 214,619 | $ | 34,501,241 | $ | (19,312,578 | ) | $ | 169,885 | $ | 15,573,167 | |||||||
See notes to consolidated financial statements.
F-6
WESTSIDE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of operations and organization
Westside Energy Corporation ("Westside") (formerly EvenTemp Corporation) was incorporated in Nevada on November 30, 1995. EvenTemp operated an auto repair and accessory business. This business ceased operating in August 1999. The name of the company was changed to Westside Energy Corporation in March 2004.
Westside is engaged primarily in the acquisition, exploration, development, production, and sales of, oil, gas and natural gas liquids. Westside sells its oil and gas products primarily to domestic natural gas pipelines and crude oil marketers.
Principles of Consolidation
Westside’s consolidated financial statements include the accounts of Westside and its wholly and majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of estimates
The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue recognition
Westside records oil and gas revenues following the entitlement method of accounting for production, in which any excess amount received above Westside's share is treated as a liability. If less than Westside's share is received, the underproduction is recorded as an asset. Westside did not have an imbalance position in terms of volumes or values at December 31, 2006.
Oil and gas properties
Westside uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.
F-7
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of the impairment by providing an impairment allowance. Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment are depreciated over their estimated useful lives.
On the sale or retirement of a complete unit of proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Seismic costs
Management considers 3-D seismic surveys over acreage with proved reserves assigned to be development activities. For development projects, the Company uses its 3-D seismic database to select drill sites, assess recompletion opportunities and production issues, quantify reservoir size and determine probable extensions and/or drainage areas for existing fields. Westside amortizes the cost of its capitalized developmental 3-D seismic survey costs using the unit-of-production method. Costs for 3-D seismic surveys over unproven acreage are defined as related to exploration activities and are expensed in the period incurred.
Cash and cash equivalents
Cash and cash equivalents include cash in banks and certificates of deposit which mature within three months of the date of purchase.
Marketable Securities
Westside classifies its investments as available-for-sale which are reported at estimated fair value with unrealized gains and losses included in other comprehensive income, net of applicable deferred income taxes. The annual amortization or accretion is recorded as a charge or credit to interest income. Realized gains and losses on sales are recognized in net income on the specific identification basis. The estimated fair values of investments are based on quoted market prices or dealer quotes.
Accounts Receivable
WestSide uses the allowance method of accounting for doubtful accounts. The year-end balance is based on historical collections and management’s review of the current status of existing receivables and estimate as to their collectibility. Westside provides reserves for accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2006 and 2005, Westside has determined that no allowance for doubtful accounts is necessary.
F-8
Debt Issuance Costs
Debt issuance costs are deferred and recognized, using the effective interest method, over the expected term of the related debt.
Property and equipment
Property and equipment are valued at cost. Additions are capitalized and maintenance and repairs are charged to expense as incurred. Gains and losses on dispositions of equipment are reflected in other income and expense.
Long-lived assets
Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed of other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of the asset's carrying amount or fair value less cost to sell.
Stock-based compensation
On January 1, 2006, Westside adopted SFAS No. 123(R), "Share Based Payment". SFAS 123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R) requires all share−based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. Westside adopted SFAS 123(R) using the modified prospective method which requires the application of the accounting standard as of January 1, 2006.
Prior to 2006, Westside began issuing common stock to employees as compensation. Westside recorded as compensation expense the fair value of such shares as calculated pursuant to Statement of Financial Accounting Standard No. 123, Accounting for Stock−Based Compensation, recognized over the related service period. Westside has no option plans for its employees. Westside accounts for stock−based compensation issued to non−employees in accordance with the provisions of SFAS No. 123 and EITF No. 96−18, "Accounting for Equity Investments That Are Issued to Non−Employees for Acquiring, or in Conjunction with Selling Goods or Services". For expensing purposes, the value of common stock issued to non−employees and consultants is determined based on the fair value of the services received or the fair value of the equity instruments issued, whichever value is more reliably measurable.
Income taxes
Westside recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. Westside provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.
