SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended August 31, 2012
For the transition period from _______________________ to _______________________
Commission file number: 001-35245
SYNERGY RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
Registrant's telephone number, including area code: (970) 737-1073
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections.
Persons who respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number.
Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark weather the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such filing). Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes o No x
The aggregate market value of the voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on February 29, 2012, was approximately $148,400,000. Shares of the registrant’s common stock held by each officer and director and each person known to the registrant to own 10% or more of the outstanding voting power of the registrant have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not a determination for other purposes.
As of November 1, 2012, the Registrant had 51,676,844 issued and outstanding shares of common stock.
Cautionary Statement Concerning Forward-Looking Statements
This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as “believes”, “expects”, “anticipates”, “intends”, “plans”, “estimates”, “should”, “likely” or similar expressions, indicates a forward-looking statement.
The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.
Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:
ITEM 1. BUSINESS
We are an oil and gas operator in Colorado and are focused on the acquisition, development, exploitation, exploration and production of oil and natural gas properties primarily located in the Wattenberg Field in the Denver-Julesburg Basin (“D-J Basin”) in northeast Colorado. We serve as the operator for most of our wells and focus our efforts on those prospects in which we have a significant net revenue interest. As of October 15, 2012, we had 226,948 gross and 191,168 net acres under lease, substantially all of which are located in the D-J Basin. Of this acreage, 8,526 gross acres are held by production.
We commenced active operations in the D-J Basin in 2008. Between September 1, 2008 and August 31, 2012, we drilled, participated or otherwise acquired an interest in 209 gross (158 net) oil and gas wells. As of August 31, 2012, 191 gross (147 net) wells were producing oil and gas and 18 wells were in various stages of completion. There have been no dry holes. We are the operator of 156 wells and participated with other operators in 53 wells.
At August 31, 2012, our estimated net proved oil and gas reserves, as prepared by our independent reserve engineering firm, Ryder Scott Company, L.P., were 5.1 MMBbls of oil and condensate and 33.4 Bcf of natural gas.
Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves and cash flow through acquisitions, development, exploitation, exploration and divestiture of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures in a combination of lower risk development and exploitation activities and higher potential exploration prospects. Key elements of our business strategy include the following:
We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:
We expanded our business during the fiscal year ended August 31, 2012. We increased our producing wells, our reserves, and our undeveloped acreage. Significant developments are described below.
We increased our proved reserve quantities by 140% during the year. The August 31, 2012, reserve report indicated that we had estimated proved reserves of 5.1 million barrels of oil and 33.4 billion cubic feet of gas. The estimated present value before tax (discounted at 10%) is $149 million.
In late summer of 2011, we commenced drilling operations with a rig under contract to us from Ensign United States Drilling, Inc. There were six wells in progress on September 1, 2011, all of which were completed during the year. Between September 1, 2011, and August 31, 2012, Ensign drilled 51 wells for us, 41 of which reached productive status by August 31, 2012. As of August 31, 2012, completion activities were underway on 10 wells, all which have since reached productive status. In addition, we participated in 13 wells drilled by other operators, five of which reached productive status prior to August 31, 2012.
Since August 31, 2012, we continue to drill wells with Ensign and expect approximately 25 wells to be drilled during the first quarter of 2013.
As a result of increasingly successful results of horizontal drilling in the Wattenberg, we entered the horizontal market with limited involvement by participating in five horizontal wells in 2012, three of which contributed revenue by fiscal year end. All wells drilled prior to 2012 were relatively low-risk vertical or directional wells.
During the year, we closed on the acquisition of interests in mineral leases in Weld, Morgan and Larimer Counties, Colorado and also purchased from some minority partners their working interests in existing wells. The interests were acquired with $2.3 million in cash and 261,482 shares of our common stock. Initial exploration activities on the prospect will focus on the potential for horizontal drilling in the Niobrara and Greenhorn formations.
We improved our access to capital resources by negotiating increases to our revolving line of credit with Community Banks of Colorado. Shortly after year-end, we increased the commitment amount from $20 million to $30 million.
During December 2011, we completed the sale of 14.6 million shares of our common stock at $2.75 per share for net proceeds totaling approximately $37.4 million after deduction of discounts, commissions and expenses. The public offering of additional shares of our common stock was underwritten by Northland Capital Markets, C. K. Cooper & Company, and GVC Capital LLC.
During the year, we recognized a one-time tax benefit of $4,911,000 for the estimated value of the net operating loss carry-forward that we accumulated from inception to August 31, 2011.
Well and Production Data
During the periods presented below, we drilled or participated in the drilling of a number of wells that reached productive status in each respective fiscal year. We did not drill any exploratory wells nor did we drill any dry holes during these years. The following table excludes wells that are in the drilling or completion phase and had not reached the point at which they are capable of producing oil and gas.
Excluded from the table above are wells that had not reached productive status as of August 31, 2012. As such, 1 gross (1 net) well in the drilling phase and 17 gross (10.2 net) wells in the completion phase were not included in the above well counts. These wells are all located in the Wattenberg Field of the D-J Basin.
The following table shows our net production of oil and gas, average sales prices and average production costs for the periods presented:
Production costs are substantially similar among our wells as all of our wells are in the Wattenberg Field and employ the same methods of recovery. Production costs generally include pumping fees, maintenance, repairs, labor, utilities and administrative overhead. Taxes on production, including ad valorem and severance taxes, are not included in production costs.
We are not obligated to provide a fixed and determined quantity of oil or gas to any third party in the future. During the last three fiscal years, we have not had, nor do we now have, any long-term supply or similar agreement with any government or governmental authority.
Oil and Gas Properties
We evaluate undeveloped oil and gas prospects and participate in drilling activities on those prospects, which, in the opinion of our management, are favorable for the production of oil or gas. If, through our review, a geographical area indicates geological and economic potential, we will attempt to acquire leases or other interests in the area. We may then attempt to sell portions of our leasehold interests in a prospect to third parties, thus sharing the risks and rewards of the exploration and development of the prospect with the other owners. One or more wells may be drilled on a prospect, and if the results indicate the presence of sufficient oil and gas reserves, additional wells may be drilled on the prospect.
We may also:
Our activities are primarily dependent upon available financing.
Title to properties we acquire may be subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, and subject to liens for current taxes not yet due and to other encumbrances. As is customary in the industry, in the case of undeveloped properties little investigation of record title will be made at the time of acquisition (other than a preliminary review of local records). However, drilling title opinions may be obtained before commencement of drilling operations.
The following table shows, as of October 15, 2012, by state, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells:
Acres that are Held by Production remain in force so long as oil or gas is produced from the well on the particular lease. Leased acres which are not Held By Production require annual rental payments to maintain the lease until the first to occur of the following: the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage. At the time oil or gas is produced from wells drilled on the leased acreage, the lease is considered to be Held by Production.
The following table shows the years our leases, which are not Held By Production, will expire, unless a productive oil or gas well is drilled on the lease.
The overriding royalty interests that we own are not material to our business.
Proved Reserve Estimates
Ryder Scott Company, L.P. (“Ryder Scott”) prepared the estimates of our proved reserves, future productions and income attributable to our leasehold interests for the year ended August 31, 2012. Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years. The estimates of drilled reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by teams of geoscientists and engineers employed at Ryder Scott. The office of Ryder Scott that prepared our reserves estimates is registered in the state of Texas (License #F-1580). Ryder Scott prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for our wells. Additionally, authorizations for expenditure, geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to Ryder Scott engineers for consideration in estimating our underground accumulations of crude oil and natural gas.
The report of Ryder Scott dated November 2, 2012, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99 to this report.
Ed Holloway, our President and Chief Executive Officer, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission. Mr. Holloway has over thirty years of experience in oil and gas exploration and development.
Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology. Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.
Estimates of volumes of proved reserves at year end are presented in barrels (Bbls) for oil and for, natural gas, in thousands of cubic feet (Mcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.
The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include decline curve analysis, which utilized extrapolations of historical production and pressure data available through August 31, 2012, in those cases where this data was considered to be definitive. The data used in this analysis was obtained from public data sources and were considered sufficient for calculating producing reserves.
The proved non-producing and undeveloped reserves were estimated by the analogy method. The analogy method uses pertinent well data obtained from public data sources that were available through August 2012.
Below are estimates of our net proved reserves at August 31, 2012, all of which are located in Colorado:
Below are estimates of our present value of estimated future net revenues from such reserves based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities – Oil and Gas. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions. The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the years ended August 31, 2012, 2011 and 2010. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels. No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead. Present values were computed by discounting future net revenues by 10% per year.
As of August 31, 2012, 2011 and 2010, our standardized oil and gas measurements were as follows:
For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2012, generated increases in projected future gross revenue from proved reserves of $302,222,999 and future net cash flow of $197,471,533 from August 31, 2011. During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $77,125,608. Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2012, of approximately $33 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.
For standardized oil and gas measurement purposes, our drilling, acquisition, and participation activities during the year ended August 31, 2011, generated increases in projected future gross revenue from proved reserves of $170,567,978 and future net cash flow of $121,103,611 from August 31, 2010. During that same period, when applying a 10% discount rate to our future net cash flows, our discounted future net cash flow from proved reserves increased by $55,200,117. Increases in our standardized oil and gas measures were the result of our expenditures during the year ended August 31, 2011, of approximately $22 million for the development of oil and gas properties and acquisitions of in place reserves, which directly related to proved oil and gas reserves.
