ITEM 1 - BUSINESS
GENERAL BUSINESS DESCRIPTION
Overview
Sonoran Energy, Inc. (the "Company", "Sonoran" and sometimes "we," "us," "our" and derivatives of such words), formerly named Showstar Online.com Inc., was incorporated on July 14, 1995 in the State of Colorado as Cerotex Holdings, Inc. The shareholders of the Company approved a change in corporate domicile to Washington State, which became effective on September 15, 2000. On June 3, 2002 the Company changed its name to Sonoran Energy, Inc. and after a new Board and Management team took over the Company in 2004, began the transition into an oil and gas exploration and production company, developing and producing crude oil and natural gas. Sonoran's portfolio during the reporting period consisted of company operated assets located in Louisiana and Texas as well as an outside operated interest in a project in Jordan. Our operational focus is on property enhancement through solid technical work, well re-entries, developmental and redevelopment drilling, operating cost reduction, asset redeployment and value driven acquisitions of properties in the right circumstances.
The principal assets of the company consists of proved and unproved oil and gas properties in Louisiana and Texas along with the related oil and gas production equipment necessary to operate the properties. The Company is currently concentrating its energies on domestic projects, but has signed a production sharing agreement for the Azraq block with the Government of Jordan.
Business Strategy
We are an independent oil and gas company engaged in the acquisition, development, production and exploration of oil and gas properties located primarily in North America. Our primary objective is to increase shareholder value. To accomplish this objective, our business strategy is focused on the following:
Further Exploitation of Existing Properties. We seek to add proved reserves and increase production through the use of advanced technologies, including detailed reservoir engineering analysis, drilling development wells utilizing sophisticated techniques and selectively recompleting existing wells. We also focus on reducing the operating costs associated with our properties. We believe that the properties we have acquired have significant potential and in certain cases have not been actively developed in the past.
Property Portfolio Management. We regularly evaluate our property base to identify opportunities to divest non-core, higher cost or less productive properties with limited development potential. This strategy allows us to focus on a portfolio of core properties with significant potential to increase our proved reserves and production.
Pursuit of Strategic Acquisitions. We regularly review opportunities to acquire producing properties, leasehold acreage and drilling prospects. We seek negotiated transactions to acquire operational control of properties that we believe have significant exploitation and exploration potential. Our strategy includes a significant focus on increasing our holdings in fields and basins in which we already own an interest.
Maintenance of Financial Flexibility. We believe the company should be structured and financed so that internally generated cash flows cover all operating expenses, general and administrative expense and interest expense, that drawn borrowing capacity should be used for lower risk development expenditures and that the capital markets should be used to fund acquisitions of producing properties and leasehold acreage, and to fund higher risk development and exploration activities.
Strategic alignment. We have secured through the alignment with our strategic partnerships a unique ability to analyze and operate both our existing properties and future potential acquisitions. When our domestic production has reached a critical mass, we plan to re-evaluate the suitability of adding an exploratory and/or International component to our strategy.
Risk management. The Company has used commodity price derivatives in the past to reduce our exposure to price fluctuations and reserves the right to do so in the future, if management believes that such derivatives will improve the balance between risk and rewards.
We generally seek to be the operator of our assets, in order to better direct and control activities and budgets.
DESCRIPTION OF BUSINESS - OIL AND GAS OPERATIONS
EXPLORATION AND DEVELOPMENT
The oil and gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and gas, as well as, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, locating and obtaining sufficient rig availability, and obtaining purchasers and transporters of the oil and gas we produce. There is also competition between oil and gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States; however, it is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and gas and may prevent or delay the commencement or continuation of a given operation. The exact effect of these risk factors cannot be accurately predicted.
GENERAL
During the fiscal year 2008, the Company focused on ensuring the necessary funding for our development operations in Louisiana and Texas. This was primarily done by entering into a loan agreement with Standard Bank (as primary lender). A number of equity investments were also undertaken in support of the debt structure to provide additional funding to continue our development. The actual development operations performed are described below under the individual property sections.
Sonoran also committed a significant amount of effort to improving our administrative, financial, and accounting operations. This included projects to assess financial risk and identify and implement appropriate internal controls. The overall project was designed to ensure compliance with the requirements of Sarbanes Oxley, but included additional measures to increase efficiency and improve the accuracy of the financial and operating information available to management. A prime example of our efforts in this area was the implementation of ENERTIA which is an integrated finance, accounting, production and land system that we believe has resulted in significant important improvement in our administrative functions. We completed our Phase 1 implementation, which covered financial accounting and reporting during the third quarter. Preliminary work on the production and land functions was also completed but additional enhancements will be implemented in the coming fiscal year. ENERTIA provides a viable platform for implementing a comprehensive set of improvements in our finance/accounting control environment and will be a significant enabler in our efforts to improve our financial accounting practices.
OIL AND GAS PRODUCTION OPERATIONS
Louisiana Property
The Company has working interests in (8) production wells and four (4) associated salt water disposal wells (SWD) located in Beauregard, Livingston, Rapides and Vernon parishes in Louisiana from the Austin Chalk reservoir.
During fiscal year 2008, the Company’s most significant operational effort was the Louisiana well workover program. This program was designed to clean out a salt water disposal well and restore two high-impact wells to production. We consider this a high-risk project for our Company due to the depth and cost associated with deep Austin Chalk wells (>18,000 ft.). The Company sought to mitigate this risk by engaging
major service companies and by bringing in outside technical experts with specific local knowledge to supplement our internal engineering resources. Overall, the potential rewards, which included the opportunity to significantly increase production, were sufficient to justify the project. However, a number of challenges were encountered, and, although much was learned about the reservoir from the operation, we were not able to bring the two wells into production. Specifically, the Company successfully removed a metal fish from the Crosby 25 #1SWD well, replummed the Crosby 25-1 (also removed a metal fish), and repaired a tubing hole in the Crosby 36 and readied it for a short side-track. However, the down hole conditions of the wells were much worse than anticipated and will require an additional intervention for each well. During March 2008, the Company decided to temporarily suspend its workover program in Louisiana to concentrate resources in other operations. We believe our efforts on these properties will provide a significant benefit as we design and implement the next phase of interventions. The timing of interventions on other Louisiana properties was delayed due to the effort and cost associated with these properties. The Company is currently planning a new round of interventions on these Louisiana wells during the first half of fiscal year 2009.
East Texas Property
The JRC/Lisa Layne, fields in Wood County, Texas comprise six producing wells and three water disposal wells. Five of the producing wells are completed in the Paluxy reservoir with the remaining producer completed in the Sub-Clarksville formation. The Ann McKnight Unit is located in Smith County, Texas, and has two production wells and one water injection well. During the year, the #101 well produced utilizing a submersible electrical pump and the #201 well produced using a rod-pumping system before it was shut-in due to a tubing hole.
During fiscal year 2008, a number of improvements were implemented in the salt water disposal system of the JRC/Lisa Layne field. The most significant was the installation of a new high pressure surface ESP pump and the replacement of older flow lines. Unfortunately, production from the area was reduced by higher than expected injection pressure in our SWD wells due to scaling and fill. The condition of the well was assessed in fiscal 2008 with a workover planned for early fiscal 2009. The company expects to see greater reliability and increased production from the JRC/Lisa Layne Field in the coming year.
Central Texas Property
The KWB Unit is located near San Angelo, Texas and comprises approximately 3,113 acres. The KWB Unit is located on the western side of the eastern shelf of the Permian Basin. The Unit contains numerous productive units in the Strawn, Canyon, and Cisco horizons, as well as at least three additional zones of interest. Both the Strawn & Canyon Reservoirs at KWB are very NGL-rich, with gas MMBTU contents of 1,200-1,500/Mcf. This high NGL content represents an additional revenue stream for each well producing at KWB.
KWB was acquired by Sonoran in fiscal year 2005 but remained inactive until fiscal year 2007. After an in-depth technical review, a significant field re-development commenced in the last quarter of fiscal 2007 with the construction of new roads, the laying of liquid and gas pipe-lines, fabrication of a central production facility, and ultimately with the successful re-completion and stimulation of five wells in the Canyon Formation Sonoran realized first sales from the KWB field in April 2007.
Upon acquisition, the KWB Unit contained 63 cased inactive wells, and 25 plugged wells, with an estimated 93.5% of the Strawn’s original oil in-place still un-produced.
By the end of April 2008, Sonoran had re-entered, recompleted, and completed initial assessment on a total of 13 wells. As of year-end, there were 10 active producers, with re-completions continuing across the field.
West Texas Property
Sonoran’s Reeves County, Texas asset consists of four inactive wells and approximately 880 acres. These wells were initially completed as gas wells, but since the time of Sonoran’s acquisition, the wells have remained shut-in pending review. A preliminary technical evaluation of these wells indicated that probable reserves were sufficient
to warrant further study. Well intervention options are currently being studied, but the timing of future interventions is still under development.
Azraq Production Sharing Agreement (Azraq PSA)
The Azraq block sits on the same trend as several other productive basins in the Middle East, yet remains relatively under-explored with limited use of modern seismic, drilling and production technology. The Azraq PSA covers an area of approximately 11,250 square kilometers offering a number of exploration plays.
On July 16, 2007, we entered into an agreement with SM Seven Holdings Limited and Sonoran Energy Jordan for operations in the Azraq PSA. This agreement allows us to focus more on our domestic operations, while maintaining a suitable interest in the project and its potential upside.
MARKETING OF CRUDE OIL AND NATURAL GAS
During fiscal 2008, the Company sold all of its products to Texon LP under contracts that generally have a fixed primary term and then convert to a month to month basis. Since the contract reference industry price indices we are not concerned about the short term nature of the contracts or that we have committed to sell our production to one buyer. For the year ending April 30, 2008 the average value realized for oil was $ 81.18 per barrel, gas was $6.83 per Mcf and plant products was $51.34 per barrel.
We plan to continue to sell our current production under the terms of the above referenced contracts. However, we will also continue to monitor and review these contracts to maximize the value of our production.
During fiscal year 2007, Crude oil from the Louisiana properties was sold to Texon LP under the terms of an existing contract between Sonoran Energy and Texon LP on a month to month basis. For the year ending April 30, 2007 the average value realized for oil was $ 60.79 per barrel.
Crude oil from a portion of the East Texas properties was sold to Eastex Crude Company for most of 2007 based on agreements effective at the time of the purchase of the working interests in November 2004. The remainder of the production was sold to Plains Marketing, LP under a contract dated October 1, 2005 to November 1, 2005, and month to month thereafter. For the year ending April 30, 2007 the average value realized for oil from the East Texas properties was $ 61.90 per barrel.
During fiscal year 2007, natural gas sold from the Louisiana properties was sold under the terms of a contract between Sonoran Energy Inc. and Cokinos Natural Gas Company effective September 1, 2005 to March 31, 2006, and month to month thereafter to August 31, 2006. The Company then sold its natural gas to Texon LP starting in October 2006 under a contract effective September 1, 2006 to September 1, 2007 and monthly thereafter. For the year ending April 30, 2007 the average value realized for the gas was $6.09 per Mcf.
Natural gas from our West Texas properties is sold to Targa field Services LP under a gas purchase agreement dated February 1, 2007. The terms of this agreement provide for the company to receive a share of the natural gas liquids extracted by Targa. The average value realized for our gas was $7.63 per Mcf ( including natural gas liquids) for the year ending April 30, 2007.
There were no sales of crude oil from our West Texas properties during fiscal year 2007. The company entered into a crude oil sales contract with Texon LP effective May 1, 2007.
OFFICES
The Company’s executive office is located at 14180 Dallas Parkway, Suite 400, Dallas, Texas where we lease approximately 10,349 square feet of office space under a lease expiring March 31, 2012.
As of April 30, 2008 the Company had 12 employees based in Louisiana and Texas. In addition, Sonoran currently has long term contracts for operational and other support with qualified personal within the areas of operations. The
Company may also enter into additional contracts for field level personnel (i.e., pumpers, rig crews, roustabouts and equipment operators) that perform basic daily activities associated with producing oil and gas. Daily operations include inspections of surface facilities and equipment, gauging, reporting and shipping oil, and routine maintenance and repair activities on wells, production facilities and equipment. In the event operations are controlled by a Joint Venture agreement and or operated by other parties, the operator nominated within the Joint Venture agreement will contract necessary field personnel.
ITEM 1A.
ITEM 1A. RISK FACTORS
Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.
Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and gas that we can economically produce and have an adverse effect on the value of our properties. Prices for oil and gas have increased significantly and been more volatile over the past twelve months. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:
· the domestic and foreign supply of oil and gas;
· the ability of members of the Organization of Petroleum Exporting Countries, or OPEC, and other
producing countries to agree upon and maintain oil prices and production levels;
· political instability, armed conflict or terrorist attacks, whether or not in oil or gas producing regions;
· the level of consumer product demand;
· the growth of consumer product demand in emerging markets, such as China;
· weather conditions, including hurricanes;
· the price and availability of alternative fuels;
· labor unrest in oil and gas producing regions;
· the price of foreign imports; and
· worldwide economic conditions.
These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and gas.
Assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
Our recent growth is due significantly to acquisitions of properties and undeveloped leaseholds. We expect that acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and gas prices, operating and capital costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.
As a result of these factors, we may not be able to acquire oil and gas properties that contain economically recoverable reserves on acceptable terms or we may acquire reserves that become uneconomic.
Estimates of oil and gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.
This report on Form 10-K contains estimates of our proved oil and gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploitation and development, prevailing oil and gas prices and other factors, many of which are beyond our control.
Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of these oil and gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, we cannot assure you that the estimated costs or estimated reserves are accurate, that development will occur as scheduled or that the actual results will be as estimated.
We intend to fund our development, acquisition and exploitation activities in part through additional debt financing. A higher level of debt could negatively impact our financial condition, results of operations and business prospects.