Loss per share
F-9
Basic and diluted net loss per share calculations are calculated on the basis of the weighted average number of common shares outstanding during the year. The per share amounts include the dilutive effect of common stock equivalents in years with net income. Westside had losses in 2006 and 2005. Basic and diluted loss per share is the same due to the absence of common stock equivalents as the effect of our potential common stock equivalents would be anti-dilutive.
Derivatives
All derivative instruments are recorded on the balance sheet at their fair value. Changes in the fair value of each derivative is recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. To make this determination, management formally documents the hedging relationship and its risk−management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as cash−flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions.
Westside also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting cash flows of hedged items. A derivative that is highly effective and that is designated and qualifies as a cash−flow hedge has its changes in fair value recorded in other comprehensive income to the extent that the derivative is effective as a hedge. Any other changes determined to be ineffective do not qualify for cash−flow hedge accounting and are reported currently in earnings.
Westside discontinues cash−flow hedge accounting when it is determined that the derivative is no longer effective in offsetting cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is redesignated as a non−hedging instrument because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a cash−flow hedge instrument is no longer appropriate. In situations in which cash−flow hedge accounting is discontinued, Westside continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings.
When the criteria for cash−flow hedge accounting are not met, realized gains and losses (i.e., cash settlements) are recorded in other income and expense in the Statements of Operations. Similarly, changes in the fair value of the derivative instruments are recorded as unrealized gains or losses in the Statements of Operations. In contrast, cash settlements for derivative instruments that qualify for hedge accounting are recorded as additions to or reductions of oil and gas revenues while changes in fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings.
New accounting standards
Westside does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its results of operations, financial position or cash flows.
F-10
Note 2 - Marketable securities
The aggregate amortized cost, gross unrealized gains, gross unrealized losses, and estimated fair value, for available-for-sale securities by major security type at December 31, 2006 and 2005, are as follows:
| 2006 | |||||||||||||
| Gross | Gross | Estimated | |||||||||||
| Amortized | Unrealized | Unrealized | Fair | ||||||||||
| Cost | Gains | Losses | Value | ||||||||||
| Corporate Bonds | $ | 425,000 | $ | - | $ | - | $ | 425,000 | |||||
| Total | $ | 425,000 | $ | - | $ | - | $ | 425,000 | |||||
| 2005 | |||||||||||||
| Gross | Gross | Estimated | |||||||||||
| Amortized | Unrealized | Unrealized | Fair | ||||||||||
| Cost | Gains | Losses | Value | ||||||||||
| Corporate bonds | $ | 1,050,000 | $ | - | $ | - | $ | 1,050,000 | |||||
| Total | $ | 1,050,000 | $ | - | $ | - | $ | 1,050,000 | |||||
The amortized cost and estimated fair value of debt securities at December 31, 2006 by contractual maturity, are shown below. Expected maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.
| Amortized | Estimated | ||||||
| Cost | Fair Value | ||||||
| Due in one year or less | $ | - | $ | - | |||
| Due after one year through five years | 425,000 | 425,000 | |||||
| $ | 425,000 | $ | 425,000 | ||||
NOTE 3 - Notes Payable
On March 15, 2006, Westside entered into a $45 million three year Advancing Term
Credit Agreement with GasRock Capital, LLC (“GasRock”). This agreement was paid in full in March 2007 (see note 13) and a new credit agreement was created with a related party lender. The GasRock agreement provided for the following:
1. Up to $9.5 million to be used for closing costs pertaining to the purchase of EBS for approved drilling and for pipeline expansion.
F-11
2. Up to $7.5 million to be used for the cash portion of an earn−out agreement entered into in connection with Westside's acquisition of all of the outstanding equity interests (the "Equity Interests") in EBS Oil and Gas Partners Production Company, L.P. and EBS Oil and Gas Partners Operating Company, L.P. (collectively "EBS"), provided that any amount advanced for payment of the earn−out agreement will reduce dollar−for−dollar the amount available for the uses described in purpose 4 below.
3. Up to $1.5 million to be used in certain circumstances for Westside's overhead.
4. Up to an additional $34.0 million made available at later dates (subject to GasRock's approval) for additional exploitation of proved developed non−producing reserves, additional lender−approved drilling of new wells, lease acquisitions, pipeline expansion or seismic expenses.