In general, the volume of production from our oil and gas properties declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Accordingly, volumes generated from our future activities are highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.
Various state and federal agencies regulate the production and sale of oil and natural gas. All states in which we plan to operate impose restrictions on the drilling, production, transportation and sale of oil and natural gas.
The Colorado Oil and Gas Conservation Commission (“COGCC”) is the primary regulator of exploration and production of oil and gas resources in the area in which we operate. Via the permitting and inspection process, COGCC regulates oil and gas operators and, among other criteria, enforces specifications regarding the mechanical integrity of wells as well as the prevention and mitigation of adverse environmental impacts.
The Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. FERC’s jurisdiction over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce.
FERC has pursued policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. We do not know what effect FERC’s other activities will have on the access to markets, the fostering of competition and the cost of doing business.
Our sales of oil and natural gas liquids will not be regulated and will be at market prices. The price received from the sale of these products will be affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines.
Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production and related operations. Most states require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil and gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and gas is produced from our properties. The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects its profitability. Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with those laws.
As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve our natural resources and the environment. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.
The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in their interpretation could have a significant impact on us, as well as the oil and natural gas industry in general.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.
Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations. We are required to maintain such permits or meet general permit requirements. The EPA and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and natural gas exploration and production operations. A number of agencies have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit pollutants. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.
The EPA recently amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act (the “SDWA”) to exclude hydraulic fracturing from the definition of “underground injection.” However, the U.S. Senate and House of Representatives are currently considering the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”), which will amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, which could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements.
The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. While no federal law is presently in place, some states have enacted laws pertaining to chemical disclosure. In December 2011, the State of Colorado approved regulation requiring parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process. The regulation went into effect in April 2012 and requires the reporting of additives used.
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.
Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2012 for emissions occurring in 2011.
Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (the “ACESA”) which would establish an economy-wide cap-and-trade program to reduce United States emissions of greenhouse gases including carbon dioxide and methane that may contribute to the warming of the Earth’s atmosphere and other climatic changes. If it becomes law, ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas.
Climate change has emerged as an important topic in public policy debate regarding our environment. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases, which may ultimately pose a risk to society and the environment. Products produced by the oil and natural gas exploration and production industry are a source of certain greenhouse gases, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.
We operate in the Wattenberg Field of the D-J Basin, where the rock formations are typically tight and it is a common practice to utilize hydraulic fracturing to allow for or increase hydrocarbon production. Hydraulic fracturing involves the process of forcing a mixture of fluid and white sand into a formation to create pores and fractures, thus creating a passageway for the release of oil and gas. All of our producing wells were hydraulic fractured and we expect to employ the technique extensively in future wells that we drill.
We outsource all hydraulic fracturing services to service providers with significant experience, and whom we deem to be competent and responsible. Our service providers supply all personnel, equipment and materials needed to perform each stimulation, including the mixtures that are injected into our wells. These mixtures primarily consist of water and sand, with nominal amounts of other ingredients that include chemical compounds commonly found in consumer products. This mixture is injected into our wells at pressures of 5,500-6,000 psi at injection rates that that range between 25-55 barrels of mixture per minute. On average, a single stage stimulation will utilize approximately 4,500 barrels of water and 125,000 pounds of sand.
We require our service companies to carry adequate insurance covering incidents that could occur in connection with their activities. Our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the respective geographic location. We have not had any incidents, citations or lawsuits relating to any environmental issues resulting from hydraulic fracture stimulation and we are not presently aware of any such matters.
In recent years, environmental opposition to hydraulic fracturing has increased, and various governmental and regulatory authorities are considering the adequacy of current regulations. In Colorado, the primary regulator is the Colorado Oil and Gas Conservation Commission, which requires parties engaged in hydraulic fracturing to disclose the concentrations of the chemicals used in the process. Some localities are considering more stringent regulation. We continue to monitor these developments, as we consider the process to be critical to our success.
Competition and Marketing
We are faced with strong competition from many other companies and individuals engaged in the oil and gas business, many are very large, well established energy companies with substantial capabilities and established earnings records. We may be at a competitive disadvantage in acquiring oil and gas prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs. It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business.
Exploration for and production of oil and gas are affected by the availability of pipe, casing and other tubular goods and certain other oil field equipment including drilling rigs and tools. We depend upon independent drilling contractors to furnish rigs, equipment and tools to drill our wells. Higher prices for oil and gas may result in competition among operators for drilling equipment, tubular goods and drilling crews, which may affect our ability expeditiously to drill, complete, recomplete and work-over wells.
The market for oil and gas is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted. These factors include the proximity of wells to, and the capacity of, natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation. In addition, there is always the possibility that new legislation may be enacted, which would impose price controls or additional excise taxes upon crude oil or natural gas, or both. Oversupplies of natural gas can be expected to recur from time to time and may result in the gas producing wells being shut-in. Imports of natural gas may adversely affect the market for domestic natural gas.
The market price for crude oil is significantly affected by policies adopted by the member nations of Organization of Petroleum Exporting Countries ("OPEC"). Members of OPEC establish prices and production quotas among themselves for petroleum products from time to time with the intent of controlling the current global supply and consequently price levels. We are unable to predict the effect, if any, that OPEC or other countries will have on the amount of, or the prices received for, crude oil and natural gas.
Gas prices, which were once effectively determined by government regulations, are now largely influenced by competition. Competitors in this market include producers, gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as residual fuel oil. Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry.
Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term contracts priced at spot market prices.
Our offices are located at 20203 Highway 60, Platteville, CO 80651. Our office telephone number is (970) 737-1073 and our fax number is (970) 737-1045.
The Platteville office and equipment yard is rented to us pursuant to a lease with HS Land & Cattle, LLC, a firm controlled by Ed Holloway and William E. Scaff, Jr., two of our officers. The lease requires monthly payments of $10,000 and expires on July 1, 2013.
As of October 15, 2012, we had 11 full time employees.
Neither we, nor any of our properties, are subject to any pending legal proceedings.
We make available on our website, www.syrginfo.com, under “Investor Relations, SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”).
The “Investor Relations, News / Events” pages on our website contain press releases and investor presentations with more recent information than may have been available at the time of the most recent filing with the SEC.
Our Code of Ethics and Board of Directors Committee Charters (Audit and Compensation Committees) are also available on our website under “Investor Relations, Corporate Governance.”
ITEM 1A. RISK FACTORS
Investors should be aware that any purchase of our securities involves certain risks, including those described below, which could adversely affect the value of our common stock. We do not make, nor have we authorized any other person to make, any representation about the future market value of our common stock. In addition to the other information contained in this annual report, the following factors should be considered carefully in evaluating an investment in our securities.
Laws and Regulations
Our operations will be affected from time to time and in varying degrees by political developments and Federal and state laws and regulations regarding the development, production and sale of crude oil and natural gas. These regulations require permits for drilling of wells and also cover the spacing of wells, the prevention of waste, and other matters. Rates of production of oil and gas have for many years been subject to Federal and state conservation laws and regulations and the petroleum industry is subject to Federal tax laws.
In addition, the production of oil or gas may be interrupted or terminated by governmental authorities due to ecological and other considerations. Compliance with these regulations may require a significant capital commitment by and expense to us and may delay or otherwise adversely affect our operations.
From time to time legislation has been proposed relating to various conservation and other measures designed to decrease dependence on foreign oil. No prediction can be made as to what additional legislation may be proposed or enacted. Oil and gas producers may face increasingly stringent regulation in the years ahead and a general hostility towards the oil and gas industry on the part of a portion of the public and of some public officials. Future regulation will probably be determined by a number of economic and political factors beyond our control or the oil and gas industry.
Our activities are subject to existing federal and state laws and regulations governing environmental quality and pollution control. Compliance with environmental requirements and reclamation laws imposed by Federal, state, and local governmental authorities may necessitate significant capital outlays and may materially affect our earnings. It is impossible to predict the impact of environmental legislation and regulations (including regulations restricting access and surface use) on our operations in the future although compliance may necessitate significant capital outlays, materially affect our earning power or cause material changes in our intended business. In addition, we may be exposed to potential liability for pollution and other damages.
Dry holes and non-productive wells
Oil and gas exploration is not an exact science, and involves a high degree of risk. The primary risk lies in the drilling of dry holes or drilling and completing wells, which, though productive, do not produce gas and/or oil in sufficient amounts to return the amounts expended and produce a profit. Hazards, such as unusual or unexpected formation pressures, downhole fires, blowouts, loss of circulation of drilling fluids and other conditions are involved in drilling and completing oil and gas wells and, if such hazards are encountered, completion of any well may be substantially delayed or prevented. In addition, adverse weather conditions can hinder or delay operations, as can shortages of equipment and materials or unavailability of drilling, completion, and/or work-over rigs. Even though a well is completed and is found to be productive, water and/or other substances may be encountered in the well, which may impair or prevent production or marketing of oil or gas from the well.
Exploratory drilling involves substantially greater economic risks than development drilling because the percentage of wells completed as producing wells is usually less than in development drilling. Exploratory drilling itself can be of varying degrees of risk and can generally be divided into higher risk attempts to discover a reservoir in a completely unproven area or relatively lower risk efforts in areas not too distant from existing reservoirs. While exploration adjacent to or near existing reservoirs may be more likely to result in the discovery of oil and gas than in completely unproven areas, exploratory efforts are nevertheless high risk activities.