As of April 30, 2008, we had approximately $22.3 million of current liabilities, including $12.0 million (before discount of $0.6 Million) of a senior secured credit facility that is required to be repaid over the next three years in quarterly installments of $1.5 million starting October 31, 2008. We are currently not in compliance with our negative debt covenants associated with our senior secured credit facility. We will need to restructure our debt facility and procure additional debt in order to fund our development, acquisition and exploration activities or for other purposes. Our level of debt and the covenants contained in the agreements governing our debt could have important consequences, including the following:
· a high level of debt may impair our ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions, general corporate or other purposes;
· a leveraged financial position would make us more vulnerable to economic downturns and could limit
our ability to withstand competitive pressures; and
· any debt that we incur may be at variable rates which make us vulnerable to increases in interest rates.
The operation of our wells may not be profitable or achieve our targeted returns.
We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are dependent upon the current and future market prices for oil and gas, costs associated with producing oil and gas and our ability to add reserves at an acceptable cost.
In addition, we may not be successful in implementing our business strategy of controlling and reducing our production costs in order to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:
· unexpected drilling conditions;
· pressure or irregularities in formations;
· equipment failures or accidents;
· adverse weather conditions, including hurricanes;
· compliance with governmental requirements; and
· shortages or delays in the availability of drilling rigs and the delivery of equipment.
Current levels of production are inadequate to support the operations of the Company and permit a profit.
If we continue to be unable to generate sufficient cash flow from operations to service our debt, we may have to obtain additional financing through the issuance of debt and/or equity. We cannot be sure that any additional financing will be available to us on acceptable terms. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. The level of our debt financing could also materially affect our operations.
If our revenues were to decrease due to lower oil and gas prices, decreased production or other reasons, and if we could not obtain capital through our senior revolving credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves or maintain production levels could be greatly limited.
We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.
Our future performance will be substantially dependent on retaining key members of our existing management. The loss of the services of any of our existing executive officers or key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. As a result of increasing levels of exploration and production in response to strong prices of oil and natural gas, the demand for oilfield services has risen, and the costs of these services are increasing, while the quality of these services may suffer. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in Texas and Louisiana, we could be materially and adversely affected because our operations and properties are concentrated in those areas.
The marketability of our oil and gas production depends on services and facilities that we typically do not own or control. The failure or inaccessibility of any such services or facilities could result in a curtailment of production and revenues.
The marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Pursuant to interruptible or short term transportation agreements, we generally deliver gas through gathering systems and pipelines that we do not own. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. If any of the pipelines or other facilities becomes unavailable, we would be required to find a suitable alternative to transport and process the gas, which could increase our costs and reduce the revenues we might obtain from the sale of the gas. Oil is currently trucked from our locations and is not dependent on the availability of pipelines.
Our business is highly competitive.
The oil and gas industry is highly competitive in many respects, including identification of attractive oil and gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and, in some cases, with more expertise. There can be no assurance that we will be able to compete effectively with these entities.
Our oil and gas activities are subject to various risks which are beyond our control.
Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and gas. Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and gas in commercial quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest. Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:
· human error, accidents, labor force and other factors beyond our control that may cause personal injuries
or death to persons and destruction or damage to equipment and facilities;
· blowouts, fires, hurricanes, pollution and equipment failures that may result in damage to or destruction
of wells, producing formations, production facilities and equipment;
· unavailability of materials and equipment;
· engineering and construction delays;
· unanticipated transportation costs and delays;
· unfavorable weather conditions;
· hazards resulting from unusual or unexpected geological or environmental conditions;
· environmental regulations and requirements;
· accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids, into the
environment;
· changes in laws and regulations, including laws and regulations applicable to oil and gas activities or
markets for the oil and gas produced;
· fluctuations in supply and demand for oil and gas causing variations of the prices we receive for our oil
and gas production; and
· the internal and political decisions of OPEC and oil and natural gas producing nations and their impact
upon oil and gas prices. As a result of these risks, expenditures, quantities and rates of production,
revenues and cash operating costs may be materially adversely affected and may differ materially from
those anticipated by us.
Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, because we acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage caused by the former operators.
We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and gas activities.
We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:
· personal injury
· bodily injury
· third party property damage
· directors and officers liability
· legal defense costs
· pollution in some cases
· well blowouts in some cases
· workers compensation.
There can be no assurance that this insurance coverage will be sufficient to cover every claim made against us in the future. A loss in connection with our oil and natural gas properties could have a materially adverse effect on our financial position and results of operation to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.
REGULATIONS
In the United States, legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations have a significant impact on oil and gas drilling, gas processing plants and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, Sonoran is unable to predict the future cost or impact of complying with these laws and regulations. Sonoran considers the cost of environmental protection a necessary and manageable part of its business. Sonoran has been able to plan for and comply with new environmental initiatives without materially altering its operating strategies.
Exploration and Production. Sonoran's operations are subject to various types of regulation at the federal, state and local levels. These regulations include requiring permits for the drilling of wells; maintaining prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface plugging and abandoning of wells and the transporting of production. Sonoran's operations are also subject to various conservation matters, including the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition state conservation laws establish maximum rates of production oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas Sonoran can produce from its wells and to limit the number of wells or the locations at which Sonoran can drill.
Environmental. Our exploration, development, and production of oil and gas, including our operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. Such laws and regulations can increase the costs of planning, designing, installing and operating oil and gas wells. Our domestic activities are subject to a variety of environmental laws and regulations, including but not limited to, the Oil Pollution Act of 1990 ("OPA"), the Clean Water Act ("CWA"), the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), the Clean Air Act ("CAA"), and the Safe Drinking Water Act ("SDWA"), as well as state regulations promulgated under comparable state statutes. We are also subject to regulations governing the handling, transportation, storage, and disposal of naturally occurring radioactive materials that are found in our oil and gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities, limit or prohibit other activities because of protected areas or species, and impose substantial liabilities for cleanup of pollution.
Under the OPA, a release of oil into water or other areas designated by the statute could result in the company being held responsible for the costs of remediating such a release, certain OPA specified damages, and natural resource damages. The extent of that liability could be extensive, as set forth in the statute, depending on the nature of the release. A release of oil in harmful quantities or other materials into water or other specified areas could also
result in the company being held responsible under the CWA for the costs of remediation, and civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws, can impose joint and several and retroactive liability, without regard to fault or the legality of the original conduct, on certain classes of persons for the release of a "hazardous substance" into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Potentially liable parties include site owners or operators, past owners or operators under certain conditions, and entities that arrange for the disposal or treatment of, or transport hazardous substances found at the site. Although CERCLA, as amended, currently exempts petroleum, including but not limited to, crude oil, gas and natural gas liquids from the definition of hazardous substance, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA. Furthermore, there can be no assurance that the exemption will be preserved in future amendments of the act, if any.
RCRA and comparable state and local requirements impose standards for the management, including treatment, storage, and disposal of both hazardous and non-hazardous solid wastes. We generate hazardous and non-hazardous solid waste in connection with its routine operations. From time to time, proposals have been made that would reclassify certain oil and gas wastes, including wastes generated during drilling, production and pipeline operations, as "hazardous wastes" under RCRA which would make such solid wastes subject to much more stringent handling, transportation, storage, disposal, and clean-up requirements. This development could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and gas wastes could have a similar impact.
Because oil and gas exploration and production, and possibly other activities, have been conducted at some of our properties by previous owners and operators, materials from these operations remain on some of the properties and in some instances require remediation. In addition, in certain instances we have agreed to indemnify sellers of producing properties from which we have acquired reserves against certain liabilities for environmental claims associated with such properties. While we do not believe that costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, there can be no guarantee that such costs will not result in material expenditures.
Additionally, in the course of our routine oil and gas operations, surface spills and leaks, including casing leaks, of oil or other materials occur, and we incur costs for waste handling and environmental compliance. Moreover, we are able to control directly the operations of only those wells for which we act as the operator. Management believes that the company is in substantial compliance with applicable environmental laws and regulations.
We do not anticipate being required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. There can be no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future.
Occupational Health and Safety. Sonoran is also subject to laws and regulations concerning occupational safety and health. Due to the continued changes in these laws and regulations, and the judicial construction of many of them, Sonoran is unable to predict with any reasonable degree of certainty its future costs of complying with these laws and regulations. Sonoran considers the cost of safety and health compliance a necessary and manageable part of its business. Sonoran has been able to plan for and comply with new initiatives without materially altering its operating strategies.
Sonoran is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as CERCLA and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Sonoran has used discounting to present value in determining its accrued liabilities for environmental remediation or well closure, but no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Sonoran's financial
statements. Sonoran adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.
TAXATION
The operations of the Company, as is the case in the petroleum industry generally, are significantly affected by federal tax laws. Federal, as well as state, tax laws have many provisions applicable to corporations which could affect the future tax liability of the Company. We have filed our US Federal tax returns through fiscal years ending 2004. As additional returns are filed, the Company will continue to develop detail tax records that could alter the relationship between book and tax income.
ENVIRONMENTAL
The Company's activities are subject to existing federal and state laws and regulations governing environmental quality and pollution control. These laws may require the acquisition of permits relating to certain ongoing operations, for drilling, emissions, waste water disposal and other air and water quality controls. In view of the uncertainty and unpredictability of environmental statutes and regulations, the Company cannot ensure that such laws and regulations will not materially and adversely affect the business of the Company. The Company does not anticipate any material effect on its capital expenditures or earnings as the result of governmental regulations, enacted or proposed, concerning environmental protection or the discharge of material into the environment.
COMMITMENTS AND CONTINGENCIES
Sonoran is liable for future restoration and abandonment costs associated with its oil and gas properties. These costs include future site restoration, post closure and other environmental exit costs. The estimated costs of future restoration and well abandonment are reviewed annually for each well and we are recognizing the costs through annual charges to expense. State regulations require operators to post bonds that assure that well sites will be properly plugged and abandoned. Each state in which Sonoran operates requires a security bond varying in value from state to state and depending on the number of wells that Sonoran operates. Management views this as a necessary requirement for operations within each state and does not believe that these costs will have a material adverse effect on its financial position as a result of this requirement.
ITEM 1B
ITEM 1B - UNRESOLVED STAFF COMMENTS
This section is not required of a smaller reporting company.
ITEM 2
ITEM 2 - PROPERTIES
(a) DESCRIPTION OF PROPERTY
The principal assets of the Company consist of proved and unproved oil and gas properties along with oil and gas production related equipment acquired as part of the leases. The properties are described above in the “Oil and gas production operations” section in this report.
b) RESERVES, ACREAGE AND SALES PRICE
Reserve data for April 30, 2008 was prepared by Haas Petroleum Engineering Services, Inc., Independent Petroleum Engineers. Information concerning the change in volumes and the present value of future net revenue from these proved reserves is shown in Note 17 of Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K .
The East Texas, KWB and Louisiana properties have proved net reserves as of April 30,
(1) The following table shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with generally accepted accounting principles, or GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our gas and oil properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating gas and oil companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that many other companies in the oil and gas industry calculate PV-10 on the same basis.
PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
The Company cautions that there are many inherent uncertainties in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available, and these changes could be material.
The Company's estimated future net recoverable oil and gas reserves, noted above, have not been filed with any other Federal authority or agency.
Sonoran's net share of the oil and gas wells and acreage after royalty and other working interests for the past three years ending April 30, were as follows:
Sonoran did not participate in the drilling of any new wells on any property that they operated in fiscal 2008 however nine re-completions were undertaken.
Sonoran's average sales prices for the month of April 2008 per barrel or per MCF of crude oil and natural gas, respectively, and production costs per equivalent barrel (gas production is converted to equivalent barrels at the rate of 6 MCF per barrel, representing the estimated relative energy content of gas to oil) for the past three years ending April 30, were as follows:
The lower operating costs reflect the fact that the Company now operates its own properties and a dramatic reduction in the high level of intervention and supervision needed in prior years. The high level of operating costs in 2007 and 2006 was also driven by the start up nature of our assets. Because these assets had not been in production for a number of years they required a high level of intervention and supervision. We expect to continue to decrease cost per BOE as we increase efficiency by reducing production interruptions.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
Wells Land and Cattle Co., Inc., et.al. v. Sonoran Energy, Inc.
On or about May 18, 2007 Wells Land and Cattle Co., Inc., et al, filed a lawsuit alleging that Sonoran was illegally disposing of salt water into a salt water disposal well on their property, that Sonoran routinely trespasses on its land to reach another well which is not located on plaintiff’s land, that Sonoran spilled salt water onto Plaintiff’s land, and that an oil well lease covering one well has expired due to lack of production. Plaintiff claims that damages exceed $1,000,000 and asks the court for a permanent injunction against Sonoran from trespassing on Plaintiff’s property for the purpose of reaching the disposal well that is not on its property. Sonoran intends to vigorously defend its actions in this matter and anticipates that the matter will be eventually settled for an immaterial amount.
Korker Diversified Holdings Inc. v. Savings Plus Internet and Sonoran Energy, Inc.
During August 2000, the Company was named as a defendant in a lawsuit filed in British Columbia related to Savings Plus’s failure to repay a $35,000 loan that it received from Korker. During April 2008, the Company agreed to withdraw its appeal and committed to pay a total of $145,000 in 8 monthly installments of $15,000 and a final payment of $25,000. The cost of this settlement has been fully accrued as of April 30, 2008.
BPR Energy Inc
A former contract operator filed a $1,200,000 lien against our properties in Louisiana alleging non-payment of invoices. The Company disputed the validity of many of these invoices and believes that the operator may have significantly overcharged for the services provided. We dismissed the former operator and hired employees to handle the field operations internally. We withheld payments from the former operator pending our efforts to reach an acceptable settlement arrangement. On November 19, 2007, the Company settled all outstanding issues with the former operator. The financial terms of the settlement are subject to a confidentiality agreement; however, the Company recognized a credit to lease operating expense as of October 31, 2007 in the amount of approximately $105,000 as a result of settling the outstanding invoices for less than the liability that was recorded at October 31, 2007.
