| COUGAR OIL AND GAS CANADA, INC. |
Management Discussion and Analysis
1ST QUARTER
March 31, 2011
BASIS OF PRESENTATION
The following is management’s discussion and analysis (MD&A) of Cougar Oil and Gas Canada, Inc. (“Cougar”, “we”, “us”, “our”), unaudited operating and financial results for the three months ended March 31, 2011. It should be read in conjunction with the unaudited interim financial statements and related notes of the Company for the three months ended March 31, 2011 and the MD&A and the audited financial statements and the related notes for the period ended December 31, 2010. The MD&A is dated May 11, 2011. The financial data presented herein has in part been derived from the Company’s audited financial statements prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP’) and in accordance with accounting policies set out in the Company’s financial statements. The reporting currency is the Canadian dollar unless otherwise stated.
Additional information regarding Cougar’s financial and operating results may be obtained on the internet at www.sedar.com and www.edgar.com.
FORWARD LOOKING STATEMENTS
From time to time, our representatives or we 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.
Certain statements contained in this report, including statements regarding the anticipated development and expansion of our business, our intent, belief or current expectations, our directors or officers, primarily with respect to the future operating performance of the Company and the products we expect to offer and other statements contained herein regarding matters that are not historical facts, but are “forward-looking” statements. Future filings with the SEC, future press releases and future oral or written statements made by us or with our approval, which are not statements of historical fact, may contain forward-looking statements, because such statements include risks and uncertainties, actual results may differ materially from those expressed or implied by such forward-looking statements.
All forward-looking statements speak only as of the date on which they are made. We undertake no obligation to update such statements to reflect events that occur or circumstances that exist after the date on which they were made.
Unless otherwise stated, all amounts shown in this “Operating and Financial Review” section of this report are in Canadian Dollars.
The following discussions and analysis should be read in conjunction with the ‘Selected Consolidated Financial Information’ included elsewhere herein and our historical consolidated financial statements and the accompanying notes.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS
Overview
History
Cougar Oil and Gas Canada Inc., formerly Ore-More Resources Inc., was incorporated under the laws of the Province of Alberta, Canada on June 20, 2007. Our principal activity is in the exploration, development, production and sale of oil and natural gas.
In January 2010, the Company entered into a stock purchase agreement (the “Agreement”) with Cougar Energy, Inc. (which we refer to as CEI) and CEI’s then shareholders whereby Cougar agreed to acquire the entire issued and outstanding shares of the common stock of CEI.
Upon consummation of the acquisition, CEI became the only wholly owned subsidiary of the Company. Subsequent to the completion of the reverse acquisition, the Company amended its article of incorporation and changed its 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 the Company’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 the Company is the legal acquirer rather than a business combination. The Company did not recognize goodwill or any intangible assets in connection with this transaction. Accordingly, the Company’s historical consolidated financial statements are those of CEI from its date of inception on November 21, 2008.
Prior to the acquisition of CEI, the company had operating assets and activities within the oil and gas industry, and therefore the acquisition of CEI is not characterized as a shell transaction under SEC rules and regulations.
On January 1, 2011, the Companies amalgamated and continued under the name Cougar Oil and Gas Canada, Inc.
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 downhole 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 six 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 formation 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 at approximately 25 bbls/day. A casing leak occurred 3 weeks after production was restored and the well has been shut in until a service rig can be mobilized after the spring breakup. Therefore the work required is expected to be completed during Q2.
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.
In December of 2010, the company initiated licensing of 2 wells for an infill drilling program for Q1 2011. The Company drilled and completed a horizontal well on one of the locations during the first quarter and the well is currently pumping to clean up fluids that were pumped down hole during the drilling process.
The Company completed an extensive 3D program over the lands acquired in July 2010. The size of this 3D program coupled with the drill results will support additional drilling programs described below. See subsequent event notes
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 Trout HZ 102/10-21-089-03W5
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. With the current size of pumping equipment available at the site, it is anticipated it will take some time to recover all of the lost drilling fluids and begin producing the Keg River reservoir fluids.
During the horizontal leg, there was extensive loss of circulation and 50,000 bbls of water were lost to the formation. The well was completed and put on test with a portable hydraulic pump jack. As of filing, the well continues to recover drilling fluids, although fluid levels had climbed recently. Until a larger downhole pump is installed and larger volumes are pumped, it is not expected that the hydrocarbon rates of production will increase. This is typical of wells in this area and this formation.
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.