To secure Westside's obligations under the Credit Agreement, Westside granted a security interest in all of its assets in favor of GasRock. The Credit Agreement also required hedging for a substantial portion of Westside's reserves. Amounts outstanding under the Credit Agreement bear interest at an annual rate equal to the greater of (a) 12.0% or (b) the one−month London interbank offered rate (LIBOR), plus 6.50%. 85.0% of monthly revenue from oil & gas production and commodity hedging, net of production operations related costs, are applied to the repayment of the indebtedness under the Credit Agreement, subject to the limited ability of Westside to remit less than 85% and to retain more than 15% of monthly net revenue to cover Westside's overhead. Westside also paid a facility fee equal to 2.0% of all advances, with the amount of such fee not paid at the time of the advance but added to the outstanding principal balance and amortized in accordance with the terms of the Credit Agreement. In consideration of GasRock providing the financing under the Credit Agreement, GasRock received a 1.0% overriding royalty interest (proportionately reduced to Westside's working interest) in each producing well and lease within Westside as of the date of the execution of the Credit Agreement. GasRock also received a 1.0% overriding royalty interest (proportionately reduced to Westside's working interest) in each producing well and lease and related unit acquired during the term of the Credit Agreement if Westside used advances under the Credit Agreement to acquire same. The Credit Agreement contained customary representations and warranties, customary affirmative and negative covenants (including a maximum leverage ratio), and customary events of default.
During 2005, Westside entered into an agreement with EBS Oil and Gas Partners Production Company, L.P. ("EBS Production"), a privately held entity engaged in the drilling and completion of wells on various oil and gas leases covering lands located in Cooke, Montague, and Wise Counties, Texas. Under the terms of the agreement, Westside made available to EBS Production, on a revolving basis, funds of up to a maximum sum of $1,000,000 outstanding at any given time. The funds were advanced to cover the costs incurred by EBS Production in connection with its acquisition of oil and gas leases.
During November 2005, Westside purchased from a group of private investors their rights as lenders in certain outstanding debt owed by EBS to such group. The outstanding balance of, and the purchase price paid by Westside for, the debt was $3.85 million. The debt was secured by subordinate liens on and security interests in substantially all of EBS Production's assets. The debt accrued interest at the rate of 12% per annum.
During December 2005, Westside made an additional loan to EBS for $250,000. The documentation governing the purchased debt was amended to cover this additional loaned amount as if it was part of the original purchased debt. Accordingly, the additional loaned amount accrues interest, is secured, and matures in the same manner as the original purchased debt.
F-12
As of December 31, 2005, Westside had a total $4,100,000 due from EBS Production. In March 2006, Westside completed the acquisition of EBS.
The short and long-term debt was paid in full in March 2007 (see Note 13)and was replaced with a new credit facility.
NOTE 4 − DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
On March 17, 2006, Westside entered into swap agreements in order to provide a measure of stability to Westside's cash flows due to volatile oil and gas prices and to manage the exposure to commodity price risk.
SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of each derivative is recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. To make this determination, management formally documents the hedging relationship and its risk−management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as cash−flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions.
Westside also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting cash flows of hedged items. A derivative that is highly effective and that is designated and qualifies as a cash−flow hedge has its changes in fair value recorded in other comprehensive income to the extent that the derivative is effective as a hedge. Any other changes determined to be ineffective do not qualify for cash−flow hedge accounting and are reported currently in earnings.
Westside discontinues cash−flow hedge accounting when it is determined that the derivative is no longer effective in offsetting cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is redesignated as a non−hedging instrument because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a cash−flow hedge instrument is no longer appropriate. In situations in which cash−flow hedge accounting is discontinued, Westside continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings.
When the criteria for cash−flow hedge accounting are not met, realized gains and losses (i.e., cash settlements) are recorded in other income and expense in the Statements of Operations. Similarly, changes in the fair value of the derivative instruments are recorded as unrealized gains or losses in the Statements of Operations. In contrast, cash settlements for derivative instruments that qualify for hedge accounting are recorded as additions to or reductions of oil and gas revenues while changes in fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings.
F-13
Based on the above, management has determined the swaps qualify for cash−flow hedge accounting treatment. As of December 31, 2006, Westside recognized a derivative asset of $169,885 with the change in fair value reflected in other comprehensive income.
