ITEM 1. BUSINESS
HISTORY
The Company was incorporated in Delaware on December 15, 1999. On December 22, 1999, we merged with Island Critical Care Corp., an inactive Florida corporation. The purpose of this merger was to effect a change in the domicile of the Florida corporation to Delaware. Island Critical Care Corp. (a Florida corporation) was originally incorporated on March 15, 1996 under the name 9974 Holdings Inc., and subsequently changed its name from 9974 Holdings Inc. to Ontario Midwestern Railway Co. Inc, and finally the Florida corporation's name was changed to Midwestern Railway Co. Inc. All three changes in name of the Florida corporation were completed prior to its merger with the Delaware corporation. On January 13, 2000, we merged with Island Critical Care Corporation, an Ontario corporation. On February 5, 2003, the Company filed a petition for bankruptcy in the District of Prince Edward Island, Division No. 01, Prince Edward Island Court (No. 1713, Estate No. 51-104460). The Company emerged from bankruptcy pursuant to a court order on April 7, 2004 with no assets and no liabilities. Upon emergence from bankruptcy, the Company adopted Fresh Start Accounting pursuant to SOP 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code." On December 27, 2004, we changed our name from Island Critical Care Corporation to Kodiak Energy, Inc. ("Kodiak" or “Company”).
GENERAL
Kodiak Energy, Inc. is engaged in the development and exploration for natural resources. During the year ended December 31, 2009, the Company transitioned from a development stage enterprise to an operating company. Since 2005 and until the fourth quarter of 2009, the Company has been active in Canada and the United States in acquiring properties that are prospective for petroleum and natural gas and related hydrocarbons. The prospects the Company holds are generally under leases and include partial and full working interests. In all of the core properties, Kodiak is the operator and majority interest owner. In two properties, we have the option to perform certain exploratory drilling to earn additional interests. The prospects are subject to varying royalties due to the state, province, territory, or federal governments and, in some instances, to other royalty owners in the prospect.
As at December 31, 2010, the Company had three wholly-owned subsidiaries: Kodiak Petroleum ULC (“KULC”), an inactive Alberta company; Kodiak Petroleum (Montana), Inc. (“KPMI”), a Delaware company that operates Kodiak’s projects in New Mexico and Montana; and Kodiak Petroleum (Utah), Inc. (“KPUI”), a Delaware company and holding company holding the shares of Kodiak Petroleum (Montana), Inc.; and one majority owned subsidiary, 1438821 Alberta Ltd.(”1438821”), an Alberta company incorporated in November, 2008. In January 2009, the Company vended its Lucy, British Columbia and CREEnergy Project, Alberta projects into 1438821 for financing purposes. In February 2009, 1438821 changed its name to Cougar Energy, Inc. (“Cougar”). Through the Company’s private subsidiary, Cougar Energy, Inc., and that entity’s acquisition of producing properties effective September 30, 2009 and October 1, 2009, the Company became a development company with oil and gas reserves, production, and recognized revenue as a result of operations effective October 2009.
On January 25, 2010, the Kodiak finalized a share purchase agreement between the OreMore Resources (“Oremore”) and the Company whereby the Company sold to OreMore a total of 8,461,549 shares of the common shares of CEI held by Kodiak. The share purchase agreement called for the OreMore to issue a total of 1.5 shares of common stock for each share of CEI tendered by Kodiak, resulting in the OreMore issuing a total of 12,692,324 shares of common stock to Kodiak. As further consideration for the acquisition of the CEI common shares, the OreMore forgave all current indebtedness owed to OreMore by Kodiak and guaranteed by Cougar Energy, Inc which was in the amount of $1,296,889 USD. An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Company were cancelled and Kodiak would nominate two board members to the Board of OreMore until the next AGM of OreMore. Subsequent to that event, OreMore changed it’s name to Cougar Oil and Gas Canada, Inc and a 3 for 1 share split was completed. At time of filing, Kodiak owns 59.74% of the outstanding shares of Cougar Oil and Gas Canada, Inc and files Cougar financials on a consolidated basis.
The Company’s principal executive offices are located at 833 4th Avenue S.W., Suite 1120, Calgary, AB, Canada and our telephone number is (403) 262-8044.
The information in these consolidated financial statements should be read in conjunction with the December 31, 2010 consolidated financial statements.
The accompanying consolidated financial statements in this annual report on Form 10-K include the accounts of the Company, three wholly-owned subsidiaries: Kodiak Petroleum ULC (“KULC”), an inactive Alberta company; Kodiak Petroleum (Montana), Inc. (“KPMI”), a Delaware company that operates Kodiak’s projects in New Mexico and Montana; and Kodiak Petroleum (Utah), Inc. (“KPUI”), an inactive Delaware company; and one majority- owned subsidiary, Cougar Oil and Gas Canada Inc. In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All significant inter-company transactions have been eliminated in consolidation.
OIL AND GAS PRODUCTION
As of December 31, 2010, the Company had production on a consolidated basis from its Cougar holdings. The Company had no production from its other holdings in New Mexico.
During 2010 the Cougar had net daily crude oil production ranging from a low of approximately 80 barrels per day to a high of approximately 225 barrels per day. The Companies monthly crude oil production has ranged from 3,170 barrels to 5,874 barrels. Management believes the current group of producing wells is capable of daily production exceeding 250 barrels per day but this production potential has been curtailed as a result of ongoing maintenance and repair issues over the reporting period. As these maintenance and repair issues are resolved it is anticipated production will increase accordingly. It is also anticipated production will increase as a result of the ongoing development drilling operations. We averaged $30.00/bbl Cdn for the year for operating costs including maintenance costs. We believe that through ongoing maintenance and upgrades, we will reduce those costs to the $25 Cdn range and perhaps as low as $17 Cdn which we have experienced for short periods of time. We continue to receive $50 plus as a net back after royalties and are net positive for operations at year end.
Refer to the Companies reserves report for additional information regarding NPV and forecast production.
COMPETITIVE STRENGTHS
Dominant Position in the Trout Area, Alberta
The Company has acquired a strategically valuable core area in the Trout properties. By acquiring operatorship of wells, facilities, pipelines and roads, the Company can set the pace for the development rather than be dependent on other non-receptive operators.
Attractive Underlying Economics
The Company currently has net crude oil production of approximately 125 barrels per day (bbl/d). The majority of the production consists of light sweet crude oil and has an average operating cost of $30/bbl. Cdn. This results in a substantial netback at the current and forecast commodity prices. These attractive economics are a result of acquiring an extensive production infrastructure including wells, pipelines, treating facilities, roads, and access to power.
Stable Base Production
The majority of the Company’s current producing properties are located in mature reservoirs with predictable lower annual decline rates. This allows the Company to more accurately predict cash flow and plan development and exploration opportunities.
Commodity Position
All the Company’s current proved and probable production in the Trout Area is light sweet crude oil, which receives the going price for crude without discounts.
Valuable Acreage Positions
Trout Area, Alberta
As described above, the Trout land position.
New Mexico, United States
Excellent land position - large contiguous block with long term leases - straddling the Sheep Mountain Pipeline and giving access to markets for the CO2 found on the properties for enhanced recovery in the Permian Basin.
Development and Exploration Opportunities
Core Trout Project, Alberta
The infrastructure will support substantially increased production levels (up to 2,500bbl/d) from the area with nominal increases in costs - providing opportunities to consolidate other properties into this Core Project, which the Company is actively working on.
The existing land base provides many opportunities for drilling programs to add reserves and production. The Company has acquired 2D and 3D seismic on much of these lands. In addition, the existing suspended wells provide many opportunities for workovers to add reserves and production at much lower than drilling or acquisition costs, which has been demonstrated with the current programs initiated.
The First Nations JV Project provides additional drilling and development opportunities with adjacent land to our Core Trout Project that may use the existing infrastructure.
Lucy, British Columbia
Our Muskwa Shale project in the Horn River Basin of north east British Columbia has prospects for natural gas that are comparable to many of the major developments currently under way in the area. With an investment in a fracture program on the 2 existing wells, a development into a producing property may be possible that may show the large recoverable reserves seen in the area.
New Mexico, United States
With pipeline quality CO2 found in the 3 wells drilled to date, and large land base straddling the existing CO2 pipeline, the project is an opportunity as economics change in the enhanced oil recovery projects, to build a commercial CO2 development.
Little Chicago, Northwest Territories
With our high quality seismic over the prospect, experience working in the area, and understanding of the area geology, we have a strategic advantage and the opportunity to continue identifying prospects based on that information. As economic factors change and/or the Mackenzie Valley Pipeline construction is committed to, we anticipate re-entering the area.
BUSINESS STRATEGIES
Financial Flexibility
The Company has used and expects to use a variety of sources of funding to finance its acquisitions and capital development and exploration programs for 2011:
§
Internally generated cash flow from operations - will be key going forward.
§
Debt financing - both revolving line of credit and specific debt instruments for specific projects - normally lower risk projects or smaller acquisitions. Also vendor take backs - in certain circumstances when it benefits both the vendor and the purchaser - a type of debt structure may be set up with the vendor.
§
Equity issues when terms and conditions are appropriate - for higher risk projects or larger acquisitions or debt reduction
This ability to adjust projects and timelines, due to large land bases and multiple projects and work within different financing models, has allowed the Company to survive the recent recession and actually show growth in difficult times.
DESCRIPTION OF OUR EXPLORATION AND PRODUCTION PROPERTIES AND PROJECTS
MAINTENANCE AND PRODUCTION
General
As the operator of wells in which we have an interest, we design and manage the development of these wells and supervise operation and maintenance activities on a day-to-day basis. We employ production and reservoir engineers, geologists and other specialists.
Field operations conducted by our contractors include duties whose primary responsibility is to operate the wells. Other contracted field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new and existing wells (such as electric service , salt water disposal facilities, and gas feeder lines). We utilize third-party contractors on an “as needed” basis to supplement our field personnel and related equipment.
Oil and Gas Leases and Development Rights
As of December 31, 2010, we held approximately 46,970 gross acres under oil and gas leases. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount typically ranges from 12% to 30% resulting in a 70% to 88% net revenue interest to us.
Because the acquisition of oil and gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other oil and gas operators. In order to gain the right to drill these leases, we may purchase leases from other oil and gas operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 5% to 15%, which further reduces the net revenue interest available to us to between 55% and 73
As of December 31, 2010, approximately 12% of our oil and gas leases were held by production and will be held indefinitely
In the Trout Area, Alberta as of December 31, 2010, we held oil and gas leases on approximately 15,580 gross acres, of which approximately 65% are held indefinitely and 35% are due to expire in 2015 and are not currently held by production.
In the Alexander Area, Alberta as of December 31, 2010, we held oil and gas leases on approximately 160 gross acres, of which 0 gross acres (0%) are not currently held by production. There are no expiry issues for this lease.
In Lucy, British Columbia as of December 31, 2010, we held oil and gas leases on approximately 1,975 gross acres, of which approximately 1,975 gross acres (100%) are not currently held by production. The Lucy mineral lease was extended as part of an approved Experimental Scheme application to the regulatory agency. The Lucy lease is currently extended indefinitely.
In the Sofia and Speardraw Areas, northeast New Mexico as of December 31, 2010, we hold CO2 and oil and gas leases on approximately 29,712 gross acres, of which approximately 29,712 gross acres (100%) are not currently held by production. Expiries range from 2011 Q2 to 2013 Q2.
In the Hill County Area, northwest Montana as of December 31, 2010, we held oil and gas leases on approximately 879 gross acres, of which approximately 879 gross acres (100%) are not currently held by production. The Montana leases will expire in 2011 Q2.
Oil Marketing Contracts
The Company currently has an oil marketing contract with an established Canadian marketing company. The contract is a monthly evergreen contract for oil purchased at the 40 degree price for light sweet crude oil at Edmonton, Alberta. The contract can be terminated with 30 days notice.
Exploration and Production
Our operations are subject to various types of regulation at federal, state, provincial, territorial and local levels. These types of regulations may include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most provinces, states, territories and some municipalities in which we operate also regulate one or more of the following:
·
the location of wells;
·
the method of drilling and casing wells;
·
the surface use and restoration of properties upon which wells are drilled;
·
the plugging and abandoning of wells; and
·
notice to surface owners and other third parties.
Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
See additional discussion in Item 1A.
ITEM 1A. RISK FACTORS
BUSINESS RISKS
Going Concern Uncertainty
There is uncertainty that the Company will continue as a going concern, which presumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has not generated positive cash flow since inception and has incurred operating losses and will need additional working capital for its future planned activities. Continuation of the Company as a going concern is dependent upon obtaining sufficient working capital to finance ongoing operations. The Company’s strategy to address this uncertainty includes additional equity and debt financing; however, there are no assurances that any such financings can be obtained on favorable terms, if at all. These financial statements do not reflect the adjustments or reclassification of assets and liabilities that would be necessary if the Company were unable to continue its operations.
Financial Markets Instability and Uncertainty
The 2008/09 worldwide financial and credit crisis has severely restricted the availability of capital and credit to fund the continuation and expansion of junior oil and gas operations worldwide. The shortage of capital and credit, combined with recent substantial losses in worldwide equity markets, led to an extended worldwide economic recession and a very slow recovery. This limited access to capital still exists today except on extremely dilutive or oppressive terms for exploration and development. The slowdown in economic activity caused by this recession has immediately reduced worldwide demand for energy, resulting in substantially lower oil and natural gas and other commodity prices. Oil has recovered somewhat, however, natural gas continues to be depressed due to an excess of supply. The prolonged reduction in oil and natural gas prices has depressed the levels of exploration, development and production activity. That is impacting negatively on our Company’s ability to raise capital to finance our ongoing capital projects. The Company may be required to consider divestiture of some properties or working interests to raise funds. Until the financial market conditions improve, we will face significant challenges in meeting our ongoing financial obligations. This continuing global financial crisis may have impacts on our business and financial condition that we cannot currently predict. Global market and economic conditions, including those related to the credit markets, could have a material adverse effect on our business, financial condition and results of operations. A general slowdown in economic activity could adversely affect our business by impacting our ability to access additional exploration and development capital in the interim.
The Oil and Gas Industry Is Highly Competitive
The oil and gas industry is highly competitive. We compete with oil and natural gas companies and other individual producers and operators, many of which have longer operating histories and substantially greater financial and other resources than we do. We compete with companies in other industries supplying energy, fuel and other needs to consumers. Many of these companies not only explore for and produce crude oil and natural gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to absorb the burden of any changes in laws and regulation in the jurisdictions in which we do business and handle longer periods of reduced prices of gas and oil more easily than we can. Our competitors may be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.
Trends and Uncertainties
We are subject to the following trends and uncertainties:
·
Adverse weather conditions that may affect our ability to conduct our exploration activities;
·
General economic conditions, including supply and demand for petroleum based products in Canada, the United States, and remaining parts of the world;
·
Political instability in the Middle East and other major oil and gas producing regions;
·
Domestic and foreign tax policy;
·
Price of oil and gas foreign imports;
·
Cost of exploring for, producing, and delivering oil and gas;
·
Overall supply and demand for oil and gas;
·
Availability of alternative fuel sources;
·
Discovery rate of new oil and gas reserves; and
·
Pace adopted by foreign governments for the exploration, development and production of their national reserves.
Government and Environmental Regulation
Our business is governed by numerous laws and regulations at various levels of government. These laws and regulations govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues. The laws and regulations may, among other potential consequences, require that we acquire permits before commencing drilling, restrict the substances that can be released into the environment with drilling and production activities, limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas, require that reclamation measures be taken to prevent pollution from former operations, require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remediation of contaminated soil and groundwater, and require remedial measures to be taken with respect to property designated as a contaminated site.
Under these laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages as well as environmental damage that occurs over time. However, we do not believe that insurance coverage for the full potential liability of environmental damages is available at a reasonable cost. Accordingly, we could be liable, or could be required to cease production on properties, if environmental damage occurs.
The costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations could occur that may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.
Since the 2008/09 market decline, we are unable to forecast when the long term CO2 contracts delivered into the Permian Basis of S.W. Texas will recover to make our project in northeast New Mexico commercial. The following factors have negatively impacted the project:
·
Supply and demand of oil commodity prices, which have declined and not fully recovered and stabilized;
·
Unstable market has resulted for CO2 used for enhanced recovery in the Permian Basin; and
·
Informal nature of the current federal policies regarding carbon capture and how that will affect CO2 pricing in the long term.
We Recently emerged from a Development Stage Company Implementing a New Business Plan
We recently emerged from a development stage company with only a limited operating history upon which to base an evaluation of our current business and future prospects, and we have just begun to implement our business plan for the development stage prospects.
The Successful Implementation of Our Business Plan is Subject to Risks Inherent in the Oil and Gas Business
Our oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties and to drill exploratory wells. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs will be charged against earnings as impairments.
We Expect Our Operating Expenses to Increase in the Future and May Need to Raise Additional Funds
As our operations grow and develop, so will operating expenses. We have a history of net losses and may incur additional losses and operating expenses over the next 12 months as we continue to develop our business plan. In addition, we may experience a material decrease in liquidity due to unforeseen expenses or other events beyond our control. As a result, we may need to raise additional funds, and such funds may not be available on favorable terms, if at all. If we cannot raise funds on acceptable terms, we may not be able to execute on our business plan, take advantage of future opportunities or respond to competitive pressures or unanticipated requirements. This may seriously harm our business, financial condition and results of operations.
Operational Risks
Other Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous federal, state, provincial, territorial and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies - federal, state, provincial, and territorial - are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply.
Legislation continues to be introduced and revised. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility, security laws or regulations, but such expenditures could be substantial.
The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating hazards and risks that could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation, and penalties and suspension of operations.
In addition, we may be liable for environmental damages caused by previous owners of property we purchase and lease. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.
In accordance with customary industry practices, we maintain insurance against some, but not all, potential losses. We carry business interruption insurance and protection against loss of revenues. Any insurance we obtain may not be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. We may elect to self-insure if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.
We are not currently participating in any non-operated wells and accordingly are not exposed to the risks associated with non-operated participation in oil and natural gas operations.