Current Status:
The 102/10-21-89-3W5 horizontal well is currently pumping using a hydraulic pump jack installed onto the well head and the production is being stored in tanks and trucked to the main 12-22 battery. The hydraulic jack is limited to a maximum production rate of 30m3 per day with production currently made up of a mix of lost drilling fluids and new reservoir water with a measured salinity of 20.5% . (The expected field salinity is 24 to 28%). There has been an increase of gas with the production indicating some improved reservoir inflow. The pumping system currently installed on the well does not have the capability to produce enough fluid to draw down the fluid level and allow the oil to enter the wellbore. The high hydrostatic pressure reduces oil inflow, however this was the only equipment available in the area at the time of completion that could be installed prior to break up. The drill cuttings have been analyzed and as expected there is a strong dolomite composition in the horizontal leg. Historically we have found in this formation, that since a water molecule is much smaller than an oil molecule, water has the ability to enter the wellbore preferentially ahead of the oil with the reduced production rates.
History and Planning Summary:
| | · | The 3D seismic that was purchased in September 2010 was used to identify the structurally highest part of the targeted Keg River reservoirs in sections 21 and 22-89-3W5. |
| | · | The Keg River formation does not appear to have a basic oil water contact but rather has oil and water in transition with the highest percentage of oil at the top of the formation and the highest percentage of water at the bottom of the formation. |
| | · | Three vertical wells and one horizontal well were identified using the purchased 3D seismic. |
| | · | There were two cored vertical wells at 16-21-89-3w5 and 10-21-89-3w5 that had good porosity but relatively poor permeability and production. The cores showed excellent oil concentration in the Keg River formation. |
| | · | A horizontal well was planned to target the oil reserves which could not be effectively drained using the two original vertical wells. |
| | · | The well target would be the Keg River formation and the horizontal leg was planned to run along the top of the structural trap. |
| | · | It was anticipated that a horizontal well would be able to effectively produce the Keg River oil and would not require any well stimulation other than an acid wash to stimulate inflow. |
| | · | After presenting our planning information to the engineering firm GLJ, they granted a reserves value of 218,000 barrels of recoverable oil with a discounted net present value of almost $5MM (NPV-10%). |
Anticline (Structural) Trap:
An anticline is an example of rocks which were previously flat, but have been bent into an arch. Oil that finds its way into a reservoir rock that has been bent into an arch will flow to the crest of the arch, and get trapped (provided, of course, that there is a trap or cap rock above the arch to seal the oil in place).
Drilling Summary:
The 102/10-21-89-3W5 well was licensed in early February and the location was built as a padded dirt lease. A drilling rig was moved to location on February 19 and the well was spudded on February 21. Drilling continued until March 20 when the well was cased and the drilling rig was released from site. The total measured depth of the well is 2105m including a 410m horizontal leg. The horizontal leg was shortened due to the structure rapidly dropping off as we drilled SW off the 3D seismic data grid since the lower the structure the less chance of producing oil.
The drilling ran into several significant problems resulting in the total cost exceeding the budgeted amount by approximately 30%. The lease construction had to be built as a dirt pad rather than a planned winter lease due to the drilling being pushed back to very end of the winter season, which also meant delays in licensing and difficulty in obtaining a rig during the busy season. Therefore there was little choice in the selection of the drilling rig and we had to accept an undersized rig that had difficulty in drilling the larger surface hole required. The drilling company and some of the service providers used some inexperienced crews, due again to the busy winter drilling season, that resulted in delays in performing the drilling operations. This affected most companies in the area and they also experienced delays and cost overruns as a result. More problems occurred during drilling into the Muskeg salt formation building an angle towards the planned 90 degree horizontal leg. Drilling rates were slow which was compounded by an unexpected complete loss of drilling fluids in the horizontal leg. An estimated 50,000bbls of water was lost drilling the horizontal leg. The directional equipment used included a gamma signal which verified formation tops. Drill cuttings and the gamma ray data confirmed the horizontal leg was drilled in the Keg River formation and the leg was always within 1.5m of the formation top (structurally highest part of the reservoir). The anticipated severe lost circulation in the Wabamun formation was effectively isolated with the planned bypass casing string.
Completion Summary:
Tubing was run into the horizontal leg and swabs were pulled from various spots in the horizontal leg to clean up any near wellbore damage. The tubing was landed at approximately 1000m and the pump and rods were run in the hole and the well was put on production. Produced fluids are stored in two 400bbl tanks and trucked to the main 12-22 battery.