NOTE 5 - ASSET RETIREMENT OBLIGATIONS
Westside recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. For Westside, asset retirement obligations relate to the abandonment of oil and gas producing facilities. The amounts recognized are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate.
Westside records depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a straight line basis, while the accretion to be recognized will escalate over the life of the producing assets, typically as production declines. The following table indicates the changes to Westside's asset retirement obligations in 2006 and 2005:
| 2006 | 2005 | ||||||
| Balance at beginning of year | $ | 27,880 | $ | 6,646 | |||
| Liabilities incurred | 122,855 | 20,370 | |||||
| Accretion expense | 2,752 | 864 | |||||
| Balance at end of year | $ | 153,487 | $ | 27,880 | |||
NOTE 6 - CONCENTRATION OF CREDIT RISK
At December 31, 2006, Westside's cash in financial institutions exceeded the federally insured deposits limit by $4,458,265. An investment of $447,176 in a bank account with an original maturity of less than 90 days, backed by collateralized mortgage obligations, is included in cash and cash equivalents at December 31, 2006. The collateral for this investment had a market value of approximately $460,881 at December 31, 2006.
NOTE 7 - COMMITMENTS AND CONTINGENCIES
Westside is not currently involved in any pending legal proceedings. In the future, Westside may become involved in various legal proceedings from time to time, either as a plaintiff or as a defendant, and either in or outside the normal course of business. Westside is not now in the position to determine when (if ever) such a legal proceeding may arise. If Westside ever becomes involved in a legal proceeding, Westside's financial condition, operations, or cash flows could be materially adversely affected, depending on the facts and circumstances relating to such proceeding.
In June 2006, Westside entered into a 24-month office lease agreement for $8,159 per month.
F-14
Westside is subject to cash calls related to its various investments in oil and gas prospects. The potential cash calls are in the normal course of business for Westside's oil and gas interests. Westside will require funds in excess of its net cash flows from operations to meet its cash calls for its various interests in oil and gas prospects to explore, produce, develop, and eventually sell the underlying natural gas and oil products.
NOTE 8 - INCOME TAXES
During 2006 and 2005, Westside incurred net losses and therefore, had no tax liability. The net deferred tax asset generated by the loss carry-forward has been fully reserved. The cumulative net operating loss carry-forward is approximately $30,800,000 at December 31, 2006 and will expire in the years from 2019 to 2026.
At December 31, 2006, the deferred tax assets consisted of the following:
| Deferred tax assets | ||||
| Net operating losses | $ | 10,472,000 | ||
| Less: valuation allowance | (10,472,000 | ) | ||
| Net deferred tax asset | $ | - | ||
NOTE 9 - IMPAIRMENT OF LONG-LIVED ASSETS
Pursuant to FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, impairment losses of $4,310,330 and $636,278 for 2006 and 2005, respectively, have been recognized in loss from continuing operations before income taxes under the caption "Impairment". The impairment loss was determined by subtracting the carrying value from the discounted present value of the estimated future cash flows of the wells and the expected expiration of unproved leases as of the end of each year.
NOTE 10 - COMMON STOCK
During 2006, Westside had the following equity transactions:
Westside issued 94,384 shares of common stock for services valued at $327,148. Additionally, 175,308 common shares valued at $609,129 were issued for future services. The par value of these shares was recorded through common stock and additional paid-in capital. As the shares are earned, the value of the shares is recorded to expense and additional paid-in capital. For the year ended December 31, 2006, $437,837 was earned and expensed.
357,500 warrants were exercised for total proceeds of $813,750. 357,500 shares of common stock were issued for the warrants exercised.
In a private placement, 3,278,000 shares were sold for net proceeds of $9,659,544. Additionally, two employees purchased 179,972 shares for $472,500.
During 2005, Westside had the following equity transactions:
218,000 warrants were exercised for total proceeds of $225,000.
F-15
Westside also issued 33,972 shares of common stock for services valued at $128,138. Additionally, 76,442 common shares valued at $291,480 were issued for future services. The par value of these shares was recorded through common stock and additional paid-in capital. As the shares are earned, the value of the shares is recorded to expense and additional paid-in capital. For the year ended December 31, 2005, $115,168 was earned and expensed.