Title to Oil and Natural Gas Properties
We believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry and specific to the jurisdiction that the properties reside.
Although title to these properties is subject to encumbrances, in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry - we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In some cases, lands over which leases have been obtained may be subject to prior liens that have not been subordinated to the leases. In addition, we believe we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.
Pipeline Rights-of-Way
Substantially all of our gathering systems and pipelines are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our facilities are located on property owned in fee or on property obtained via long-term leases or surface easements.
Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and provincial or state highways, where necessary.
Certain of our rights to lay and maintain pipelines are derived from recorded oil and gas leases for wells that are currently in production, however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.
Seasonal Nature of Business
Seasonal weather conditions, road bans and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform a significant percentage of our development during the summer, fall and winter months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies and personnel during the summer, fall and winter months, which could lead to shortages and increase costs or delay our operations.
In addition, freezing weather, winter storms, and flooding in the spring and summer may impact operations, which could adversely affect our production volumes and revenues and increase our lease operating costs due to the time spent by field employees to bring the wells back on-line.
Environmental, Health and Safety Matters and Regulation
General
Our operations are subject to stringent and complex federal, provincial and local laws and regulations governing environmental protection as well as the discharge of materials into the environment, the generation, storage, transportation, handling and disposal of wastes, the safety of employees and governing the protection of human health and safety. These laws and regulations may, among other things:
·
require the acquisition of various permits before exploration or development commences;
·
limit or curtail some or all of the operations of facilities deemed in non-compliance with permits or other legal requirements;
·
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production, gathering, treating and transportation activities;
·
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas; and
·
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells, and restore, remediate or mitigate impacted environmental media.
These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, federal, provincial and territorial agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The oil and gas industry, in particular, recently has come under greater scrutiny by environmental regulators and non-governmental organizations. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for or restrictions, or other regulatory burdens on operations of the oil and gas industry, could have a significant impact on our operating costs.
Waste Management
Waste management is governed by various regulatory agencies enforcing specific federal, provincial, territorial, and state regulations and statutes. These regulatory agencies regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. The Company is strictly compliant and will maintain compliance with all applicable waste management regulations and requirements regarding drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas.
Comprehensive Environmental Response, Compensation, and Liability
We currently own, lease or operate numerous properties that have been used for oil and gas exploration, production, and transportation. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. Under such laws, we could be required to remove previously disposed substances and wastes, including wastes disposed of or released by us or prior owners or operators in accordance with the then current laws or otherwise, remediate contaminated property, perform plugging or pit closure operations to prevent future contamination, or take other environmental response actions.
Water Discharges and Water Quality
Water discharge and water quality is governed by various regulatory agencies enforcing specific federal, provincial, territorial, and state regulations and statutes. These regulatory agencies impose restrictions and strict controls with respect to the discharge of pollutants in waste water and storm water, including spills and leaks of oil and other substances, into waters of the province. The Company is strictly compliant and will maintain compliance with all applicable regulations and requirements regarding water discharges and water quality. Spill prevention, control and countermeasure requirements of the regulatory agencies may require appropriate containment berms and similar structures to help prevent any type of fluid discharge in the event of a petroleum hydrocarbon tank spill, rupture or leak.
Our operations also produce waste waters that are disposed via underground injection wells. These activities require a permit and are subject to applicable regulatory agency requirements. Currently, our operations comply with all applicable requirements and have a sufficient number of operating injection wells. However, a change in the regulations or the inability to obtain new injection well permits in the future may affect our ability to dispose of the produced waters and ultimately affect the results of operations.
Air Emissions
Air emissions are governed by various regulatory agencies enforcing specific federal, provincial, territorial and state and regulations and statutes. These regulatory agencies regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require the Company to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.
Our Ability to Produce Sufficient Quantities of Oil and Gas from Our Properties May Be Adversely Affected by a Number of Factors Outside Our Control
The business of developing and exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil wells involves the risk that the wells may be unproductive or that, although productive, that the wells may not produce oil or gas in economic quantities. Other hazards, such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations. A productive well may become uneconomic due to pressure depletion, water encroachment, mechanical difficulties, etc, which impair or prevent the production of oil and/or gas from the well.
There can be no assurance that oil and gas will be produced from the properties in which we have interests. In addition, the marketability of any oil and gas that we acquire or discover may be influenced by numerous factors beyond our control. These factors include the proximity and capacity of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. We cannot predict how these factors may affect our business.
In addition, the success of our business is dependent upon the efforts of various third parties that we do not control. We rely upon various companies to assist us in identifying desirable oil and gas prospects to acquire and to provide us with technical assistance and services. We also rely upon the services of geologists, geophysicists, chemists, engineers and other scientists to explore and analyze oil prospects to determine a method in which the oil prospects may be developed in a cost-effective manner. In addition, we rely upon the owners and operators of oil drilling equipment to drill and develop our prospects to production. Although we have developed relationships with a number of third-party service providers, we cannot assure that we will be able to continue to rely on such persons. If any of these relationships with third-party service providers are terminated or are unavailable on commercially acceptable terms, we may not be able to execute our business plan.
Market Fluctuations in the Prices of Oil and Gas Could Adversely Affect Our Business
Prices for oil and natural gas tend to fluctuate significantly in response to factors beyond our control. These factors include, but are not limited to actions of the Organization of Petroleum Exporting Countries and its maintenance of production constraints, the U.S. economic environment, weather conditions, the availability of alternate fuel sources, transportation interruption, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that could limit future drilling activities for the industry.
Changes in commodity prices may significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in charges to earnings due to impairment.
Changes in commodity prices may also significantly affect our ability to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil producing properties, as buyers and sellers have difficulty agreeing on the value of the properties. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation of projects. We expect that commodity prices will continue to fluctuate significantly in the future.
Risks of Penny Stock Investing
The Company's common stock is considered to be a "penny stock" because it meets one or more of the definitions in the Exchange Act Rule 3a51-1, a Rule made effective on July 15, 1992. These include but are not limited to the following:(i) the stock trades at a price less than five dollars ($5.00) per share; (ii) it is NOT traded on a "recognized" national exchange; (iii) it is NOT quoted on the NASD's automated quotation system (NASDAQ), or even if so, has a price less than five dollars ($5.00) per share; OR (iv) is issued by a company with net tangible assets less than $2,000,000, if in business more than three years continuously, or $5,000,000, if in business less than a continuous three years, or with average revenues of less than $6,000,000 for the past three years. The principal result or effect of being designated a "penny stock" is that securities broker-dealers cannot recommend the stock but must trade in it on an unsolicited basis.
Risks Related to Broker-Dealer Requirements Involving Penny Stocks / Risks Affecting Trading and Liquidity
Section 15(g) of the Securities Exchange Act of 1934, as amended, and Rule 15g-2 promulgated there under by the Commission require broker-dealers dealing in penny stocks to provide potential investors with a document disclosing the risks of penny stocks and to obtain a manually signed and dated written receipt of the document before effecting any transaction in a penny stock for the investor's account. These rules may have the effect of reducing the level of trading activity in the secondary market, if and when one develops.
Potential investors in the Company's common stock are urged to obtain and read such disclosure carefully before purchasing any shares that are deemed to be "penny stock." Moreover, Commission Rule 15g-9 requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor's financial situation, investment experience and investment objectives. Pursuant to the Penny Stock Reform Act of 1990, broker-dealers are further obligated to provide customers with monthly account statements. Compliance with the foregoing requirements may make it more difficult for investors in the Company's stock to resell their shares to third parties or to otherwise dispose of them in the market or otherwise.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None
ITEM 2.
ITEM 2. PROPERTIES
CANADA
Through Kodiak’s approximate 60% ownership of the subsidiary, Cougar Oil and Gas Canada, Inc., the Company’s Canadian focus is in the definitive projects of:
1.
Cougar Trout Properties, Alberta (Core Area) - farm-in and acquired lands in the Trout, Kidney and Equisetum fields;
2.
First Nations Joint Venture Project, Alberta - exploration and development opportunities within the adjacent to the Trout Core Properties.;
3.
Lucy, British Columbia - Horn River Basin Muskwa shale gas project; and
4.
Other Alberta properties.
Cougar Trout Properties, Alberta (Core Area)
During the third quarter of 2009, Cougar Oil and Gas Canada, Inc., the Company’s majority-controlled Canadian subsidiary, completed the following transactions:
Acquisitions. On September 30, 2009 and October 1, 2009, acquired from an unrelated private company certain wells, facilities and producing operations in and adjacent to the First Nation Joint Venture project in Alberta, Canada. The acquisition included 11 producing wells, 21 suspended wells and associated production, water disposal, production facilities and pipelines in the Trout field. Gross production at the time of the acquisition was approximately 170 barrels of oil per day (boe/d). Cougar actively worked during the fourth quarter of 2009 to maximize production and revenue and assessed other opportunities in the area to supplement this initial asset base. The Company negotiated commercial terms for properties that had the greatest upside through normal maintenance and enhanced recovery programs, in addition to the potential for additional drilling. These negotiations culminated at the end of September and beginning of October 2009 with Cougar successfully acquiring the Trout Core Area properties from two private oil and gas companies. These acquisitions represented the Company’s first significant producing resource properties. The Cougar team had high graded many of the properties within these acquisitions and determined potential to increase existing production in the first round of development. Operations commenced on these properties during the winter of 2009/10, consisting of maintenance and work over programs. At the end of 2009, the Company reactivated 4 wells that were previously suspended and completed substantial geological evaluation on the properties. Kodiak negotiated a bridge loan, on behalf of Cougar, for this acquisition. The acquisitions closed September 30, 2009 and October 1, 2009.
1.
Private Company Production and Property Acquisition (completed September 30, 2009)
a)
Approximately 7,100 gross acres of mineral rights with an average 85% working interest (all continued through production and no expiries).
b)
Approximately 125 barrels per day (bbl/d) net production (170 bbl/d gross) and an estimated 85 bbl/d at date of acquisition.
c)
11 pumping wellbores - 8 at time of acquisition - 3 workovers pending partner approval of AFEs.
d)
1 observation wellbore and 21 suspended wellbores.
e)
8 single well batteries, 3 water disposal wellbores with associated facilities, 2 multi well batteries with existing fluid handling capacity in excess of 2,500bbl/day (oil, gas and water handling and treating capability).
f)
Approximately 38.7 km of pipelines (oil and produced water).
g)
Approximately 13 km2 of 3D seismic over the properties and approximately 84 km of 2D seismic over the properties and adjacent lands.
h)
Based on the June 30, 2009 independent look ahead engineering report provided by an independent and private company, the estimated Proved and Probable oil reserves were approximately CAD$7,250,000 (Net Present Value 10% discount).
The agreed purchase price for this acquisition was CAD$6,000,000 with an initial payment of CAD$1,000,000 at closing. The balance of CAD$5,000,000 is payable under a debt instrument consisting of monthly installments commencing January 1, 2010 and continuing until March 1, 2014.
The purchase price was negotiated at $52.50 USD per barrel (/bbl) when oil was selling at plus $75.00/bbl USD. The cash portion of the acquisition cost and subsequent guarantees were provided by Kodiak.
The majority of this acquisition is outside the boundary of the First Nation Joint Venture Project lands. At the time of the property acquisition, the surface facilities had a replacement value of CAD$6,500,000 with a depreciated value of CAD$1,000,000. The overall project has an estimated CAD$50,000,000 in sunk costs, including wells, facilities, pipelines, roads and power lines. The substantial infrastructure results in lower overall operating costs, lower development costs and accelerating the operations schedule. Kodiak was able to borrow sufficient funds for the acquisition on behalf of Cougar by way of a bridge loan. Cougar then closed the acquisitions September 30, 2009. This was a critical mass property acquisition as there is substantial infrastructure, resulting in lower overall operating costs, lower development costs and giving our schedule an 1-3 leap forward to achieve our goals.
Without this kind of infrastructure, the initial production would have lower netbacks due to higher trucking costs and regular non-producing periods due to weather. In lieu of this acquisition, a large amount of capital would have to be spent to bring facilities to this baseline, which we now have. At current costs, the infrastructure replacement value would be substantially in excess of CAD$6,000,000. This capital will now be able to be spent on the drill bit and development work - allowing for a more aggressive growth plan.
2.
Private Company Production and Property Acquisition (completed October 1, 2009)
a)
Approximately 2.560 gross acres of land within and adjacent to the CREEnergy Project area lands.
b)
65% working interest in 6 wells - 2 producing wells and 4 suspended wells located in the Kidney and Equisetum fields and within or adjacent to the CREEnergy Project lands.
c)
Approximately 12 bbl/d net production (20 bbl/d gross) of light oil at time of acquisition.
d)
Based on the April 1, 2009 engineering report provided by an independent and private company, the estimated Proved and Probable oil reserves were approximately CAD$459,000 (Net Present Value - 10%).
The Company, through is private subsidiary Cougar, negotiated a purchase agreement with the private company consisting of cash for the P1 reserves and Cougar shares for the P2 reserves.
Acquired Production and Properties Additional Discussion
The existing infrastructure and initial production on the acquired properties enables the Company to realize higher netbacks and focus on deploying capital to the drill bit and development work. Additional details include:
·
The existing area field personnel agreed to transfer to Cougar with their many years of hands-on field expertise thereby greatly reducing the risk of downtime due to lack of qualified field personnel.
·
The existing pipeline systems provides direct access to sales of oil products, which results in the access to sales being in the Company’s control and not third party pipeline operator dependent.
·
There are 2 batteries for the handling and treating of oil and the disposal of the produced water. The batteries are capable of handling an estimated 2,500 bbl/d with nominal refit costs.
·
Many of the wells are piped into the batteries to reduce the need for trucking, which is important for the higher water cut wells. These pipelines can be expanded to further lower operating costs.
·
There are 37 wells, which 13 were producing as of December 31, 2009. The 20 suspended wells are workover or recompletion candidates.
·
The produced water can be used for future water floods, which regularly have been shown to add substantial incremental production in the area.
During 2010 the Cougar had net daily crude oil production ranging from a low of approximately 80 barrels per day to a high of approximately 225 barrels per day. Cougars monthly crude oil production has ranged from 3,170 barrels to 5,874 barrels. Management believes the current group of producing wells is capable of daily production exceeding 250 barrels per day but this production potential has been curtailed as a result of ongoing maintenance and repair issues over the reporting period. As these maintenance and repair issues are resolved over the next year it is anticipated production will increase accordingly. It is also anticipated production will increase as a result of the ongoing development drilling operations. We averaged $30.00/bbl Cdn for the year ended 2010 for operating costs including maintenance costs. We believe that through ongoing maintenance and upgrades, we will reduce those costs to the $25 Cdn range and perhaps as low as $17 Cdn which we have experienced for short periods of time. We continue to receive $50 plus as a net back after royalties and are net positive for operations at year end.
Refer to the Companies reserves report for additional information regarding NPV and forecast production.
The Trout field is a technically complicated field to operate as a result of two common wellbore scenarios. These scenarios include managing very high water cuts which results in excessive equipment fatigue and the extremely corrosive uphole formations which result in multiple casing failures. The Company identified these two scenarios prior to purchasing the Trout properties and believes the technical complexity of the Trout field reduces competition from entering the area resulting in additional available economic upside. Through our close attention to detail, extensive operations/maintenance experience, both down hole and at surface - we have the ability to manage costs, technical problems at a level not typically possible by majors.
GLJ Petroleum Consultants Ltd., Reserve Evaluations and Operations Update (October 1, 2009, December 31, 2009 and December 31, 2010 )
These independent engineering reports were prepared by GLJ and are based on the acquisitions of September 30, 2009 and October 1, 2009. The reports update the look forward reports that were prepared as part of the negotiations for property acquisitions. Due to the 3rd quarter financial statement cut off at September 30, 2009, only parts of the October 1, 2009 report were included in the 3rd quarter financial statements due to U.S. GAAP rules.
The October 1, 2009 report provided the initial analysis of the consolidated properties in the Trout Field and other Alberta properties acquired at Alexander and Crossfield. The December 31, 2009 report gave the analysis with the initial work programs implemented and plans for the balance of the winter work season.
Thus, we continue to demonstrate our ability to increase reserve value with limited capital infusion and our expectations of the opportunities these properties presented were supported by the reports and the results of the field work.
First Nations Joint Venture Project, Alberta
History
Kodiak has a well developed relationship and track record with Aboriginal communities in northern Canada. This comes from a strong commitment by Kodiak management and personnel for open and honest communications and negotiations with the Aboriginal community leaders - a demonstrated respect for their culture, land and residents. Kodiak's reputation has also been recognized through negotiations with regulatory agencies, resulting in several of those agreements being used as templates with other companies and projects. Our reputation has become known outside the far north of Canada.
CREEnergy Oil and Gas Inc. (CREEnergy) represented that they were the authorized agent for multiple First Nations communities. Some of these new First Nations communities are in various stages of ratification from the Federal Government of Canada to satisfy outstanding Treaty Land Entitlement (TLE) claims. Within these new First Nations are approximately 15 townships or 540 sections of mineral rights for development in Alberta.
In order to advance economic sustainability for First Nations communities that CREEnergy represented, CREEnergy searched for an oil and gas partner to develop certain oil and gas projects. Kodiak was one of the industry companies shortlisted in the search. Through discussions, meetings and negotiations since May 2008, CREEnergy selected Kodiak as their joint venture partner to develop those resource projects. The joint venture agreement between CREEnergy and Kodiak was the result of the negotiations.
To develop and strengthen the relationship with CREEnergy, Kodiak formed a subsidiary company, Cougar Energy, Inc., to focus on this relationship. As a result, Cougar became the operating entity for Kodiak in Western Canada.
Joint Venture Information and Summary
In December 2008, a strategic alliance and joint venture agreement was established between CREEnergy Oil and Gas Inc. (CREEnergy) and Kodiak Energy, Inc. (Kodiak). The Agreement was built on the foundation of respect for the First Nations communities, their Heritage, their Lands and the Environment. CREEnergy has agreed to work with Kodiak to develop oil and gas reserves within their lands for the benefit of both CREEnergy and Kodiak.