Although the completion of oil and gas wells is, to a certain extent, less risky than drilling for oil and gas, the process of completing an oil or gas well is nevertheless associated with considerable risk. In addition, even if a well is completed as a producer, the well for a variety of reasons may not produce oil or gas in quantities sufficient to repay our investment in the well.
The acquisition, exploration and development of oil and gas properties, and the production and sale of oil and gas are subject to many factors not under our control. These factors include, among others, general economic conditions, proximity to pipelines, oil import quotas, supply, demand, and price of other fuels and the regulation of production, refining, transportation, pricing, marketing and taxation by various governmental authorities.
Supply and demand
Buyers of our gas, if any, may refuse to purchase gas from us in the event of oversupply. If we drill wells that are productive of natural gas, the quantities of gas that we may be able to sell may be too small to pay for the expenses of operating the wells. In such a case, the wells would be "shut-in" until such time, if ever, that economic conditions permit the sale of gas in quantities which would be profitable.
Insurable risks, defects, and hazards
Interests that we may acquire in oil and gas properties may be subject to royalty and overriding royalty interests, liens incident to operating agreements, liens for current taxes and other burdens and encumbrances, easements and other restrictions, any of which may subject us to future undetermined expenses. We do not intend to purchase title insurance, title memos, or title certificates for any leasehold interests we will acquire.
It is possible that at some point we will have to undertake title work involving substantial costs. In addition, it is possible that we may suffer title failures resulting in significant losses.
The drilling of oil and gas wells involves hazards such as blowouts, unusual or unexpected formations, pressures or other conditions, which could result in substantial losses or liabilities to third parties. Although we intend to acquire adequate insurance, or to be named as an insured under coverage acquired by others (e.g., the driller or operator), we may not be insured against all such losses because insurance may not be available, premium costs may be deemed unduly high, or for other reasons. Accordingly, uninsured liabilities to third parties could result in the loss of our funds or property.
Opposition to Hydraulic Fracturing
Hydraulic fracturing, the process used for releasing oil and gas from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development. While companies have been using the technique for decades, as drilling expands to more populated areas, environmentalists raise concern about the effects on the population’s health and drinking water.
In April of this year, the Obama administration proposed the first national standards to control air pollution from gas wells stimulated by hydraulic fracturing. The EPA published claims that the new regulations would ensure pollution is controlled without slowing natural gas production, actually resulting in more product for fuel suppliers to bring to market. The proposal would restrict the venting of gases during the well completion phase, and require the implementation of a new technology to reduce emissions of pollutants during completion of wells. Implementation of the pollution-reducing equipment for so-called “green completions” is required by January 2015.
Locally, some counties and municipalities are attempting to impose more stringent regulations than those required by the Colorado Oil and Gas Conservation Commission. Litigation has been initiated to determine the legality of these attempts. Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, state and/or local levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and gas resources from shale formations which are not commercial without the use of hydraulic fracturing. This could have an adverse effect on our business.
Related Party Transactions
Our transactions with related parties may cause conflicts of interests that may adversely affect us. Ed Holloway and William E. Scaff, Jr., both of whom are officers, directors and principal shareholders, control two entities, Petroleum Exploration & Management, LLC ("PEM") and HS Land & Cattle, LLC (“HSLC”), with whom we do business. We presently lease the Platteville office space and equipment storage yard from HSLC at a rate of $10,000 per month. During 2011, we purchased all of the operating oil and gas assets owned by PEM. Material transactions with related parties are approved by our independent directors.
We believe that the transactions and agreements that we have entered into with these affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third parties. However, these relationships could create, or appear to create, potential conflicts of interest when our board of directors is faced with decisions that could have different implications for us and these affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public's perception of us, as well as our relationship with other companies and our ability to enter into new relationships in the future, which could have a material adverse effect on our ability to do business.
Our failure to obtain capital may significantly restrict our proposed operations. We need additional capital to fund our capital expenditure plans. We do not know what the terms of any future capital raising may be but any future sale of our equity securities would dilute the ownership of existing stockholders and could be at prices substantially below the price investors paid for their shares of our common stock. Our failure to obtain the capital required will result in the slower implementation of our business plan. There can be no assurance that we will be able to obtain the necessary capital.
We will need to consistently generate positive cash flow or obtain additional financing until we are able to consistently yield sufficient cash essential for the growth of our operations in executing our strategic business plan.
As a result of our short operating history, it is difficult for potential investors to evaluate our business.
Market for our Common Stock
There is only a limited public market for our common stock. Although our common stock has been listed on the NYSE MKT since July 27, 2011, the trading in our stock has, at times, been limited and sporadic. Additionally, the trading price of our common stock may fluctuate widely in response to various factors, some of which are beyond our control. Factors that could negatively affect our share price include, but are not limited to:
Shares issuable upon the exercise of outstanding warrants and options may substantially increase the number of shares available for sale in the public market and may depress the price of our common stock. We have outstanding options and warrants which could potentially allow the holders to acquire a substantial number of shares of our common stock. Until the options and warrants expire, the holders will have an opportunity to profit from any increase in the market price of our common stock without assuming the risks of ownership. Holders of options and warrants may exercise these securities at a time when we could obtain additional capital on terms more favorable than those provided by the options or warrants. The exercise of the options and warrants will dilute the voting interest of the current owners of our outstanding shares by adding a substantial number of additional shares of common stock.
Reliance on Key Personnel
We are dependent upon the contributions of our senior management team and other key employees for our success. If one or more of these executives, or other key employees, were to cease to be employed by us, our progress could be adversely affected. In particular, we may have to incur costs to replace senior executive officers or other key employees who leave, and our ability to execute our business strategy could be impaired if we are unable to replace such persons in a timely manner.
See Item 1 of this report.
Our common stock is listed on the NYSE MKT under the symbol “SYRG”.
Trading of our stock on the NYSE Amex (predecessor to the NYSE MKT) began on July 27, 2011. Prior to listing on the NYSE Amex, our stock traded on the OTC Bulletin Board.
Shown below is the range of high and low sales prices for our common stock as reported by the NYSE MKT since July 27, 2011. Prior to July 27, 2011, the high and low prices were reported by the OTC Bulletin Board. Market quotations from the OTC Bulletin Board reflect inter-dealer prices, without retail mark-up, mark-down or commissions and may not necessarily represent actual transactions.
As of October 15, 2012, the closing price of our common stock on the NYSE MKT was $4.22.
As of October 15, 2012, we had 51,637,924 outstanding shares of common stock and 189 shareholders of record. The number of beneficial owners of our common stock is approximately 2,100.
Since inception, we have not paid any cash dividends on common stock. Cash dividends are restricted under the terms of our credit facility and we presently intend to continue the policy of using retained earnings for expansion of our business.
Our articles of incorporation authorize our board of directors to issue up to 10,000,000 shares of preferred stock. The provisions in the articles of incorporation relating to the preferred stock allow our directors to issue preferred stock with multiple votes per share and dividend rights, which would have priority over any dividends paid with respect to the holders of our common stock. The issuance of preferred stock with these rights may make the removal of management difficult even if the removal would be considered beneficial to shareholders generally, and will have the effect of limiting shareholder participation in certain transactions such as mergers or tender offers if these transactions are not favored by our management.
Additional Shares Which May be Issued
The following table lists additional shares of our common stock, which may be issued as of October 15, 2012, upon the exercise of outstanding options or warrants or the issuance of shares for oil and gas leases.
A. Between December 2009 and March 2010, we sold 180 Units at a price of $100,000 per Unit to private investors. Each Unit consisted of one $100,000 note and 50,000 Series C warrants. The notes were convertible into shares of our common stock at a conversion price of $1.60 per share, at the option of the holder. Each Series C warrant entitles the holder to purchase one share of our common stock at a price of $6.00 per share at any time prior to December 31, 2014. Between June 2010 and March 2011, note-holders converted all notes into 11,250,000 shares of our common stock.
We paid Bathgate Capital Partners (now named GVC Capital), the placement agent for the Unit offering, a commission of 8% of the amount Bathgate Capital raised in the Unit offering. We also sold to the placement agent, for a nominal price, warrants to purchase 1,125,000 shares of our common stock at a price of $1.60 per share. The placement agent’s warrants expire on December 31, 2014. As of October 15, 2012, warrants to purchase 355,399 shares had been exercised by their holders.
B. Each shareholder of record on the close of business on September 9, 2008, received one Series A warrant for each share which they owned on that date (as adjusted for a reverse split of our common stock which was effective on September 22, 2008). Each Series A warrant entitles the holder to purchase one share of our common stock at a price of $6.00 per share at any time prior to December 31, 2012.
C. Prior to our acquisition of a corporation on September 9, 2008, that corporation sold 1,000,000 Units at a price of $1.00 per Unit and 1,060,000 Units at a price of $1.50 per Unit to private investors. Each Unit consisted of one share of Predecessor Synergy’s common stock and one Series A warrant. In connection with the acquisition, these Series A warrants were exchanged for 2,060,000 of our Series A warrants. The Series A warrants are identical to the Series A warrants described in Note B above.
D. Between December 1, 2008 and June 30, 2009, we sold 1,000,000 units at a price of $3.00 per unit. Each unit consisted of two shares of our common stock, one Series A warrant and one Series B warrant. The Series A warrants are identical to the Series A warrants described in Note B above. Each Series B warrant entitles the holder to purchase one share of our common stock at a price of $10.00 per share at any time prior to December 31, 2012.