Crowell ., et.al. v. Sonoran Energy, Inc.
On or about August 28, 2007, a Louisiana land owner filed a lawsuit alleging that Sonoran contaminated ground water by improper operations of our salt water disposal facilities. The plaintiff is requesting a fund to be established for environmental studies and related remediation along with punitive damages for failure to plug and abandon the site. The properties involved have not been active since they were acquired by the Company and any operational issues are related to activities carried out under the former owner and operator. Since we have already recorded an adequate amount to cover plugging and abandonment activities, we believe that insurance coverage and recoveries from previous operators will limit our exposure in this matter to an immaterial amount.
ITEM 4
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5
ITEM 5 - MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) PRICE RANGE OF COMMON SHARES
The common stock of Sonoran is traded through the National Quotation Bureau under the symbol "SNRN". The following are high and low bid prices for each quarter of 2008 and 2007, and reflect inter-dealer prices without retail markup, markdown or commission.
The Company has paid one dividend on its common shares in the past five years. In July 2003, the Company announced an 8% Unit dividend and warrant (one warrant for every 10 shares held) payable August 22, 2003 to shareholders of record on July 25, 2003. The warrants expired on July 25, 2005 and the exercise period was not extended.
We have never paid cash dividends on our common stock. We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the
board of directors and will be dependent upon then existing conditions, including our prospects, debt structure, and such other factors, as the board of directors deems relevant.
Approximately 771 shareholders of record as of April 30, 2008 held our common stock. In many instances, a registered shareholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA.
The following table sets forth selected financial data, derived from the consolidated financial statements, regarding our financial position and results of operations as of the dates indicated. Future results may differ substantially from historical results because of changes in oil and natural gas prices, production declines and other factors.
This information should be read in conjunction with the Company’s financial statements and notes thereto and Management’ Discussion and Analysis of Financial Conditions and Results of Operations presented elsewhere herein.
Overall revenue decreased from last year to this year, due to the change of other income items and the end of existing consulting contracts of $411,192 offset by an increase in revenue from Oil and Gas operations of $225,867. Lease operating expenses and general and administrative costs showed a significant decline due to cost reduction measures in both areas. Other expenses have continued to increase this year due to interest expense and refinance charges.
Total Assets continue to increase yearly as additional wells are added and capital is used to enhance production. Liabilities are also increasing year to year in conjunction with development of production areas. The significant increase in current liabilities in 2008 was driven by the costs associated with our Louisiana recompletions.
ITEM 7
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
The information in this report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. This Act provides a “safe harbor” for forward-looking statements to encourage companies to provide prospective information about themselves provided they identify these statements as forward looking and provide meaningful cautionary statements identifying important factors that could cause actual results to differ from the projected results. All statements other than statements of historical fact made in this report are forward looking. In particular, the statements herein regarding industry prospects and future results of operations or financial position are forward-looking statements. Forward-looking statements reflect management’s current expectations and are inherently uncertain. Our actual results may differ significantly from management’s expectations as a result of many factors, including, but not limited to, the volatility in prices for crude oil and natural gas, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market competition, interruption in production, our ability to obtain additional capital, and the success of our development, marketing and operational activities.
You should read the following discussion and analysis in conjunction with the consolidated financial statements of Sonoran Energy, Inc. and subsidiaries and notes thereto, included herewith. This discussion should not be construed to imply that the results discussed herein will necessarily continue into the future, or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment of management.
Plan of Operation
We are an independent oil and gas company engaged in the acquisition, development, production and exploitation of oil and gas properties. Our current focus is on properties located in North America. When domestic production reaches a critical mass we will re-evaluate the suitability of adding an exploratory and international component to our strategy. Our primary objective is to increase shareholder value. To accomplish this objective, our business strategy is currently focused on further exploitation of existing properties. We seek to add proved reserves and increase production through the use of advanced technologies, including detailed reservoir engineering analysis, drilling development wells utilizing sophisticated techniques and selectively re-completing existing wells. We also focus on reducing the per unit operating costs associated with our properties. We believe that the properties we have acquired have significant potential and in certain cases have not been properly exploited in the past. We will also continue to look for opportunities, both internally and externally, to grow the company into a more substantial independent oil and gas company.
CRITICAL ACCOUNTING POLICIES
Use of Estimates
Under generally accepted accounting principles management is required to make use of estimates and assumptions that could affect the reported amounts on the financial statements and in disclosures in the notes to the financial statements at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Oil and Gas Producing Activity
The accounting for, and disclosure of, oil and natural gas producing activities requires that the Company choose between GAAP alternatives and that we make judgments regarding estimates of future uncertainties.
Sonoran Energy uses the full cost method of accounting, which requires capitalizing all acquisition, exploration, exploitation and development costs. When costs relating to unproved properties are incurred, they are capitalized in unproved properties. When costs are expended in drilling an exploratory well, those costs would initially be capitalized in wells-in-progress. When the work on an exploration well is finished, all costs relating to it, including those in unproved properties and wells-in-progress, are transferred to the full cost pool. When costs are expended in drilling a development well, those costs are immediately added to the full cost pool.
The Company reviews its unproved oil and natural gas properties periodically. While they still have economic value as unproved properties, these costs remain in unproved properties. When unproved properties become proved by virtue of having proved reserves discovered on them, then the cost associated with them is transferred to the full cost pool. If an unproved property becomes worthless, all cost associated with it is also transferred into the full cost pool. Unproved properties are not subject to depletion.
Depletion is calculated using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total amount of proved reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration, exploitation and development activities.
At the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). When computing our full cost ceiling limitation, we evaluate the limitation at the end of each reporting period date. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation for price changes that occur after the balance sheet to assess impairment as permitted by Staff Accounting Bulletin Topic 12-Oil and Gas Producing Activities.
The quarterly calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are always different from the quantities of oil and natural gas that are ultimately recovered.
In September 2004, the SEC released SAB No. 106 concerning the application of SFAS No. 143 “Accounting for Asset Retirement Obligations,” or SFAS No. 143, by oil and natural gas producing companies following the full cost method of accounting. In SAB No. 106, the SEC addressed the impact of SFAS No. 143 on the ceiling test calculation and on the calculation of depreciation, depletion and amortization. SAB No. 106 became effective for us on May 1, 2006 and has not had a significant impact on our ceiling test calculation. This change has not had a significant impact on our depreciation, depletion and amortization expense.
Stock based Compensation
Effective May 1, 2006, we adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, (“SFAS No. 123(R)”), which requires the measurement and recognition of compensation expense for all share-based payment awards to employees and directors based on estimated fair values. We adopted SFAS No. 123(R) using the modified prospective transition method. In accordance with modified prospective application provisions of SFAS No. 123(R), compensation cost for the portion of awards that were outstanding as of May 1, 2006, for which the requisite service was not rendered, are recognized as the requisite service is rendered, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). Additionally, compensation costs for awards granted after May 1, 2006 are recognized over the requisite service period based on the grant-date fair value. In accordance with the modified prospective transition method, our consolidated financial statements for prior periods have not been restated to reflect the impact of SFAS No. 123(R). In connection with the adoption of FAS 123(R) on May 1, 2006 we did not record compensation expense for options outstanding on that date because the requisite service period for all options outstanding had elapsed as of that date. However, we have recognized stock-based compensation expense of approximately $567,968 representing the grant-date fair value of shares and options granted during the year ended April 30, 2008, and for which the requisite service period elapsed. The Company recognized stock-based compensation expense of approximately $150,000 representing the grant-date fair value of shares and options granted during the year ended April 30, 2007.
New Accounting Pronouncements
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement 109. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. We adopted this standard effective May 1, 2007. As a result of the implementation of this standard, we recognized no adjustments in our provision for unrecognized income tax benefits.
We are subject to U.S. federal income tax and to the income tax of multiple state jurisdictions. We have evaluated the impact of this pronouncement by reviewing known differences between our financial accounting records and positions that we plan to take in our tax filings. The Company has filed its US Federal Tax returns through fiscal year ending 2004, but we believe our state tax returns are current. As US Federal Tax returns are filed, the Company will have to develop detail tax records and will have to make certain elections that could alter the relationship between book and tax income. The Company has initiated a project to develop appropriate tax records so that the delinquent returns can be completed. Since the Company has never been profitable, we believe there is no significant exposure to penalties or interest. The Company has a deferred tax asset related to future deductions for net operating loss carryforwards, which is reduced to zero value by a valuation allowance. Any changes in the deferred tax asset would be completely offset by an equal increase, or decrease, in our valuation allowance. To date, we do not anticipate that the filing of these returns will result in a material change to our financial condition, results of operations, or cash flows.
Our policy is to recognize potential interest and penalties related to income tax matters in income tax expense. We believe we have appropriate support for the income tax positions taken and to be taken on our US Federal income tax returns and that our accruals for tax liabilities are adequate for all open years based on an assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter.
In September 2006, Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS 157”), was issued. SFAS 157 provides guidance for using fair value to measure assets and liabilities. It applies whenever other standards require or permit assets or liabilities to be measured at fair value, but it does not expand the use of fair value in any new circumstances. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007. In February 2008, FASB issued FASB Staff Position No. FAS 157-2. This FSP defers the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair market value in the financial statements on a recurring basis (at least annually) to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of the FSP. We believe that the adoption of SFAS No. 157 will not have a material impact on our consolidated financial position, results of operations, or cash flows.
In February 2007, SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (“SFAS 159”), was issued. SFAS 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected are to be recognized in earnings at each subsequent reporting date. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The effect of adopting SFAS 159 has not been determined, but it is not expected to have a significant effect on our reported financial position, result of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” to improve reporting and to create greater consistency in the accounting and financial reporting of business combinations. The standard requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008, with the exception of the accounting for valuation allowances on deferred taxes and acquired tax contingencies. SFAS 141R amends SFAS 109, such that adjustments made to valuation allowances on deferred income taxes and acquired income tax contingencies associated with acquisitions that closed prior to the effective date of SFAS 141R would apply the provisions of SFAS 141R. An entity may not apply SFAS 141R before that date. Given SFAS 141R relates to prospective and not historical business combinations, the Company cannot currently determine the potential effects adoption of SFAS No. 141R may have on its consolidated financial statements.
In April 2008 the FASB issued FASB Staff Position No 142-3 (“FSP”), Determination of Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under Statement 142 and the period of expected cash flows used to measure the fair value of the asset under FASB Statement No. 141R , and other U.S. generally accepted accounting principles. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Management of the Company believes that the adoption of this FSP will not have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
LIQUIDITY AND CAPITAL RESOURCES
The Company had cash and cash equivalents of $612,998 at April 30, 2008 for a decrease of $90,510 when compared to April 30, 2007. The components of the changes in cash for 2008 are more fully described in the Statements of Cash Flows included in Item 8 of this Form 10-K.
During the third quarter of 2008, the Company obtained additional funding from Standard Bank under a new $15,000,000 credit facility (the Facility), which closed on November 29, 2007. The Company borrowed a total of $12,000,000 under this facility during the quarter which was used to repay the NGPC facility, repurchase an override from NGPC, and to partially fund its Louisiana work over program. The remaining $3 million dollars is not currently available, as the Company is expected to be in default of several covenants of the Facility by July 31, 2008. The funds raised under this facility were primarily used to conduct recompletions on two high impact Louisiana wells. However, the operations were suspended without achieving production. During March 2008 and June 2008, the Company obtained funds from two large shareholders to support its planned operations in West Texas. These operations have a lower risk profile, but take longer to provide the desired increase in production. The company has seen some successes in its West Texas operations, and higher oil prices have increased the feasibility of certain low cost well interventions in East Texas. While the two large shareholders have provided funds for developments over the past year, there is no assurance that they will continue to support the Company’s activities.
The Company projects that production levels in August will be sufficient to cover operating expenses and provide sufficient funding for operating and debt service requirements. However, the Company will need to seek additional debt or equity funds to continue to develop its assets including seeking a partner for its Louisiana project. The company believes that it will be able to obtain additional funding as needed to continue to meet the anticipated liquidity and capital resource needs of the Company for the fiscal year ending April 30, 2009.
Compliance with the negative covenants in the Facility is not required until after April 30, 2008. However, the Company is not currently in compliance and must make significant improvements to achieve compliance. The Company is currently negotiating a restructuring of the Facility. Accordingly, the full amount outstanding under the Facility is reported as a current liability. If an agreement is not reached, the company could be forced to seek protection from creditors. The Company expects to reach an agreement that will reduce cash requirements to an acceptable level.
The Company is not a party to off-balance sheet arrangements and does not engage in trading activities involving non-exchange traded contracts. In addition, the Company has no financial guarantees, debt or lease agreements or other arrangements that could trigger a requirement for an early payment or that could change the value of the Company's assets. Management continues to examine various alternatives for increasing capital resources
including, among other things, participation with industry and/or private partners and specific rework of existing properties to enhance production and expansion of its sales of crude oil and natural gas.
ANALYSIS OF SIGNIFICANT CHANGES IN RESULTS OF OPERATIONS
Results of Operations for the Years Ended April 30, 2008, 2007 and 2006 with comparisons:
REVENUES
Revenue decreased to $2,344,580 for the year ended April 30, 2008 from the $2,512,037 for the year ended April 30, 2007 due primarily to the lack of Scottsdale Oilfield Services consulting contracts which amounted to $411,192 in 2007 offset by an increase in revenue from Oil and Gas operations of $225,867 due primarily the increased Oil and Gas prices. The last of the consulting contracts ended in the last quarter of 2007 and the Company has not actively sought any further contracts.
Revenue increased to $2,512,037 for the year ended April 30, 2007 from the $1,938,234 for the year ended April 30, 2006 due primarily to increased production from our Louisiana properties.