In June of 2010 - CREEnergy defaulted on its agreements with Cougar Oil and Gas Canada, Inc and Cougar terminated any funding at that time. Cougar had met all the commitments and terms required by the agreements and that was acknowledged by CREEnergy but CREEnergy could not deliver the leases as promised. Cougar continued to find a solution with CREEnergy, but as of year-end, discussions had broken down. Once Cougar became aware of the default of CREEnergy, Cougar opened negotiations directly with the First Nation Tribal Council of Peerless Trout directly and has continued on with that process since. We have established a good working dialogue and created employment. In the seismic program we became a major employer of the community for the duration of that project. We continue to work with the Council toward formalizing a Joint Venture. Cougar is exploring recourse against CREEnergy to recover funds advanced for the agreements.
Lucy, Northern British Columbia
Cougar Energy, Inc is the operator and 80% working interest owner of a 1,920 acre lease located in Northeastern British Columbia. The Company believes the lease is situated on the southeast edge of the Horn River Basin and the Muskwa Shale gas prospect. Industry continues to show increased interest in this shale gas play with several comparisons of the Muskwa Shale gas potential as an analogue of the Barnett Shale gas potential.
The Company has been involved in two previous drilling operations on the lease. In the fourth quarter of 2006, Kodiak farmed in as a non-operated partner, paying 10% to earn 7.5%, on a drilling operation in the Lucy (Gunnell) area. This first drilling operation, designed to target a Middle Devonian reef prospect, had several operational problems and was unsuccessful.
After performing an internal review of seismic and drilling data, it was determined that there was a seismic anomaly on the southern half of the lease. This anomaly was identified on several different seismic lines and a decision was made to drill a well on that part of the lease to evaluate both the anomaly as the primary target and the Muskwa Shale, seen in the first well but not evaluated by the operator at that time.
In the third quarter of 2007, the Company served its partners with an independent operations notice which resulted in the Company increasing its working interest in the lease to 80%.
In the first quarter of 2008, a second drilling operation was completed and a vertical well was cased. It was determined that the Middle Devonian seismic anomaly was not a reef buildup and the wellbore was cased due to encountering significant gas shows in the previously identified Muskwa Shale with a formation thickness of approximately sixty meters.
The Company submitted an application to the British Columbia Oil & Gas Commission (“OGC”) for an experimental scheme to test the Muskwa Shale gas potential. On August 12, 2008, Kodiak received the final approval of the Lucy experimental scheme application. The Company has prepared a multi-phase work program designed to test the deliverability of the Muskwa Shale gas formation using vertical and horizontal drilling and completion techniques. Kodiak’s proposed work program would allow for early production into a pipeline in order to monitor long-term deliverability rates and pressures of horizontal and vertical test wells on the periphery of the Horn River Basin.
These results would be some of the first commercial production results for a Horn River Basin shale gas project and would provide information that would help define the effective exploration area of the Basin and assist in the validation of adjoining properties in a divestiture process, should that occur.
Kodiak engaged an industry-recognized shale gas assessment laboratory to prepare and analyze the drill cuttings from the 2008 well in order to evaluate the Muskwa Shale interval for gas potential. The shale gas assessment is conducted by performing various tests on the rock cuttings that were obtained while drilling the well in order to determine the type, quality and amount of both adsorbed and free gas.
The most important conclusion from the drill cutting analysis is that the information received continues to support the evaluation of Kodiak’s Muskwa (Evie) Shale gas prospect. The laboratory data is consistent with other public industry and government data on the Muskwa Shale. It should also be noted that the numbers obtained on the laboratory analysis of drill cuttings may be conservative due to the nature of sampling drill cuttings on a drilling rig. Another significant point is that all three wells on the Kodiak lease, drilled deep enough to penetrate the Muskwa Shale, had elevated gas detector readings while penetrating the shales.
The prospect is still in the early stages of delineation and no assurance can be given that its exploitation will be successful. Further appraisal work is required before these estimates can be finalized and commerciality assessed.
The severe turn down in gas prices over the past year has made natural gas projects difficult to show returns on investment - especially high capital cost projects such as those in the Horn River Basin - despite the very large reserves and recovery rates attributed to the Muskwa shales. The current $3 to $5 gas prices limit the return for this project in the short term and the availability to obtain development financing.
The current intention is to perform the following work commitments for the license (as new information and financing becomes available, the plans may be revised). In lieu of obtaining our own financing, we are actively enlisting JV partners to move the project forward by way of divesting part of our interest.
·
Perforate the Muskwa intervals, perform a vertical shale gas fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to an existing pipeline approximately 1 Km from the wellhead; and
·
Drill and case a 1,000 meter horizontal leg from an existing cased vertical well on the lease, perform a horizontal staged fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to pipeline.
In April 2009, Kodiak, through its subsidiary, Cougar, entered into a standard farm-out and participation agreement with one of its partners. The partner would provide 90% of the funding for the first phase of the “Lucy” Horn River work program. Upon completion of the funding, the partner will have earned an additional 30% working interest in the wells and property. Cougar will maintain operator status and majority ownership of the project with the management of Kodiak/Cougar overseeing the execution of the work program. Upon fulfillment of the funding provisions of the farm-out and participation agreement, Cougar’s working interest in the “Lucy” Horn River Basin project would be 50%.
Our partner did not complete its financing commitment and this farm-out and participation agreement expired on August 15, 2009. After due diligence was completed in October, 2009, the partner transferred its interest in its Alexander and Crossfield, Alberta wells to the Company as a penalty for non-completion (see below).
Cougar Central Alberta Producing Properties, Alberta
Private Company Production and Property Acquisition (completed October 1, 2009)
1.
2 producing oil properties in the Crossfield and Alexander fields in Central Alberta.
2.
100% working interest in the Crossfield property - 1 producing well with single well battery with approximately 5 barrels per day (bbl/d) net production - This well was sold in September 2010 for $210,000 Cdn for P1 reserve value.
3.
55% working interest in the Alexander property - 1 shut in oil well with a single well battery, 1 suspended well. Production of approximately 14 bbl/d net production upon restarting shut in oil well in June 2010.
In August, 2009, it was determined that Cougar’s working interest partner in the Lucy, B.C. project was unable to complete the financing as required in the farm-out agreement and as a result, in October after due diligence and environmental reviews, Cougar has accepted the transfer of the partner’s Alexander and Crossfield, Alberta properties as a penalty payment. The properties received are valued at approximately $500,000 CAD (NPV 10% escalated pricing). Cougar has assumed asset retirement obligations in connection with the properties estimated at $50,000 CAD.
Production from the Company’s new proved reserves commenced on October 1, 2009 and recognition of the associated revenue and cash flow began on that date.
Little Chicago, Northwest Territories
The Company is the operator and largest working interest owner of the 201,160 acre Exploration Licence 413 (“EL 413”) in the Mackenzie River Valley centered along the planned Mackenzie Valley Pipeline.
In 2006, the Company signed an exploration farm-in agreement with the two 50% working interest owners of EL 413. The Company reprocessed 50 km of existing seismic data in Q4 of 2006 and during the 2006-07 winter work season, the Company shot and acquired 84 km of high resolution proprietary 2D seismic and gravity survey data on the farm-out lands, thus earning a 12.5% working interest in the property. In September, 2007, the Company acquired Thunder River Energy, Inc.’s (“Thunder”) remaining 43.75% in the property giving the Company a 56.25% interest in EL 413. A letter of intent signed earlier in 2008 with the Company’s remaining partner in the project, which would have allowed Kodiak to acquire the balance of the working interest in EL 413 and become a 100% working interest owner, recently expired.
A 2007/08 43 km 2D high resolution proprietary seismic program and gravity survey was completed on the property and the results were processed and interpreted and used to support the Company’s planned drilling program. This project was completed on budget and schedule. The seismic and gravity data from the two projects show substantial structural closure and formation character and support the planning for a future multiple well drilling program. That data was included in an updated Chapman Prospective Resource report published in May, 2008.
The decision to acquire additional seismic and gravity data in the winter of 2007/08 was made to improve the potential to drill both the Devonian Bear Rock and the Basal Cambrian Sand targets from a common drilling site. This would substantially lower drilling costs on a per well basis and reduce the overall project risk.
Kodiak has analyzed the 2007/08 seismic data and the various reservoir indicators/lands and identified 11 drill locations. These drill locations have been selected to evaluate three primary target formations on EL 413 including the Devonian Bear Rock Oil Prospect, the Basal Cambrian Sand /Top Precambrian Oil and Gas Prospect and the Canol Oil Prospect. These locations have been further high graded into a two phase drilling program consisting of two wells with a planned total depth of 2400 meters each targeting both the Basal Cambrian/Precambrian and the Bear Rock prospects and a multi-well shallow drilling program with a planned total depth of 400m each targeting the Canol prospect. A scouting trip was completed in the third quarter of 2008 that allowed the Company to review potential access routes, well sites and camp locations.
The Devonian Bear Rock Prospect (“Bear Rock”) is the first described target and is located at a shallow depth of approximately 700 meters (2,300 ft.). This reservoir was previously identified and preliminarily evaluated in the initial Chapman Report prepared in 2005. The expected product from the reservoir is light and medium oil, with no consideration to solution gas.
The combined seismic obtained during 2007 and 2008 acknowledged a series of pools distributed throughout the project. The Chapman Report identified fifteen Bear Rock leads located along the seismic lines with five of them being selected as well defined high grade Bear Rock leads. This is an increase of 5 additional leads from the initial 2007 work program. Indicators of these potentially prolific reservoirs are present along several seismic lines that may imply these Bear Rock occurrences to be present throughout EL 413.
The additional 2008 seismic further defined a hydrocarbon trap in the Basal Cambrian Sand sitting on the top of the Precambrian. This interval, found at a depth of approximately 2,300 meters (7,545 feet), has never been regionally penetrated and tested; however, it has been proven as a productive reservoir in the Colville Hills area approximately 125 kilometers (77 miles) east of EL 413. With this additional data, the Chapman Report identified five drilling locations that will allow the Basal Cambrian Sand and the top of the Precambrian to be drilled and tested.
Physical evidence of hydrocarbons is present with a natural surface oil seep on the northern edge of the license area on the banks of the Mackenzie River. This natural occurrence is suggestive of a shallow oil pool, possibly in the Canol formation, and warrants further investigation. While reviewing core samples and well logs from previous regional drilling activity, Kodiak was able to map out the Canol/Imperial formation and determine that it is the likely source of the natural surface seeps. This prospect will be found on the Northwest quarter of EL 413 and is at a very shallow depth of approximately 350 meters (1,148 feet). The Company has identified 5 drilling locations which will be evaluated during a planned future project drilling program.
Kodiak is preparing for the previously mentioned drilling program and has commenced work on the necessary permits and applications. The Company is working with the Sahtu and the Gwich’in, which are the beneficiaries of the land claims containing the EL 413 license. The Company does not believe there will be any difficulty finishing the Access and Benefits Agreement prior to submitting the final applications to the regulators for approval. The Company is currently in discussions with other industry partners to share in the costs of the drilling programs, thus reducing risk and capital commitments. Financing plans will be finalized when overall partnerships are established. Kodiak intends on retaining operatorship.
In addition, Kodiak had made application with regulators to extend the EL 413 license and received written notification from Indian and Northern Affairs Canada that a one year extension is available. The one year license extension, which is subject to certain terms and conditions, was provided just prior to expiry and provides for one additional year.
Upon review of the overall status of all projects in the area, current commodity prices being much below levels required to justify development on this and other projects, continued delay of the Mackenzie Valley Pipeline Project, the risk that any discovered gas reserves would be indefinitely stranded without such development, the Company continues to seek partnership in the development; however, the deteriorating economic factors make this difficult. We will still retain the confidential proprietary seismic data for future assessment of the "Little Chicago Prospect" and the Company will determine the best way to monetize that asset through either divestiture and/or possibly renominating the prospect when conditions are more appropriate. In Q4 2010 the Mackenzie Valley Pipeline Project received partial regulatory approval, however at time of filing there has been no commitment by industry owners of the pipeline to construction.
Province/Granlea, Southeast Alberta
The Company purchased a 50% working interest in two sections (1280 acres gross - 640 net) of P&NG rights at a provincial land sale on September 22, 2005. In 2005, a 2D seismic program was completed on the property and in 2006, a well was drilled and completed; surface facilities were installed and a pipeline tie-in was completed. Production commenced in September, 2006. The well produced for a short period until excess water rates occurred and in October, 2006 the well was shut in. After the well bore was evaluated as having no current economic production potential, the well was abandoned. The leases expired in Q3 2010.
UNITED STATES
New Mexico
Through its acquisition of Thunder, the Company acquired a 100% interest in 55,000 acres of property located in northeast New Mexico. Additional land acquisitions have increased the Company’s land position to approximately 79,000 acres. These lands have potential for natural gas and CO2 and oil and helium resources at shallow depths. In 2008, the Company purchased 19,000 stations of gravity data and 37 miles of trade seismic data, completed a 35 mile 2D high resolution proprietary seismic program and a three well drilling program.
The three wells were drilled with air to reduce formation damage and they were cased to the base of the Yeso formation. Based on gas detector results, drill cutting samples and open hole logs, all wells showed three potential shallow porous sandstone formations capable of CO2 production with up to 200 feet of identified net pay thickness. The Yeso, Glorieta and Santa Rosa formations were perforated and flow tested to determine deliverability and pressure. There were multiple gas samples analyzed at specialized independent laboratories from two separate extended flow tests that identified CO2 concentration quality from 98.4% to 99.5%. Two of the wells were stimulated with a nitrified acid squeeze and were able to sustain an extended flow rate of approximately 375mcf/d. The shallow sands have been mapped using offset well control and the newly acquired seismic data and the Company has determined there is a very high likelihood of encountering the target formations throughout the leased project area; provided, however, that no assurance can be given that this will be the case.
The 35 mile 2D high resolution seismic program was completed on schedule and on budget and after reviewing the seismic data, the Company was able to effectively map out a probable long term development area which would result in CO2 production from the previously identified formations. The seismic is currently being evaluated to identify possible conventional oil and gas prospects on the leased project area.
A preliminary project feasibility study was commissioned to identify capital development costs and timelines as well as projected operating costs in order to provide information to support a large scale long-term plan of development. This information will enable the definitions for pipeline access planning and negotiation, transportation agreements, sales contracts for the CO2, additional land acquisition terms and conditions, facility engineering and construction and ultimately the parameters for financing the project development.
Several companies have expressed interest in participating in the New Mexico properties at several levels of involvement. Discussions are still ongoing with several firms regarding potential opportunities for the project, including integration of the CO2 production into Permian Basin enhanced oil recovery projects and the Company has also entered into farm-out negotiations with several companies interested in exploring deeper oil and natural gas prospects on the properties.
Due to lower commodity prices for Permian Basin oil (the primary market for CO2) and CO2 contract prices (deliverable into the Denver City Hub), aggressive development is not financeable at this time. Aside from ongoing maintenance of leases and wells, the Company is focusing its efforts on updating engineering models, and business opportunities so that when prices recover and investment markets improve, we will have the opportunity to move this project forward. The leases are 10 year leases and no expiries are imminent.
Kodiak has entered into a Farmout Agreement with a private company to develop the deeper rights of Kodiak’s approximate 30,000 gross acres of oil and gas rights in NE New Mexico. Kodiak retains the rights to the CO2 and Helium. The transaction anticipates additional seismic work and/or drilling of a number of wells on the Farmout acreage or before June 1, 2011. The Farmee will earn 100% of pre-selected, semi-contiguous 6-section blocks for each 2000’ well drilled until their continuous option or right to earn ceases. Farmor will retain a convertible overriding royalty of 7.5% on Helium and 5% on balance of rights (no deductions) on the test well blocks and a 25% potential working interest in an Area of Mutual Interest opportunity. There is a provision for a drop fee in the event of default on the part of the Farmee.
Montana
During 2006, the Company, under a joint venture farm-out agreement, participated in a seismic acquisition program, and a two well drilling program to earn a 50% non-operating working interest in the wells and well spacing. This joint venture project provides the Company with the right to participate on a 50% basis going forward on this prospect in the Hill County area of Montana. The operator of the project had 60,000 contiguous undeveloped acres of P&NG rights in the area, as well as some excess capacity in facilities and pipelines. Two wells were drilled in the third quarter of 2006; one is cased for subsequent evaluation of the multiple zones found and one was abandoned. In order to facilitate the efficient exploration of this prospect area, the Company acquired from the original operator a 100% working interest of 12,000 acres of P&NG rights while retaining the right to participate and initiate operations on the remaining approximate 48,000 acres of prospect leases. After an internal geological review of this prospect, and in light of current commodity prices, the Company, in the fourth quarter of 2008, wrote off its costs relative to this project and subsequently, in 2009, the Company has allowed the majority of the acreage to expire As of December 31, 2010, we held oil and gas leases on approximately 879 gross acres, of which approximately 879 gross acres (100%) are not currently held by production. The balance of the Montana leases will expire in 2011 Q2.
OFFICE PROPERTY
During December, 2009, Kodiak Energy, Inc. relocated its offices to 833 4th Avenue S.W., Suite 1120, Calgary, AB, T2P 3T5. Through Cougar Oil and Gas Canada, we lease offices on a 3 year term, expiring in February of 2013. The current lease is approximately $14,000 CAD per month.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
From time to time, the Company may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. The Company is currently not aware of any such legal proceedings that the Company believes will have, individually or in the aggregate, a material adverse affect on our business, financial condition or operating results.
ITEM 4.
ITEM 4. [RESERVED]
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION
The Company's common shares are currently quoted on the Over the Counter Bulletin Board under the symbol KDKN. On December 24, 2007, the Company's common shares commenced trading on the Toronto Venture Stock Exchange in Canada under the symbol KDK. On November 4, 2009, The Company voluntarily requested the TSX Venture Exchange ("TSX-V") in Canada to delist its common shares from trading on the TSX-V. See "PART II, Item 9B. Other Information" in this Form 10-K for further information on the delisting. Trading ranges of the Company’s common shares on the OTC:BB by quarter for fiscal 2010 and 2009 were as follows:
The Company has not paid cash dividends since inception. The Company intends to retain all of its earnings, if any, for use in its business and does not anticipate paying any cash dividends in the foreseeable future. The payment of any future dividends will be at the discretion of the Board of Directors and will depend upon a number of factors, including future earnings, the success of the Company's business activities, capital requirements, the general financial condition and future prospects of the Company, general business conditions and such other factors as the Board of Directors may deem relevant.