In connection with this unit offering, we paid the sales agent for the offering a commission of 10% of the amount the sales agent sold in the offering. We also issued warrants to the sales agent. The warrants allow the sales agent to purchase 31,733 units (which units were identical to the units sold in the offering) at a price of $3.60 per unit. The sales agent warrants will expire on the earlier of December 31, 2012, or twenty days following written notification from us that our common stock had a closing bid price at or above $7.00 per share for any ten of twenty consecutive trading days.
E. During the fiscal year ended August 31, 2012, we entered into an agreement with a public relations firm, and agreed to issue warrants to the firm in exchange for services provided. For the one year term, warrants to purchase 100,000 shares of stock at $2.69 per share are available to the firm and become exercisable at quarterly intervals upon our being satisfied with the firm's services.
F. See Item 11 of this report for information regarding shares issuable upon exercise of options held by our officers and employees.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data presented in this item has been derived from our audited financial statements that are either included in this report or in reports previously filed with the U.S. Securities and Exchange Commission. The information in this item should be read in conjunction with the financial statements and accompanying notes and other financial data included in this report.
The fluctuation in results of operations and financial position is due in part to acquisitions of producing oil and gas properties coupled with the aggressive drilling program we executed during 2010, 2011 and 2012.
See Note 15 to the Financial Statements included as part of this report for our quarterly financial data.
The following discussion and analysis was prepared to supplement information contained in the accompanying financial statements and is intended to explain certain items regarding the financial condition as of August 31, 2012, and the results of operations for the years ended August 31, 2012, 2011 and 2010. It should be read in conjunction with the “Selected Financial Data” and the accompanying audited financial statements and related notes thereto contained in this annual report on Form 10-K.
This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in the subsection entitled “Risk Factors” above, which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
Synergy Resources Corporation (“we,” “our,” “us” or “the Company”) is a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the Denver-Julesburg Basin (“D-J Basin”) of Colorado. All of our producing wells are in the Wattenberg Field, which has a history as one of the most prolific production areas in the country. During 2011, we expanded our undeveloped acreage holdings in eastern Colorado and western Nebraska, and may commence development activities in these areas.
Since commencing active operations in September 2008, we have undergone significant growth. As disclosed in the following table, as of August 31, 2012, we have drilled, acquired, or participated in 209 gross oil and gas wells and have successfully completed 191 wells that were in production. There were 18 wells in progress at August 31, 2012.
As of August 31, 2012, we:
Estimated BOE proved reserves increased 140% during the fiscal year 2012, primarily as a result of the success achieved under the 2012 drilling program.
Our strategy for continued growth includes additional drilling activities, acquisition of existing wells, and recompletion of wells to more rapidly access and/or extend reserves through improved hydraulic stimulation techniques. We attempt to maximize our return on assets by drilling and operating wells in which we have a majority net revenue interest. We attempt to limit our risk by drilling in proven areas. To date, we have not drilled any dry holes. All wells drilled prior to 2012 were relatively low-risk vertical or directional wells. However, the increased pace of horizontal drilling activity in the D-J Basin by numerous operators has provided us with the opportunity to witness best practices in the industry first hand. Consequently, we agreed to participate in our first horizontal well, which began drilling operations in January 2012 and commenced production in March 2012. The introduction of horizontal drilling to the D-J Basin has accelerated the retrieval of natural gas reserves in the Niobrara Shale and Codell formations. We subsequently agreed to participate in additional horizontal wells. By the end of August, we were a participant in three horizontal wells that were in production, two wells that were in the completion phase and one well that was in the drilling phase. We expect to participate in additional horizontal wells and we are preparing to drill and operate horizontal wells for our own account during our 2013 fiscal year.
Historically, our cash flow from operations was not sufficient to fund our growth plans and we relied on proceeds from the sale of debt and equity securities. Our cash flow from operations is increasing, and we plan to finance an increasing percentage of our growth with internally generated funds. Ultimately, implementation of our growth plans will be dependent upon the success of our operations and the amount of financing we are able to obtain.
Results of Operations
Material changes of certain items in our statements of operations included in our financial statements for the periods presented are discussed below.
For the year ended August 31, 2012, compared to the year ended August 31, 2011
For the year ended August 31, 2012, we reported net income of $12,123,942, or $0.26 per share, $0.25 per diluted share, compared to a net loss of $(11,600,158), or $(0.45) per basic and diluted share for the period ended August 31, 2011.
Our rapid improvement in profitability was driven by our successful drilling program. The significant variances between the two years are (i) increased revenues and expenses associated with more producing wells, (ii) the cessation of certain interest and other non-cash expenses, and (iii) the effect of income taxes. As further explained below, our net loss for 2011 resulted from non-cash charges related to the convertible promissory notes and the derivative conversion liability. The following discussion also expands upon items of inflow and outflow that affect operating income.
Oil and Gas Production and Revenues – For the year ended August 31, 2012, we recorded total revenues of $24,969,213 compared to $10,001,668 for the year ended August 31, 2011, an increase of $14,967,545 or 150%. We experienced an overall 151% annual increase in production from the prior year having realized a full year of production from wells at the beginning of the year, and the addition of wells, including new wells drilled as well as those acquired. Although there was significant commodity price fluctuation during the year, overall pricing on a BOE basis was not significantly different from 2011 to 2012. For the fiscal year ended August 31, 2012, our gas / oil ratio (“GOR”) on a BOE basis was 44/56 compared to 45/55 for the fiscal year ended August 31, 2011.
As of August 31, 2012, we had 191 producing wells. Net oil and gas production averaged 1,149 BOE per day in 2012, as compared with 452 BOE per day for 2011, a year over year increase of 154% in BOEPD production. The significant increase in production from the prior year reflects 52 additional wells that went into productive status since August 31, 2011 and a full year of production from the 111 wells that were added over the course of fiscal year 2011. Production for the fourth fiscal quarter of 2012 averaged 1,270 BOE per day.
Revenues are sensitive to changes in commodity prices. From 2011 to 2012, our realized annual average sales price per barrel of oil rose 5%; however, we experienced a decline of 24% in our realized annual average sales price per Mcf of natural gas. There was a 45% and 130% swing in the price of crude and natural gas from the respective low to high prices during the twelve month period ended August 31, 2012. Barrel and Mcf prices at year end were up 2% and down 9%, respectively, from twelve month average. We did not utilize any commodity price hedges during either year, but expect to do so in the future.
While our balanced production mix of oil and gas and the high liquid content of our gas help to mitigate the negative effect of volatility in commodity prices, downward price pressure could have a negative effect on revenues reported in future periods.
Lease Operating Expenses (“LOE”) and Production Taxes – Direct operating costs of producing oil and natural gas and taxes on production and properties are reported as lease operating expenses as follows:
Lease operating and work-over costs tend to fluctuate with the number of producing wells, and, to a lesser extent, on variations in oil field service costs and changes in the production mix of crude oil and natural gas. From 2011 to 2012, we experienced an increase in production cost per BOE in connection with additional costs to bolster output from some of our older wells. Taxes, the largest component of lease operating expenses, generally move with the value of oil and gas sold. As a percent of revenues, taxes averaged 10% in both 2012 and 2011.
Depletion, Depreciation and Amortization (“DDA”) – We recognized DDA expense of $6,009,510 and $2,838,307 for the fiscal years ended August 31, 2012 and 2011, respectively, of which $5,837,788 and $2,743,441 was the depletion of oil and gas properties for 2012 compared to 2011. Depletion expense more than doubled, primarily as a result of growth in production and producing properties from 2011 to 2012.
Capitalized costs of evaluated oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate. For fiscal year 2012, our depletable reserve base was 5,321,502 barrels of oil and 34,555,031 Mcf of natural gas. Fiscal year 2012 production represented 4% and 3% of those reserve bases, respectively.
Depletion expense per BOE declined 16% from 2011 to 2012. For the fiscal year ended August 31, 2012, depletion of oil and gas properties was $13.88 per BOE compared to $16.62 for the fiscal year ended August 31, 2011. During 2012, we have been able to increase reserves and production faster than the increase in capitalized costs, which caused the decline in the expense per BOE.
General and Administrative (“G&A”) – The following table summarizes the components of general and administration expenses:
Although G&A costs increased during 2012, they increased at a lower rate than the overall growth of our business, as we strive to maintain an efficient overhead structure. For the fiscal year ended August 31, 2012, G&A was $8.46 per BOE compared to $17.59 for the fiscal year ended August 31, 2011.
Cash based compensation and benefits include payments to employees and directors. Share based compensation is associated with compensation in the form of either stock options or common stock grants for employees, directors, and service providers. The amount of expense recorded for stock options is calculated using the Black-Scholes-Merton option pricing model, while the amount of expense recorded for common stock grants is calculated based upon the closing market value of the shares on the date of grant.
Professional fees have increased as we have grown our business. The two primary factors driving this increase are the additional accounting and auditing fees incurred in connection with operating as a public company, and the additional professional services required to meet the compliance requirements of the Sarbanes–Oxley Act, as we have progressed from a smaller reporting company to an accelerated filer under SEC definitions. The listing on the NYSE: MKT contributed to costs in excess of those reported in the comparable prior year period when our stock was listed on the OTC Bulletin Board.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties. Those costs are reclassified from general and administrative expenses and capitalized into the full cost pool. The increase in capitalized costs from 2011 to 2012 reflects our increasing activities to acquire leases and develop the properties.