Scottsdale Oil Field Services in 2007 added $411,192 of consulting revenue for the year ended April 30, 2007 compared to $396,890 for the year ended April 30, 2006. The last of the consulting contracts ended in the last quarter of the fiscal year ended April 30, 2007.
OIL AND GAS PRODUCTION COSTS
Production costs decreased to $1,363,784 for the year ended April 30, 2008 as compared to $1,789,825 for the year ended April 30, 2007. The decrease in cost is due to lower repairs and maintenance, supplies and consumables, transportation and engineering costs. We have also credited operational expense related to settlement of outstanding contract operator charges of $107,023. Workover expense increased from $144,827 in 2007 to $230,171 in 2008.
Production costs increased to $1,789,825 for the year ended April 30, 2007 as compared to $1,265,718 for the year ended April 30, 2006. The increase in cost is almost entirely attributed to the Louisiana operations which represent 86% of the total increase. The addition of the Strickland 17 #1, which was not producing in 2006, accounted for
$124,762 of the increase. Also included is an increase of $97,107 in workover expense from $41,110 for the year ended April 30, 2006 to $138,218 for the year ended April 30, 2007 related to the repair and maintenance of the saltwater handling system in East Texas. Continued high operating costs for our Louisiana properties during the year prompted a shift in operating philosophy, whereby we discontinued the use of a contract operator and hired employees to handle field operations. We also discontinued the use of certain rental equipment. The company disputed the validity of certain charges by the former field operator and has withheld payment on a significant portion of these expenses. As previously mentioned, a credit for a settlement of overcharges was recorded in 2008.
PROVISION FOR DEPLETION, DEPRECIATION AND AMORTIZATION
The provision for depletion, depreciation and amortization was $1,221,311 for the year ended April 30, 2008 compared to $611,553 for April 30, 2007. During this fiscal year the Company recorded a $12,871,984 increase in proved properties resulting in an increase in depletion expense of $583,867, including an increase in depreciation expense related to the addition to fixed assets of $25,891.
The provision for depletion, depreciation and amortization was $611,553 for the year ended April 30, 2007 compared to $245,444 for April 30, 2006. During this fiscal year the Company recorded a $16,200,000 increase in proved properties plus increased production resulted in an increase in depletion expense of $300,000. The increase in expense also reflects the addition to fixed assets.
IMPAIRMENT AND LEGAL SETTLEMENT EXPENSE
Impairment of goodwill:
During December 2006, we became aware that Scottsdale Oil Field Services’ business with its existing outside customers would cease sometime during 2007. As there is no future expected return to the levels at purchase date, the Company recorded an impairment charge on the Goodwill of the total value of $394,585 in the fiscal year ended April 30, 2007.
Legal Settlement expense:
The net amount of obligations relieved through the legal settlements that took place in June and September 2006, plus the value of our obligations incurred under those settlements, less costs we have incurred through April 30, 2008 has been recorded on our consolidated statements of operations for the year ended April 30, 2008 and 2007 under litigation settlement expense, as follows:
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses decreased $1,695,113 for the year ended April 30, 2008, when compared to the same period for 2007. The decrease is due primarily to decreased legal expense of $577,089 due to settlement of legal issues, decreased consultants fees of $480,706 because of lower usage, decreased travel of $144,063 due to limited international travel and relocation to Dallas, decreased relocation costs of $92,409, decrease in investor
relations expense of $244,281 from reductions in external consulting requirements, reduction in officer’s salaries of $168,016 and in stock compensation expense of $118,324 offset by increased accounting and audit expense of $251,520 due to increased audit scope and contractor costs related to the preparation of prior year tax returns and increased salaries and employee benefits of $57,844.
General and administrative expenses decreased $3,541,682 for the year ended April 30, 2007, when compared to the same period for 2006. The primary reasons for the decreases were a reduction in stock based compensation of $3,718,000, salaries and wages of $436,000 and consulting fees of $342,500. The decreases were partially offset by increased non-recurring legal fees of $550,000 for the two court cases settled in 2006, accounting and auditing fees of $160,000 and relocation expense of $100,000.
OTHER INCOME (EXPENSE)
Interest expense of $2,133,430 in the year ended April 30, 2008 increased $789,423 when compared to $1,344,007 incurred in the year ended April 30, 2007.
The Company increased its interest bearing debt by $4.9 million during the year ended April 30, 2008 through the entering into a new financing for $12.0 million offset by the repayment of $6.9 million of the old senior secured credit facility debt and conversion of $0.2 million of convertible debt to common shares. The early payout of the NGP loans resulted in a charge to Loss on debt extinguishment of $344,163 which represents deferred costs that would have been amortized over the life of the loan.
The new financing carried fees and set-up costs totaling $1,042,579 that are being amortized over the 36 month term of the loan resulting in a charge to interest expense of $120,647 for the year ended April 30, 2008. In addition, the new financing carried warrants that were valued at $643,076 that are being amortized over the 36 month term of the loan resulting in a charge to interest expense of $89,316 for the year ended April 30,2008. The increase in interest expense is attributed to the cost of NGP loan and the convertible debt for a longer period in 2008 plus the costs associated with the increased debt level in 2008.
The Company increased its interest bearing debt by $6.3 million during the year ended April 30, 2007 through the issuance of $1.1 million of new convertible debt plus entering into a financing with NGP for $6.9 million offset by the repayment of $1.7 million of old convertible debt. The early payout of the Cornell Financing resulted in an additional charge to interest of $154,000 that would have been amortized over the life of the Cornell loan.
The NGP financing carried fees and set-up costs totaling $675,939 that was expected to be amortized over the 15 month term of the loan resulting in a charge to interest of $225,313for the year ended April 30, 2007. In addition, the NGP financing carried warrants that were valued at $318,563 that was expected to be amortized over the 15 month term of the loan resulting in a charge to interest of $106,185 for the year ended April 30, 2007. The difference between the average monthly interest costs of the two loans added an additional $261,000 to expense for the year ended April 30, 2007 due to the higher borrowed amount.
ITEM 7A.
ITEM 7A. QUANTATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The carrying amounts reported in our consolidated balance sheets for cash and cash equivalents, trade receivables and payables, notes and long-term debt approximate their fair values.
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents and the interest rate paid on our borrowings, other than our 10% and 12% convertible notes. The Company has entered into a zero cost interest rate collar for its senior debt as discussed in Note 4, Interest Rate Covers, in the Notes to the Financial Statements in this Form 10K.
Commodity Price Risk
Our revenue, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell most of our oil and natural gas production under market price contracts.
To reduce exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow, and as required by a previous lender, we utilize various derivative strategies to manage the price received for a portion of our future oil and natural gas production. Crude oil and natural gas floors and ceilings for the year ended April 30, 2008 are discussed in Note 4, Oil and Gas Put Options, in the Notes to The Financial Statements in this Form 10K.
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS
SONORAN ENERGY, INC. AND SUBSIDIARIES
Index to Consolidated Financial Statements
Page
Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheet as of April 30, 2008 and 2007
Consolidated Statements of Operations for the years ended April 30, 2008 and 2007
Consolidated Statement of Changes in Shareholders' Equity for the years ended April 30, 2008 and 2007
Consolidated Statements of Cash Flows for the years ended April 30, 2008 and 2007
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors
Sonoran Energy, Inc.
Dallas, Texas
We have audited the consolidated balance sheet of Sonoran Energy, Inc. and subsidiaries (the “Company”) as of April 30, 2008, and the related consolidated statement of operations, changes in shareholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 audit provides a reasonable basis for our opinion.
We were not engaged to examine management’s assertion about the effectiveness of internal control over financial reporting as of April 30, 2008 included in the accompanying Annual Report on Form 10-K and, accordingly, we do not express an opinion thereon.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sonoran Energy, Inc. and subsidiaries as of April 30, 2008 and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States.
The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements the Company had a net working capital deficit of approximately $20.5 million, accumulated shareholders’ deficit of approximately $55.4 million, has continuing operating losses and is not in compliance with their restrictive debt covenants associated with the Senior Secured Credit Facility. These conditions raise substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
UHY
Dallas, Texas
August 13, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
Sonoran Energy, Inc.
Dallas, Texas
We have audited the consolidated balance sheet of Sonoran Energy, Inc. and subsidiaries (the “Company”) as of April 30, 2007, and the related consolidated statements of operations, changes in shareholders’ equity (deficit) and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sonoran Energy, Inc. and subsidiaries as of April 30, 2007, and the results of their operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.
HEIN & ASSOCIATES LLP
Dallas, Texas
August 13, 2007
a
SONORAN ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheet
April 30, 2008
See accompanying notes to consolidated financial statements
SONORAN ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
See accompanying notes to consolidated financial statements
SONORAN ENERGY, INC. AND SUBSIDIARIES
Consolidated Statement of Changes in Shareholders’ Equity/ (Deficit)
For the Years Ended April 30, 2007 and 2008
See accompanying notes to consolidated financial statements
SONORAN ENERGY, INC. AND SUBSIDIARIES
Consolidated Statement of Cash Flows
See accompanying notes to consolidated financial statements
SONORAN ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
April 30, 2008
Note 1: Nature of Organization and Summary of Significant Accounting Policies
Nature of Organization
Sonoran Energy, Inc. (the "Company") was incorporated under the laws of Colorado as Cerotex Holdings, Inc. on July 14, 1995. The Company's shareholders approved a change of corporate domicile to Washington State, which became effective on September 15, 2000. Prior to June 2002, the Company developed software and an art site on the Internet. The Internet project was terminated in April 2002. On June 3, 2002, the Company changed its name to Sonoran Energy, Inc. and entered the oil and gas industry. The Company's primary objective is to identify, acquire and develop oil and gas projects.
The Company has acquired interests in producing properties through leases on which it drills and/or operates oil or gas wells in efforts to discover and/or to produce oil and gas. The Company's interests in the properties vary depending on the percent interest available at the time of acquisition. At April 30, 2008, the Company owned working interests in oil and gas properties located within the states of Louisiana and Texas.
Basis of Consolidation
The consolidated financial statements include the accounts of Sonoran Energy, Inc., Scottsdale Oil Field Services Ltd. and Baron Oil AS and its wholly owned subsidiary. All significant intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates
In preparing financial statements in conformity with accounting principles generally accepted in the United States, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserve volumes, future development, dismantlement and abandonment costs, share-based compensation expenses, estimates relating to certain oil and natural gas revenues and expenses and the fair market value of derivatives and equity securities. Actual results may differ from management’s estimates.
Cash Equivalents
For the purposes of the statement of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.
The Company places its cash and cash equivalents with high quality institutions. At times such cash may be in excess of the FDIC insurance limit.
Fixed Assets
Fixed assets are recorded at cost, less accumulated depreciation. Major items and betterments are capitalized; minor items and repairs are expensed as incurred. Depreciation expense is computed under the straight-line method over the estimated useful lives of the assets ranging from 3 years to 5 years. Depreciation expense on equipment was $88,439 and $62,547 for the years ended April 30, 2008 and 2007, respectively.
The Company’s fixed assets are made up of the following:
Goodwill
Goodwill represents the excess of the aggregate price paid by us over the value of the net equity acquired in the acquisition of Scottsdale Oil Field Services in 2006. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”, we no longer amortize goodwill, but are required to review goodwill for impairment at least annually or whenever events indicate that the carrying amount of the asset may not be recoverable in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”
As at April 30, 2008 the Company does not have a goodwill balance.
During December 2006, we became aware that Scottsdale Oil Field Services’ business with outside customers would cease sometime during 2007. As there is no future expected return to the levels at purchase date, the Company recorded an impairment charge on the Goodwill of the total value of $394,585 in the year ended April 30, 2007.
Intangible Assets
Our intangible assets consist of proprietary computer programs. These intangible assets are amortized on a straight-line basis over five years resulting in a charge to expense of $42,000 for each of the years ending April 30, 2008 and 2007.
Oil and Gas Producing Activities
The accounting for, and disclosure of, oil and natural gas producing activities requires that the Company choose between GAAP alternatives and that we make judgments regarding estimates of future uncertainties.
Sonoran Energy uses the full cost method of accounting, which requires the capitalization of all acquisition, exploration, exploitation and development costs. When costs relating to unproved properties are incurred, they are capitalized in unproved properties. When costs are expended in drilling an exploratory well, those costs are initially capitalized in wells-in-progress. When the work on an exploration well is finished, all costs including associated costs in unproved properties and wells-in-progress, are transferred to the full cost pool. When costs are expended to drill a development well, those costs are immediately added to the full cost pool.
The Company reviews its unproved oil and natural gas properties periodically. While they still have economic value as unproved properties, these costs remain in unproved properties. When unproved properties become proved by virtue of having proved reserves discovered on them, then the cost associated with them is transferred to the full cost pool. If an unproved property becomes worthless, all cost associated with it is also transferred into the full cost pool. Unproved Properties are not subject to depletion.
Depletion is calculated using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs associated with proven reserves are divided by the total amount of proved reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded.
At the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). When computing our full cost ceiling limitation, we evaluate the limitation at the end of each reporting period date.
The quarterly calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are always different from the quantities of oil and natural gas that are ultimately recovered.
In September 2004, the SEC released SAB No. 106 concerning the application of SFAS No. 143 “Accounting for Asset Retirement Obligations,” or SFAS No. 143, by oil and natural gas producing companies following the full cost method of accounting. In SAB No. 106, the SEC addressed the impact of SFAS No. 143 on the ceiling test calculation and on the calculation of depreciation, depletion and amortization. SAB No. 106 became effective for us on January 1, 2005 and has not had a significant impact on our ceiling test calculation. This change has not had a significant impact on our depreciation, depletion and amortization expense.
The Company recorded depletion expense of $1,090,874 and $507,006 for the years ended April 30, 2008 and 2007, respectively.