As at December 31, 2010 there were 119,683,294 shares of common stock issued and outstanding and there were approximately 12,124 holders of record of our common stock.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets out information with respect to compensation plans under which equity securities of our Company were authorized for issuance as of December 31, 2010:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Not required
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
FORWARD LOOKING STATEMENTS
From time to time, we or our representatives have made or may make forward-looking statements, orally or in writing. Such forward-looking statements may be included in, but not limited to, press releases, oral statements made with the approval of an authorized executive officer or in various filings made by us with the Securities and Exchange Commission. Words or phrases "will likely result", "are expected to", "will continue", "is anticipated", "estimate", "project or projected", or similar expressions are intended to identify "forward-looking statements". Such statements are qualified in their entirety by reference to and are accompanied by the above discussion of certain important factors that could cause actual results to differ materially from such forward-looking statements.
Management is currently unaware of any trends or conditions other than those mentioned elsewhere in this management's discussion and analysis that could have a material adverse effect on the Company's consolidated financial position, future results of operations, or liquidity. However, investors should also be aware of factors that could have a negative impact on the Company's prospects and the consistency of progress in the areas of revenue generation, liquidity, and generation of capital resources. These include: (i) variations in revenue, (ii) possible inability to attract investors for its equity securities or otherwise raise adequate funds from any source should the Company seek to do so, (iii) increased governmental regulation, (iv) increased competition, (v) unfavorable outcomes to litigation involving the Company or to which the Company may become a party in the future and, (vi) a very competitive and rapidly changing operating environment. The risks identified here are not all inclusive. New risk factors emerge from time to time and it is not possible for management to predict all of such risk factors, nor can it assess the impact of all such risk factors on the Company's business or the extent to which any factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statements. Accordingly, forward-looking statements should not be relied upon as a prediction of actual results.
The financial information set forth in the following discussion should be read in conjunction with the consolidated financial statements of Kodiak Energy, Inc. included elsewhere herein.
PLAN OF OPERATION
Canada
Through Kodiak’s majority owned subsidiary, Cougar Oil and Gas Canada, Inc., the Company’s focus is:
PLANS FOR GROWTH
Trout Operations Growth Plans - The Company has prepared a multifaceted development program that is designed to carry the Company forward with the overall goals of increasing production. The plan is to efficiently execute field programs that combine the optimization of existing wells and infrastructure with additional infill drilling and supplemented with land acquisitions and 3D seismic supported exploration drilling. This combination of field operations represents a balanced portfolio of risk versus reward, which can be easily adjusted depending on cash flow, commodity prices and financing.
Field Optimization - Following the acquisition of the properties in the Trout area all of the existing wellbores and production practices were reviewed to identify inefficient practices. Approximately thirty field optimization projects were identified during the field review. The projects were primarily focused around field management and deliverability of existing assets.
The Company has finished implementing approximately half of the optimization projects originally identified during the field review, which resulted in a production increase in excess of 250%. The projects implemented in the field have included repair and replacement of surface and down hole production equipment, implementation of chemical enhancement programs and debottlenecking of pipeline and infrastructure facilities. The Company plans to continue to execute the remaining field optimization programs over the next 12 months.
During the last couple of months Cougar has been working on several well reactivations in the Trout production field.
The 10-21 reactivation involved deepening the existing well by approximately 15 meters to penetrate a previously unproduced Keg River oil formation. Last week the Corporation successfully installed a packer in the wellbore to shutoff an uphole water source which will allow for the Keg River to be efficiently produced. The well also had a temporary hydraulic pumpjack installed on it and this has been replaced with a conventional pumpjack which will allow a substantially larger production rate.
The 13-25 reactivation involved repairing a wellbore and pumpjack that had been shut in for over three years. The downhole work was successfully repaired with no problems but the pumpjack repair took longer due to time required to get the gear box repaired. A maintenance crew recently finished all of the repair work and the well is currently on production.
The 11-22 reactivation involved a series of downhole repairs and installation of surface equipment. The downhole work included replacing a badly corroded production liner and stimulating the productive Keg River zone with an acid wash. The surface equipment will be moved from another site once the snow has melted and the lease has dried up. It is anticipated the 11-22 reactivation will be finished in Q2.
The reactivated wells also benefit from a 5% royalty holiday for the first twelve months of production. The royalty incentive was put in place by the provincial government and provides for very attractive economics and a quicker project payout.
Infill Drilling - The majority of the wells on the Trout properties were drilled almost twenty years ago when oil prices were much lower and infrastructure was much less developed. Infill drilling is an important optimization technique in which new vertical, directional and horizontal wells are added to an existing pool to maximize the total oil recovery.
The Company recently acquired 12 Km2 of 3D seismic over a core area of the existing property which complements the 3D seismic acquired in the original acquisition. The Company has finished evaluating these two 3D seismic surveys over their Trout and Peerless properties and has identified an additional 4-5 infill drilling locations to increase the overall drainage of the oil reserves. These infill locations have an expected find and development (F&D) cost of $5-7 per barrel. The Company plans include the first 2-infill wells in Q1, 2011. See subsequent event notes.
The Company has evaluated the overall seismic mapping for the area and has planned an extensive 3D program to be initiated in Q1, 2011. The size of this 3D program coupled with the drill results will support additional drilling programs described below. See subsequent event notes
In December of 2010, the company initiated licensing of 2 wells for an infill drilling program for Q1 2011. The horizontal well was initiated in late February of 2011.
The drilling, completion and workover operations in the Trout field have finished and the equipment has been demobilized back to the Red Earth area in anticipation of spring road bans. The planned second new drill has been deferred until the Corporation’s Q3 drilling program. There was not enough time to drill the second well before the spring weather resulted in road bans being implemented in Alberta. If the drilling rig was not moved off before road bans the Corporation would have been responsible for a very large stand-by charge every day the drilling rig and equipment was stranded by the road bans so the decision was made by management to demobilize the drilling equipment after the first well was finished.
Cougar finished drilling the horizontal Keg River oil well on March 20, 2011. The horizontal leg was successfully drilled in the top two (2) meters of a ten (10) meter thick Keg River zone and has approximately 400 meters of horizontal productive formation. Upon entering the Keg River formation there was an immediate loss of circulation and increase of wellbore gas indicating a substantial reservoir was encountered. Using electro-magnetic directional tools the Corporation was able to successfully steer the horizontal wellpath to the required endpoint.
Once the drilling rig moved off the horizontal location the service rig and production equipment were moved on and rigged up. The Keg River in the Trout field has excellent inflow capability due to the substantial porosity and permeability and as such does not require the costly and time consuming stimulation work required by most of the current tight oil plays. The completion operations for Cougar’s horizontal well consisted of landing the tubing string and swabbing in multiple spots along the toe to the heel of the horizontal wellbore to confirm and induce formation inflow. Throughout the swabbing test the fluid level was maintained in the casing indicating a strong inflow of formation fluids. The final production equipment including the bottom hole pump and rods was run and the well has been put on production. It is anticipated it will take several weeks to recover all of the lost drilling fluids and begin producing the Keg River reservoir fluids.
The new wells benefit from a 5% royalty holiday for the first twelve months of production. The royalty incentive was put in place by the provincial government and provides for very attractive economics and a quicker project payout.
Cougar has completed the initial review of the processed 3D seismic data that was acquired in January. The seismic data confirms the multi-well vertical and horizontal development potential of the existing Keg River and Granite Wash oil pools but the 3D seismic also identified several new undeveloped oil reservoirs. The development drilling locations are key to increasing production and cash flow and the new undeveloped reservoirs can add significant reserves for the company to pursue. The Corporation is finalizing the locations for the next drilling program and expects to begin the permitting process by the end of April once the next phase seismic review has been completed.
Additional Development - In addition to the production optimization and infill drilling projects, The Company has been aggressively planning out the future growth for the Company. These plans include the acquisition of existing assets in the area and the development of neglected production areas. The Company is continuously evaluating acquisition opportunities in the core area and will act on these opportunities if the project details and economics are synergistic. Development plans include the following:
(a)
The Company has identified several neglected production areas and has implemented a strategy to acquire land from public or private landowner around these areas whenever possible. Once the land has been acquired the Company will typically perform some additional seismic acquisition and review and then proceed with the drilling operations.
(b)
The Trout area has excellent well control to assist the modeling of the future drilling programs. The majority of the wells drilled in the area were cored which allows for a detailed rock evaluation in additional to the conventional well log information. There is an important blend of geological and geophysical analysis to identify the target formations and the structure required to trap the oil in place.
(c)
The Company is also evaluating other production areas in western Canada as potential acquisition targets and secondary core areas.
Continued Development of the Trout Area through Systematic Operational Controls
As we develop our maintenance program through the Trout Area lands in north central Alberta, we will continue to utilize our economic model to drive efficiency and minimize costs. We will focus our maintenance program on industry best practices and continued technological enhancements to maximize our return on assets and capital deployed.
Consolidate the Trout Area
To further enhance our economies of scale, we intend to be aware of other acquisition opportunities in the area. Consistent with our strategy to improve our financial flexibility, we intend to make acquisitions utilizing either equity and/ or debt instruments.
Develop Trout Area Assets
We intend to prudently develop this acreage position by redeploying cash flow generated from area operations. We are currently evaluating a series of developmental drilling locations in addition to several step-out drilling locations with the goal of adding incremental reserves and cash flow. As we are focused on locations in areas with existing infrastructure, we expect our development plan to have a near-term material impact on our proved reserves and production. We believe investing in this area is the most expedient way for us to improve our financial flexibility and return on capital.
The First Nation Joint Ventures
First Nation ventures provide additional drilling and development opportunities with adjacent land to our Core Trout Project that may use the existing infrastructure. The Company continues to actively work on the First Nation joint ventures with a goal of responsible development of the leased oil and natural gas mineral rights. Private First Nation land represents some of the largest unleased blocks of mineral rights in the province of Alberta. Cougar has identified this type of Joint Venture as a strategically critical growth opportunity. The Company had paid an exclusivity fee to an First Nation agent, which provides the opportunity to lease specific mineral rights. The Company is also currently working with other First Nation groups to develop mutually beneficial joint venture agreements, which will allow Cougar and the First Nations to explore and develop conventional oil and natural gas prospects on both private and public lands. These joint venture projects will generally be developed using traditional exploration and development techniques, which include leasing blocks of mineral rights and using seismic and drilling to develop the prospects. Further information regarding these joint ventures will be provided when available.
Current Status
In June of 2010 - CREEnergy defaulted on its agreements with Cougar Oil and Gas Canada, Inc. and Cougar terminated any funding at that time. Cougar had met all the commitments and terms required by the agreements and that was acknowledged by CREEnergy but CREEnergy could not deliver the leases as promised. Cougar continued to work to find a solution with CREEnergy, but as of yearend, discussions had broken down. Once Cougar became aware of the default of CREEnergy, Cougar opened negotiations directly with the Peerless Trout First Nation directly and has continued on with that process since. We have established a good working dialogue and created employment. In the 2011 Q1 Trout 3D seismic program Cougar became a major employer of local Peerless Trout Lake First Nation contractors and labourers for the duration of that project. We continue to work with the Chief and Council toward formalizing a Joint Venture. Cougar is exploring recourse against CREEnergy to recover funds advanced for the agreements.
Northern Alberta - First Nations Joint Ventures:
•
Approximately 75,000 gross acres for access and development inside the land claim
•
Approximately 90,000 gross acres for development outside the land claim in identified 2 mile perimeter currently tendered as Joint Venture - Cougar 85% and operator
-
Light crude and natural gas prospects
Project Status:
•
Negotiations underway to develop and finalize Joint Venture agreements with communities to develop oil and natural gas prospects within the Peerless Lake and Trout Lake land claim.
•
In Parallel - Develop Joint Venture agreement to acquire, explore, develop and operate adjacent lands to the benefit of both Cougar and the Peerless Trout First Nation - Native Joint Ventures have priority with province over other industry and thus reduced competition for a Cougar/Peerless Trout First Nation JV.
Operating Plan - 2011/2012:
•
Explore and develop lands already identified by 2D and 3D seismic acquired - targeting Keg River light oil prospects
•
Acquire additional seismic and perform drilling programs
•
Execute similar maintenance programs on existing wells as Trout properties
•
Acquire additional lands adjacent to the land claim in a Joint Venture structure (anticipated model is 85/15 shared ownership).
Lucy, British Columbia
Our Muskwa Shale project in the Horn River Basin of north east British Columbia has prospects for natural gas that are comparable to many of the major developments currently under way in the area. With an investment in a fracture program on the two existing wells, a development into a producing property may be possible that may show the large recoverable reserves seen in the area.
The current intention is to perform the previously planned vertical and horizontal work programs for the license. In lieu of obtaining our own financing, we are actively enlisting joint venture partners to move the project forward by way of divesting part of our interest. Monthly the Company reviews the opportunity and balances the risk versus reward, which can be adjusted depending on cash flow, commodity prices and financing. When the stability of natural gas prices over a period of time that then translates into a netback on the Lucy prospect we will look to assign capital dollars to the project. Until then there is no expiry on the lease.
Manning Heavy Oil Project
See subsequent event notes
On March 17, 2011 Cougar has entered into a two phase farm-in agreement with TAMM Oil and Gas Corporation (TAMM) which will ultimately result in Cougar earning a 50% working interest in approximately 47 sections or 30,000 acres of heavy oil prospective lands in the Manning area. This is in the same area as the heavy oil farm-in agreement previously announced by the Corporation on February 14, 2011. TAMM originally acquired these lands in 2008 and has a previously prepared independent third party estimate of 3.14 billion barrels of original oil in place
for the prospect.
The Farm-in agreement has two earning phases which will allow Cougar to become the operator and earn a 50% working interest in the prospect. The first phase of the farm-in is a work commitment to earn a 30% working interest of the TAMM prospect. The work commitment will consist of Cougar spending $2.5 million over the next 12 months on a work program consisting of seismic and drilling evaluation, and independent third party geological and project feasibility studies. Cougar will also become the operator of the project area once the first phase is completed.
The second phase of the farm-in will allow Cougar to earn an additional 20% working interest of the TAMM prospect and includes a work commitment to spend an additional $6.5 million over a 24 month period following the first phase. The work program will consist of drilling, coring, feasibility studies and updates to reserve/resource estimates.
Cougar has also continued the preparation for the Manning area heavy oil farm-ins. The geological review has included core and log analysis and detailed geological mapping. Several drilling locations have been identified and the Corporation expects to begin the permitting process for these heavy oil prospects by the end of April.
Summary
The Company plans to develop and optimize its assets in Alberta and British Columbia. Due to the strength of the crude oil commodity prices Cougar will focus on the development of the crude oil properties over natural gas. A maintenance and development program has been prepared and will be implemented, as capital is available focusing on low risk work. The Company will also continue preparing for a planned two well drilling program and nine square mile seismic program in parallel to the maintenance programs.
Little Chicago - Northwest Territories
The Company is the operator and largest working interest owner of the 201,160 acre Exploration License 413 (“EL 413”) in the Mackenzie River Valley centered along the planned Mackenzie Valley Pipeline.
Upon review of the overall status of all projects in the area, current commodity prices being much below levels required to justify development on this and other projects, continued delay of the Mackenzie Valley Pipeline Project, the risk that any discovered gas reserves would be indefinitely stranded without such development, the Company continues to seek partnership in the development; however, the deteriorating economic factors make this difficult. We will still retain the confidential proprietary seismic data for future assessment of the "Little Chicago Prospect" and the Company will determine the best way to monetize that asset through either divestiture and/or possibly renominating the prospect when conditions are more appropriate. Recently the Government of Canada has approved the pipeline proposal - however the majority stakeholders in the pipeline have not committed to construction and have advised that they will not make that commitment either way until 2014.
UNITED STATES
New Mexico
Through its acquisition of Thunder, the Company acquired a 100% interest in 55,000 acres of property located in northeast New Mexico. Additional land acquisitions have increased the Company’s land position to approximately 79,000 acres. These lands have potential for natural gas and CO2 and oil and helium resources at shallow depths.
Due to lower commodity prices for Permian Basin oil (the primary market for CO2) and CO2 contract prices (deliverable into the Denver City Hub), aggressive development is not financeable at this time. Aside from ongoing maintenance of leases and wells, the Company is focusing its efforts on updating engineering models, and business opportunities so that when prices recover and investment markets improve, we will have the opportunity to move this project forward. The leases are 10 year leases and no expiries are imminent. A budget of $500,000 CAD would be required to move this project to the next stage in order to further define the reserves and the potential deliverability of those reserves in order to add definition to the engineering and economical prospect.
Kodiak has entered into a Farmout Agreement with a private company to develop the deeper rights of Kodiak’s approximate 30,000 gross acres of oil and gas rights in NE New Mexico. Kodiak retains the rights to the CO2 and Helium. The transaction anticipates additional seismic work and/or drilling of a number of wells on the Farmout acreage or before June 1, 2011. The Farmee will earn 100% of pre-selected, semi-contiguous 6-section blocks for each 2000’ well drilled until their continuous option or right to earn ceases. Farmor will retain a convertible overriding royalty of 7.5% on Helium and 5% on balance of rights (no deductions) on the test well blocks and a 25% potential working interest in an Area of Mutual Interest opportunity. There is a provision for a drop fee in the event of default on the part of the Farmee.
FINANCIAL INFORMATION
Financial Condition and Changes in Financial Condition:
The Company’s total assets have decreased to $29,515,286 as at December 31, 2010 from $31,657,559 as at December 31, 2009. This 2010 decrease is the result of write-downs of its unproved properties of approximately $4,365,315, net with additional acquisitions of oil and gas properties. Total assets consist of cash and other current assets of $750,245 (December 31, 2009 - $557,355) and other assets of $313,247 (December 31, 2009 - $296,153).