NOTE 11 - WARRANTS
There were no warrants issued or outstanding until the year ended December 31, 2004. During 2004, Westside issued warrants attached to debt, stock purchases, and for consulting services. All issuances were approved by the Board of Directors. During 2006, no additional warrants were issued. A summary of changes in outstanding warrants is as follows:
| Weighted | |||||||
| Average | |||||||
| Warrants | Share Price | ||||||
| Outstanding at December 31, 2004 | 1,495,500 | $ | 1.30 | ||||
| Changes during the year: | |||||||
| Granted | - | - | |||||
| Exercised | (218,000 | ) | 0.97 | ||||
| Forfeited | - | - | |||||
| Outstanding at December 31, 2005 | 1,277,500 | 1.36 | |||||
| Changes during the year: | |||||||
| Granted | - | - | |||||
| Exercised | (357,500 | ) | 2.28 | ||||
| Forfeited | - | - | |||||
| Outstanding at December 31, 2006 | 920,000 | $ | 0.99 | ||||
| Exercisable at December 31, 2006 | 920,000 | $ | 0.99 | ||||
NOTE 12 − PURCHASE OF EBS OIL AND GAS PARTNERS PRODUCTION COMPANY, L.P.
On March 15, 2006, Westside acquired EBS Oil and Gas Partners Production Company, L.P. and EBS Oil and Gas Partners Operating Company, L.P. (collectively "EBS"). The acquired EBS assets consist (in part) of rights in approximately 9,837 gross acres and an approximately one−sixth interest in Tri-County Gathering, a pipeline system serving part of the Barnett Shale area. The interest in the pipeline system was sold in November 2006 for $5,000,000.
F-16
The purchase price for the Equity Interests consisted of an initial purchase price paid at closing (the "Initial Purchase Price") and additional consideration to be paid after closing (the "Additional Consideration"). The Initial Purchase Price was set at $9,804,839, subject to certain adjustments. The adjustments included a reduction in the Initial Purchase Price for all debt owed by EBS, including (a) indebtedness in the approximate amount of $5,850,000 owed by EBS to Westside, and (b) indebtedness in the approximate amount of $1,600,000 owed by EBS to a third party. After making adjustments, Westside paid in cash at the closing approximately $151,000 to the Class B partners of EBS and an EBS payable in the amount of approximately $294,000, and Westside received a credit in the approximate amount of $1,700,000 against the future payment of the Additional Consideration. Funding for the cash paid at the closing and the retirement of the Third Party Loan was provided from Westside's available cash and by GasRock Capital LLC ("GasRock") pursuant to an Advancing Term Credit Agreement (the "Credit Agreement"). The additional consideration was resolved and finalized in 2006.
The following table summarizes the estimated fair values of the assets that Westside acquired and the liabilities that it assumed from EBS on the date of acquisition.
| Current Assets | $ | 8,094,600 | ||
| Fixed Assets | 13,441,303 | |||
| Total Assets Acquired | $ | 21,535,903 | ||
| Accounts Payable | (12,935,559 | ) | ||
| Accrued Expense | (58,800 | ) | ||
| Asset Retirement Obligation | (122,855 | ) | ||
| Total Liabilities Assumed | (13,117,214 | ) | ||
| Net Assets Acquired | $ | 8,418,689 |
The following unaudited pro forma information assumes the acquisition of EBS occurred as of January 1, 2006 and January 1, 2005, respectively. The pro forma results are not necessarily indicative of what actually would have occurred had the acquisition been in effect for the period presented.
Year Ended December 31, 2006:
As Reported | Pro- Forma | ||||||
| Total Assets | $ | 34,504,280 | $ | 34,504,280 | |||
| Revenues | $ | 3,915,209 | $ | 4,584,021 | |||
| Net Loss | $ | (13,911,912 | ) | $ | (14,087,928 | ) | |
| Loss Per Share | $ | (0.66 | ) | $ | (0.67 | ) | |
F-17
Year Ended December 31, 2005
As Reported | Pro- Forma | ||||||
| Total Assets | $ | 18,067,329 | $ | 38,124,798 | |||
| Revenues | $ | 595,657 | $ | 2,156,103 | |||
| Net Loss | $ | (1,939,322 | ) | $ | (3,418,183 | ) | |
| Loss Per Share | $ | (0.11 | ) | $ | (0.20 | ) | |
NOTE 13 - SUBSEQUENT EVENTS
Westside closed a $25 million senior secured loan from four entities managed by Wellington Management Company, LLP to replace the credit facility previously provided by GasRock Capital, LLC. Two of the lending entities are among the largest institutional holders of the Company’s outstanding shares.