Revenue Recognition
The Company utilizes the sales method of accounting for crude oil and natural gas sales whereby revenues are recognized as the Company's share of the oil and gas is produced and delivered to a purchaser based upon its net revenue interest in the properties. The Company utilizes the accrual method of accounting for its consulting services recognizing income when services are provided.
Net loss per share
Net loss per basic share excludes dilution and is determined by dividing loss available to common shareholders by the weighted average number of common shares outstanding during the period. Net loss per diluted share reflects the potential dilution that could occur if securities and other contracts to issue common stock were exercised or converted into common stock. Due to the Company's losses, any inclusion of other securities to issue common stock would have an anti-dilutive effect on loss per diluted share.
The diluted net loss per shares excludes the effect of convertible preferred shares, common stock options and warrants exercisable into 298,353,935 shares of common stock and debt convertible into 4,560,239 shares of common stock because inclusion of such would be anti-dilutive for the year ended April 30, 2008,
Accounts Receivable
The Company's accounts receivable at April 30, 2008 and 2007 reflect amounts that are due from working interest owners in oil wells that the Company operates and the sale of crude oil and natural gas to several primary customers. The Company determines any required allowance by considering a number of factors including length of time trade accounts receivable are past due and the Company's previous loss history. Receivables are considered past due when they are unpaid greater than thirty days. The Company records a reserve account for accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to
the allowance for doubtful accounts. The Company has reviewed its Joint Interest Billing summary and identified potential uncollectible accounts in the amount of $70,815 which have been recorded as an allowance for doubtful accounts with a charge to bad debt expense of $30,087 for the year ended April 30, 2008. The Company recognized an allowance and expense of $40,728 for April 30, 2007 and there was no allowance or expense recorded in 2006.
Income Taxes
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due plus deferred taxes related primarily to differences between the recorded book basis and tax basis of assets and liabilities for financial and income tax reporting. The deferred tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Deferred taxes are also recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future income taxes.
Stock-Based Compensation
Effective May 1, 2006, we adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, (“SFAS No. 123(R)”), which requires the measurement and recognition of compensation expense for all share-based payment awards to employees and directors based on estimated fair values. We adopted SFAS No. 123(R) using the modified prospective transition method. In accordance with modified prospective application provisions of SFAS No. 123(R), compensation cost for the portion of awards that were outstanding as of May 1, 2006, for which the requisite service was not rendered, are recognized as the requisite service is rendered, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). Additionally, compensation costs for awards granted after May 1, 2006 are recognized over the requisite service period based on the grant-date fair value. In accordance with the modified prospective transition method, our consolidated financial statements for prior periods have not been restated to reflect the impact of SFAS No. 123(R). In connection with the adoption of FAS 123(R) on May 1, 2006 we did not record compensation expense for options outstanding on that date because the requisite service period for all options outstanding had elapsed as of that date. However, we have recognized stock-based compensation expense of approximately $567,968 representing the grant-date fair value of shares and options granted during the year ended April 30, 2008, and for which the requisite service period elapsed. The Company recognized stock-based compensation expense of approximately $150,000 representing the grant-date fair value of shares and options granted during the year ended April 30, 2007.
Fair Value of Financial Instruments
The Company's financial instruments, including cash, accounts receivables, current liabilities, and short-term debt, are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. Convertible debentures are carried at cost which approximates fair value because of fair value interest rates and discounts associated with the beneficial conversion feature.
Derivative financial instruments
In connection with the NGPC Credit Agreement, the company entered into oil and natural gas derivative financial instruments to protect against commodity price decreases and to achieve a more predictable cash flow. SFAS No. 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value unless such financial instruments are appropriately excluded under the normal purchases and normal sales exemption. SFAS
No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. We have not designated our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative’s fair value currently in earnings
Note 2: Continuance of Operations
These consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles applicable to a going concern which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. The general business strategy of the Company is to develop and operate its existing oil and gas properties, and to acquire additional properties. The Company has a working capital deficit of approximately $20.5 million, accumulated shareholders’ deficit of $55.4 million, has incurred continued operating losses, and requires additional capital to fund development activities, meet its obligations and maintain its operations. These conditions raise significant doubt about the Company's ability to continue as a going concern. Doubts are also raised by the fact that the Company is not in compliance with negative covenants of its $15,000,000 credit facility with Standard Bank, which closed on November 29, 2007 (Facility). . The Company is currently negotiating a restructuring of the Facility. However, due to the uncertainty regarding the Company’s ability to restructure the facility, the full amount outstanding is reported as a current obligation. The Company will continue to seek equity investments, restructure its Facility, and work on programs to develop its oil and gas properties. There can be no assurance, however, that these efforts will generate sufficient cash flow to meet its obligations or to continue its development program. Given the current commodity price environment, our ability to obtain financial support from our key shareholders, and the progress on development of our assets over the past few months, we expect to reach an acceptable resolution to remedy the expected default of the Facility’s covenants. If an agreement is not reached, the Company could be forced to seek protection from creditors. Subsequent to the year ended April 30, 2008, the Company has received continued support of key shareholders as evidenced by investments totaling $1,500,000 during June and July of 2008. These financial statements do not include any adjustments that might result from the uncertainty around continuance of operations.
Note 3: Related Party Transactions
During the year ended April 30, 2008 an officer of the Company purchased 800,000 shares at $0.125 per share, for total proceeds of $100,000.
During the year ended April 30, 2008 a director of the Company purchased 5,400,000 shares at $0.125 per share, for total proceeds of $675,000.
During the year ended April 30, 2008 a director of the Company purchased 1,000,000 shares at $0.119 per share, for total proceeds of $119,000.
During the year ended April 30, 2008 a major shareholder of the Company purchased 6,500,000 shares at $0.10 per share, for total proceeds of $650,000, exercised 20,000,000 warrants at $0.10 per share for a total of $2,000,000 and purchased 1,500,000 preferred shares at $1.00 per share for a total of $1,500,000.
A director of the Company acted as an escrow agent for $217,309 of funds that the Company had earned from a transaction related to our interest in the Azraq Production Sharing Agreement. The funds were received by the Company October 29, 2007 and his agency was concluded.
During the year ended April 30, 2007 Directors of the Company advanced funds to the Company in exchange for $295,000 in Convertible notes bearing interest at 10% on $270,000 and 12% on $25,000. The notes contain provisions for warrants at $0.55 per share and a convertible strike price of $0.23.
During the year ended April 30, 2008 members of the Board were issued stock in payment of 2006 accrued directors fees totaling $198,630.
During the year ended April 30, 2007 the Company hired a Consultant, to assist in developing the Louisiana program, from a Company managed by a member of the Board of Directors and incurring $189,000 in fees until February 2007 when the contract was completed.
During the year ended April 30, 2007 the Company contracted investor relations services, from a Company managed by a member of the Board of Directors and incurring $170,180 in fees. The fees were almost all earned four months prior to the member joining the Board. An additional $ 65,541 in fees was incurred during 2008.
Note 4: Other Assets
Certificate of Deposit
Prior to 2008, the Company was required to post a $50,000 bond with the state government for its operations in Louisiana. The funds were held by a financial institution in an investment certificate, which provided interest at a variable rate. During 2008, the bond was cancelled and replaced by a bond provided by the Company’s insurance carrier.
Loan Fees
The Company incurred debt issuance costs in connection with the Cornell Capital convertible debentures, the NGP Senior Secured Facility and the Standard Bank Facility. The Company amortizes these costs over the life of the debt resulting in the unamortized portion showing on the balance sheet. The specific costs and amortization expense are detailed in Note 6 in the notes to the consolidated financial statements.
Oil and gas put options
Pursuant to our senior credit agreement, we are required to enter into financial contracts to reduce the risk of changes in the commodity prices of a portion of our production at specified prices for oil and natural gas. The objective of the contracts is to reduce our exposure to commodity price risk associated with expected oil and natural gas production.
During the quarter ended January 31, 2007 we paid $494,290 to enter into financial contracts to set price floors of $50 per barrel for oil and $5 per Mcf for natural gas until December 1, 2008. At April 30, 2008, the contracts had average monthly volumes of 7,375 barrels of oil and 31,250 Mcf of gas. We have no derivative hedging contracts that set a price ceiling. We do not designate our derivatives as cash flow or fair value hedges.
We do not hold or issue derivative financial instruments for speculative or trading purposes. We are exposed to credit losses in the event of nonperformance by the counterparty to our financial hedging contracts. We anticipate, however, that our counterparty, Chevron, will be able to fully satisfy their obligations under the contracts. Changes in the fair values of our derivative instruments or settlements due from our counterparty are recorded immediately in earnings in other income or expense on our statements of operations.
The fair value of our derivative instruments are computed based on quotes for exchange-traded options with similar terms.
The options were valued at $2,290 as of April 30, 2008 resulting in a charge of $122,510 that has been shown in the income statement as other income and expense for the year ended April 30, 2008. The options were valued at $124,800 as of April 30, 2007 resulting in a charge of $369,490 that has been shown in the income statement as other income and expense for the year ended April 30, 2007. There were no realized gains or losses during either year ended April 30, 2008 or 2007 related to these contracts.
Intangible Assets
The Company amortizes Intangible Assets over the useful life of the asset which has been set at 5 years resulting in a charge to earnings of $42,000 for each year ended April 30, 2008 and 2007.
Interest Rate Collars
On January 4, 2008, the Company entered into a zero cost interest rate collar to establish a floor and ceiling for interest rate charges under its new credit facility with Standard Bank. Standard is the counter party on the collar. Under the terms of the collar agreement, the Company receives a cash settlement, if LIBOR is greater than 5.5%, and must pay a settlement, if LIBOR is below 3.6%. The settlement dates coincide with the scheduled quarterly interest payment dates under the Credit Agreement with Standard Bank. The notional amount of the collar declines as loan principle is repaid based on the following schedule:
The Company has elected not to use hedge accounting for this transaction. Gains and losses will be recognized in the Statement of Operations as the collar is marked to market each month. The fair value of the Company's derivative instruments outlined above approximates a loss of $106,020 as of April 30, 2008 and is based upon the amount at which it could be settled with a third party, although the Company has no current intention to trade any of these instruments and plans to hold them to reduce its interest rate exposure under the Standard Facility. The unrealized loss has been included in other income/expense in the statement of operations.
Note 5: Notes Payable-Legal Settlement
The legal settlement relates to the following two cases that were settled in June and September 2006:
Longbow, LLC v. Sonoran Energy, Inc. - Superior Court of California, County of Kern, Metropolitan Division Case No. S-1500-CV-25398-SPC
In March, 2004, a complaint was filed by Longbow, LLC against the Company alleging that Sonoran failed to provide timely notice related to an option for right of first refusal on the sale of our interest in the Emjayco Glide #33 Property, the Keystone-Deer Creek Property and the Deer Creek-Merzonian Property. Subsequently, Sonoran had entered into an agreement to sell those properties to a third party, Harvest Worldwide, LLC.
During September, 2006, an out of court settlement was reached to allow Longbow to purchase the properties in question, subject to Sonoran arranging for the removal of liens held by Ironwood and assuming partial responsibility for the retirement of certain obligations. We agreed to pay down a note on the three properties with shares of our stock that were held in trust after being recovered from Mark Anderson. In addition, we agreed to issue shares of our common stock, pay cash, and issue convertible notes to settle the balance of the assumed liabilities. Based on the settlement of this matter, we completed the sale of these properties and a gain of $484,046 was included as a reduction to litigation settlement expense on our statement of operations for the year ended April 30, 2007. The liens were removed during the quarter ended July 31, 2007.
Sonoran Energy, Inc v. Mark Roy Anderson et al
Mark Anderson was sued, individually and in the form of his corporate alter egos, by Sonoran seeking rescission of all shares issued to these entities, with additional compensation due for various timing failures and legal exposures resulting from Anderson's various shortcomings. The final settlement was dependant upon the resolution of the Longbow case (above) and included the assumption of certain obligations and payment of certain outstanding legal fees. These payments were partially offset by the cancellation of a commission payable of $250,000 and a loan payable of $48,476.
Through April 30, 2007, we paid settlement expenses in the form of cash, issuance of shares, and issuance of convertible debentures. Additionally, a portion of Anderson’s shares were used to satisfy certain outstanding legal fees. We computed the value of our obligations under the note payable and other liabilities by subtracting our estimate of the value of the shares surrendered by Anderson. At April 30, 2007, approximately 4,346,000 of Anderson’s shares were held in trust by attorneys or by the holder of the note payable to settle our liabilities. We computed the value of these shares using the closing price of our common stock on April 30, 2007 less an estimate of costs to sell those shares. The net amount of our obligations less the value of shares of our common stock pledged to settle those obligations was recorded on our consolidated balance sheet under current liabilities in the amount of $840,542.
During the year ended April 30, 2008, we issued 1,900,000 shares of common stock in payment of the note and 2,321,802 of Anderson’s shares were also applied to the reduction of the note resulting in the Ironwood note balance being reduced to $46,194. At April 30, 2008, approximately 2,023,000 shares were still being held in trust by attorneys or by the holder of the note payable. We computed the value of these shares using the closing price of our common stock on April 30, 2008 less an estimate of costs to sell those shares.
The net change in our obligations less the value of shares of common stock previously pledged to settle those obligations was recorded as a reduction in current liabilities and is shown in our Consolidated Statements of Operations as a credit of $102,143 in “Legal settlement expense”. The remaining liability which is shown in our Consolidated Balance Sheet as “Note payable regarding legal settlement” has been reduced to $464,641 as of April 30, 2008.