The Company has included in oil and gas properties evaluated and unevaluated properties. Evaluated properties net of accumulated depreciation, depletion and amortization was $5,772,328 (December 31, 2009 - $4,657,403). Unevaluated properties decreased to $22,622,246 from $26,081,786 on December 31, 2009. The major difference is the write-off of assets of $4,144,000 relating to expired leases.
The Corporation reports its reserves in the United States based on a “constant pricing and cost assumptions” model to meet US GAAP requirements and the values shown in that portion of the GLJ report and the resultant differences are due to those base assumptions.
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as filed in the US, as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.
Other assets of $313,247 remained as of December 31, 2010 (December 31, 2009 - $296,153).
Our total current liabilities were $5,607,308 (December 31, 2009 - $4,451,528) and consisted of accounts payable and accrued liabilities relating to capital activities and general and administrative costs incurred. Also included in current liabilities were notes payable of $Nil (December 31, 2009 - $1,364,036), Operating line of credit of $2,035,994 (December 31, 2009 - $Nil) and Current portion of long term debt of $839,060 (December 31, 2009 - $538,831).
We had long term liabilities of $2,769,965 (December 31, 2009 - $3,400,489). This decrease was primarily due payments against our long term debt. Asset retirement obligations of $1,471,808 (December 31, 2009 - $1,285,614) were recorded at year end. The increase is a result of the acquisitions and the company’s transfer of assets from unevaluated to evaluated.
Shareholders’ equity amounted to $19,666,205 (December 31, 2009 - $22,519,928), net of an accumulated deficit of $35,237,407 (2009 - $28,283,170) and comprehensive loss of $256,401 (December 31, 2009 - $416,905). Non controlling interest was $411,430 (December 31, 2009 - $258,127).
Overall Operating Results (All dollar values are expressed in United States dollars unless otherwise stated)
In 2010, the Company had revenue during the year of $3,112,225 (2009 - $607,469) and operating costs of $1,556,974 (2009 - $418,218) relating to start up of production from its Trout, Alberta project in the fourth quarter of 2009. The Company has now moved from an exploratory stage to a production company.
Net Loss for the year ended December 31, 2010 totaled $6,954,237 (2009 - $19,573,082). These losses include general and administrative expenses of $2,856,086 (2009 - $2,219,441) which includes stock-based compensation expense amounting to $856,121 (2009 - $774,199); net loss (non cash) on settlement of debt of $522,171 (2009 - $Nil); interest expense of $346,548 (2009 - $106,612); depletion depreciation and accretion including ceiling test impairment write-downs of $ 5,536,041 (2009 - $18,317,295) and deferred income tax recoveries of $NIL - (2009 - $Nil).
General and administrative expenses include the cost of consulting personnel and others who provided investor relations services, public company costs for SEC reporting compliance, accounting, audit and legal fees and other general and administrative office expenses. General and administrative expense also includes stock-based compensation relating to the cost of stock options granted to directors, officers and other personnel of $856,121 in 2010 (2009 - $774,199). General and administrative costs have been increasing, as the scope of the company’s activities have increased, and we believe substantial amounts will continue to be spent on such costs in the near term as we progress with the evaluation of our oil and gas prospects. A significant increase in our shareholder base from 7,000 to approximately 12,000 shareholders during the past year has also contributed to our increased general and administrative costs.
Interest expense for the year ended December 31, 2010 was $346,548 (2009 - $106,612).
Depletion, depreciation and accretion including ceiling test impairment write-downs includes the cost of depletion and depreciation relating to production from producing properties in 2009, ceiling test impairment write-downs and the cost of depreciation relating to office furniture and equipment. Costs attributable to certain Canadian cost center properties were determined to be unsupportable and, as a result, ceiling test write-downs of $221,315 for December 31, 2010 (2009 - $18,168,878) relating to the Company’s Canadian cost center were recorded and included in this expense. Costs attributable to certain United States cost center properties were determined to be unsupportable and, as a result, ceiling test write-downs of $4,144,000 for 2010 (2009 - $498,867) relating to the Company’s United States cost center were recorded and included in this expense. The remaining capitalized costs relating to Canadian and United States unproven properties have been excluded from the depletable cost pools for ceiling test purposes.
Quarterly Information
In the fourth quarter of 2010, Kodiak began economic production on its evaluated proven assets. The following table show selected quarterly information for this production. As this was the first quarter of production, there are no comparisons for prior quarters or years.
2010:
2009:
Capital Expenditures
Capital Expenditures incurred by the Company during the years ended December 31, 2010 and 2009 are set out below.
Property and Equipment
Property and equipment is recorded at cost. Depreciation of assets is provided by use of a declining balance method over the estimated useful lives of the related assets. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred.
Liquidity and Capital Resources
Since inception to December 31, 2010, the Company’s operations have been financed from the sale of securities and loans from shareholders. Working capital deficiency increased from $3,894,173 as at December 31, 2009 to a working capital deficiency of $4,857,063 at December 31, 2010. Of the total deficiency, $2,035,994 (December 31, 2009 - $Nil) is an operating line of credit and $839,060 (December 31, 2009 - $538,831) is the current portion of long term debt. As at December 31, 2010, the Company was not in breach or default of any covenants or terms of any credit or lending agreements.
During 2009, the Company raised $1,278,349 in private placement financing proceeds in Cougar Energy, Inc. These financings enabled Cougar Energy to finance ongoing capital expenditures and general and administrative expenses.
During 2009, the Company received $1,350,000 CAD by way of a bridge loan at an interest rate of 12% per annum and issuance of 383,188 restricted common shares of Kodiak based on the 10 day weighted average at market close price on September 25, 2009, less 10% discount to market. Proceeds were advanced to its subsidiary, Cougar Energy, to fund the down payment for the acquisition of September 30, 2009. This loan was assumed by a non related third party in December of 2009 and subsequently in 2010 converted to equity.
During the year ended December 31, 2010, the Company reached formal agreement with a Canadian bank for credit facilities. The credit facility is a revolving demand loan facility in the amount of Cdn$2,500,000 bearing an interest at prime plus 3.5% per annum. Under the terms of the Agreement, the credit facility is committed for the development of existing proved non-producing/undeveloped petroleum and natural gas reserves. As at December 31, 2010, U.S$2,035,994 of the revolving line was drawn.
The Company advanced $900,000 to Cougar Oil and Gas Canada, Inc. and received an 18 months unsecured convertible note from Cougar on January 31, 2011 in the same amount with an interest rate of prime plus 3% per annum. Kodiak will also receive a 1% gross over-riding royalty on two wells that the funds are intended to finance. The note is convertible into common shares of the Company at a price of $3.52 per share.
During February 2011, the Cougar Oil and Gas Canada, Inc received the initial draw down of 950,000 Swiss Francs ($985,388 CDN) on an unsecured note agreement with a maximum issuance of 4,700,000 Swiss Francs (approximately $5,000,000 CDN), subject to certain conditions. The note has a term of 18 months and accrues interest at the rate of Bank of Canada prime plus 3% per annum. The holder of the note, Zentrum Energie Trust SA, has the option to convert the balance of the note plus accrued interest into common shares of Cougar at the rate of $3.00 per common share along with a warrant to purchase additional common shares on a 1:1 basis for a period of 4 years at a price of $3.90 per common share.
The Company is in the process of raising additional financing in its Cougar Energy, Inc. subsidiary that will provide financing to carry out its business plan through 2011. See Subsequent Event Note 19 to the consolidated financial statements. Such additional financing will be required for the company’s 2011 planned activities. No assurances can be given that the Company will be able to raise additional financing or, if offered terms for financing, they will be on accepted terms. In the event that additional capital is raised at some time in the future, existing shareholders will experience dilution of their interest in the Company, or the Company’s interest in the subsidiary.
Our independent registered public accountants have stated in their report dated April 13, 2011 that we have incurred operating losses since inception, and that we are dependent upon management's ability to develop profitable operations and/or obtain necessary funding from outside sources, including by the sale of our securities, or obtaining loans from financial institutions, where possible. These factors, among others, may raise substantial doubt about our ability to continue as a going concern. The report may cause difficulty in raising future financings.
2010:
2009:
2010:
2009:
2010:
2009:
2010:
2009:
2010:
2009:
2010:
2009:
2010:
2009:
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from changes in petroleum and natural gas and related hydrocarbon prices, foreign currency exchange rates and interest rates.
PETROLEUM AND NATURAL GAS AND RELATED HYDROCARBON PRICES
The Company’s oil and gas business makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices. Declines in oil and gas prices reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves). Declines in oil and gas prices can reduce the value of our oil and gas properties and increase impairment expense, as occurred in 2009.
We expect oil and gas price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.
OPERATING COST RISK
During 2009 and 2010, we have generally experienced fluctuations in operating costs (including costs of drilling and completing wells) which impact our cash flow from operating activities and profitability. We expect our drilling activity in 2011 to be focused on drilling oil wells. Several other companies seek to drill similar wells in the general area in 2011 whereby drilling and operating costs may rise in response to demand for limited rigs and services in the area.
Fluctuations in drilling costs and production costs, as well as fluctuations in oil and gas prices can have a significant impact on our profitability and may be deciding factors on how many wells we will drill in a given project or even if severe shut in production to control overall costs.
FOREIGN CURRENCY EXCHANGE RATES
The Company, operating in both the United States and Canada, faces exposure to adverse movements in foreign currency exchange rates. These exposures may change over time as business practices evolve and could materially impact the Company’s financial results in the future. To the extent revenues and expenditures denominated in other currencies vary from their U. S. dollar equivalents, the Company is exposed to exchange rate risk. The Company can also be exposed to the extent revenues in one currency do not equal expenditures in the same currency. The Company is not currently using exchange rate derivatives to manage exchange rate risks.
INTEREST RATES
The Company’s interest income and interest expense, in part, is sensitive to the general level of interest rates in North America. The Company is not currently using interest rate derivatives to manage interest rate risks.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
KODIAK ENERGY, INC
RBSM LLP
CERTIFIED PUBLIC ACCOUNTANTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Kodiak Energy, Inc.
Alberta, Canada
We have audited the accompanying consolidated balance sheet of Kodiak Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and the related consolidated statements of operations and comprehensive loss, stockholders’ equity, and cash flows for the year ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based upon our audit.
We have conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audit provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kodiak Energy, Inc. at December 31, 2010 and the results of its operations and its cash flows for the year ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2, the Company has incurred operating losses and has a working capital deficiency. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/S/ RBSM LLP
New York, New York
April 13, 2011
MEYERS NORRIS PENNY LLP
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
OPINION ON THE AUDIT OF THE FINANCIAL STATEMENTS
To the Board of Directors and the Stockholders of
Kodiak Energy, Inc.
We have audited the accompanying consolidated balance sheets of Kodiak Energy, Inc. (the “Company and subsidiaries”) as of December 31, 2009 and the consolidated statements of operations, stockholder’s equity and cash flows for the year ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluation of the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2009 and the results of its operations and its cash flows for the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company’s ability to continue as a going concern is dependent on obtaining sufficient working capital to fund future operations. Management’s plan in regard to these matters is also described in Note 2. These financial statements do not include any adjustments that might result from the outcome of this uncertainty.
As discussed in Note 1 to the consolidated financial statement, the Company and subsidiaries have changed their reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements as of December 31, 2009.
/s/ MEYERS NORRIS PENNY LLP
Chartered Accountants
Calgary, Canada
March 19, 2010
The accompanying notes are an integral part of these consolidated financial statements
The accompanying notes are an integral part of these consolidated financial statements
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies applied in the presentation of the accompanying financial statements follows:
Basis and Presentation
The accompanying consolidated financial statements include the accounts of Kodiak Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us” or “our”). The Company was incorporated under the laws of the state of Delaware on December 15, 1999 under the name “Island Critical Care, Corp.” On December 30, 2004 the name was changed to “Kodiak Energy, Inc”. During the year ended December 31, 2009, the Company transitioned from a development stage enterprise to an operating company. The Company’s principal activity is in the exploration, development, production and sale of oil and natural gas.
The consolidated financial statements include the accounts of the Company, three wholly-owned subsidiaries: Kodiak Petroleum ULC (“KULC”), an inactive Alberta company; Kodiak Petroleum (Montana), Inc. (“KPMI”), a Delaware company that operates Kodiak’s projects in New Mexico and Montana; and Kodiak Petroleum (Utah), Inc. (“KPUI”), an inactive Delaware company; and one majority- owned subsidiary, Cougar Oil and Gas Canada Inc. In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All significant inter-company transactions have been eliminated in consolidation.
Reverse Acquisition
In January 2010, Cougar Oil and Gas Canada ("COG"), formerly Ore-More Resources, Inc. entered into a stock purchase Agreement (the “Agreement”) with Cougar Energy, Inc, a majority-owned subsidiary of the Company (which we refer to as CEI) and CEI’s then shareholders whereby COG agreed to acquire the entire issued and outstanding shares of the common stock of CEI in two stages:
a) On January 20, 2010, COG finalized stock purchase agreements effective January 18, 2010 by and between COG and Zentrum Energie Trust AG, CAT Brokerage AG, LB (Swiss) Private Bank for its client, Mauschen Finanz Inc. and Rahn and Bodmer (collectively the “Vendors”), whereby COG purchased from the Vendors shares and warrants of the common stock of CEI held by the Vendors. The Vendors tendered a total of 884,616 common shares of CEI and 884,616 warrants granting the right to the holder, which would be COG pursuant to the transfer, to purchase an additional 884,616 common shares of CEI on or before December 4, 2011. As consideration for the common shares and warrants of CEI tendered by the Vendors, COG issued a total of 3,980,775 shares of its common stock to the Vendors and an equal number of warrants, entitling the holders to exercise a total of 5,348,085 warrants. The warrants have the following exercise prices and expiry dates:
·
1,246,155 warrants to purchase common shares exercisable at $0.288 per common share and expiring on March 4, 2011.
·
2,025,000 warrants to purchase common shares exercisable at $0.288 per common share and expiring on October 31, 2011.
·
2,076,930 warrants to purchase common shares exercisable at $0.577 per common share and expiring on December 4, 2011.
The shares and warrants were exchanged during the week ended January 30, 2010.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
b) On January 25, 2010, COG finalized a share purchase agreement between COG and the Company whereby COG purchased from the Company a total of 8,461,549 shares of the common shares of CEI held by the Company. The share purchase agreement called for COG to issue a total of 1.5 shares of its common stock for each share of CEI tendered by the Company, resulting in COG issuing a total of 12,692,324 shares of common stock. As further consideration for the acquisition of the CEI common shares, COG forgave all current indebtedness owed to COG by the Company and guaranteed by CEI, which was in the amount of $1,296,888. An additional condition to the agreement was that a total of 12,000,000 restricted common shares of Ore-More Resources, Inc were cancelled.
Upon consummation of the acquisition, CEI became the only wholly-owned subsidiary of COG. Subsequently, on February 4, 2010, Ore-More Resources, Inc filed a Certificate of Amendment to its Certificate of Incorporation with the Registrar of Corporations in Alberta, Canada, changing the Company’s name to “Cougar Oil and Gas Canada, Inc.”.
The acquisition is accounted for as a “reverse acquisition”, since the stockholders of CEI owned a majority of COG’s common stock immediately following the transaction and their management has assumed operational, management and governance control. The reverse acquisition transaction is recorded as a recapitalization of CEI, pursuant to which CEI is treated as the surviving and continuing entity although Ore-More Resources, Inc is the legal acquirer, rather than a business combination. Cougar Oil and Gas Canada did not recognize goodwill or any intangible assets in connection with this transaction. Accordingly, the Company’s historical consolidated financial statements include those of CEI from its date of inception on November 21, 2008.
Functional currency
The reporting currency of the Company is the United States dollar, while the functional currency is the Canadian dollar. When a transaction is executed in a foreign currency, it is re-measured into Canadian dollars based on appropriate rates of exchange in effect at the time of the transaction. At each balance sheet date, all recorded balances are adjusted to the reporting currency of the Company to reflect the current exchange rate. The resulting foreign currency transactions gains (losses) are included in general and administrative expenses in the accompanying consolidated statements of operations.
The cumulative translation adjustments are included in accumulated other comprehensive loss in the equity section of the consolidated balance sheet.
Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of unproved properties, future taxable income and related assets/liabilities, the collectability of outstanding accounts receivable, stock-based compensation expense, contingencies and the results of current and future litigation.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
Oil and natural gas reserve estimates which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, the creditworthiness of counterparties, interest rates, the market value of the Company’s common stock and corresponding volatility and the Company’s ability to generate future taxable income. Future changes in these assumptions may affect these significant estimates materially in the near term. The Company has also evaluated subsequent events for recording and disclosures, including assumptions used in its estimates.
Reclassification
Certain reclassifications have been made to prior periods’ data to conform to the current year’s presentation. These reclassifications had no effect on reported income or losses.
Revenue Recognition
The Company uses the sales method of accounting for the recognition of natural gas and oil revenues. The Company is the operator on all of its properties. The Company has an agreement with the marketers of our product to sell, on its behalf, production from the properties for which it has working interest ownership. Since there is a ready market for natural gas, crude oil and natural gas liquids (“NGLs”), production is sold at various locations at which time title and risk of loss pass to the marketer.
The Company records its share of revenues based on sales volumes and contracted sales prices. The sales price for natural gas, natural gas liquids and crude oil are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. Historically, these adjustments have been insignificant. In addition, natural gas and crude oil volumes sold are not significantly different from the Company’s share of production.
The Company receives its share of revenue after all calculated crown royalties are paid on natural gas, crude oil and NGLs in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements. Private royalties are accrued and paid upon receipt of payment.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
Cash and Cash Equivalents, and Concentrations of Credit Risk
Cash and cash equivalents represent cash in banks. The Company considers any highly liquid debt instruments purchased with a maturity date of three months or less to be cash equivalents. The Company’s accounts receivable are concentrated among entities engaged in the energy industry, within Canada and the United States. Financial instruments and related items, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, cash equivalents and receivables. The Company places its cash and temporary cash investments with credit quality institutions. At times, such investments may be in excess of the Canada Deposit Insurance Corporation or Federal Deposit Insurance Corporation's insurance limit.