NOTE 14 -- SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Capitalized Costs
Capitalized costs incurred in property acquisition, exploration, and development activities as of December 31, 2006 are as follows:
| Total Capitalized | $ | 34,000,234 | ||
| Less: Accumulated depletion | (10,815,176 | ) | ||
| Net Capitalized | $ | 23,149,058 |
Costs incurred for property acquisition, exploration, and development activities for the year ended December 31, 2006 are as follows:
| Acquisition of properties | ||||
| Proved | $ | - | ||
| Unproved | 8,418,689 | |||
| Exploration costs | - | |||
| Development costs | 4,887,554 | |||
| Total costs incurred for property acquisition, exploration, and development activities | $ | 13,306,243 | ||
Results of operations for oil and gas producing activities for the year ended December 31, 2006 are as follows:
| Oil & gas sales | $ | 3,915,209 | ||
| Production costs | (1,779,192 | ) | ||
| Exploration expenses | - | |||
| Depreciation, depletion and amortization | (5,551,536 | ) | ||
| Impairment | (4,310,330 | ) | ||
| (7,725,849 | ) | |||
| Income tax expense | - | |||
| Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs) | $ | (7,725,849 | ) |
F-18
Reserve information
The following estimates of proved and proved developed reserve quantities and related standardized measure of discounted net cash flow are estimates only, and do not purport to reflect realizable values or fair market values of the Company's reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's reserves are located in the United States.
Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.
The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent a year to reflect the estimated timing of the future cash flows.
| 2006 | 2005 | ||||||||||||
| Oil | Gas | Oil | Gas | ||||||||||
| (MBbls) | (MMcf) | (MBbls) | (MMcf) | ||||||||||
| Total proved reserves | |||||||||||||
| Beginning of year | 85.206 | 1,191.699 | 1.679 | 90.789 | |||||||||
| Extensions and discoveries | 8.856 | 1,001.032 | - | - | |||||||||
| Revisions of previous estimates | (33.740 | ) | (133.747 | ) | 0.182 | 43.585 | |||||||
| Purchases of minerals in place | 112.174 | 4,136.802 | 84.185 | 1,120.091 | |||||||||
| Production | (22.881 | ) | (360.751 | ) | (0.840 | ) | (62.766 | ) | |||||
| End of the year | 149.615 | 5,835.035 | 85.206 | 1,191.699 | |||||||||
| Proved developed reserves | 85.385 | 3,277.562 | 85.206 | 1,191.699 | |||||||||
F-19
| Standardized Measure of Discounted Future | ||||
| Net Cash Flows at December 31, 2006 | (000's) | |||
| Future cash inflows | $ | 41,158 | ||
| Future production costs | (12,516 | ) | ||
| Future development costs | (8,943 | ) | ||
| Future income tax expenses, at 34% | (5,411 | ) | ||
| Future gross cash flows | 14,288 | |||
| Less: 10% annual discount for estimated timing of cash flows | (2,085 | ) | ||
| Standardized measures of discounted future net cash flows relating to proved oil and gas reserves | $ | 12,203 | ||
The following reconciles the change in the standardized measure of discounted future net cash flow during 2006.
| (000's) | ||||
| Beginning of year | $ | 6,404 | ||
| Sales of oil and gas produced, net of production costs | (2,136 | ) | ||
| Net changes in prices and production costs | 6,934 | |||
| Purchases of minerals | 4,556 | |||
| Extensions, discoveries and improved recovery | 1,862 | |||
| Net changes in estimated future development costs | - | |||
| Revisions of previous quantity estimates | (4,414 | ) | ||
| Change in production rates | 657 | |||
| Change in discount | 858 | |||
| Change in income tax expense | (2,518 | ) | ||
| End of year | $ | 12,203 | ||
APPENDIX A
Glossary of Certain Natural Gas and Oil Terms
The following are abbreviations and definitions of certain terms commonly used in the natural gas and oil industry and in this Annual Report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf/d. One billion cubic feet per day.