Operating Income (Loss) – For the year ended August 31, 2012, we generated operating income of $11,754,491, compared to $2,820,240 for the year ended August 31, 2011. This tri-fold increase in operating income resulted primarily from the increasing contribution of wells brought into production during the last two years, which includes wells drilled under the 2012 and 2011 drilling programs, the acquisition of producing properties from PEM and other parties, and increased production from older wells that were recompleted using newer hydraulic fracturing techniques. Increased revenues more than offset increased costs incurred by us to accomplish these objectives.
Other Income (Expense) – Other income for the fiscal year ended August 31, 2012 was $37,451, consisting solely of interest income. Interest cost of $208,344 was incurred during 2012, all of which was capitalized as part of the cost of oil and gas properties. For the fiscal year ended August 31, 2011, we reported several significant items of expense in addition to interest income of $55,776. These other expenses reported in 2011 primarily related to our convertible promissory notes, including net interest expense of $589,539, accretion of debt discount of $2,664,138, amortization of debt issuance costs of $1,587,799, and a change in the fair value of the derivative conversion liability of $10,229,229. During 2011, interest expense was also recorded on the related party note and the bank line of credit in the amounts of $74,047 and $41,559, respectively. Of these expenses, we capitalized interest and amortization of $710,137.
The convertible promissory notes contained a conversion feature which was considered an embedded derivative and recorded as a liability at its initial estimated fair value. This derivative conversion liability was then marked-to-market over time, with the resulting change in fair value recorded as a non-cash item in the statement of operations. All expenses related to the convertible promissory notes ceased mid-year 2011, as all noteholders converted their holdings into equity.
Income Taxes – We reported income tax expense of $4,579,000 offset by a tax benefit of $4,911,000 for the fiscal year ended August 31, 2012, resulting in a net income tax benefit of $332,000 and a corresponding net deferred tax asset in the same amount. For all reporting periods prior to 2012, no income tax expense or benefit was reported, as all tax assets or liabilities were effectively offset by a valuation allowance.
The income tax benefit is a one-time event representing the expected value of the future deduction of the net operating loss carry-forward generated during our start-up years.
Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome. During the current fiscal year, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carry-forward, and we released our entire valuation allowance of $4,911,000. Prior to 2012, management concluded that it was more likely than not that our net deferred tax asset would not be realized in the foreseeable future and, accordingly, a full valuation allowance was provided against the net deferred tax asset.
During 2012 management concluded that positive indicators outweighed negative indicators and that it was appropriate to release the valuation allowance. Although we reported net losses every year since inception through August 31, 2011, we attributed all of the net losses for the 2011 and 2010 fiscal years to a single discrete item. The discrete item was the fair value accounting treatment of the components of the convertible promissory notes issued in 2010, which created non-cash expenses for accretion of debt discount, amortization of issuance costs, and change in fair value of derivative liability. As all of the convertible notes were converted, those expenses will not recur, and it is appropriate to exclude them from a consideration of future profitability. Secondly, we had begun to report net income and had significantly increased oil and gas reserve values. Lastly, we completed a debt financing arrangement and an equity financing arrangement that allow us to continue with our operating plan. Accordingly, we believed that it was appropriate to release the valuation allowance related to the deferred tax asset created by the net operating loss carryover.
Future reporting periods are expected to report income tax expense at an estimated effective tax rate of approximately 37%.
For the year ended August 31, 2011, compared to the year ended August 31, 2010
For the year ended August 31, 2011, we reported a net loss of $(11,600,158), or $(0.45) per share, compared to a net loss of $(10,794,172), or $(0.88) per share for the period ended August 31, 2010. As explained below, the net loss for each year is significantly affected by non-cash charges related to the convertible promissory notes and the derivative conversion liability. The following discussion also expands upon items of inflow and outflow that affect operating income. In most cases, the nature of the change from 2010 to 2011 involves the significant growth in number of producing properties and activities to acquire additional undeveloped acreage and proved properties.
Oil and Gas Production and Revenues – For the year ended August 31, 2011, we recorded total oil and gas revenues of $9,777,172 compared to $2,158,444 for the year ended August 31, 2010, as summarized in the following table:
Net oil and gas production for the year ended August 31, 2011, was 165,056 BOE, or 452 BOE per day, as compared with 44,606 BOE, or 122 BOE per day, for the year ended August 31, 2010. The significant increase in production from the prior year resulted from realizing a full year of production from wells at the beginning of the year, and the addition of wells, including new wells drilled and those acquired in the PEM acquisition. Production for the fourth fiscal quarter of 2011 averaged 577 BOE per day.
Lease Operating Expenses – As summarized in the following table, our lease expenses include the direct operating costs of producing oil and natural gas, taxes on production and properties, and well work-over costs:
Lease operating and work-over costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas. Taxes tend to increase or decrease primarily based on the value of oil and gas sold, and, as a percent of revenues, averaged 10% in 2011 and 11% in 2010.
Depletion, Depreciation and Amortization (“DDA”) – DDA expense is summarized in the following table:
The determination of depletion, depreciation and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves and actual production volumes. As of August 31, 2011, we had 4,446,565 BOE of estimated net proved reserves compared to 1,423,524 BOE of estimated net proved reserves as of August 31, 2010. Depletion expense per BOE increased approximately 7% as a result of cost increases across all of our operating sectors, including costs incurred for lease acquisition, drillings, and well completion.
Impairment of Oil and Gas Properties – We use the full cost accounting method, which requires recognition of impairment when the total capitalized costs of oil and gas properties exceed the “ceiling” amount, as defined in the full cost accounting literature. During the years ended August 31, 2011 and 2010, no impairment was recorded because our capitalized costs subject to the ceiling test were less than the estimated future net revenues from proved reserves discounted at 10% plus the lower of cost or market value of unevaluated properties. The ceiling test is performed each quarter and there is the possibility for impairments to be recognized in future periods. Once impairment is recognized, it cannot be reversed.
General and Administrative – The following table summarizes the components of general and administration expenses:
Cash based compensation includes payments to employees. The increase of $724,061 from 2010 to 2011 reflects the expansion of our business, including the addition of 5 employees during the year. Stock-based compensation includes compensation paid to employees, directors, and service providers in the form of stock options or shares of common stock.
The amount of expense recorded for stock options is calculated by using the Black-Scholes-Merton option pricing model. The amount of expense recorded for shares of common stock is calculated based upon the closing market value of the shares.
The increase in professional fees includes certain accounting fees and investment banking fees related to the acquisition of assets from PEM. In addition, our progression from smaller reporting company to accelerated filer required additional professional services related to our compliance with the rules and regulations of Sarbanes–Oxley.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties. Those costs are reclassified from general and administrative expenses and capitalized into the full cost pool. The increase in capitalized costs from 2010 to 2011 reflects our increasing activities to acquire leases and develop the properties.
Operating Income (Loss) – For the year ended August 31, 2011, we generated operating income of $2,820,240, as compared with an operating loss of $781,525 for the year ended August 31, 2010. This increase of $3,601,765 resulted primarily from the increasing contribution of wells brought into production during the two fiscal years, which includes wells drilled under the 2011 and 2010 drilling programs, the acquisition of producing properties from PEM and other parties, and increased production from older wells that were recompleted using newer hydraulic fracturing techniques. Increased revenues more than offset increased costs incurred by us to accomplish these objectives.
Other Income (Expense) – During the year ended August 31, 2011, we recognized $14,420,398 in other expense compared to $10,012,647 during the comparable period in 2010. During 2011, interest expense was also recorded on the related party note and the bank line of credit in the amounts of $74,047 and $41,559, respectively. Of these expenses, we capitalized interest and amortization of $710,137 compared to $269,761 capitalized in 2010.
The amounts included in other income (expense) are primarily related to components of the 8% convertible promissory notes. The 8% convertible promissory notes contained a conversion feature, which was considered an embedded derivative and recorded as a liability at its initial estimated fair value. This derivative conversion liability was then marked-to-market over time, with the resulting change in fair value recorded as a non-cash item in the statement of operations. Prior to August 31, 2011, all of the notes had been converted, thereby eliminating the derivative conversion liability. We recognized a non-cash expense of $10,229,229 and $7,678,457 during the years ending August 31, 2011 and 2010, respectively, related to the change in fair value of the derivative conversion liability.
Interest expense, net, contained several components related to the 8% convertible promissory notes. In addition to the 8% coupon rate, we recorded amortization of debt issue costs of $1,587,799 and accretion of debt discount of $2,664,137 during the year ended August 31, 2011. During the year ended August 31, 2010, amortization of debt issue costs was $453,656 and accretion of debt discount was $1,333,590. In connection with the conversion of the remaining 8% convertible promissory notes outstanding during 2011, the Company accelerated its recognition of all remaining amounts for unamortized debt issuance costs and debt discount and the acceleration is included in the amounts presented above.
Income Taxes – Income taxes had no impact on our results of operations for the fiscal years ended August 31, 2011 and 2010, as we had reported a net loss every year since inception and for tax purposes had a net operating loss carry-forward (“NOL”) of approximately $11.3 million. The NOL is available to offset future taxable income. As of August 31, 2011 and 2010, management concluded that it was more likely than not that we would not be able to realize the benefits of our tax assets in the foreseeable future, therefore a full valuation allowance had been provided against deferred tax assets as of August 31, 2011 and 2010.