Anticipated Operations:
The key element to increasing production rate is increasing the pressure drawdown of the reservoir by reducing the back pressure imposed by the production system. Currently the pumping system installed on the horizontal well cannot produce enough fluid and the fluid level/hydrostatic pressure in the wellbore is too high reducing oil production. Once the lease conditions improve (dry up) an electric submersible pump (ESP) will be installed in the well to produce a higher volume of fluid. A temporary surface flow line will be used to transport the produced fluid to the main 12-22 battery, to better evaluate the potential of the well. To reduce operating costs the well will be shut in to monitor pressures until the ESP can be installed. Regular pump offs will be continued to test inflow using the hydraulic pump jack. During the drilling operations the water which was lost to the formation effectively swept all the hydrocarbons away from the wellbore and it will take time to migrate back to the horizontal wellbore. However, there has been an increase in produced gas seen over the last week indicating the wellbore continues to clean up. Coupled with the increase in fluid level, we believe that hydrocarbon is migrating into the well bore, however with the low volume pump we cannot fully test that concept.
Future Horizontal wells:
This well was planned to efficiently produce a reservoir that had good porosity and oil content and poorer permeability. The better than expected reservoir quality resulted in the lost circulation in the Keg River. Horizontal drilling is still an effective way to produce this reservoir but future wells should be done using underbalanced drilling techniques.
3D Seismic Program
Cougar has completed the initial review of the processed 3D seismic data that was acquired in January/February 2011. 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 May 2011.
The announced first stage five (5) well drilling program was selected after an extensive review of the 3D seismic data, the regional and local geological mapping, the core data and the well performance of the existing regional wells. All of the current targets are vertical locations with new potential reservoirs identified with the seismic. Of the 15 locations 7 are targeting new reservoirs and balance are development wells of existing reservoirs.
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 a 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 has commenced recourse against CREEnergy to recover funds advanced for the agreements.
We have tendered several business models to the communities. We intend on developing the relationship and the opportunities to the joint benefit of both Cougar and the communities of Peerless/Trout Lake in a way that respects their heritage, the land and the environment.
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 are 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
On February 14, 2011, Cougar completed negotiations on a two section heavy oil farm-in with a private company in the Manning area of north western Alberta. The farm-in includes a commitment for Cougar to drill one well to a minimum contract depth of 500m by the end of Q3, 2011 in order to earn a 100% working interest. Upon successful completion of the farm-in the private company retains a 3% royalty interest on the two sections. Cougar has completed the initial review of this farm-in acreage and selected two possible drilling locations for the commitment well.
The permitting process has started and we are targeting a Q3, 2011 drilling program for this project. Cougar will earn 100% working interest in 1280 acres of land prospective for Heavy Oil after drilling this well.
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.
We are evaluating trade seismic for the second Manning farm-in announced on March 17, 2011. This will be the first step in the earning process for this project. 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 1280 acre farm- in which the planned well is expected to be drilled in Q3, 2011.
The activity level is rapidly changing in this area – with increased recent interest shown by the land sales in April that resulted in over 148,000 acres in the immediate or adjacent area and an additional 130,000 acres close by being leased on 15 year leases for over 6 million dollars
Summary
The Company plans to develop and optimize its assets in Alberta and British Columbia as the primary focus. 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 five well drilling program on the Trout Properties and the one well drill and test for the Manning Farm in for Q3/Q4 2011. This will be followed up with subsequent drilling programs on the Trout Properties, and coring programs on the Manning Properties for winter of 2011/2012.
Organizational Structure
Cougar Oil and Gas Canada, Inc. previously held shares of a wholly owned (100%) subsidiary Cougar Energy, Inc. Cougar Energy, Inc. owned the assets and liabilities associated with the oil and gas operations. Cougar Oil and Gas Canada, Inc. and Cougar Energy, Inc. completed a merger on January 1, 2011. Therefore, prior to January 1, 2011, Cougar’s financial statements were shown as “consolidated” amounts.
FINANCIAL INFORMATION
Financial Condition and Changes in Financial Condition:
The Company’s total assets have increased to $14,047,130 as at March 31, 2011 from $10,267,188 as at December 31, 2010. This increase is primarily due to the costs associated to the drilling of a horizontal well and completing a 3D seismic program during the quarter ended March 31, 2011. Total assets consist of cash and other current assets of $903,501 (December 31, 2010 - $579,240).