Bcfe. One billion cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.
Boe. Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.
Bop/d. Barrels of oil per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Btu/cf. The heat content, expressed in Btu’s, of one cubic foot of natural gas.
Completion. The installation of permanent equipment for the production of natural gas or oil.
Developed acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production.
Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploitation. The continued development of a known producing formation in a previously discovered field. To make complete or maximize the ultimate recovery of oil or natural gas from the field by work including development wells, secondary recovery equipment or other suitable processes and technology.
Exploration. The search for natural accumulations of natural gas and oil by any geological, geophysical or other suitable means.
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Fracturing. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating artificial channels. As part of this technique, sand or other material may also be injected into the formation to keep the channels open, so that fluids or gases may more easily flow through the formation.
Gross acres. The total acres in which we own any amount of working interest.
Gross wells. The total number of producing wells in which we own any amount of working interest.
Horizontal drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.
Injection well or injector. A well that is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.
Lease. An instrument that grants to another (the lessee) the exclusive right to enter to explore for, drill for, produce, store and remove natural gas and oil on the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.
Mcf/d. One Mcf per day.
Mcfe. One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcfs, at a ratio of 6 Mcf to 1 Bbl of oil.
MMBtu. Million British thermal units.
MMcf. One million cubic feet of natural gas at standard atmospheric conditions.
Net acres. Gross acres multiplied by Westside’s percentage working interest in the acreage.
Net production. Production that is owned by Westside less royalties and production due others.
Net wells. The sum of all the complete and partial well ownership interests (i.e., if we own 25% percent of the working interest in eight producing wells, the subtotal of this interest to the total net producing well count would be two net producing wells).
Operator. The individual or company responsible for the exploration, exploitation, development and production of a natural gas or oil well or lease.
Overriding royalty interest. Ownership in a percentage of production or production revenues, free of the cost of production, created by the lessee, company and/or working interest owner and paid by the lessee, company and/or working interest owner out of revenue from the well.
Pay zones. A reservoir or portion of a reservoir that contains economically producible natural gas and oil reserves.
Permeability. The capacity of a geologic formation to allow water, natural gas or oil to pass through it.
Plugging and abandonment. Sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.
PV-10 value. The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expenses, production taxes and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization or Federal income taxes, and discounted using an annual discount rate of 10%.
Productive well. A well with the capacity to produce hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonable anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the royalty owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Secondary recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.
Three-dimensional seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflected seismic data collected over a surface grid. Three-dimensional seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.
Tcf. One trillion cubic feet of natural gas
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Working interest. An interest in a natural gas and oil lease that gives the owner of the interest the right to drill for and produce natural gas and oil on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Westside Energy Corporation has duly caused this annual report on Form 10-KSB to be signed on its behalf by the undersigned, thereunto duly authorized.
| April 17, 2007 | WESTSIDE ENERGY CORPORATION | ||
| By: | /s/ Douglas G. Manner | ||
| Douglas G. Manner, | |||
| Chief Executive Officer | |||
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.
| Name | Title | Date | ||
| /s/ Douglas G. Manner | Director, Chief Executive Officer | April 17, 2007 | ||
| Douglas G. Manner | (Principal Executive Officer) | |||
| /s/ Keith D. Spickelmier | Director, Chairman of the Board | April 17, 2007 | ||
| Keith D. Spickelmier | ||||
| /s/ Craig S. Glick | Director, | April 17, 2007 | ||
| Craig S. Glick | ||||
| /s/ John T. Raymond | Director, | April 17, 2007 | ||
| John T. Raymond | ||||
| /s/ Herbert C. Williamson | Director, | April 17, 2007 | ||
| Herbert C. Williamson | ||||
| /s/ Sean J. Austin | Vice President and | April 17, 2007 | ||
| Sean J. Austin | Chief Financial Officer | |||
(Principal Financial Officer & Principal Accounting Officer) |