Note 6: Credit Agreement
Standard Bank PLC and Nordkap
On November 29, 2007, the Company entered into a Credit Agreement with Standard Bank PLC and Nordkap (Standard Agreement), granting the Company a credit facility of up to $15 million, over a three-year period, with an initial availability of $12 million. The lenders received 6,119,750 warrants priced at 3 tiers above market price on the date of closing, with maturities ranging from 4 to 6 years. As lead bank, Standard Bank PLC will also have an overriding royalty of 2% in all of our oil and gas properties. Payments for the overriding royalty are deferred until the earlier of November 29, 2010 or the date on which the loan is repaid. The value of the override as of the closing date was $868,902 and was recorded as a reduction to the full cost pool and as an increase in deferred loan fees.
The Standard Agreement is secured by first liens on substantially all of our properties and requires quarterly interest payments, at LIBOR plus 5.50 % (8.35% as at April 30, 2008). The Company recorded interest charges related to the Standard Agreement of $ 449,845 for the year ending April 30, 2008.
The Standard Agreement requires us to maintain certain financial ratios and other negative covenants, the most restrictive of which are:
a current ratio of at least 1.10 : 1.00;
a debt coverage ratio of no more than 2.00:1.00;
an interest coverage ratio of at least 3.00:1.00;
and a present value ratio 1.25:1.00.
Compliance with these covenants begins after April 30, 2008. However, the Company is not currently in compliance and must make significant improvements to achieve compliance. Any default on the restrictive covenants could result in the termination of future loans and the acceleration of the debt outstanding.
In addition, there are minimal quarterly production volumes that take effect beginning October 31, 2008.
The Company incurred debt issuance costs in connection with the Standard Agreement of $1,042,578 which are included in loan fees as of April 30, 2008. A total of 6,119,750 warrants were granted to the lenders in the Standard Agreement. These warrants were valued using the Black Scholes method and resulted in a valuation of $643,076. The debt issuance cost, warrants and the Standard Bank PLC overriding royalty interest total $2,554,556 and are being amortized over 36 months, the term of the facility. Amortization of $327,261 is included in interest expense related to the Standard Agreement for the year ended April 30, 2008.
NGP Asset Holdings, LP
On December 4, 2006, we executed a Credit Agreement (the "Facility") with NGPC Asset Holdings, LP ("NGPC"), the Administrative Agent for certain institutional investors. Pursuant to the terms of the Facility, NGPC agreed to give the Company access to a $12 million of borrowings with an initial borrowing base of $7 million and interest at prime plus 4% (12.25 at April 30, 2007) or Libor plus 6% (11.32% at April 30, 2007) monthly, on amounts borrowed and grant NGPC an overriding royalty on all of the Company's production. The Company also issued 2,870,000 warrants to purchase the Company's common stock at a price of $0.20 per share. The warrants are exercisable for a period of 7 years after the payoff of any funds borrowed. All outstanding principal and interest was due at maturity, February 28, 2008.
The NGP credit agreement was paid off and the override was purchased back with part of the proceeds from the Standard Bank Credit Agreement described in the previous paragraphs.
The Company recorded interest charges for the year ended April 30, 2008 of $394,891. The Company had recognized a value of $318,562 for the warrants associated with the loan and recorded this amount as a discount on the debt and a corresponding increase to additional paid in capital on the Balance Sheet.
The Company incurred other costs in connection with this facility of $676,139 which were included in loan fees on our Balance Sheet. The debt issuance cost of $676,139 and the warrants at fair value of $313,562 were being amortized over 15 months, the term of the facility. Total amortization of $573,009 of the debt issuance costs and $126,822 of the discount are included in interest expense on our statements of operations for the year ended April 30, 2008. In addition, as the loan was paid off early we have recorded the unamortized balance of the loan fees of $258,608 and the unamortized balance of the warrant discount of $85,555 as Loss on debt extinguishment on the income statement for April 30, 2008.
Note 7: Notes Payable-other
Notes and loan payables consist of the following items:
The notes are repayable as follows:
2009 $ 313,746
2010 89,989
2011 7,976
8,673
5,660
$ 426,044
Note 8: Income Taxes
A reconciliation of the U.S. statutory federal income tax rate to the effective tax rate is as follows:
The valuation allowance offsets the net deferred tax asset for which there is no assurance of recovery. The change in the valuation allowance for the years ended April 30, 2008 and 2007 totaled $3,153,000 and $3,447,000 respectively. A current tax benefit $2,667,000 and $3,434,000 was recorded for the years ended April 30, 2008 and 2007, respectively. These amounts were offset by and equal deferred income expense due primarily to the increase in the valuation allowance.
At April 30, 2008, the Company had net operating loss carryforwards of approximately $40,300,000. The net operating loss carryforwards expire from 2022 through 2028.
At April 30, 2008, the Company had a deferred income tax asset of $16,0740,000. Of that amount, $15,906,000 related primarily to net operating loss carryforwards and $168,000 relates to book and tax differences in the recognition of stock based compensation, accrued compensation to officers and amortization of intangible assets.
The deferred income tax asset is offset by a valuation allowance and deferred tax liability of $11,200 related to book and tax differences for the amortization of goodwill and intangible assets.
The valuation allowance will be evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. At that time, the allowance will either be increased or reduced; reduction could result in the complete elimination of the allowance if positive evidence indicates that the value of the deferred tax assets is no longer impaired and the allowance is no longer required.
The Company has filed US Federal Tax returns through fiscal years ending 2004. As additional returns are filed, the Company will continue to develop detail tax records and will have to make certain elections that could alter the relationship between book and tax income. The company initiated a project last fiscal year to develop appropriate tax records so that the remaining delinquent returns can be completed. The company expects to have its filing current by August 30, 2008. Since the company has never been profitable, we believe there is no significant exposure to penalties or interest. In addition, any changes in the deferred tax asset would be completely offset by an equal increase, or decrease, in our valuation allowance.
Should the Company undergo an ownership change as defined in Section 382 of the Internal Revenue Code, the Company's tax net operating loss carryforwards generated prior to the ownership change will be subject to an annual limitation, which could reduce or defer the utilization of these losses.
Note 9: Convertible Debentures
Our convertible debentures consist of the following:
In connection with the issuance of the 10% and 12% convertible notes, we issued 10,000 warrants for each $10,000 of principal amount. A total of 1,086,500 warrants were issued. The warrants are exercisable one year from issuance and expire three years from issuance. Upon issuance, we recorded the warrants as a discount to the 10% convertible debentures and a corresponding increase to additional paid in capital using the Black-Scholes method, using the following assumptions:
Expected life (1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 years
Risk-free rate (2). . . . . . . . . . . . . . . . . . . . . . . . . . . .4.43% to 4.79%
Expected Dividends (3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.00%
Volatility factor (4) . . . . . . . . . . . . . . . . . . . . . . . . . 133.4%
(1) Based on our estimate of time until the warrants will be exercised due to the volatility of our stock
(2) Based on the quotes for U.S. Treasury issues with three year maturities.
(3) We have not historically, nor do we anticipate, paying dividends.
(4) Based on historic trading prices, measured daily for a period three years prior to issuing the warrants.
In accordance with EITF 00-27, Application of EITF Issue No. 98-5, "Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios," we first allocated proceeds from the issuance of notes between the notes and the detachable warrants. This resulted in an effective conversion ratio that was less than the market price of our stock on certain issuances. We recorded a debt discount equal to the difference between the effective conversion ratio and the market price of our stock on the date of issuance of the notes for which such conversion was beneficial to the holder.
The following summarizes the discount on convertible notes as at April 30:
Discount - beginning balance
$ 101,529 $ -
Warrants, at fair value
- 98,734
Beneficial conversion features, intrinsic value
- 43,344
101,529 142,078
Less: amortization of discount
(71,672) (40,549)
Discount at April 30 - ending
$ 29,857 $ 101,529
Note 10: Asset Retirement Obligation
In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method. The provisions of SFAS No. 143 were effective for fiscal years beginning after June 15, 2002.
The following table is a reconciliation of the Company's liability for asset retirement obligations as at April 30:
Balance - opening
$ 1,427,570
$
795,589
Change in assumptions
(218,454)
564,139
Liability Settled
-
-
Accretion Expense
108,381
67,842
Balance - closing
$ 1,317,497
$
1,427,570
The reduction in 2008 reflects reduced estimated costs due to estimated production lives and movement from unproved to proved reserves. The addition during 2007 relates to increased estimated costs associated with the Louisiana and KWB wellbores.
Note 11: Shareholders' Equity
Preferred Stock
The Company is authorized to issue 25 million shares of no par value Series A preferred stock which may be issued with such preferences, stated values, rights, qualifications or limitations as determined by the Board of Directors.
In March 2008, the Company sold 3,000,000 units (consisting of one share of Series A Preferred Stock and one warrant to purchase three shares of Series A Preferred Stock at an exercise price of $1.00 per share with an exercise period of five years) for a unit price of $1 per unit, for a total of $3,000,000. Each share and warrant of the Series A Preferred is convertible into 20 shares of common stock upon the approval of the shareholders to increase the available common stock outstanding by 500,000,000 shares.
We have assigned a value to the warrants based on an allocation method that reflects the relative value of the preferred shares and warrants resulting in the stock being valued at $436,910 and additional paid in capital being credited with the balance of $2,563,090.
As of April 30, 2007, the Company had no preferred stock issued and outstanding.
Common Stock
The company is authorized to issue 250,000,000 shares of common stock with no par value. As of April 30, 2008, the company had issued 184,744,904 shares and 129,573,150 as of April 30, 2007.
Common Stock Dividend and Warrants
The Company did not declare a dividend during 2008 or 2007.
During the year ended April 30, 2008, an investor, an officer, and a director were granted warrants to purchase 3,950,000 additional shares. The exercise price on the 3,950,000 warrants was set at $0.25 per share. As part of the Standard Bank and Nordkop Senior Debt Facility the lenders were granted 2,009,916 warrants with an exercise price of $0.19, 2,009,916 warrants at $0.23 and 2,009,916 warrants at $0.30.
As part of a private placement done during the year ended April 30, 2007, an investor was granted warrants to purchase additional shares. The exercise price on 50,000,000 warrants was set at $0.10 per share. As part of the Senior Debt Facility the lender was granted 2,870,000 warrants with an exercise price of $0.20.
Note 12: Stock based compensation
During the year ended April 30, 2008 the Company has compensated Directors for services by issuing shares of restricted common stock. In addition, three officers of the Company received stock and option grants and an employee was awarded a stock grant. During the year ended April 30, 2008 the Board of Directors granted stock options to the officers and employees in recognition of performance for the past year. The total stock based compensation included in General and Administrative expense for the year ended April 30, 2008 was $567,968 compared to $676,001 for the year ended April 30, 2007.
Common Stock grants
As required by SFAS 123(R), Stock grants are valued at the grant date market price.
During the year ended April 30, 2008 the Directors received 993,151 common shares valued at $.20 for a total of $198,630 which was a payment for prior year services.
During April and May, 2007 the officers were granted a total of 1,150,000 shares valued at grant date market prices averaging $0.135 for a total cost of $155,000. The grants are to be earned over a 36 month period starting from their employment date and will vest in 24 equal installments beginning on the 1st anniversary of their employment date. The Company has recorded an expense of $51,833 for the year ended April 30, 2008 leaving a balance of $103,167 to be charged to expense at $12,958 per quarter for future periods.
In March 2007, an employee was granted 48,000 shares valued at the grant date market price of $0.14 for a total cost of $6,720. The grants are to be earned over a 24 month period starting from their employment date and will
vest in 12 equal installments of 2,000 shares beginning on the 1st anniversary of their employment date and the balance on the 2nd anniversary of the employment date. The Company has recorded an expense of $3,735 for the year ended April 30, 2008 leaving a balance of $2,985 to be charged to expense at $747 per quarter for future quarters.
The following is a summary of non-vested restricted shares for the year ended April 30, 2008:
During the year ended April 30, 2007, the Company issued 1,051,001 shares of its common stock to officers, employees and directors in recognition of their services. The value of the stock issued was recorded at the quoted market price on the date of the grant and totaled $369,501. The services are included in the accompanying financial statements under "general and administrative expense".
The Company granted an ex Chief Financial Officer 1,200,000 restricted shares and 1,000,000 options during the year ended April 30, 2007, both vesting over 11 months. The individual left the Company effective April 30, 2007, resulting in the final grants being 900,000 shares of fully-vested, restricted stock and 749,997 stock options. The Company also granted a new employee 50,000 restricted common shares on hiring.
During the year ended April 30, 2007, the Company issued 224,627 shares of its common stock to outside service providers, in exchange for financial consulting, investor relations and other consulting services. The value of the stock issued was recorded at the value of the services and totaled $156,500. The services are included in the accompanying financial statements under "general and administrative expense".
Common Stock options
The following table summarizes stock option activity related to our employees during fiscal year 2007 and 2008:
Weighted average
Weighted average
Aggregate
Stock
exercise price
remaining terms
intrinsic
Options
per share
(in years)
value
Options outstanding at April 30, 2006
9,950,000
$ 0.53
Granted
749,997
$ 0.33
Forfeitures
7,500,000
$ 0.53
Exercised
-
$ 0.00
Options outstanding at April 30, 2007
3,199,997
$ 0.47
2.50
$ -
Granted
6,150,000
$ 	 0.28
2.90
$ -
Forfeitures
1,250,000
$ 0.42
-
$ -
Exercised
-
-
-
$ -
Options outstanding at April 30, 2008
8,099,997
$ 0.33
2.70
$ -
Options exercisable at April 30, 2008
3,699,997
$ 0.40
As required by SFAS 123(R), the granting of options are share based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital.
The option grant to officers and employees in the year ended April 30, 2008 was valued using the Black-Sholes option-pricing model for a total cost of $512,400 which has been charged against expense in the year ended April 30, 2008.
The option grant to officers and employees in the year ended April 30, 2007 was valued using the Black-Sholes option-pricing model for a total cost of $336,000 which has been charged against expense in the year ended April 30, 2007.