Liquidity and Capital Resources
Our primary source of liquidity since inception has been net cash provided by sales and other issuances of equity and debt securities. Our secondary sources of capital have been cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities. Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us. While we believe that we have sufficient liquidity available to us from cash flows from operations and under our revolving credit facility unforeseen events may require us to obtain additional equity or debt financing. We have on file with the SEC an effective universal shelf registration statement that we may use for future securities offerings. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.
In November 2011, we modified our borrowing arrangement with Community Banks of Colorado, successor in interest to Bank of Choice, to increase the maximum allowable borrowings and to reduce the interest rate. In April 2012, the agreement was amended to further increase the borrowing base. The revolving line of credit provides us a borrowing capacity to $20 million. Outstanding borrowings accrue interest at the greater of 3.25% annually or the bank’s prime rate, which was also 3.25% at August 31, 2012. The maturity date for the arrangement is November 30, 2014.
The arrangement contains covenants that, among other things, restrict the payment of dividends and require compliance with certain financial ratios, for which we were fully in compliance as of August 31, 2012. The borrowing arrangement is collateralized by certain of our assets, including producing properties. Maximum borrowings are subject to reduction based upon a borrowing base calculation. As of August 31, 2012, the borrowing base calculation was not restrictive. We utilized a portion of the financing available through this arrangement to retire amounts outstanding under our related party note payable.
At August 31, 2012, we had cash and cash equivalents of $19,284,382 and a $17,000,000 balance available under our revolving credit facility.
On October 18, 2012, we entered into an amendment to this revolving line of credit agreement. The amended terms include an increase from $20 million to $30 million in the maximum amount of borrowings available, subject to certain collateral requirements. Other terms of the agreement, including interest on borrowed amounts and the commitment expiration date of November 30, 2014, were not materially changed.
Proceeds from any future borrowings are expected to be used primarily to fund lease acquisitions and drilling and completion costs.
On December 30, 2011, we completed the sale of 14.6 million shares of common stock in a public offering at a price of $2.75 per share. We netted $37,421,783 in proceeds, after deductions for the underwriting discounts, commissions and expenses of the offering.
We do not currently engage in any commodity hedging activities, although we may do so in the future.
We believe that the proceeds from our equity offering, plus cash flow from operations, plus additional borrowings available under our revolving line of credit will be sufficient to meet our liquidity needs during the remainder of this fiscal year. The amount, timing and allocation of capital expenditures is generally within our control, as participations are a limited portion of our operations. Fluctuations in prices for oil and natural gas could cause us to defer or accelerate our spending.
Our sources and (uses) of funds for the fiscal years ended August 31, 2012, 2011 and 2010, are shown below:
Net cash provided by operating activities was $21,252,102 and $7,916,308 for the years ended August 31, 2012 and 2011, respectively. The significant improvement reflects the operating contribution from 2011 wells that were producing for the entire year, plus the contribution from wells that began production during 2012.
In addition to our analysis using amounts included in the cash flow statement, we evaluate operations using a non-GAAP measure called “adjusted cash flow from operations”, which adjusts for cash flow items that merely reflect the timing of certain cash receipts and expenditures. Adjusted cash flow from operations was $18,274,492 for the year ended August 31, 2012, compared $6,346,800 for the year ended August 31, 2011. The improvement of $11,927,692 under that measure is closely correlated to, and primarily explained by, increased revenues of $14,967,545 less increased operating costs of $6,437,497. The timing of cash receipts and payments explains $2,977,610 of the variance in the measure.
The cash flow statement reports actual cash expenditures for capital expenditures, which differs from total capital expenditures on a full accrual basis. Specifically, cash paid for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On a full accrual basis, capital expenditures totaled $49,730,946, $47,237,827 and $12,888,373 for the years ended August 31, 2012, 2011 and 2010, respectively, compared to cash payments of $46,751,260, $30,247,327 and $9,152,175, respectively.
A reconciliation of the differences is summarized in the following table:
During the fiscal year ended August 31, 2012, we engaged in drilling or completion activities on 70 wells. Most of our capital expenditures for the fiscal year ended August 31, 2012, represent drilling and completion cost on wells on which production commenced during the year. In addition, we incurred costs of $9.1 million on the acquisition of mineral leases, $2.0 million of which were acquired in exchange for our common stock.
Our primary need for cash for the fiscal year ending August 31, 2013, will be to fund our drilling and acquisition programs. Under the updated plans for our 2013 capital budget, we estimate capital expenditures of approximately $82 million for additional drilling, participating in drilling, and acquiring properties. We increased the budget from $55 million in connection with the acquisition of assets from Orr Energy LLC (“Orr”) for cash payment of $30 million. As an operator, we plan to spend approximately $15 million to drill 25 vertical wells and approximately $17 million to drill 4 horizontal wells. An additional $13.5 million has been estimated as our portion of the cost of vertical and horizontal wells in which we will participate as a non-operator. We also plan recompletion costs approximating $1.5 million on 10 wells that indicate good potential for additional hydraulic stimulation. We allocated $5 million for the acquisition of undeveloped acreage. Our capital expenditure plans described herein represent cash payments, and exclude assets acquired in exchange for common stock. The proposed acquisition of assets from Orr anticipates partial payment in shares of common stock with a value of $12 million. Our capital expenditure estimate is subject to adjustment for drilling success, acquisition opportunities, operating cash flow, and available capital resources.
On October 23, 2012, we entered into an agreement to acquire developed and undeveloped oil and gas properties in the D-J Basin. Closing of the transaction is expected to occur before December 31, 2012. The purchase price for these oil and gas properties is expected to be $42 million, consisting of cash and restricted shares of Synergy's common stock.
The following table summarizes our contractual obligations as of August 31, 2012:
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have or are reasonable likely to have a current or future material effect on our financial condition, changes in financial condition, results of operations, liquidity or capital resources.
Non-GAAP Financial Measures
We use "adjusted cash flow from operations" and "adjusted EBITDA," non-GAAP financial measures, for internal managerial purposes, when evaluating period-to-period comparisons. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-GAAP financial measures that we use may not be comparable to measures with similar titles reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.
See Reconciliation of Non-GAAP Financial Measures below for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure.
Reconciliation of Non-GAAP Financial Measures
Adjusted cash flow from operations. We define adjusted cash flow from operations as the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables and payables. We believe it is important to consider adjusted cash flow from operations as well as cash flow from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during the period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next.
Adjusted EBITDA. We define adjusted EBITDA as net income (loss) plus interest expense, net of interest income, income taxes, stock based compensation, and depreciation, depletion and amortization for the period plus/minus the change in fair value of our derivative conversion liability. We believe adjusted EBITDA is relevant because it is a measure of cash available to fund our capital expenditures and service our debt and is a metric used by some industry analysts to provide a comparison of our results with our peers. The following table presents a reconciliation of each of our non-GAAP financial measures to its nearest GAAP measure.
Trend and Outlook
During the past several months, the gas gathering system in the Wattenberg Field has been unable to gather all the gas that could be produced. Production from new wells, particularly new horizontal wells, has strained the capacity of the system that gathers natural gas and associated liquids. The additional supply of gas creates elevated line pressure in the pipeline. When we are unable to deliver all of our gas into the pipeline, the production of oil and liquids are simultaneously restricted.
Several corrective measures are underway. DCP Midstream Partners, our third party provider of gathering, processing and transportation facilities, is rapidly expanding their capacity. DCP is creating a “super system” in Weld County of a broad network of gathering and processing facilities that afford significant optionality and flexibility, which enables DCP to optimize its processing capacity. A significant improvement in the system will occur in 2013, when a new processing plant in LaSalle, Colorado comes on line. In addition to substantially increasing capacity, DCP will improve reliability by extending the high pressure gathering system grid connected to its processing plants. Other gas gathering providers have announced similar initiatives to improve the infrastructure.
The recently announced Front Range Pipeline will also help producers in the D-J Basin maximize the value of their NGL production by providing connectivity to the premium Mont Belvieu, TX market. DCP, Enterprise Products Partners and Anadarko Petroleum are building an interstate NGL pipeline that will originate in Weld County, Colorado. Initial capacity on Front Range is expected to be 150,000 bpd, which can be expanded to approximately 230,000 bpd. Connectivity to Mont Belvieu includes transportation via the recently announced Texas Express Pipeline, in which DCP has a vested interest as a 10% owner. The Texas Express Pipeline is expected to be completed by the second quarter of 2013, and Front Range Pipeline is expected to be in service by the fourth quarter 2013. We expect these third party capital projects to accommodate our and other producer’s throughput, including anticipated aggressive growth in the basin.
For our part, we have begun installing improved equipment, including compressors, to strategic pad locations. We are also accelerating our previously planned maintenance and modification expenditures on certain wells to improve volume output.
Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our substantial capital requirements, (iv) completion of acquisitions of additional properties and reserves, (v) competition from larger companies, and (vi) prices for oil and gas. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.
It is expected that our principal source of cash flow will be from the production and sale of oil and gas reserves, which are depleting assets. Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing more easily or on better terms, and lessens the difficulty of obtaining debt financing. However, price increases heighten the competition for oil and gas prospects, increase the costs of exploration and development, and, because of potential price declines, increase the risks associated with the purchase of producing properties during times that prices are at higher levels.