The Company has included in oil and gas properties developed and undeveloped properties. Developed properties net of accumulated depreciation, depletion and amortization was $7,728,000 at March 31, 2011 (December 31, 2010 - $5,745,788). Undeveloped properties increased to $5,410,978 at March 31, 2011 from $3,936,797 on December 31, 2010. The increase in capitalized cost of developed properties was mainly due drilling on a horizontal well during the quarter. Increases in undeveloped properties in the quarter were primarily the result of a 3D seismic program that was completed in the Trout area. A ceiling test write down for the period ending March 31, 2011 of $934,433 has been recorded.
Our total current liabilities increased $2,463,455 from $5,206,803 at December 31, 2010 to $7,670,258 at March 31, 2011. The net increase is due primarily to increases in our trade accounts payable. Accounts payable and accrued liabilities increased to $4,223,122 at March 31, 2011 from $1,889,266 at December 31, 2010. The increase is due to increased work over activity during the quarter and capital spending. Our current debt at March 31, 2011 has increased modestly to $3,010,722 from $2,859,529 at December 31, 2010, an increase of $151,193.The increase is caused by an increase in our operating line and current portions of long term debt.
At March 31, 2011, we had long term liabilities of $2,950,629 (December 31, 2010 - $2,707,186). This increase is due to added borrowing of $1,013,845 in an unsecured convertible debenture denominated in Swiss francs which when the beneficial conversion feature is deducted has a carrying value of $501,099 at March 31, 2011. Debt repayments during the quarter of $255,000 and an increase in the current portion which reduces the remaining long term amount by an additional $61,406 results in a net increase of only $243,443 during the quarter.
Additionally, Kodiak advanced $900,000 to Cougar by way of an intercompany note during the quarter. The net carrying value of the note is $835,605 at March 31, 2011 ($Nil at December 31, 2010).
Asset retirement obligations increased by $39,696 for the three months ended March 31, 2011 to $1,372,443 from $1,332,747 at December 31, 2010. The increase is a result of accretion expense of $24,962 and asset retirement obligation additions of $14,733 during the quarter
Total stockholders’ equity as at March 31, 2011 amounted to $1,218,195, up from $1,020,452 at December 31, 2010, despite a comprehensive loss during the quarter of $1,872,607 (March 31, 2010 – comprehensive loss of $305,109). The losses were more than offset by an increase in common stock due to the exercise of warrants of $1,255,845 during the quarter, as well as, additions to additional paid in capital of $547,059 from the beneficial conversion feature on debt issued and $267,445 from the fair value of issued options.
Overall Operating Results
Revenue during the current quarter is marginally down as compared to the same quarter in 2010. Net oil revenues were $706,074 in the first quarter of 2011 versus $755,331 in 2010 due to operational difficulties that impaired the production from some wells. The Company had an active work over program to repair the wells but they took some time to respond.
As a result of the work over program, operating costs increased substantially in 2011 over 2010. An increase of $232,979 from $316,361 in the first quarter of 2010 to $549,340 in the same quarter of 2011 was experienced.
General and administrative expenses also increased significantly to $612,589 in the first quarter of 2011 from $393,107 in the first quarter of 2010. The increase of $219,482 is mainly due to stock based compensation expense incurred in 2011 of $267,445 up from $64,114 in 2010. Otherwise G&A expenses at roughly the same levels.
The Company recorded an impairment of its oil and gas properties of $934,433 in the first quarter of 2011 ($Nil – 2010). The impairment was the result of the capital expenditures, primarily on the horizontal well, which were in excess of the ceiling test amount which was based on the reserve report values at December 31, 2010 adjusted for depletion during the quarter. The intent of the capital program was to increase production and cash flow rather than to increase reserves. Depletion and amortization were slightly higher from $267,331 in the first quarter of 2010 to $307,420 in 2011, the result of a higher depletion base.
Increased interest expense in the first quarter of 2011 of $147,308 from $78,478 in 2010 is a reflection of higher debt and accounts payable levels.
As a result of the factors discussed above, the Company incurred a net loss for the three months ended March 31, 2011 of $1,845,016 as compared to a net loss of $299,946 in the first quarter of 2010, a net change of $1,545,070.
Liquidity and Capital Resources
The Company has a working capital deficit of $6,766,757 at March 31, 2011, which is up by $2,139,194 from $4,627,563 at December 31, 2010. Approximately $3.3 million of the working capital deficit at March 31, 2011 relates to supplier debt (December 31, 2010 – approximately $1.3 million), while the remainder relates to debts that are secured by the oil and gas assets, and related party amounts. The Company is working to reduce the working capital deficiency through equity and convertible debt financing and asset acquisitions.