The Company will issue new shares to anyone exercising options.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used for the options included in the above table:
The Black-Scholes options valuation model was developed for use in estimating the fair value of traded options, which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility
Note 13: Employee Benefit Plans
Simple IRA Plan
During the fiscal year ending April 30, 2008 the Company established a Simple IRA plan that is available to all full-time employees under which participants can make voluntary pretax contributions. The Company currently matches up to 1% of the participating employee’s salary. The Company contributed a total of $7,642 for the fiscal year ending April 30, 2008.
Stock purchase plan
During the fiscal year ending April 30, 2008 the Company established a stock purchase plan that is available to all full-time employees, directors and long term contractors. Twice a year on January 31st and July 31st the employee, director, or contractor may make an irrevocable election to purchase up to $25,000 worth of the Company’s stock either through payroll deduction or cash payment, or a combination of both. The stock purchased under this plan is restricted from market trading for 6 months after issuance. The actual number of shares is determined based on the average price in the month following the election to participate and the Company matches the amount of shares purchased. The Company issued 2,170,810 share of restricted common stock in July 2008 under this plan.
Note 14: Gain on Asset Sale
The Company entered into a series of agreements to form a joint venture with an industry partner to facilitate exploitation of its interest in the Azraq Production Sharing Arrangement (Azraq PSA) with the Kingdom of Jordan. The Company received proceeds of $1,000,000 in return for the industry partner's entry into the project, and
assumption of most of the financial obligation and operating risks associated with the Azraq PSA. Of this amount, $552,373 was used to pay expenses directly related to the transaction. The remaining $447,627 exceeded the $58,774 recorded to the project for Jordan. The remaining value received of $388,853 was recognized as a gain.
Note 15: Net Loss Per Common Share
Basic net income (loss) per share is computed by dividing the net income attributable to common shareholders by the weighted average number of shares outstanding during the period.
Diluted net income (loss) per share is computed in the same manner, but also considers the effect of the common stock shares underlying the following:
The shares of the common stock underlying the stock options, warrants, restricted shares, convertible debt and preferred shares, shown in the preceding table, are not included in weighted average shares outstanding for the years ended April 30, 2008 and 2007 as their effects would be anti-dilutive.
Note 16: Commitments and Contingencies
Concentrations
During the year ended April 30, 2008, the Company sold all of its products through Texon LP. Accounts receivable as of April 30, 2008 was $217,472 for this purchaser.
While the Company is concentrating its marketing arrangements, it is management's belief that the oil and gas the Company produces could be sold to other crude oil purchasers, refineries or pipeline companies. The Company sells its oil pursuant to short-term contracts at market prices. Market demand for the Company's production is subject to various influences that can never be assured. The base values for the Company's crude oil sales is set by major oil companies in response to area and market strengths and international influences.
During the year ended April 30, 2008 the Company received more than 10% of total services from two suppliers, Nabors Drilling and Weatherford, for supplies to our workover projects in Louisiana. Accounts payable as of April 30, 2008 was $146,861 from these suppliers.
Lease Commitments
The Company has leased office premises in Chandler, Arizona and Dallas, Texas. Future minimum payments required are:
Rent expense was $278,787 and $ 241,312 for 2008 and 2007, respectively.
Effective May 7, 2007 the Company amended the Dallas facility lease to include an additional 3,866 square feet of adjoining office space. These incremental costs are included in the above table
The Company has made a sublease arrangement for its Chandler, Arizona facility at or near the current lease obligation. The future minimum payments included above for this office space is $351,587 for the lease expiring June 30, 2010.
Contingencies
Wells Land and Cattle Co., Inc., et.al. v. Sonoran Energy, Inc.
On or about May 18, 2007 Wells Land and Cattle Co., Inc., et.al. filed a lawsuit alleging that Sonoran was illegally disposing of saltwater into a saltwater disposal well on their property, that Sonoran routinely trespasses on its land to reach another well which is not located on plaintiff’s land, that Sonoran spilled saltwater onto Plaintiff’s land, and that an oil well lease covering one well has expired due to lack of production. Plaintiff claims that damages exceed $2,000,000 and asks the court for a permanent injunction against Sonoran from trespassing on Plaintiff’s property for the purpose of reaching the disposal well that is not on its property. Sonoran intends to vigorously defend its actions in this matter and anticipates that the matter will be eventually settled for an immaterial amount.
Property Liens
We have received notice of various liens totaling approximately $640,000 on certain of our oil and gas properties in connection with various vendors with outstanding accounts payable.
Other
We are subject to other lawsuits and controversies which are not discussed herein. Management, based on the facts and circumstances, do not believe that any such matter will have a material adverse effect on the results of operations or the financial condition of the Company.
Environmental
We as an owner and operator of oil and gas properties are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may impose liability on the lessee under an oil and gas lease or concession for the cost of pollution clean-up resulting from operations and also may subject the lessee to liability for pollution damage.
Note 17: Oil and Gas Reserves and Related Financial Information (Unaudited)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Costs incurred in oil and gas property acquisition, exploration and development activities are summarized as follows:
All of our operations are directly related to oil and natural gas producing activities located in Louisiana and Texas.
Capitalized Costs Relating to Oil and Gas Producing Activities:
Costs Incurred in Oil and Gas Producing Activities:
Results of Operations from Oil and Gas Producing Activities:
* The Company did not have a provision for federal income taxes for 2008 and 2007, therefore we did not compute a tax provision for the disclosure listed above.
Proved Oil and Gas Reserve Quantities
At April 30, 2008 and 2007, the estimated oil and gas reserves presented herein were derived from reports prepared by Haas Petroleum Engineering Services, Inc., an independent engineering firm. The Company cautions that there are many inherent uncertainties in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available, and these changes could be material.
Estimated quantities of proved reserves, all located within the United States, as well as the changes in proved reserves during the year ended April 30, 2008 and 2007, are presented in the following tables:
Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
The estimated quantities of proved reserves for the fiscal year ending April 30, 2008 included revisions of previous estimates for oil, which decreased by 93,265 Bbl as a result of lower volumes for our East Texas properties, and gas which decreased by 1,499,080 Mcf due to lower volumes for the Central Texas wells. These were partially offset in the extension, discoveries and improved recoveries category because of increases of 62,661 Bbl for oil and 913,410 Mcf for gas by additional properties is Central Texas and Louisiana moving from unproved to proved.
The fiscal year ending April 30, 2007 proved reserves quantities included revisions of previous estimates due to a decline in oil volumes for our East Texas properties. Extensions, discoveries and improved recoveries include gas volumes increases of 3,756,570 Mcf because of initial reclassification of Central Texas properties from unproved to proved.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company's proved oil and gas reserves. Estimated future cash inflows were 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 at April 30, 2008 and 2007 discounted at 10 percent. The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions.
The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows:
The fiscal year ending April 30, 2008 net present value discounted at 10 percent of proved reserves increased by $8,963,263 from the year ending April 30, 2007 primarily due to increased development cost related to one East Texas property and three Louisiana wells. Four additional Central Texas properties and one Louisiana sidetrack were added to the extensions and discoveries category, and revision of previous quantity estimates includes a decline in gas volumes for the Central Texas wells offset by increased price estimates.
The fiscal year ending April 30, 2007 net present value discounted at 10 percent of proved reserves increased by $13,577,342 from the year ending April 30, 2006 primarily due to reserves additions in Central Texas moving from unproved to proved reserves.
Note 18: Segment Information
The Company is presently operating in two segments:
Consulting services consisted of engineers performing services based outside the Corporate offices with no Company assets being allocated to this function. The last of the consulting contracts ended in the year ended April 30, 2007.
Note 19: Subsequent Events
Convertible Notes
On June 13, 2008 a convertible note was issued to a significant shareholder in the amount of $500,000.
On June 16, 2008 a second convertible note was issued to another significant shareholder in the amount of $500,000.
Equity Investments
On July 22, 2008, the Company sold 500,000 additional shares of its Series A Convertible Preferred Stock to our largest investor at $1.00 per share for total proceeds of $500,000 paid to the Company. These shares are convertible into restricted common stock at $0.05 per share and would result in issuing 10,000,000 shares of common stock at conversion.
ITEM 9
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The "Company" engaged UHY LLP ("UHY") as its new independent accountant on February 20, 2008. Prior to February 20, 2008, the Company had not consulted with UHY regarding (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company's consolidated financial statements, and no written report or oral advice was provided to the Company by UHY concluding there was an important factor to be considered by the Company in reaching a decision as to an accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of a disagreement, as that term is defined in Item 304(a)(2) of Regulation S-B and the related instructions to Item 304 of Regulation S-B, or a reportable event, as that term is defined in Item 304(a)(2) of Regulation S-B.
On December 18, 2007, Sonoran Energy, Inc. (the "Company") was informed that Hein & Associates LLP ("Hein") would be resigning from its position as the Company's independent accountants. The Company's Board of Directors accepted Hein's decision. During the Company's fiscal year ended April 30, 2007 and the subsequent interim period through December 18, 2007, there were no reportable events as such term is defined by paragraph (a)(1)(iv) of Item 304 of Regulation S-K promulgated by the Securities and Exchange Commission.
On February 2, 2007, Sonoran Energy, Inc. (the "Company") engaged Hein & Associates, LLP ("Hein”) as its new independent accountants. Prior to February 2, 2007, the Company had not consulted with Hein regarding (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company's consolidated financial statements, and no written report or oral advice was provided to the Company by Hein concluding there was an important factor to be considered by the Company in reaching a decision as to an accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of a disagreement, as that term is defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K, or a reportable event, as that term is defined in Item 304(a)(1)(iv) of Regulation S-K.
ITEM 9A
ITEM 9A - CONTROLS AND PROCEDURES
(a) Disclosure Controls and Procedures. Disclosure controls and procedures are controls and other procedures that are designed to ensure that the information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the reports that a company files or submits under the Exchange Act is accumulated and communicated to the Company's management, including its Principal Executive Officer and Principal Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
We maintain disclosure controls and procedures designed to ensure that material information related to our company is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Evaluation of Disclosure Controls and Procedures
SONORAN ENERGY INC's management is responsible for establishing and maintaining effective internal control over financial reporting (as defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act). Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions.
SONORAN ENERGY INC's management, under the direction of the Chief Executive Office and Chief Financial Officer, assessed the effectiveness of SONORAN ENERGY INC's internal controls over financial reporting as of April 30, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO, in Internal Control-Integrated Framework. Based on this assessment, management believes that sufficient evidence exists, as of April 30, 2008, to support a conclusion that SONORAN ENERGY INC's internal controls over financial reporting are effective.
Changes in Internal controls over Financial Reporting
There were no changes in SONORAN ENERGY INC's internal controls over financial reporting that occurred during the fiscal quarter ended April 30, 2008 that have materially affected, or are reasonably likely to materially affect, SONORAN ENERGY INC's internal control over financial reporting.
ITEM 9B
ITEM 9B - OTHER INFORMATION
None.
PART III
ITEM 10
ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
Section 16(a) of the Exchange Act ("Section 16(a)") requires the Company's Officers and Directors, and persons who own more than ten percent of a registered class of the Company's equity securities, to file reports of ownership on Form 3 and changes in ownership on Form 4 or Form 5 with the Securities and Exchange Commission (the "SEC"). Such Officers, Directors and ten percent shareholders are also required by SEC rules to furnish the Company with copies of all such forms that they file. The Company's initial registration statement on Form 10-SB became effective on or about April 5, 2000. Management is confident that all filings required are current as of the statement date.
PETER ROSENTHAL, CHAIRMAN, CEO, PRESIDENT, DIRECTOR
Prior to joining Sonoran Energy, Inc Mr. Rosenthal held the position of General Manager, UK North Sea Operations with Amerada Hess Corporation (now Hess Corporation). Before that, Mr. Rosenthal held the position of Managing Director, Amerada Hess Denmark and prior to that Operations Manager, Amerada Hess Denmark. Previously, Mr. Rosenthal held different positions with Elf Aquitaine in Norway, where he worked both onshore and offshore. Previous to Elf, Mr. Rosenthal worked for COWI Engineers in Denmark as well for SBM in Monaco, where he worked with the design and construction of floating Oil & Gas facilities.
Mr. Rosenthal brings 17 years of Oil & Gas experience to Sonoran Energy. He was appointed Chairman and CEO of Sonoran Energy in April 2004.
ANDREW WILLIAMS, SENIOR VP/CFO
Andrew G. Williams has approximately 30 years of oil and gas finance and accounting experience. Prior to joining Sonoran Energy in April, 2007, he was a Consultant with Sirius Solutions providing Sarbanes Oxley Compliance services to Oil and Gas clients as well as process improvements and Internal Audit services. Prior to joining Sirius in May 2006, Mr. Williams had worked on accounting compliance and process improvement initiatives for DHL in Houston and Gap, Inc in Albuquerque, NM. Prior to Gap, Inc he had worked for BP Amoco for 17 years.
Mr. Williams is a Certified Public Accountant and has a BS in Accounting from the University of Arkansas.
RALPH WATKINS, SENIOR VP/COO
Ralph Watkins brings 23 years of U.S. and international oil and gas development, operations, and engineering management experience to Sonoran Energy. During the past five years, Mr. Watkins previously served in various senior positions with BP, Occidental, Cairn Energy, and Killam Oil. His management roles have included Subsurface Manager for Cairn Energy’s 1,900 square-mile exploration and development block in north-west India, Manager of Production for U.S. producer Killam Oil Co., Ltd., and Production Engineering Manager for Shell/BP/Deminex’s Egyptian joint-venture.
With a degree in petroleum engineering from Texas A&M University, Mr. Watkins brings to Sonoran Energy a broad background that bridges practicality with technical leadership.
TERRY WHISTLER, VP/CORP CONTROLLER/CORP SECRETARY
Mr. Whistler brings over 22 years of professional experience to Sonoran Energy. Prior to joining Sonoran Energy in May 2007 he served as controller in the IT solutions group with Affiliated Computer Services for 5 years. His management roles have included Santa Fe International, Meridian Oil, and Texas Oil and Gas.