Furniture and Fixtures
Furniture and fixtures are recorded at cost and depreciated on both straight-line and declining balance basis over estimated useful lives of five years. Repair and maintenance costs are charged to expense as incurred while acquisitions are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of property, plant and equipment are recorded in the period incurred. The net book value of the property, plant and equipment that is retired or sold is charged to accumulated depreciation and amortization, and the difference is recognized as a gain or loss in the results of operations in the period the retirement or sale transpires.
Segment Information
The Company applies Accounting Standards Codification subtopic Segment Reporting 280-10 (“ASC 280-10”). ASC 280-10 establishes standards for reporting information regarding operating segments in annual consolidated financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. ASC 280-10 also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision making group, in making decisions how to allocate resources and assess performance. The information disclosed herein, materially represents all of the financial information related to the Company's principal operating segments.
Impairment of long lived assets
The Company applies Accounting Standards Codification subtopic 360-10, Property, Plant and Equipment (“ASC 360-10”). The Statement requires that long-lived assets and certain identifiable intangibles held and used by the Company be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Events relating to recoverability may include significant unfavorable changes in business conditions, recurring losses, or a forecasted inability to achieve break-even operating results over an extended period. The Company evaluates the recoverability of long-lived assets based upon forecasted undiscounted cash flows. Should impairment in value be indicated, the carrying value of intangible assets will be adjusted, based on estimates of future discounted cash flows resulting from the use and ultimate disposition of the asset. ASC 360-10 also requires assets to be disposed of is reported at the lower of the carrying amount or the fair value less costs to sell.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
Oil and Gas Properties
The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of properties within a relatively large geopolitical cost center in our case, by country, and are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs designated as unproven properties are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration and development activities. The Company has not capitalized any internal costs or interest at December 31, 2010 and 2009. Unevaluated and undeveloped costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.
Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable country cost center. The Company has assessed the impairment for oil and natural gas properties for the full cost pool at December 31, 2010 and 2009 and will assess quarterly thereafter using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes is compared to (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues is based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test takes into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price is consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities since inception through December 31, 2010. Application of the ceiling test is required for reporting purposes, and any write-downs are not reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
Reserves
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. Under the SEC’s final rule, prior period reserves were not restated. The Company has used this guidance in reporting reserve information.
Fair Values
The Company applies Accounting Standards Codification subtopic 820-10, Fair Value Measurements and Disclosures (“ASC 820-10”). ASC 820-10 defines fair value, establishes a framework for measuring fair value, and enhances fair value measurement disclosure. ASC 820-10 delayed, until the first quarter of fiscal year 2009, the effective date for ASC 820-10 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of ASC 820-10 did not have a material impact on the Company’s financial position or operations. Refer to Note 13 for further discussion regarding fair valuation.
Comprehensive Income (Loss)
The Company applies Statement of Accounting Standards Codification subtopic 220-10, Comprehensive Income (“ASC 220-10”). ASC 220-10 establishes standards for the reporting and displaying of comprehensive income and its components. Comprehensive income is defined as the change in equity of a business during a period from transactions and other events and circumstances from non-owners sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. ASC 220-10 requires other comprehensive income (loss) to include foreign currency translation adjustments and unrealized gains and losses on available for sale securities.
Net Loss per Share
The Company applies Accounting Standards Codification subtopic 260-10, Earnings Per Share (“ASC 260-10”) specifying the computation, presentation and disclosure requirements of earnings per share information. Basic loss per share has been calculated based upon the weighted average number of common shares outstanding. Stock options and warrants have been excluded as common stock equivalents in the diluted loss per share because their effect is anti-dilutive on the computation.
Stock based compensation
The Company follows Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”) which requires that all share-based payments to both employees and non-employees be recognized in the income statement based on their fair values. The fair value of share-based compensation to employees will be determined using an option pricing model at the time of grant. Fair value for common shares issued for goods or services rendered by non-employees are measured based on the fair value of the goods or services received. Stock-based compensation expense is included in general and administrative expense with a corresponding increase to Additional Paid in Capital. Upon the exercise of the stock options, consideration paid together with the previously recognized Additional Paid in Capital is recorded as an increase in share capital.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
Asset Retirement Obligations
The Company recognizes a liability for asset retirement obligations in the period in which they are incurred and in which a reasonable estimate of such costs can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites. The asset retirement obligation is measured at fair value and recorded as a liability and capitalized as part of the cost of the related long-lived asset as an asset retirement cost. The asset retirement obligation accretes until the time the asset retirement obligation is expected to settle while the asset retirement costs included in oil and gas properties are amortized using the unit-of-production method.
Amortization of asset retirement costs and accretion of the asset retirement obligation are included in depletion, depreciation and accretion. Actual asset retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligations and the actual retirement costs incurred is recorded in depletion, depreciation and accretion.
Environmental
Oil and gas activities are subject to extensive federal, provincial, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated
Income Taxes
The Company applies Accounting Standards Codification subtopic 740-10, Income Taxes (“ASC 740-10”) which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The adoption of ASC 740-10 did not have a material impact on the Company’s consolidated results of operations or financial condition. Please refer to Note 18.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
Flow-through Shares
From time to time the Company finances a portion of its Canadian exploration programs with flow-through common shares issued pursuant to certain provisions of the Income Tax Act (Canada) (the “Act”). Under the Act, where the proceeds are used for eligible expenditures, the related income tax deductions may be renounced to subscribers. Accordingly, the tax credits associated with the renunciation of such expenditures are recorded as an increase to deferred income tax liabilities. Any premium received from subscribers on the sale of such flow-through common shares is recorded initially as a current liability and then discharged and recognized as a reduction of deferred income taxes when the flow-through eligible expenditures relating to the flow-through premium are incurred by the Company.
Non-controlling Interests
We adopted the accounting standard for non-controlling interests in the consolidated financial statements as of January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. This standard also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the non-controlling owner.
Accounting for Changes in Ownership Interests in Subsidiaries
The Company’s ownership interest in a consolidated subsidiary may change if it sells a portion of its interest, or if the subsidiary issues or re-purchases its own shares. If the transaction does not result in a change in control over the subsidiary and it is not deemed to be a sale of real estate, the transaction is accounted for as an equity transaction. If the transaction results in a change in control it would result in the deconsolidation of a subsidiary with a gain or loss recognized in the statement of operations. During 2010 the Company’s ownership interest in Cougar Energy Inc. changed which were accounted for as equity transactions. See Note 11 Non-Controlling Interest for a description of the transactions and the impact to the financial statements.
Accounting for Sales of Stock by a Subsidiary
The Company's majority owned subsidiary issued common shares in various transactions, which resulted in a dilution of the Corporation's percentage ownership in the Subsidiary. The Company accounted for the sale of the Subsidiary common shares in accordance with guidance related to equity transactions. The guidance allows for the election of an accounting policy of recording such increase or decreases in a parent's investment either in income or in equity. The Corporation adopted a policy of recording such gains or losses directly to additional paid in capital.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)
Recent Accounting Pronouncements
In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. This ASU updates ASC Topic 350, Intangibles-Goodwill and Other, to amend the criteria for performing Step 2 of the goodwill impairment test for reporting units with zero or negative carrying amounts and requires performing Step 2 if qualitative factors indicate that it is more likely than not that a goodwill impairment exists. The ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. The Company does not currently have any reporting units with zero or negative carrying values.
In July 2010, the FASB issued Accounting Standards Update 2010-20 which amend “Receivables” (Topic 310). ASU 2010-20 is intended to provide additional information to assist financial statement users in assessing an entity’s risk exposures and evaluating the adequacy of its allowance for credit losses. The disclosures as of the end of a reporting period are effective for interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The amendments in ASU 2010-20 encourage, but do not require, comparative disclosures for earlier reporting periods that ended before initial adoption. However, an entity should provide comparative disclosures for those reporting periods ending after initial adoption. The Company does not expect to have a significant impact on its financial statements with the adoption of ASU 2010-20.
There were various other updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's consolidated financial position, results of operations or cash flows.
NOTE 2 - GOING CONCERN MATTERS
These consolidated financial statements have been prepared assuming the Company will continue as a going concern, which presumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has not generated positive cash flow since inception and has incurred operating losses and will need additional working capital for its future planned activities. The success of these programs is yet to be determined. These conditions raise doubt about the Company’s ability to continue as a going concern. Continuation of the Company as a going concern is dependent upon obtaining sufficient working capital to finance ongoing operations. The Company’s strategy to address this uncertainty includes additional equity and debt financing; however, there are no assurances that any such financings can be obtained on favorable terms, if at all. These financial statements do not reflect the adjustments or reclassification of assets and liabilities that would be necessary if the Company were unable to continue its operations.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 3 - OIL AND GAS PROPERTIES
Major classes of oil and gas properties under the full cost method of accounting at December 31, 2010 and 2009 consist of the following:
Unevaluated and Unproved Properties
The Company has certain unevaluated and unproved properties, valued at cost, that have been excluded from costs subject to depletion. These costs amounting to $22,622,246 and $26,081,786 as at December 31, 2010 and 2009, respectively, are subject to a test for impairment which is separate from the test applied to proved properties.
During the year ended December 31, 2010 certain unproved properties in the United States were returned due to other business opportunities. These properties were removed from undeveloped properties at their carrying value of $4,144,000 and have been included in depletion and depreciation the statement of operations.
Full Cost Accounting Ceiling Test on Canadian Proved Oil and Gas Properties
Quarterly, the Company assesses the value of unamortized capitalized costs within its cost center over the discounted present value of cash flows associated with its reserves. Any excess requires an immediate write-down of its capital costs by this amount, under the full cost ceiling test.
At December 31, 2010, a ceiling test was performed on the Company's properties subject to depletion. Costs of unproved properties aggregating $22,622,246 and future abandonment costs of $307,000 have been excluded from this test. This test disclosed that the carrying costs of the Company's depletable Canadian properties did not exceed their net present value and consequently no ceiling write-down was required.
Included in the Company’s oil and gas properties are asset retirement obligations of $1,306,481 and $1,219,785, comprising both current and long term items as of December 31, 2010 and 2009, respectively.
NOTE 4 - ACCOUNTS RECEIVABLE
Accounts receivable consist of the following:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 5 - OTHER ASSETS
Other assets represent long term deposits required by governmental regulatory authorities for environmental obligations relating to well abandonment and site restoration activities.
NOTE 6 - OPERATING LINE OF CREDIT
During the year ended December 31, 2010 the Company reached formal agreement with a Canadian bank for credit facilities. The credit facility is a revolving demand loan facility in the amount of Cdn$2,500,000 bearing an interest at prime plus 3.5% per annum. Under the terms of the Agreement, the credit facility is committed for the development of existing proved non-producing/undeveloped petroleum and natural gas reserves. As at December 31, 2010, U.S $2,035,994 of the revolving line was drawn.
NOTE 7- LONG TERM AND SHORT TERM LIABILITIES
The Company has the following liabilities:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 7- LONG TERM AND SHORT TERM LIABILITIES (continued)
The total amount due to the vendor of the Trout Core properties is payable in accordance with the following schedule:
The Company has the right to prepay the vendor loan in full, without penalty, semi-annually commencing March 31, 2010 at a proportionate discount to the original purchase price. The indebtedness is secured by a debenture covering a fixed and floating charge over Cougar's interest in the acquired properties.
During the year ended December 31, 2010, non cash interest of $261,443 was recorded as interest expense in relation to the discount on the vendor acquired indebtedness.
During the year ended December 31, 2010 the total amounts owing on the note payable at December 31, 2009 in the amount of $1,364,046, were extinguished as a result of the share exchange with Ore-More Resources, Inc as noted in Note 1.
NOTE 8- ASSET RETIREMENT OBLIGATIONS
The Company’s financial statements reflect the provisions of Accounting Standards Codification Subtopic 410-20, Asset Retirement Obligations (“ASC 410-20”). ASC 410-20 provides that, if the fair value for an asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by ASC 410-20, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties on the Consolidated Balance Sheet. Periodic accretion of discount of the estimated liability is recorded, as appropriate, as an expense in the Consolidated Statement of Operations and is included in depletion, depreciation and accretion. The Company’s asset retirement obligations relate to the all wells. The Company has recognized an asset retirement liability of $1,471,808 and $1,285,614 at December 31, 2010 and 2009, respectively.
At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $3,227,980 (December 31, 2009 - $3,033,143). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 14 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 7.5% and a rate of inflation of 2.5%.
Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and natural gas properties are as follows:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION
The Company has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 8,000,000 of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable equally over the first three years of the term of the option.
Significant option groups outstanding at December 31, 2010 and 2009 and related weighted average price and life information as follow:
Transactions involving options issued to employees are summarized as follows:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)
During the year ended December 31, 2010, the Company granted 300,000 options to purchase the Company's common stock at $0.19 per share expiring five years from the date of issuance. The options vest over three years at the anniversary of the date of issuance. The fair value was determined using the Black Scholes Option pricing model with the following assumptions: Dividend yield-0%, risk free interest rate: 2.56%; volatility: 139%; expected term: 5 years.
Cougar Oil and Gas Canada Stock Option Plan
Cougar Oil and Gas Canada has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 10% of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable equally over the first three years of the term of the option.
A summary of options granted and outstanding under the plan is as follows:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)
Transactions involving options issued to employees are summarized as follows:
During the year ended December 31, 2010, the Company granted an aggregate of 1,260,000 stock options with an exercise price from Cdn $1.40 to Cdn $2.92 per share expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:
Cougar Energy, Inc. Stock Option Plan
Cougar Energy, Inc. has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 10% of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable equally over the first three years of the term of the option.
A summary of options granted and outstanding under the plan is as follows
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)
Transactions involving options issued to employees are summarized as follows:
During the year ended December 31, 2010, the Company granted 60,000 additional options with an exercise price of Cdn $1.30 per share expiring five years from issuance. The fair value was determined using the Black-Sholes option pricing model with the following assumptions:
The fair value of all employee options vesting during the year ended December 31, 2010 and December 31, 2009 of $856,121 and $774,199, respectively, was charged to current period operations.
Subsequent to the period end, on January 1, 2011, Cougar Energy, Inc. merged with its parent, Cougar Oil and Gas Canada Inc. Both of the companies are Alberta corporations and were merged in a statutory amalgamation under Alberta corporate law. Upon that merger, and after giving effect to the Cougar Oil and Gas Canada/Cougar Energy Inc. share exchange at 1:1.5 and the subsequent 3:1 split of Cougar Canada Oil and Gas Canada Inc. shares, the 725,000 and 265,000 outstanding Cougar Energy, Inc stock options exercisable at $0.65 and $1.30 per share respectively shown above became 3,262,500 and 1,192,500 outstanding Cougar Oil and Gas Canada stock options exercisable at Cdn $0.144 and Cdn $.289 per share, respectively.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)
Kodiak Energy Inc. Warrants
During years ended December 31, 2006 and 2010, the Company, as part of certain private placement financings, issued warrants that are exercisable in common shares of the Company. A summary of such outstanding warrants follows:
In 2010, in connection with the settlement of debt, the Company issued an aggregate of 9,276,108 warrants with an exercise price of $0.50 per share expiring August 15, 2012. The fair value was determined using the Black-Sholes option pricing model with the following assumptions:
The determined fair value of the issued warrants of $308,425 was charged to loss on settlement of debt in the current period operations.
Cougar Oil and Gas Canada Warrants
Warrants
The following table summarizes in warrants outstanding and related prices for the shares of the Company’s common stock issued to shareholders at December 31, 2010:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)
Transactions involving the Company’s warrant issuance are summarized as follows:
NOTE 10- STOCKHOLDERS EQUITY
The Company is authorized to issue 10,000,000 and 300,000,000 shares of $0.001 par value preferred and common stock, respectively. As of December 31, 2010 and December 31, 2009, the Company had nil preferred shares issued and outstanding and 119,683,294 and 110,407,186 shares of common stock, respectively.
During the year ended December 31, 2010, the Company issued an aggregate of 9,276,108 shares of its common stock in settlement of outstanding debt and related accrued interest of $921,356. The excess of market value of the common stock over the carrying value of the debt and related interest of $287,299 was charged to loss on settlement of debt in the current period operations.
NOTE 11- NON CONTROLLING INTEREST
A reconciliation of the non controlling loss attributable to the Company:
Net loss Attributable to the Company and transfers (to) from non-controlling interest for the year ended December 31, 2010 and 2009:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 11- NON CONTROLLING INTEREST (continued)
The following table summarizes the changes in Non Controlling Interest from December 31, 2008 to December 31, 2010:
NOTE 12- LOSS PER SHARE
A reconciliation of the numerator and denominator of basic and diluted loss per share is provided as follows:
Basic loss per share is based on the weighted average number of shares outstanding during the periods. Diluted loss is per share is based on the weighted average number of shares and all dilutive potential shares outstanding during the periods. The Company had outstanding stock options and warrants as at December 31, 2010 and 2009, as disclosed in note 9 that were anti dilutive due to the net loss of those periods.
NOTE 13- COMMITMENTS AND CONTINGENCIES
Lease Commitments
As of December 31, 2010 and 2009, the Company had lease commitments for vehicles, office rent and office equipment. The following lease commitments for the years shown:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 13- COMMITMENTS AND CONTINGENCIES (continued)
Cougar Oil and Gas Canada, Inc..
The Company relocated its offices in December 2009 and pays rent of approximately $14,000 per month until the lease expires in February 2013. The remaining lease commitments pertain to two trucks and a number of office computers. Rent expense for the year ended December 31, 2010 and 2009 is $131,631 and $73,753, respectively.
Litigation
The Company is subject to other legal proceedings and claims, which arise in the ordinary course of its business. Although occasional adverse decisions or settlements may occur, the Company believes that the final disposition of such matters should not have a material adverse effect on its financial position, results of operations or liquidity. There was no outstanding litigation as of December 31, 2010.
NOTE 14- FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES
ASC 825-10 defines fair value as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required or permitted to be recorded at fair value, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the asset or liability, such as inherent risk, transfer restrictions, and risk of nonperformance. ASC 825-10 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. ASC 825-10 establishes three levels of inputs that may be used to measure fair value:
Level 1 - Quoted prices in active markets for identical assets or liabilities.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 14- FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES (continued)
Level 2 - Observable inputs other than Level 1 prices such as quoted prices for similar assets or liabilities; quoted prices in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which all significant inputs are observable or can be derived principally from or corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.