A decline in oil and gas prices (i) will reduce our cash flow which in turn will reduce the funds available for exploring for and replacing oil and gas reserves, (ii) will potentially reduce our current LOC borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, and (v) may result in marginally productive oil and gas wells being abandoned as non-commercial. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.
Other than the foregoing, we do not know of any trends, events or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues or expenses.
Critical Accounting Policies
The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.
We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 1 of the Notes to the Financial Statements for a detailed discussion of the nature of our accounting practices and additional accounting policies and estimates made by management.
Oil and Gas Sales: We derive revenue primarily from the sale of produced crude oil and natural gas. Revenues from production on properties in which we share an economic interest with other owners are recognized on the basis of our interest. Revenues are reported on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.
Oil and Gas Reserves: Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of our oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves.
Oil and Gas Properties: We use the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unevaluated properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Asset Retirement Obligations (“ARO”): We are subject to legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an ARO requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using our credit adjusted risk free interest rate. Estimates are periodically reviewed and adjusted to reflect changes.
The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. This is typically when a well is completed or an asset is placed in service. When the ARO is initially recorded, we capitalize the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset. ARCs related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value (accretion of ARO), while the capitalized cost decreases over the useful life of the asset, recognized as depletion.
Stock-Based Compensation: We recognize all equity-based compensation as stock-based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date. The expense is recognized over the vesting period of the grant.
Income Taxes: Deferred income taxes are recorded for timing differences between items of income or expense reported in the financial statements and those reported for income tax purposes using the asset/liability method of accounting for income taxes. Deferred income taxes and tax benefits are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, and for tax loss and credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. We provide for deferred taxes for the estimated future tax effects attributable to temporary differences and carry-forwards when realization is more likely than not. If we conclude that it is more likely than not that some portion, or all, of the net deferred tax asset will not be realized, the balance of net deferred tax assets is reduced by a valuation allowance.
We consider many factors in our evaluation of deferred tax assets, including the following sources of taxable income that may be available under the tax law to realize a portion or all of a tax benefit for deductible timing differences and carry-forwards:
Recent Accounting Pronouncements
We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new pronouncements on U.S. GAAP and their impact on us.
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires us to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. We are required to implement this guidance effective for the first quarter of fiscal 2014 and do not expect the adoption of ASU 2011-11 to have a material impact on our financial statements.
Various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to a have a material impact on our financial position, results of operations or cash flows.
Commodity Risk - Our primary market risk exposure results from the price we receive for our oil and natural gas production. We do not currently engage in any commodity hedging activities, although we may do so in the future. Realized commodity pricing for our production is primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. Pricing for oil and natural gas production has been volatile and unpredictable in recent years, and we expect this volatility to continue in the foreseeable future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable commodity index price.
Interest Rate Risk - At August 31, 2012, we had debt outstanding under our bank credit facility totaling $3,000,000. Interest on our bank credit facility accrues at the greater of 3.25% or the prime rate, which was also 3.25% at August 31, 2012. While we are currently incurring interest at the floor of 3.25%, we are exposed to interest rate risk on the bank credit facility if the prime rate exceeds the floor. The agreement provides an interest rate index of LIBOR plus 2.5% at our option. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Hypothetically, a 1.0% increase in the prime rate for the year ended August 31, 2012 would have resulted in an estimated $33,000 increase in interest expense for the year ended August 31, 2012.
See the financial statements and accompanying notes included with this report.
Evaluation of Disclosure Controls and Procedures
An evaluation was carried out under the supervision and with the participation of our management, including our President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-K. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-K, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our President and Chief Executive Officer as well as our Chief Financial Officer to allow timely decisions regarding required disclosure.
Based on that evaluation, our management concluded that, as of August 31, 2012, our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
During the fourth quarter of fiscal year ended August 31, 2012, we took measures to bolster our internal control processes pertaining to financial reporting. Such measures include additional procedures and personnel to ensure accuracy in our financial reporting.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the Securities and Exchange Commission, internal control over financial reporting is a process designed by, or under the supervision of two key personnel, our President and Chief Executive Officer and our Chief Financial Officer and implemented by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with U.S. generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Ed Holloway, our President and Chief Executive Officer, and Frank L. Jennings, our Chief Financial Officer, evaluated the effectiveness of our internal control over financial reporting as of August 31, 2012 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of August 31, 2012.
Attestation Report of Registered Public Accounting Firm
The attestation report required under this Item 9A is set forth under the caption "Report of Independent Registered Public Accounting Firm", which is included with the financial statements and supplemental data required by Item 8.
Our officers and directors are listed below. Our directors are generally elected at our annual shareholders' meeting and hold office until the next annual shareholders' meeting or until their successors are elected and qualified. Our executive officers are elected by our directors and serve at their discretion.
Edward Holloway – Mr. Holloway has been an officer and director since September 2008 and was an officer and director of our predecessor between June 2008 and September 2008. Mr. Holloway co-founded Cache Exploration Inc., an oil and gas exploration and development company. In 1987, Mr. Holloway sold the assets of Cache Exploration to LYCO Energy Corporation. He rebuilt Cache Exploration and sold the entire company to Southwest Production a decade later. In 1997, Mr. Holloway co-founded, and since that date has co-managed, Petroleum Management, LLC, a company engaged in the exploration, operations, production and distribution of oil and natural gas. In 2001, Mr. Holloway co-founded, and since that date has co-managed, Petroleum Exploration and Management, LLC, a company engaged in the acquisition of oil and gas leases and the production and sale of oil and natural gas. Mr. Holloway holds a degree in Business Finance from the University of Northern Colorado and is a past president of the Colorado Oil and Gas Association.
William E. Scaff, Jr. – Mr. Scaff has been an officer and director since September 2008 and was an officer and director of our predecessor between June 2008 and September 2008. Between 1980 and 1990, Mr. Scaff oversaw financial and credit transactions for Dresser Industries, a Fortune 50 oilfield equipment company. Immediately after serving as a regional manager with TOTAL Petroleum between 1990 and 1997, Mr. Scaff co-founded, and since that date co-managed, Petroleum Management, LLC, a company engaged in the exploration, operations, production and distribution of oil and natural gas. In 2001, Mr. Scaff co-founded, and since that date has co-managed, Petroleum Exploration and Management, LLC, a company engaged in the acquisition of oil and gas leases and the production and sale of oil and natural gas. Mr. Scaff holds a degree in Finance from the University of Colorado.
Frank L. Jennings – Mr. Jennings began his service as our Chief Financial Officer on a part-time basis in June 2007. In March 2011, he joined us on a full-time basis. From 2001 until 2011, Mr. Jennings was an independent consultant providing financial accounting services, primarily to smaller public companies. From 2006 until 2011, he also served as the Chief Financial Officer of Gold Resource Corporation (AMEX:GORO). From 2000 to 2005, he served as the Chief Financial Officer and a director of Global Casinos, Inc., a publicly traded corporation, and from 1994 to 2001 he served as Chief Financial Officer of American Educational Products, Inc. (NASDAQ:AMEP), before it was purchased by Nasco International. After his graduation from Austin College with a degree in economics and from Indiana University with an MBA in finance, he joined the Houston office of Coopers & Lybrand. He also spent four years as the manager of internal audit for The Walt Disney Company.
Rick A. Wilber – Mr. Wilber has been one of our directors since September 2008. Since 1984, Mr. Wilber has been a private investor in, and a consultant to, numerous development stage companies. In 1974, Mr. Wilber was co-founder of Champs Sporting Goods, a retail sporting goods chain, and served as its President from 1974-1984. He has been a Director of Ultimate Software Group Inc. since October 2002 and serves as a member of its audit and compensation committees. Mr. Wilber was a director of Ultimate Software Group between October 1997 and May 2000. He served as a director of Royce Laboratories, Inc., a pharmaceutical concern, from 1990 until it was sold to Watson Pharmaceuticals, Inc. in April 1997 and was a member of its compensation committee.
Raymond E. McElhaney – Mr. McElhaney has been one of our directors since May 2005, and prior to the acquisition of Predecessor Synergy was our President and Chief Executive Officer. Mr. McElhaney began his career in the oil and gas industry in 1983 as founder and President of Spartan Petroleum and Exploration, Inc. Mr. McElhaney also served as a chairman and secretary of Wyoming Oil & Minerals, Inc., a publicly traded corporation, from February 2002 until 2005. From 2000 to 2003, he served as vice president and secretary of New Frontier Energy, Inc., a publicly traded corporation. McElhaney is a co-founder of MCM Capital Management Inc., a privately held financial management and consulting company formed in 1990 and has served as its president of that company since inception.
Bill M. Conrad – Mr. Conrad has been one of our directors since May 2005 and prior to the acquisition of Predecessor Synergy was our Vice President and Secretary. Mr. Conrad has been involved in several aspects of the oil and gas industry over the past 20 years. From February 2002 until June 2005, Mr. Conrad served as president and a director of Wyoming Oil & Minerals, Inc., and from 2000 until April 2003, he served as vice president and a director of New Frontier Energy, Inc. Since June 2006, Mr. Conrad has served as a director of Gold Resource Corporation, a publicly traded corporation engaged in the mining industry. In 1990, Mr. Conrad co-founded MCM Capital Management Inc. and has served as its vice president since that time.