Mr. Whistler became a Certified Public Accountant in 1991, and has a BS degree in Accounting and Computer systems from University of North Texas.
BRAD FARROW, DIRECTOR
Since 1985, Brad Farrow has led implementations for RLG International clients throughout North America and Western Europe. He introduced RLG's TMP® process (Theoretical Maximum Performance) to the drilling industry in 1996 and has helped to establish RLG as the consultant of choice for offshore performance coaching. Brad spent six years leading RLG's European Operations from Scotland. His current role as a Managing Director includes overseeing the European Operations and directing RLG's international and offshore oil and gas portfolio. Additionally, he is a director of Technical Limit Services Ltd., a performance coaching organization specializing in offshore drilling operations.
Mr. Farrow holds a Bachelor of Science degree from Concordia University in Montreal and an MBA from the University of Western Ontario. He joined the Board of Sonoran Energy, Inc on June 27, 2006.
ROBERT M. KING, DIRECTOR
Robert M. King is a strategic financial executive who has spent most of his career involved with the oil and gas industry, first as a banker, managing lending and corporate finance relationships with diversified energy companies, then as a senior financial officer of two different independent oil and gas companies, and finally as Co-Founder and Managing Director of a private equity group focused on natural gas development opportunities.
Mr. King was the Senior VP and Chief Financial Officer of Nuevo Energy Company from 1996 through 2001. From 2002 to September 2004, he was co-founder and Managing Director of Red Oak Capital Management, LLC, a private firm which raises capital for development drilling projects and provides other similar advisory services for small oil and gas companies.
Mr. King lives in Houston, Texas, where he has been involved in the management of a major nonprofit human services organization since 2004. He joined the Board on July 18, 2006.
BRIAN RAFFETY, DIRECTOR
In 1980, Mr. Rafferty began his career in cross-border investor relations at Ogilvie, Taylor Associates, Inc., a financial communications firm specializing in representing non-US companies and trade associations. In 1982, Mr. Rafferty co-founded Taylor Rafferty, which, for over two decades, has specialized in assisting international companies to build cross-border shareholdings and global capital markets capabilities. In 2005, Taylor Rafferty was acquired by Shanghai-based, Tokyo Stock Exchange-listed Xinhua Finance. With 75 employees and offices in New York, London, Tokyo, Seoul, Shanghai, Beijing and Hong Kong, Taylor Rafferty is a leader in cross-border capital markets communications.
Taylor Rafferty is retained by over 60 companies from the US, Europe, Asia, South America and Africa. Its clients represent some $750 billion in equity market value with an average market capitalization of over $10 billion. Mr. Rafferty has assisted non-US clients in virtually every type of international capital markets activity.
MEHDI VARZI, DIRECTOR
Mr. Varzi established Varzi Energy as an independent oil and gas consultancy in June 2001 after a 33-year career spanning oil, diplomacy and international finance. From 1982 - 2001, Mr. Varzi worked in the City of London, first as an oil consultant, specializing in OPEC and international oil market developments from 1982-1986 with stockbrokers Grieveson Grant; then as a Director of Energy Research with Kleinwort Benson (1986-1995), and then in the same position with Dresdner Kleinwort Wasserstein (1995-2001), retiring as Managing Director of Energy Research in 2001. From 1972-1981, Mr. Varzi served in the Iranian Ministry of Foreign Affairs, and was posted to the Iranian Embassy in Ankara from 1977-1981. From 1968-1972, Mr. Varzi served as a Senior Analyst in the International Affairs Section of the National Iranian Oil Company. Mr. Varzi regularly conducts briefings on world oil issues for private and state oil and gas companies and is currently involved in a number of oil and gas projects in the Middle East.
CHARLES WATERMAN, DIRECTOR
Mr. Waterman is the Chief Executive Officer and founding member of Jefferson Waterman International, a Washington, DC-based consultancy that advises clients on political, economic and military trends worldwide. Waterman has held several leading positions within the U.S. Central Intelligence Agency and as National Intelligence Officer in the Middle East (1963 to 1985), Mr. Waterman coordinated the intelligence input to policy deliberations in the Near East and South Asia. As a member of the Foreign Service, he spent many years living and working overseas in Kuwait, Cairo, Beirut, Amman and Jiddah. A recognized expert in the Middle East and the former Soviet Union, Mr. Waterman has extensive knowledge of the defense and petroleum industries, and has published extensively in foreign affairs journals.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the Company's executive officers, directors and persons beneficially owning more than 10% of the Company's common stock to file reports of ownership and changes in ownership with the Securities and Exchange Commission. The Company has undertaken an extensive review of the Section 16(a) reports filed on behalf of each person subject to Section 16(a) prior to April 30, 2005, to determine whether all of their reportable transactions in the Company's common stock were timely reported and to ensure proper reporting of all of their beneficial holdings. The review revealed that there were a number of holdings and transactions that were not timely reported and the Company has undertaken to assist the subject persons to file
the necessary forms. The Company has also developed new procedures to ensure improved compliance with Section 16(a) on an on-going basis.
Based solely on copies of such forms furnished as provided above, to the Company's knowledge all reports required under Section 16(a) during the most recent fiscal year or prior years, except that none of the newly appointed/elected members of the Board of Directors has filed a Form 3. These reports are intended to be filed as soon as possible.
Audit Committee Financial Expert
The entire Board of Directors of Sonoran Energy, Inc. served as the Company's Audit Committee until November 9, 2006 at which time three independent Board members were appointed by the Board to assume the responsibilities of the Audit Committee. Mr. Robert King was designated as the audit committee financial expert as that term is defined in Item 401(e)(2) of Regulation S-B.
Code of Ethics
We have adopted a "Code of Ethics for Directors, Officers and Employees", a code of ethics that applies to all employees, including our executive officers.
In the event that we make any amendments to, or grant any waivers of, a provision of the Code of Ethics for Directors, Officers and Employees that applies to the principal executive officer, principal financial officer, or principal accounting officer that requires disclosure under applicable SEC rules, we intend to disclose such amendment or waiver and the reasons therefore on a Form 8-K or on our next periodic report.
ITEM 11
ITEM 11 - EXECUTIVE COMPENSATION
The Board of Directors appointed three external Board members to a Compensation Committee on November 9, 2006. The Committee is reviewing the present compensation structure, both in the Company and the industry, and has the responsibility for recommending on-going programs for Sonoran Energy.
SUMMARY COMPENSATION TABLE
The following table sets forth the aggregate annual remuneration of Sonoran's Chief Executive Officer and the other executive officers whose annual salary and bonus exceeded $100,000 in the fiscal year ended April 30, 2008 (collectively, the "named executive officers"), and for the fiscal years ended April 30, 2007 and April 30, 2006, the Company's most recent and meaningful fiscal years. All amounts are in U.S. dollars unless otherwise noted.
The values shown in the stock awards are based on the market value at the grant date and the option awards for 2008 are based on the Black-Sholes valuation of the awards as discussed in Note 12 of the Notes to the Financial Statements contained in this form 10K. These were not and should not be considered as cash remuneration in the hands of the individuals.
(1) Salaries up to and including July 2006 were paid thru converting 70 % of the balances owing from April 30, 2004 and to July 31, 2005 to stock at a price of $.55 per share. Salaries for August through December were paid by half cash and half converted to stock. For January to April 2006, salaries plus 1/12 of the balance owing from July 2005 was paid in cash except for the CEO who took less cash and left his balance owing.
Mr. Smith, Mr. Rafidi, Mr. Nuseibeh, Mr. Mackertich, Mr. Hodgson and Mr. McFie have resigned their positions with the Company.
GRANTS OF PLAN-BASED AWARDS
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END
Option Awards
Stock Awards
Name
Number of Securities Underlying
Unexercised options
(#)
Exercisable
Number of Securities Underlying Unexercised options
(#)
Unexercisable
Equity Incentive Plan Awards:
Number of Securities Underlying Unexercised options
(#)
Unexercisable
Option Exercise Price ($)
Option Expiration Date
Number of Shares or Units of Stock That Have Not Vested
($)
Market Value of Shares or Units of Stock That Have Not Vested
($)
Equity
Incentive Plan Awards:
Number of Unearned Shares, Units or Other Rights that have not Vested
(#)
Equity
Incentive Plan Awards:
Market or Payout Value of Unearned Shares, Units or Other Rights that have not Vested
($)
Peter Rosenthal
700,000
100,000
100,000
100,000
0.15
0.30
0.60
1.20
Jan/10
Jan/11
Jan/12
Jan/13
Andrew Williams
500,000
1,000,000
166,667
166,667
166,666
0.20
0.15
0.30
0.60
1.20
May/10
Jan/10
Jan/11
Jan/12
Jan/13
500,000
32,500
Ralph Watkins
500,000
1,000,000
166,667
166,667
166,666
0.20
0.15
0.30
0.60
1.20
Apr/10
Jan/10
Jan/11
Jan/12
Jan/13
479,167
31,146
Terry Whistler
150,000
500,000
0.20
0.15
May10
Jan/10
150,00
9,750
OPTION EXERCISES AND STOCK VESTED
Option Awards
Stock Awards
Name
Number of Shares Acquired on Exercise
(#)
Value Realized on Exercise
($)
Number of Shares Acquired on Vesting
(#)
Value Realized on Vesting
($)
Ralph Watkins
-
20,833
The stock grants are to be earned over 36 months with vesting occurring over 24 months starting at the first anniversary of the grant. The value realized on vesting is the value of the stock at the grant date.
DIRECTOR COMPENSATION
ITEM 12
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of Common Stock of the Company as of the Record Date for the following: (i) each person or entity who is known to the Company to beneficially own more than 5% of the outstanding shares of the Company's Common Stock; (ii) each of the Company's Directors (and nominees for election as Directors); (iii) the Company's Chief Executive Officer and each of the officers ("Named Officers") named in the Summary Compensation Table herein; and (iv) all Directors and executive officers of the Company as a group.
The number and percentage of shares beneficially owned is determined under rules of the Securities and Exchange Commission ("SEC"), and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or dispositive power and also any shares that the individual has the right to acquire within sixty days of the Record Date through the exercise of any stock option or other right. Unless otherwise indicated in the footnotes, each person has sole voting and dispositive power (or shares such power) with respect to the shares shown as beneficially owned.
Common Stock
Ala Nuseibeh - ex dir
2,935,295
1.59
Common Stock
Khaldoun Awamleh -ex dir
1,550,000
0.84
Common Stock
CUBUS APS
66,500,000
36.00
Total
88,320,300
47.81
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
During the year ended April 30, 2008 an officer of the Company purchased 800,000 shares at $0.125 per share, for total proceeds of $100,000.
During the year ended April 30, 2008 a director of the Company purchased 5,400,000 shares at $0.125 per share, for total proceeds of $675,000.
During the year ended April 30, 2008 a director of the Company purchased 1,000,000 shares at $0.119 per share, for total proceeds of $119,000.
During the year ended April 30, 2008 members of the Board were issued stock in payment of 2006 accrued directors fees totaling $198,630.
A director of the Company acted as an escrow agent for $217,309 of funds that the Company had earned from a transaction related to our interest in the Azraq Production Sharing Agreement. The funds were received by the Company October 29, 2007 and his agency was concluded.
During the year ended April 30, 2007 Directors of the Company advanced funds to the Company in exchange for $295,000 in Convertible notes bearing interest at 10% on $270,000 and 12% on $25,000. The notes contain provisions for warrants at $0.55 per share and a convertible strike price of $0.23.
There were no transactions during the year ended April 30, 2006.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The firm of UHY LLP (“UHY”) acts as our principal independent registered public accounting firm. Through and as of August 13, 2008, UHY had a continuing relationship with UHY Advisors, Inc. (“Advisors”) from which it leased auditing staff who were full-time, permanent employees of Advisors and through which UHY’s partners provide non-audit services. UHY has only a few full-time employees. Therefore, few, if any, of the audit services performed were provided by permanent, full-time employees of UHY. UHY manages and supervises the audit services and audit staff, and is exclusively responsible for the opinion rendered in connection with its examination
The Audit Committee is responsible for approving in advance any audit services and all permitted audit-related services, tax services, and other non-audit services to be performed by the independent registered public accounting firm. The Audit Committee may delegate its pre-approval authority for these services to one or more members, whose decisions shall be presented to the full Audit Committee at its scheduled meetings. Each of these services must receive specific pre-approval by the Audit Committee unless the Audit Committee has provided general pre-
approval for such category of services in accordance with policies and procedures that comply with applicable laws and regulations.
PART IV
ITEM 15
ITEM 15 - EXHIBITS
(a) 1. FINANCIAL STATEMENTS
These documents are listed and included in Part II, Item 7 of this report:
Reports of Independent Public Accountants
Consolidated Balance Sheet at April 30, 2008 and 2007.
Consolidated Statements of Operations for the periods ended April 30, 2008, 2007 and 2006.
Consolidated Statements of Shareholders' Equity for the periods ended April 30, 2008, 2007 and 2006.
Consolidated Statements of Cash Flows for the periods ended April 30, 2008, 2007 and 2006.
Notes to Consolidated Financial Statements.
3. EXHIBITS
(b) Other Information
Nothing to report.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SONORAN ENERGY, INC.
(Registrant)
August 13, 2008
By: /s/ Peter Rosenthal
Peter Rosenthal
Director/President/CEO
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below hereby severally constitutes and appoints Peter Rosenthal and Andrew Williams, and each of them, his true and lawful attorney-in-fact and agent, with full power of substitution and re-substitution for him and in his name, place and stead, in any and all capacities to sign any and all amendments to this Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Commission, granting unto said attorney-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite or necessary fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that each said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this Report has been signed below by the following persons on behalf of registrant in the capacities and on the dates indicated.