During the quarter the following financings were arranged:
On January 31, 2011, the Company received $900,000 from Kodiak Energy Inc. and issued an 18 months unsecured convertible note to Kodiak 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.
On February 25, 2011, the Company issued a $1,013,845 unsecured convertible debenture to investors due eighteen months from issuance with interest at Bank of Canada Prime plus3% per annum due upon maturity. The debenture is convertible at any time prior to maturity, at the holder’s option, into shares of Cougar common stock at $3.00 per share. In the event of a conversion election by the holder, the holder will receive one warrant for each share received, exercisable four years from issuance with an exercise price of $3.90.
Subsequent to the quarter end the Company has completed the following financings and property acquisitions:
On April 13, 2011, the Company's majority owned subsidiary, Cougar Oil and Gas Canada, Inc. ("Cougar") issued a $1,000,000 unsecured convertible debenture due eighteen months from issuance with interest at Bank of Canada Prime plus3% per annum due upon maturity. The debenture is convertible at any time prior to maturity, at the holder’s option, into shares of Cougar common stock at $3.00 per share. In the event of a conversion election by the holder, the holder will receive one warrant for each share received, exercisable four years from issuance with an exercise price of $3.90.
On May 3, 2011, the Company's majority owned subsidiary, Cougar Oil and Gas Canada, Inc. ("Cougar") issued a $217,000 unsecured convertible debenture due eighteen months from issuance with interest at Bank of Canada Prime plus3% per annum due upon maturity. The debenture is convertible at any time prior to maturity, at the holder’s option, into shares of Cougar common stock at $3.00 per share. In the event of a conversion election by the holder, the holder will receive one warrant for each share received, exercisable four years from issuance with an exercise price of $3.90.
In April, 2011, Cougar Oil and Gas Canada, Inc. closed an acquisition from a private company for certain properties, for consideration which mainly included Cougar assuming the abandonment liability for the properties (for which the vendor had approximately $612,000 on deposit with the ERCB) and forgiving an outstanding accounts receivable of approximately $2,400 from the private company. The properties include four producing non-operated CBM gas wells and associated gathering and production facilities located in Central Alberta with a net production of approximately 25 BOEPD, and three suspended cardium oil wells located in central Alberta with the potential to reactivate two of the wells during the summer of 2011for an estimated net production of 25bbl per day. The wells are also located in an area that has recently proven successful for horizontal cardium oil development. Also included in the purchase were five standing natural gas wells in central and southern Alberta and three thousand two hundred net acres of mineral rights adjacent to Cougar's oil producing Alexander property. The wells require additional work over and/or tie-in work and will be evaluated for development, farm-out or divestiture. The mineral rights include all P&NG rights and will be evaluated for oil production potential.
Our registered independent certified public accountants have stated in their report dated April 13, 2011, that we are dependent upon management's ability to develop profitable operations and raise additional capital. These factors among others may raise substantial doubt about our ability to continue as a going concern.
MAJOR STOCKHOLDERS AND RELATED PARTY TRANSACTIONS
The following table sets forth certain information, as of March 31, 2011, concerning the ownership of our Common Shares by each person who, to the best of our knowledge, beneficially owned on that date more than 5% of our outstanding Common Shares.
Beneficial ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. In accordance with SEC rules, shares of Common Shares issuable upon the exercise of options or warrants which are currently exercisable or which become exercisable within 60 days following the date of the information in this table are deemed to be beneficially owned by, and outstanding with respect to, the holder of such option or warrant. Except as indicated by footnote, and subject to community property laws where applicable, to our knowledge, each person listed is believed to have sole voting and investment power with respect to all shares of Common Shares owned by such person.
| Beneficial Owner | | Shares | | | Percent of total issued (1) | |
Kodiak Energy, Inc. Suite 1120, 833 4th Avenue S.W. Calgary, AB T2P 3T5 | | | 38,262,812 | | | | 56.38 | % |
(1) Based on 67,870,281 shares issued and outstanding on March 31, 2011.
Our major stockholder does not have voting rights that differ from the other holders of shares of our Common Shares.
We are not aware of any arrangements that would result in a change in control of our Company at a subsequent date.
| B. | Related Party Transactions |
From time to time, the Company’s majority shareholder, Kodiak Energy, Inc. has provided working capital to the Company. There are no formal repayment terms and the loan is interest free. As of March 31, 2011 and 2010, the balance due was $436,414 and $463,351, respectively.