To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, for disclosure purposes, the level in the fair value hierarchy within which the fair value measurement is disclosed is determined based on the lowest level input that is significant to the fair value measurement.
The carrying amounts of financial instruments, which include cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued expenses, other current liabilities, revolving credit facility and debt approximate their fair values due to their short maturities and variable interest rate on the revolving credit facility and fixed rates which approximate market rates on notes payable.
NOTE 15- RELATED PARTY TRANSACTIONS
For the year ended December 31, 2010, the Company paid $Nil (December 31, 2009 - $24,107), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services. Of this amount, $nil (December 31, 2009 - $6,910) was capitalized to Unproved Oil and Gas Properties and $nil (December 31, 2009 -$17,197) was charged to General and Administrative Expense.
For the year ended December 31, 2010 and 2009, the Company incurred $48,058 (December 31, 2009 - $124,353) to Director and the former Chief Financial Officer. $9,132 was payable at December 31, 2010. The Company incurred $116,160 to a Company owned and controlled by the chairman of the Company for management consulting services. $21,114 was payable on December 31, 2010. The Company incurred expenses of the wife of the chairman of the Company of $25,871 for administration consulting services. A total of $5,321 was outstanding on December 31, 2010. These amounts were charged to General and Administrative Expense.
These related party transactions were non arm's length transactions in the normal course of business and agreed to by the related parties and the Company based on negotiations and Board approval and accordingly had been measured at the exchange amounts.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 16- SEGMENTED INFORMATION
The Company’s two geographical segments are the United States and Canada. Both segments use accounting policies that are identical to those used in the consolidated financial statements. The Company’s geographical segmented information is as follows:
NOTE 17- CHANGES IN NON-CASH WORKING CAPITAL
NOTE 18- INCOME TAXES
As at December 31, 2010, the Company's deferred tax asset is attributable to its net operating loss carry forward of approximately $11,176,000 (December 31, 2009 - $9,530,000; December 31, 2008 - $2,802,000) and will expire if not utilized in the years from 2025 to 2031. As reflected below, this benefit has been fully offset by a valuation allowance based on management's determination that it is not more likely than not that some or all of this benefit will be realized.
For the years ended December 31, 2010 and 2009, a reconciliation of the income tax benefit at the U.S. federal statutory rate to the income tax benefit at the Company's effective tax rates is as follows:
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 18- INCOME TAXES (continued)
Deferred tax assets (liabilities) at December 31, 2010 and December 31, 2009 are comprised of the following:
The valuation allowance of $10,627,000 (December 31, 2009 - $8,282,000) includes $375,000 (December 31, 2009 - $1,806,000) relating to currency revaluation adjustments that have not been charged to expense but are included in comprehensive loss in shareholders' equity.
Per Accounting Standards codification subtopic 740-10 (“ASC 740-10”) - “Accounting for Uncertainty in Income Taxes”, under the asset and liability method, it is the Company’s policy to provide for uncertain tax positions and the related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At December 31, 2010, the Company believes it has appropriately accounted for any unrecognized tax benefits. To the extent the Company prevails in matters for which a liability for an unrecognized benefit is established or is required to pay amounts in excess of the liability, the Company’s effective tax rate in a given financial statement period may be affected. Interest and penalties associated with the Company’s tax positions are recorded as Interest Expense.
NOTE 19- SUBSEQUENT EVENTS
On January 1, 2011, Cougar Oil and Gas Canada, Inc. was amalgamated with its wholly owned subsidiary, Cougar Energy, Inc. As a result of the amalgamation, the Company, which will continue under the name Cougar Oil and Gas Canada, Inc., has changed its financial reporting year end to December 31st.
KODIAK ENERGY, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 19- SUBSEQUENT EVENTS (continued)
The Company advanced $900,000 to Cougar Oil and Gas Canada, Inc. and received an 18 months unsecured convertible note from Cougar on January 31, 2011 in the same amount with an interest rate of prime plus 3% per annum. Kodiak will also receive a 1% gross over-riding royalty on two wells that the funds are intended to finance. The note is convertible into common shares of the Company at a price of $3.52 per share.
During February 2011, the Cougar Oil and Gas Canada, Inc received the initial draw down of 950,000 Swiss Francs ($1,009,755) on an unsecured note agreement with a maximum issuance of 4,700,000 Swiss Francs (approximately $4,995,630), subject to certain conditions. The note has a term of 18 months and accrues interest at the rate of Bank of Canada prime plus 3% per annum. The holder of the note, Zentrum Energie Trust SA, has the option to convert the balance of the note plus accrued interest into common shares of Cougar at the rate of $3.00 per common share along with a warrant to purchase additional common shares on a 1:1 basis for a period of 4 years at a price of $3.90 per common share.
On March 17, 2011 Cougar Oil and Gas Canada, Inc entered into a two phase farm-in agreement with TAMM Oil and Gas Corporation (TAMM) which will ultimately result in Cougar earning a 50% working interest in approximately 47 sections or 30,000 acres of heavy oil prospective lands in the Manning area. This is in the same area as the heavy oil farm-in agreement previously announced by the Corporation on February 14, 2011. TAMM originally acquired these lands in 2008 and has a previously prepared independent third party estimate of 3.14 billion barrels of original oil in place for the prospect.
The Farm-in agreement has two earning phases which will allow Cougar to become the operator and earn a 50% working interest in the prospect. The first phase of the farm-in is a work commitment to earn a 30% working interest of the TAMM prospect. The work commitment will consist of Cougar spending $2.5 million over the next 12 months on a work program consisting of seismic and drilling evaluation, and independent third party geological and project feasibility studies. Cougar will also become the operator of the project area once the first phase is completed.
The second phase of the farm-in will allow Cougar to earn an additional 20% working interest of the TAMM prospect and includes a work commitment to spend an additional $6.5 million over a 24 month period following the first phase. The work program will consist of drilling, coring, feasibility studies and updates to reserve/resource estimates.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Previous independent registered public accounting firm
On October 29, 2010, the Company notified Meyers Norris Penny LLP (“Meyers Norris Penny”) that it was dismissed as the Company’s independent registered public accounting firm. The decision to dismiss the Meyers Norris Penny as the Company’s independent registered public accounting firm was approved by the Company’s Board of Directors on October 28, 2010. Except as noted in the paragraph immediately below, the reports of Meyers Norris Penny on the Company’s consolidated financial statements for the years ended December 31, 2009 and 2008 did not contain an adverse opinion or disclaimer of opinion, and such reports were not qualified or modified as to uncertainty, audit scope, or accounting principle.
The reports of Meyers Norris Penny on the Company’s consolidated financial statements as of and for the years ended December 31, 2009 and 2008 contained an explanatory paragraph which noted that there was substantial doubt as to the Company’s ability to continue as a going concern due to uncertainty with respect to Company’s ability to fund future operations.
During the years ended December 31, 2009 and 2008 through October 29, 2010, the Company has not had any disagreements with Meyers Norris Penny on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to Meyers Norris Penny’s satisfaction, would have caused them to make reference thereto in their reports on the Company’s consolidated financial statements for such periods.
During the years ended December 31, 2009 and 2008 through October 29, 2010, there were no reportable events, as defined in Item 304(a)(1)(v) of Regulation S-K.
New independent registered public accounting firm
On October 29, 2010 (the “Engagement Date”), the Company engaged RBSM LLP (“RBSM ”) as its independent registered public accounting firm for the Company’s fiscal year ended December 31, 2010. The decision to engage RBSM as the Company’s independent registered public accounting firm was approved by the Company’s Board of Directors.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this report. They concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not adequate and effective in ensuring that material information relating to the Company would be made known to them by others within those entities, particularly during the period in which this report was being prepared.
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and in reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)). Under the supervision and with the participation of our management, including our principal executive officer (CEO) and principal financial officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements will not be prevented or detected. Management identified the following material weaknesses during its assessment of our internal control over financial reporting as at December 31, 2009.
SEGREGATION OF DUTIES AND ACCESS TO CRITICAL ACCOUNTING SYSTEMS
As at December 31, 2009, management believed the Company’s Internal Control over Financial Reporting did not meet the definition of adequate control, based on criteria established by Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management identified a material weakness relating the segregation of duties among certain personnel who had incompatible responsibilities within all significant processes affecting financial reporting. We also had a material weakness resulting from our failure to implement controls to restrict access to financially significant systems or to monitor access to those systems, which resulted in conflicting access and/or inappropriate segregation of duties. These material weaknesses affected all significant accounts. In addition, the 2007 restatement issues discussed below demonstrated a need to engage additional personnel or outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and adherence to US GAAP, to assist in income tax planning and compliance and a review of our Canadian and U. S. income tax provisions. As a result of these material weaknesses, management concluded that internal control over financial reporting was not effective as at December 31, 2009. Management feels that these material weaknesses have been remedied during 2010 and were fully remedied by December 31, 2010 as set out in the following section “Remediation of Material Weakness in Internal Control”.
REMEDIATION OF MATERIAL WEAKNESS IN INTERNAL CONTROL
During December, 2006 and the first half of 2007, the Company hired a Controller, a new CFO, a Vice-President, Operations and additional qualified personnel. The new staff and existing management have implemented new procedures and controls for many areas of the Company’s activities. During 2007, the Company initiated a review of its corporate policies and procedures with the assistance of an outside consulting firm, with a goal of having the Company become fully SOX compliant by year end 2007. Additional policies and procedures have been implemented and others strengthened. Testing of such policies and procedures was completed in late 2007 and early 2008. In addition, the Company will endeavor to engage outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and adherence to US GAAP. Beginning in 2008, the Company engaged an outside consulting firm to assist in income tax planning and compliance and beginning with our fiscal year ended December 31, 2008, to review our Canadian and U.S. income tax provisions.
During 2010, the Company engaged the services of additional personnel on a consulting basis who together are providing an additional level of review and governance with respect to the preparation and review of the Company’s quarterly and annual consolidated financial statements. Management believes that this additional level of control procedures was in place by December 31, 2010 and was operating effectively to remedy the material weakness relating to the segregation of duties among certain personnel that was previously reported. Management believes its controls and procedures related to its financial and corporate information systems are appropriate for a company of its size and mandate and, due to its internal expertise, is not dependent upon the inherent risks in external third party management of such systems. Our CFO from January, 2007 to December, 2009 retired on December 31, 2009, has joined the Board of Directors and continues to consult to the Company in a financial capacity and alleviate some of the segregation of duties and related weaknesses. The VP of Finance assumed the role of CFO ensuring a smooth transition at that time and was CFO until March 4, 2011 at which date, due to health reasons, he resigned as CFO and was retained as Business Development Manager on a consulting basis. A new CFO was hired effective March 4, 2011.
This Annual Report on Form 10-K does not include an attestation report of the Company's registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management's report on this Annual Report on Form 10-K.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There have been no changes in our internal control over financial reporting during the fourth quarter ended December 31, 2010 other than the finalization of the remediation of the weakness in internal control referred to above, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
On November 4, 2009, the Company voluntarily requested the TSX Venture Exchange ("TSX-V") in Canada to delist its common shares from trading on the TSX-V. This voluntary delisting is not pursuant to any order or communication from the TSX-V.
Kodiak's common shares are currently quoted for trading on the Over the Counter Bulletin Board (OTCBB) in the United States under the symbol KDKN. It will continue to maintain this quotation status and Canadian shareholders will be able to continue to trade through their brokers on that market.
The Company’s Board of Directors approved the voluntary delisting from the TSX-V after weighing the required expenses and multi-jurisdictional filings to maintain a dual listing of the Company's securities against the perceived shareholder benefit accrued from trading on different platforms.
The primary reasons for the voluntary delisting request were:
1.
Since the Company’s TSX-V listing effective December 24, 2007 to market close on October 30, 2009, liquidity analysis revealed an average daily trading volume of 270,413 shares on the OTCBB and 14,022 on the TSX-V for the period - a difference in trading volume and liquidity of over 19 times.
2.
Following the initial Canadian based financing associated with the TSX-V listing, the Company has repeatedly experienced little to no investment interest or support from the Canadian financial community consisting of investment banks, capital markets and retail brokerage firms, and private equity firms. The primary source of equity financing has been from Europe over the last 18 months, and we do not expect that to change in the foreseeable future. Our European investors have a stated preference for the OTCBB listing versus the TSX-V, of which the latter listing they do not follow.
3.
The Company’s Board of Directors believes that voluntarily delisting from the TSX-V and focusing on U.S. and European markets is in the best interests of our shareholders. This will eliminate the substantial cross-border financing and reporting issues.
4.
As of October 31, 2009, the Company’s transfer agent, Computershare, revealed the shareholder geographic position of all foreign based shareholders at 61.54% and Canadian based shareholders at 38.46%, of which the vast majority of the latter is founder shareholdings and only a nominal amount in the Canadian float. As a result, the OTCBB quotation system serves shareholders of the majority of Kodiak’s shares, where the Company’s stock has been trading since December 27, 2004.
5.
The internal and external compliance costs to maintain the listing of the Company’s shares on the TSX-V are relatively significant to a company of this size, which has not resulted in an additional benefit for shareholders in view of the low trading volume on the TSX-V.
6.
The Financial Industry Regulatory Authority (FINRA) is the largest independent regulator for securities firms in the United States and is responsible for establishing rules governing its broker/dealer members, including OTCBB subscribing members, on conduct, qualification standards, examinations, investigations, violations, and investor and member inquiries - thus, there is a previous and demonstrated, current market for Kodiak shareholders.
Other factors:
7.
To maintain quotation eligibility on the OTCBB, Kodiak Energy, Inc. is required to file periodic financial information with the U.S. Securities and Exchange Commission (SEC). All of the Company’s filings are located under the “Kodiak Energy, Inc.” profile on the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system through the U.S. SEC website at http://www.sec.gov.
8.
Kodiak intends on maintaining its “foreign reporting issuer status” with the Alberta Securities Commission.
9.
Kodiak was Sarbanes Oxley (SOX) compliant for 2008, is a fully reporting filer, and adheres to the security laws, rules, regulations and filing requirements of the U.S. SEC.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
DIRECTORS AND EXECUTIVE OFFICERS
Mr. William Tighe has held the positions of Chief Operating Officer, President and Director of the Company since September 2005 and Chief Executive Officer of the Company since December 2007. At Kodiak's 2008 annual meeting in December, he assumed the position of Acting Chairman of the Board with position of Chairman at the Company's board of directors meeting in January 2009. Since 2005, Mr. Tighe has focused on developing the Company's business interests. His past experience includes approximately thirty years in management, operations, maintenance, and more recently major and minor projects for both Canadian and other international energy companies. These positions were in a variety of field settings from the heavy oil industry, sour gas and liquids plants in Alberta and British Columbia and the sub-arctic in Canada, to design offices, construction, construction and startup, and operation of large gas/liquids processing operations in Southeast Asia. From 2004 to 2005, Mr. Tighe worked for Suncor Energy Ltd. as a Business Services Manager, Growth Planning and Development. From 2000 until 2004, he worked for Petro China International as Operations Development and Commissioning Manager. Prior to that, Mr. Tighe had extensive experience in both Alberta and internationally in the oil and gas industry. He attended the University of Calgary where he studied general science and computer science. Mr. Tighe is a director of Tamm Oil and Gas Corp., a junior heavy oil exploration and development company based in Calgary, Alberta, Canada. He holds an Interprovincial Power Engineering Certification II Class. We believe that the extensive Canadian and international oil and gas experience, coupled with the 5 years as President and COO of the Company as a fully reporting SOX compliant issuer, makes Mr. Tighe an asset to the Board of Directors of Kodiak Energy, Inc.
Mr. Glenn Watt has been a director of the Company since November 2005 and Vice President, Operations of the Company since April 2007. Prior to joining Kodiak, he worked primarily in the Western Canadian Sedimentary Basin and, from May 2003 to March 2007, was drilling and completions superintendent for a large Canadian oil and gas royalty trust. Prior to that, Mr. Watt worked for a major oil and gas company as a completions superintendent. He has additional field experience working on drilling rigs in Alberta and British Columbia. Mr. Watt has an honors diploma in Petroleum Engineering Technology from the Northern Alberta Institute of Technology and a Bachelor of Applied Petroleum Engineering Technology Degree from the Southern Alberta Institute of Technology. We believe that Mr. Watt’s formal education and extensive work experience in drilling and project management in the Western Canada Sedimentary Basin makes him a valuable and key member of management and Board of Directors of Kodiak Energy, Inc.
Mr. Greg Juneau has been a director of the Company since February 2009. Mr. Juneau is a Calgary-based professional engineer with over 19 years of oil and gas experience as a project engineer and manager. His areas of expertise include engineering, procurement and construction management of surface facilities. From 2000 to present, Mr. Juneau is the president and engineering manager at Segment Engineering Ltd. He coordinates full discipline engineering, procurement, construction and management (EPCM) projects consisting of oil and gas well sites, gathering systems, transmission pipelines, pump stations, satellites, batteries, compression and gas plants within British Columbia, Alberta and Saskatchewan. Mr. Juneau graduated from the University of Alberta in 1990 with a Bachelor of Science Degree in Mechanical Engineering and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), and Association of Professional Engineers and Geoscientists of BC (APEG of BC). As Kodiak’s projects mature, his extensive EPCM experience will provide independent review to the Board of Directors. We believe that Mr. Juneau’s extensive and full cycle oil and gas experience makes for an excellent independent addition to the Company’s Board of Directors.
Mr. William E. Brimacombe is a Canadian Chartered Accountant and, since January 2007, had been Chief Financial Officer of the Company until his retirement in December 2009 when he joined our Board of Directors. From 2000 to 2006, he was Vice-President Finance of AltaCanada Energy Corp., a publicly traded Canadian oil and gas company. Prior thereto, Mr. Brimacombe has over thirty years financial experience working for a number of public and private oil and gas companies with operations in Canada, the United States and other countries, including experience as an independent financial consultant during the years 1988 to 2000. In 2009, he became a Life member of the Institute of Chartered Accountants of Alberta with forty years membership in that organization. We believe that Mr. Brimacombe’s qualifications, including knowledge of both Canadian GAAP and US GAAP, oil and gas accounting and financial principles and prior successful public company roles including CFO of those companies, successful SOX compliance for Kodiak during his tenure as CFO, adds additional financial oversight for the Board of Directors.