R.W. “Bud” Noffsinger, III – Mr. Noffsinger was appointed as one of our directors in September 2009. Mr. Noffsinger has been the President/ CEO of RWN3 LLC, a company involved with investment securities, since February 2009. Previously, Mr. Noffsinger was the President (2005 to 2009) and Chief Credit Officer (2008 to 2009) of First Western Trust Bank in Fort Collins, Colorado. Prior to his association with First Western, Mr. Noffsinger was a manager with Centennial Bank of the West (now Guaranty Bank and Trust). Mr. Noffsinger’s focus at Centennial was client development and lending in the areas of commercial real estate, agriculture and natural resources. Mr. Noffsinger is a graduate of the University of Wyoming and holds a Bachelor of Science degree in Economics with an emphasis on natural resources and environmental economics.
George Seward – Mr. Seward was appointed as one of our directors on July 8, 2010. Mr. Seward cofounded Prima Energy in 1980 and served as its Secretary until 2004, when Prima was sold to Petro-Canada for $534,000,000. At the time of the sale, Prima had 152 billion cubic feet of proved gas reserves and was producing 55 million cubic feet of gas daily from wells in the D-J Basin in Colorado and the Powder River Basin of Wyoming and Utah. Since March 2006 Mr. Seward has been the President of Pocito Oil and Gas, a limited production company, with operations in northeast Colorado, southwest Nebraska and Barber County, Kansas. Mr. Seward has also operated a diversified farming operation, raising wheat, corn, pinto beans, soybeans and alfalfa hay in southwestern Nebraska and northeast Colorado, since 1982.
We believe Messrs. Holloway, Scaff, McElhaney, Conrad and Seward are qualified to act as directors due to their experience in the oil and gas industry. We believe Messrs. Wilber and Noffsinger are qualified to act as directors as result of their experience in financial matters.
Rick Wilber, Raymond McElhaney, Bill Conrad and R.W. Noffsinger, are considered independent as that term is defined Section 803.A of the NYSE MKT Rules.
The members of our compensation committee are Rick Wilber, Raymond McElhaney, Bill Conrad, and R.W. Noffsinger. The members of our Audit Committee are Raymond McElhaney, Bill Conrad and R.W. Noffsinger. Mr. Noffsinger acts as the financial expert for the Audit Committee of our board of directors.
We have adopted a Code of Ethics applicable to all employees.
ITEM 11. EXECUTIVE COMPENSATION
The following table shows the compensation paid or accrued to our executive officers during each of the three years ended August 31, 2012.
The compensation to be paid to Mr. Holloway, Mr. Scaff and Mr. Jennings will be based upon their employment agreements, which are described below. All material elements of the compensation paid to these officers is discussed below.
On June 11, 2008, we signed employment agreements with Ed Holloway and William E. Scaff Jr. Each employment agreement provided that the employee would be paid a monthly salary of $12,500 and required the employee to devote approximately 80% of his time to our business. The employment agreements expired on June 1, 2010.
On June 1, 2010, we entered into new employment agreements with Mr. Holloway and Mr. Scaff. The new employment agreements, which expire on May 31, 2013, provide that we pay Mr. Holloway and Mr. Scaff each a monthly salary of $25,000 and require both Mr. Holloway and Mr. Scaff to devote approximately 80% of their time to our business. In addition, for every 50 wells that begin producing oil and/or gas after June 1, 2010, whether as the result of our successful drilling efforts or acquisitions, we will issue, to each of Mr. Holloway and Mr. Scaff, a cash payment of $100,000 or shares of common stock in an amount equal to $100,000 divided by the average closing price of our common stock for the 20 trading days prior to the date the 50th well begins producing.
On June 23, 2011 our directors approved an employment agreement with Frank L. Jennings, our Chief Financial Officer. The employment agreement provides that we will pay Mr. Jennings a monthly salary of $15,000 and issue to Mr. Jennings:
The employment agreement expires on March 7, 2014 and requires Mr. Jennings to devote all of his time to our business.
If Mr. Jennings resigns within 90 days of a relocation (or demand for relocation) of his place of employment to a location more than 35 miles from his then current place of employment, the employment agreement will be terminated and Mr. Jennings will be paid the salary provided by the employment agreement through the date of termination and the unvested portion of any stock options held by Mr. Jennings will vest immediately.
In the event there is a change in the control, the employment agreement allows Mr. Jennings to resign from his position and receive a lump-sum payment equal to 12 months’ salary. In addition, the unvested portion of any stock options held by Mr. Jennings will vest immediately. For purposes of the employment agreement, a change in the control means: (1) our merger with another entity if after such merger our shareholders do not own at least 50% of the voting capital stock of the surviving corporation; (2) the sale of substantially all of our assets; (3) the acquisition by any person of more than 50% of our common stock; or (4) a change in a majority of our directors which has not been approved by our incumbent directors.
The employment agreements mentioned above, will terminate upon the employee’s death, or disability or may be terminated by us for cause. If the employment agreement is terminated for any of these reasons, the employee, or his legal representatives as the case may be, will be paid the salary provided by the employment agreement through the date of termination.
For purposes of the employment agreements, “cause” is defined as:
Executive officer compensation, as provided above, is structured to be competitive both in its design and in the total compensation offered. The Compensation Committee of the Board of Directors determines the compensation of the Company’s officers. The Committee’s philosophy on officer compensation is to align executive and shareholder interests. The philosophy’s objective is to provide fair compensation based upon the individual’s position, experience and individual performance.
The Company’s current policy is that the various elements of the compensation package are not interrelated in that gains or losses from past equity incentives are not factored into the determination of other compensation.
A goal of the compensation program is to provide executive officers with a reasonable level of security through base salary and benefits. The Company wants to ensure that the compensation programs are appropriately designed to encourage executive officer retention and motivation to create shareholder value. The Compensation Committee believes that the Company’s stockholders are best served when the Company can attract and retain talented executives by providing compensation packages that are competitive but fair.
The key components of the Company’s executive compensation program include annual base salaries and long-term incentive compensation consisting of stock options. It is the Company’s policy to target compensation (i.e., base salary, stock option grants and other benefits) at approximately the median of comparable companies in the oil and gas exploration and development industry. Accordingly, data on compensation practices followed by other companies in the oil and gas exploration and development industry is considered.
Base salaries generally have been targeted to be competitive when compared to the salary levels of persons holding similar positions in other oil and gas exploration and development companies and other publicly traded companies of comparable size.
Stock option grants help to align the interests of the Company’s officers with those of its shareholders. Options grants are made under the Company’s Stock Option Plan.
The Company believes that grants of stock options:
The Company’s long-term incentive program consists exclusively of periodic grants of stock options with an exercise price equal to the fair market value of the Company’s common stock on the date of grant. Decisions made regarding the timing and size of option grants take into account the performance of both the Company and the employee, “competitive market” practices, and the size of the option grants made in prior years. The weighting of these factors varies and is subjective.
In addition to cash and equity compensation programs, executive officers participate in the health insurance programs available to the Company’s other employees.
All executive officers are eligible to participate in the Company’s 401(k) plan on the same basis as all other employees. The Company matches participant’s contribution in cash, not to exceed 4% of the participant’s total compensation.
We had a consulting agreement with Ray McElhaney and Bill Conrad which provided that Mr. McElhaney and Mr. Conrad would render, on a part-time basis, consulting services pertaining to corporate acquisitions and development. For these services, Mr. McElhaney and Mr. Conrad were paid a monthly consulting fee of $5,000. The consulting agreement expired on September 15, 2009.
Employee Pension, Profit Sharing or other Retirement Plans. Effective November 1, 2010, we adopted a defined contribution retirement plan, qualifying under Section 401(k) of the Internal Revenue Code and covering substantially all of our employees. We match participant’s contributions in cash, not to exceed 4% of the participant’s total compensation. Other than this 401(k) Plan, we do not have a defined benefit pension plan, profit sharing or other retirement plan.
Stock Option and Bonus Plans
We have three stock award plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan. The plans adopted during 2011 replaced a non-qualified stock option plan and a stock bonus plan originally adopted during 2005 (the “2005 Plans”). No additional options or shares will be issued under the 2005 Plans. Each plan authorizes the issuance of shares of our common stock to persons that exercise options granted pursuant to the Plan. Our employees, directors, officers, consultants and advisors are eligible to received such awards, provided that bona fide services be rendered by such consultants or advisors and such services must not be in connection with promoting our stock or the sale of securities in a capital-raising transaction. The option exercise price is determined by our directors, though generally is based upon the closing market price of our shares on the date of grant.
Summary. The following is a summary of options granted or shares issued pursuant to the Plans as of October 15, 2012. Each option represents the right to purchase one share of our common stock.
In connection with the acquisition of a corporation in 2008, we issued options to the persons shown below in exchange for options previously issued by that corporation. The terms of the options we issued are identical to the terms of the previously issued options. The options were not granted pursuant to our 2005 Plans. As of October 15, 2012, none of these options have been exercised.
1 Options are held of record by a limited liability company controlled by Mr. Holloway.
2 Options are held of record by a limited liability company controlled by Mr. Scaff.
The following table shows information concerning our outstanding options as of October 15, 2012.
The following table shows the weighted average exercise price of the outstanding options granted pursuant to our Non-Qualified Stock Option Plan or otherwise as of August 31, 2012.
Compensation of Directors During Year Ended August 31, 2012