On January 31, 2011, the Company received $900,000 from Kodiak Energy Inc. and issued an 18 months unsecured convertible note to Kodiak 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.
The Company paid $15,000 to a company owned and controlled by the chairman of the Company for management consulting services during the three months ended March 31, 2011 ($15,000 March 31, 2010). Of this amount, $31,500 was payable on March 31, 2011 ($10,500 - March 31, 2010). For the three months ended March 31, 2011 and 2010, the Company incurred $11,110 and $3,729 to a Director and the former Chief Financial Officer. No amounts were outstanding at March 31, 2011 or March 31, 2010. The Company paid the wife of the chairman of the Company $Nil for administration consulting services during the three months ended March 31, 2011 ($5,040 - March 31, 2010). Of this amount, $1,512 was outstanding on March 31, 2011 ($5,292 - March 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.
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 under Exchange Act Rules 13a-15(f) and 14d-14(f). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations and may not prevent or detect misstatements. Therefore, even those systems determined to be effective can only provide reasonable assurance with respect to financial reporting reliability and financial statement preparation and presentation. In addition, projections of any evaluation of effectiveness to future periods are subject to risk that controls become inadequate because of changes in conditions and that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2011. In making the assessment, management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on its assessment, management concluded that, as of March 31, 2011, the Company’s internal control over financial reporting was effective.
As defined by Auditing Standard No. 5, “An Audit of Internal Control Over Financial Reporting that is Integrated with an Audit of Financial Statements and Related Independence Rule and Conforming Amendments,” established by the Public Company Accounting Oversight Board (“PCAOB”), a material weakness is a deficiency or combination of deficiencies that results in more than a remote likelihood that a material misstatement of annual or interim financial statements will not be prevented or detected. In connection with the assessment described above, management concluded the Company does not have control deficiencies that represent material weaknesses as of December 31, 2010.
Changes in Internal Control over Financial Reporting
As of March 31, 2011, management assessed the effectiveness of our internal control over financial reporting and based on that evaluation, they concluded that during the period November 21, 2008 (date of inception) through March 31, 2011 and to date, the internal controls and procedures were effective. During the course of their evaluation, we did not discover any fraud involving management or any other personnel who play a significant role in our disclosure controls and procedures or internal controls over financial reporting.
We believe that our unaudited interim financial statements for the three months ended March 31, 2011, fairly present our financial position, results of operations and cash flows for the periods covered thereby in all material respects.
We are committed to improving our financial organization. We will continue to monitor and evaluate the effectiveness of our internal controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements as necessary.
This interim report 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 the temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this interim report.
There were no changes in our internal control over financial reporting during the three months ended March 31, 2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
AUDIT COMMITTEE FINANCIAL EXPERT
As of the date of this report, the board of directors has an audit committee. The board of directors believes that Michael Hamilton, a member of the audit committee, meets the criteria for an audit committee financial expert, as that term is defined by Rule 4200(a)(15) of the NASDAQ Market Place Rules.
Mr. Hamilton will not be deemed an “expert” for any purpose, including, without limitation, for purposes of Section 11 of the Securities Act of 1933, as amended, as a result of being designated or identified as an audit committee financial expert. The designation or identification of Mr. Hamilton as an audit committee financial expert does not impose on him any duties, obligations or liability that are greater than the duties, obligations and liability imposed on him as a member of our Audit Committee and board of directors in the absence of such designation or identification. The designation or identification of Mr. Hamilton as an audit committee financial expert does not affect the duties, obligations or liability of any other member of our Audit Committee or board of directors. Mr. Hamilton is independent director.
CODE OF ETHICS
On August 17, 2010, our board of directors adopted a code of ethics for our employees and directors, including our co-chief executive officers and our principal financial officer (i) to promote the honest and ethical conduct of our senior executive and financial officers, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships, (ii) to promote full, fair, accurate, timely and understandable disclosure in periodic reports required to be filed with or submitted to the SEC and in other public communications by us; (iii) to promote compliance with all applicable laws, rules and regulations that apply to us and our senior executive and financial officers; (iv) to deter wrongdoing; and (v) to promote prompt internal reporting of breaches of, and accountability for adherence to, this code. A copy of the code of ethics is filed as an exhibit to the July 31, 2010 Annual Report by incorporation and to this Report by reference.