Mr. Richard Carmichael has been our CFO, commencing March 4, 2011 is a Chartered Accountant who has held senior financial positions within the oil and gas exploration and production, and oil and gas service industries over the past 20 years. He is an experienced financial manager with publicly traded companies using Canadian GAAP and U.S. GAAP and has had responsibilities covering corporate accounting and financial reporting, treasury and financial analysis, budgeting and planning, and acquisitions and corporate financing. Most recently, Richard was the CFO of Steen River Oil & Gas Ltd. (formerly Jed Oil Inc.) from 2007 to 2010. Richard is also CFO of Cougar Oil and Gas Canada, Inc. We believe Mr. Carmichael will provide the financial expertise and experience necessary that the Company requires.
During the last 10 years, no officer or director of the Company has been involved in any legal, bankruptcy or criminal proceedings or violated any federal, state or provincial securities or commodities laws or engaged in any activity that would limit their involvement in any type of business, including securities or banking activities. There are no direct family relationships between or amongst any of the above directors or executive officers.
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
Section 16(a) of the Exchange Act requires the Company's directors and executive officers, and persons who own more than 10% of the outstanding shares of the Company's Common Stock, to file initial reports of beneficial ownership and reports of changes in beneficial ownership of shares of Common Stock with the Commission. Such persons are required by Commission regulations to furnish the Company with copies of all Section 16(a) forms they file.
Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to the Company during the year ended December 31, 2010, and upon a review of Forms 5 and amendments thereto furnished to the Company with respect to the year ended December 31, 2010, or upon written representations received by the Company from certain reporting persons, that no Forms 5 were required for those persons for the year ended December 31, 2010.
AUDIT COMMITTEE AND FINANCIAL EXPERT
During the year end December 31, 2010, the Audit Committee met four times. The Audit Committee’s role is financial oversight. Our management is responsible for the preparation of our financial statements and our independent registered public accounting firm is responsible for auditing those financial statements. The Audit Committee is not providing any special assurance as to our financial statements or any professional certification as to the registered independent accounting firm’s work.
The Audit Committee is directly responsible for the appointment, compensation, retention and oversight of Kodiak’s independent registered accounting firm. The Audit Committee, among other things, also reviews and discusses Kodiak’s audited financial statements with management.
Our Audit Committee is comprised of two directors: Greg Juneau, who is independent and Bill Brimacombe who as a consultant to the Company is not deemed independent.
CODE OF ETHICS
A code of ethics relates to written standards that are reasonably designed to deter wrongdoing and to promote:
1.
Honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships.
2.
Full, fair, accurate, timely and understandable disclosure in reports and documents that are filed with, or submitted to the Securities and Exchange Commission and in other public communications made by the Company.
3.
Compliance with applicable government laws, rules and regulations.
4.
The prompt internal reporting of violations of the code to an appropriate person or persons identified in the code.
5.
Accountability for adherence to the code.
In October 2007, the Company adopted a formal code of business conduct. The Board of Directors evaluated the business of the Company and its personnel and has determined that its business operations are operated by a growing number of persons, some of who are also officers, directors and employees of the Company and others who are independent contractors. Although general rules of fiduciary duty and federal, state and provincial criminal, business conduct and securities laws are adequate ethical guidelines, a formal written code of business conduct would provide additional ethical standards of conduct to which the Company’s personnel should comply.
Requests for copies of our current Code of Ethics, which will be provided at no charge, should be sent in writing to Kodiak Energy, Inc., 833 4th Avenue S.W., Suite 1120, Calgary, AB T2P 3T5, Canada.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION OF EXECUTIVE OFFICERS
The following table summarizes compensation of our Chief Executive Officer, President and Chief Operating Officer; Chief Financial Officer; Vice President, Finance; Vice President, Exploration and Vice President, Operations for the fiscal year ended December 31, 2010.
COMPENSATION DISCUSSION AND ANALYSIS
Overview of Compensation Program and Philosophy
The Company has three executive officers, two of whom are the Company’s directors. The Board of Directors serves as the Company’s compensation committee, initiates and approves most compensation decisions. Annual bonuses for executives are determined by the Board of Directors.
The goal of the compensation program is to adequately reward the efforts and achievements of executive officers for the management of the Company. The Company has no pension plan and no deferred compensation arrangements. The Company has not used a compensation consultant in any capacity.
We have a formal consulting contract with Mr. William Tighe and formal consulting contracts Mr. William Brimacombe or their consulting companies. During 2010, Mr. William Tighe was to be paid Cdn $10,000 per month. During 2010, Mr. William Brimacombe was paid Cdn. $110 per hour, and a monthly vehicle allowance of Cdn. $800. During 2010, David Wilson was to be paid $10,000 per month and a monthly vehicle allowance of Cdn. $1,200 through July 2010, subsequently converted to an hourly rate of Cdn $110 per hour. Steven Peter and Glen Watt have a formal employment contracts paid Cdn. $10,000 per month each.
Compensation of Directors
The directors of the Company are not paid any cash compensation. We reimburse each of our directors for reasonable out-of-pocket expenses that they incur in connection with attending board or committee meetings.
On January 4, 2006, the Company adopted a stock-based compensation plan, under which each director of Kodiak would receive 120,000 options upon becoming a director and an additional 80,000 options in the second year and 200,000 options in the third year for each year or part of a year served as a director. On July 19, 2006 the stock option plan was approved by the shareholders of the Company. On October 23, 2006, options granted to directors were adjusted to 200,000 shares per director. The exercise price of such options is the market price per share on the date of grant.
On June 24, 2009 the Company announced that its board of directors has, pursuant to the Corporation’s incentive stock option plan, approved the granting of stock options “Options” to directors, officers and other personnel to acquire an aggregate of 4,330,000 common shares of the Corporation (“Common Shares”) at an exercise price of $0.28 per Common Share - the market closing price of the Corporation’s common shares on June 23, 2009. Of the total options granted, an aggregate of 3,300,000 Options were granted to directors and executive officers as follows and are for a five year term with vesting occurring for one third of the options at the end of each of the first three years:
No named directors or executive officers exercised any stock options during fiscal 2010.
DIRECTOR COMPENSATION TABLE
The table below summarizes the compensation paid by us to our non-employee directors during the years ended December 31, 2010 and 2009.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of the date of this report, information relating to the beneficial ownership of our common stock by those persons known to us to beneficially own more than 5% of our capital stock, by each of our directors, proposed directors and executive officers, and by all of our directors, proposed directors and executive officers as a group. The address of each person is set out in the footnotes to the table.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
DIRECTOR INDEPENDENCE
We undertook a review of the independence of our directors and, using the definitions and independence standards for directors provided in the rules of The Nasdaq Stock Market, although not required as the standard for the Company as it is traded on the Over-the-Counter Market considered whether any director has a material relationship with us that could interfere with his ability to exercise independent judgment in carrying out his responsibilities. As a result of this review, we determined that Greg Juneau each is an "independent director" as defined under the rules of The Nasdaq Stock Market.
RELATED TRANSACTIONS
For the year ended December 31, 2010, the Company paid $Nil (December 31, 2009 - $24,107), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services. Of this amount, $nil (December 31, 2009 - $6,910) was capitalized to Unproved Oil and Gas Properties and $nil (December 31, 2009 -$17,197) was charged to General and Administrative Expense.
For the year ended December 31, 2010 and 2009, the Company incurred $48,058 (December 31, 2009 - $124,353) to Director and the former Chief Financial Officer. $9,132 was payable at December 31, 2010. The Company incurred $116,160 to a Company owned and controlled by the chairman of the Company for management consulting services. $21,114 was payable on December 31, 2010. The Company incurred expenses of the wife of the chairman of the Company of $25,871 for administration consulting services. $5,321 was outstanding on December 31, 2010. These amounts were charged to General and Administrative Expense.
These related party transactions were non arm's length transactions in the normal course of business and agreed to by the related parties and the Company based on negotiations and Board approval and accordingly had been measured at the exchange amounts.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANTING FEES AND SERVICES
AUDIT FEES
The Company paid audit fees totaling $161,475 to Meyers Norris Penny LLP during 2009 and $120,541during 2010. The Company has recorded estimated audit fees to RBSM LLP of $195,087 for 2010. The 2009 fees to Meyers Norris Penny include approximately $62,000 relative to Internal Controls and Financial Reporting.
AUDIT-RELATED FEES
The Company paid tax fees to Meyers Norris Penny LLP for December 31, 2009 of $19,052; $Nil for 2010.
TAX FEES
None
ALL OTHER FEES
None
AUDIT COMMITTEE POLICIES AND PROCEDURES
In accordance with our policy, all of the above services were pre-approved by the Company's Audit Committee of the Board of Directors.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
Exhibits
23.1
Consent of RBSM
23.2
Consent of Meyers Norris Penny LLP
31.1
Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)of the Exchange Act, as enacted by Section 302 of the Sarbanes-Oxley Act of 2002.(1)
31.2
Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)of the Exchange Act, as enacted by Section 302 of the Sarbanes-Oxley Act of 2002.(1)
32.1
Certification of Chief Executive Officer, pursuant to 18 United States Code Section as enacted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification of Chief Financial Officer, pursuant to 18 United States Code Section as enacted by Section 906 of the Sarbanes-Oxley Act of 2002.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on April 13, 2011.
KODIAK ENERGY, INC.
By: /s/ William Tighe
Name: William Tighe
Title: President and Chief Executive Officer
In accordance with the Exchange Act, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated.
/s/ William Tighe
William Tighe, Chairman, Chief Executive Officer, Chief Operating Officer and President
(Principal Executive Officer)
Date: April 13, 2011
/s/ Richard Carmichael
Richard Carmichael, Chief Financial Officer
(Principal Financial and Accounting Officer)
Date: April 13, 2011
/s/ Glenn Watt
Glenn Watt, Vice President Operations and Director
Date: April 13, 2011
/s/ Gregory Juneau
Gregory Juneau, Director
Date: April 13, 2011
/s/ William E. Brimacombe
William E. Brimacombe, Director
Date: April 13, 2011
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED)
(All currency amounts in Canadian dollars))
The following sections are specific to Kodiak’s ownership of the subsidiary Cougar Oil and Gas Canada, Inc. Kodiak owns 59.74% of the outstanding shares of Cougar as of March 15, 2011. Kodiak had no Oil and Gas Producing activities on our holdings in New Mexico. No effort has been made to calculate the net percentage attributable to Kodiak in the following tables as the percentage interest varied during the year as did the land, revenue and costs.
In accordance with the Accounting Standards Update 2010-03, Extractive Activities - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, ("ASU 2010-03"), issued by the Financial Accounting Standards Board of the United States, this section provides supplemental information on oil and gas exploration and producing activities of the Company as of December 31, 2010 in the following tables. Since there were no reserves or revenue for the preceding year of 2008 there is no comparison tables provided for those years. Tables I through III provide historical cost information under US GAAP pertaining to capitalized costs related to oil and gas producing activities; costs incurred in oil and gas exploration and development; and results of operations related to oil and gas producing activities. Tables IV through XI present information on the Company’s estimated net proved reserve quantities; standardized measure of discounted future net cash flows;
This statement of reserves data and other information (the “Statement”) is dated March 8, 2011 and is effective December 31, 2010. The preparation date of the information in this Statement was March 8, 2011
Table I: Capitalized costs related to oil and gas producing activities
·
*Note - only includes 3 months of costs for 2009 - October to December 2009.
Table II: Cost incurred in oil and gas exploration and development
For the year ended December 31, 2010, the Company incurred the following costs on properties in Canada:
Table III: Results of operations for oil and gas producing activities
·
*Note - only includes 3 months of revenue for 2009 - October to December 2009.
COUGAR Oil and Gas Canada, Inc.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED)
(All currency amounts in millions Cnd.)
The results of operations for producing activities for the years ended December 31, 2009 and 2010 are shown above. Revenues include sales to unaffiliated parties. All revenues reported in this table include royalties where applicable. Income taxes are based on statutory tax rates, reflecting allowable deductions and tax credits. General corporate overhead and interest income and expense are excluded from the results of operations.
Reserves Categories
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Although probable and possible reserve locations are found by “stepping out” from proved reserve locations, estimates of probable and possible reserves are, by their nature, more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized by us. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.
“Net” reserves exclude royalties and interests owned by others and reflect contractual arrangements in effect at the time of the estimate.
Estimated Reserves
The following tables presents our estimated net proved, probable and possible oil and gas reserves relating to our oil and natural gas properties as of December 31, 2010, based on our reserve reports as of such date. The data was prepared by the independent petroleum-engineering firm GLJ Petroleum Consultants Ltd. (GLJ). Reserves at December 31, 2010 were determined using the unweighted arithmetic average of the first day of the month price for each month from January 2010 through December 2010, which we refer to as the 12-month average price as of December 31, 2010, of $73.93 per barrel of oil.
Reserves
Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity, and continual reassessment of the viability of production under various economic and political conditions.
Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir.
The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.
In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.
SEC’s final rule on our reserve estimates include: The use of the unweighted 12-month average of the first-day-of-the-month reference price of $69.87 per barrel for oil compared to average consolidated revenue of $74.64 (net of transportation) per barrel received for the months of October 1, 2009 to July 31, 2010 when we had sales. A reference price of $73.93 for December 31, 2010 was used in the most recent reserve evaluation - where the Company received 79.81 USD at December 31, 2010. - thus our comments as to subjective price points and that effect on estimates and ceiling tests and resultant write downs.
The impact of the adoption of the SEC’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.
The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Science Degree in Geology and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG). He has more than 25 years of experience in reservoir geology.
All reserve information in this report is based on estimates prepared by GLJ, independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at GLJ meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas by the Society of Petroleum Engineers. GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Internal Controls for Reserves Reporting
A significant component of our internal controls in our reserve estimation effort is our practice of using an independent third-party reserve engineering firm to prepare 100% of our year-end proved reserves and, for 2010, our probable and possible reserves. The qualifications of this firm are discussed below under “Independence and Qualifications of Reserve Preparer.” The Board of Directors of the Company has reviewed the reserves estimates and procedures prior to acceptance of the report. The Board of Directors has sufficient technical training and experience to review and approve the report
Our internal geologist is our Vice President, Exploration and reports to our President, Operations, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to our independent third party reserve engineers to estimate our year-end reserves. Our internal geologist staff consists of one degreed geologist, with over 25 years of diversified geological experience in the Canadian oil and gas industry, including in the Western Canadian Sedimentary Basin. He is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG).
Independence and Qualifications of Reserve Preparer
We engaged GLJ Petroleum Consultants Ltd. (GLJ), third-party reserve engineers, to prepare our reserves as of December 31, 2010 in accordance with reserves definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (COGE), the Canadian Securities Administrators National Instrument 51-101 (NI 51-101) using Forecast Pricing Assumptions and, for the SEC, using Constant Pricing Assumptions. The technical person responsible for our reserve estimates at GLJ meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth by The Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA). GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own any interest in our properties and are not employed on a contingent fee basis.
Year-end reserves quantities for the year ended December 31, 2010 shown in the following tables were calculated using the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period covered by the report. The estimated impact of changing to the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period was not significant as the Company had no reserves prior to September 30, 2009
Table IV: Reserve quantities information
The Group’s estimated net proved underground oil and gas reserves and changes thereto for the years ended December 31, 2010 are shown in the following table
Table V: Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of ASU 2010-03. Estimated future cash inflows from production are computed by the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period covered by the report for the year ended December 31, 2010 to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10% mid-period discount factors. This discounting requires a year-by-year estimate of when the future expenditure will be incurred and when the reserves will be produced.
The information provided does not represent management’s estimate of the Company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made for the year ended December 31, 2010 and should not be relied upon as an indication of the Company’s future cash flows or value of its oil and gas reserves.
Notes:
Numbers may not add exactly due to rounding.
Numbers are M $ Cdn as reserve reports were calculated on that basis.
Table VI: Production Volumes, Sales Prices and Production Costs
The following table sets forth information regarding our oil and natural gas properties. The oil and gas production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells.
SUMMARY OF NET REVENUE
December 31, 2010 (Undiscounted)
Notes:
Numbers may not add exactly due to rounding.
Numbers are MM $ Cdn.
Table VII: RECONCILATION OF Company Gross Reserves by Principal Product Type - Mbbl
Numbers may not add exactly due to rounding
Table VIII: Land Holdings Without Attributed Reserves as at December 31, 2010
The following table summarizes information with respect to the Company’s properties to which no reserves have been specifically attributed:
Total Unproved Properties (Hectares) - Gross 3,200 and Net 3,079
There are no material work commitments on the above undeveloped land holdings.
Additional information regarding wells, costs and associated activities
Table IX: The following table summarizes the Company’s working interests, as at December 31, 2010, in oil and gas wells located in Canada:
Notes:
1. Includes wells that are temporarily shut-in but which are capable of production.
2. Includes wells that are not capable of production but that are not yet abandoned
Additional Information Concerning Abandonment and Reclamation Costs -
The Company bases its estimates for the costs of abandonment and reclamation of surface leases, wells, facilities and pipelines on previous experience of management with similar well sites and facility locations in the area. Costs for abandonment of reserve wells are included in the GLJ Report as a deduction in arriving at future net revenue. As at December 31, 2010, management expected to incur such future costs on 47.915 net wells. Within the next five financial years, it is expected such costs will total $212, 000 in respect of abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The costs used by GLJ for abandonment of reserve wells based on industry averages in the area and regulatory published estimates. Surface lease reclamation is not considered and facilities costs were deemed recoverable with salvage of the equipment.
Table X: Company Annual Abandonment Costs (M$ CAD)
Table XI: Exploration and Development Activities
For the year ended December 31, 2010, the Company completed the following exploratory and development wells: