Management’s Discussion And Analysis For The Three And Nine Months Ended September 30, 2018

Georox Announces Name Change to Prospera Energy Inc.
July 18, 2018
Prospera Reports Sales over 87,000 BOE
November 27, 2018


(formerly Georox Resources Inc.)
SEPTEMBER 30, 2018


The following Management’s Discussion and Analysis ("MD&A") of Prospera Energy Inc. (the "Corporation" or "Prospera") as at and for the three and nine months ended September 30, 2018 is provided for the purpose of reviewing the Corporation’s results of operations and financial position for the periods then ended. This MD&A is dated as of Nobember 28, 2018 and should be read in conjunction with the Corporation’s unaudited September 30, 2018 condensed interim financial statements and audited December 31, 2017 financial statements together with the notes thereto.

Amounts are shown in Canadian dollars unless otherwise stated. All production volumes disclosed herein are sales volumes.

In the following discussion, the three months ended September 30, 2018 may be referred to as “Q3 2018” and the comparative three months ended September 30, 2017 may be referred to as “Q3 2017” and the previous three months ended June 30, 2018 may be referred to as “Q2 2018”.

Forward Looking Statements

This discussion includes certain statements that may be deemed "forward-looking statements". All statements in this discussion, other than statements of historical facts that address activities, events or developments that Prospera expects are forward looking statements. The Corporation believes the expectations expressed in such forward-looking statements are based on reasonable assumptions which the Corporation is required to make regarding future events and may constitute forward-looking statements within the meaning of applicable securities laws. Management’s assessment of future plans and operations, capital expenditure requirements, methods of financing and the ability to fund financial liabilities, changes in royalty rates and the timing and impact of accounting policies may constitute forward-looking statements under applicable laws and necessarily involve risks including and without limitation, risks associated with oil and gas exploration, development and exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations imprecision of reserve estimates, environmental risks, competition from, other producers, the inability to fully realize the benefits of acquisitions, delays resulting from, or inability to obtain, required regulatory approvals and ability to access sufficient capital from internal and external sources. Readers and investors are cautioned that such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. Factors that could cause actual results to differ materially from those in the forward-looking statements include market prices, exploration and exploitation successes, continued availability of capital and financing and general economic, market or business conditions.

Although the Corporation believes the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will be realised. The use of any of the words "anticipate", "believe", "continue", "estimate", "expect", "may", "will", "forecast", "project", "plan", "should" and similar expressions are intended to identify forward-looking information. These statements are subject to certain risks and uncertainties and may be based on assumptions that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The risks associated with these forward-looking statements include, but are not limited to, the following:

  • Fluctuations in oil production levels;
  • Volatility in market prices for gas, liquids and oil
  • Uncertainties associated with estimating reserves;
  • Well production and decline rates;
  • Changes in the general economic conditions in Canada and Worldwide;
  • The effects of weather conditions;
  • The ability of Georox to obtain financing including equity and debt, and
  • Actions taken and policies by governmental or regulatory authorities including changes to tax laws, incentive programs, royalty calculations and environmental regulations.

Additional information related to the Corporation is available on SEDAR at, and on the Corporation’s website at


Per BOE disclosures

Petroleum and natural gas reserves and volumes are converted to a common unit of measure on a basis of six thousand cubic feet (Mcf) of gas to one barrel (bbl) of oil. BOEs may be misleading, particularly if used in isolation. The forgoing conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms to the Canadian Securities Regulators’ National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1 utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

For the purpose of this MD&A, oil is defined to include the following commodities: light and medium oil and primary heavy oil.


The financial data presented herein has been prepared in accordance with International Financial Reporting Standards ("IFRS"). The Corporation has also used certain measures of financial reporting that are commonly used as benchmarks within the oil and natural gas production industry in the following MD&A discussion. The measures are widely accepted measures of performance and value within the industry, and are used by investors and analysts to compare and evaluate oil and natural gas exploration and producing entities. Most notably, these measures include “operating netback”, “funds flow from (used in) operations”.

Operating netback is a benchmark used in the crude oil and natural gas industry to measure the contribution of oil and natural gas sales and is calculated by deducting royalties and operating expenses from revenues. Management utilizes this measure to analyze operating performance.

Funds flow from (used by) operations is cash flow from operating activities before changes in non-cash working capital and certain other items, and is used to analyze operations, performance and liquidity. The Corporation considers funds flow from (used by) operations a key measure as it demonstrates the Corporation’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Corporation’s calculation of funds flow from (used by) operations may not be comparable to that reported by other companies.

The reconciliation between funds flow from (used by) operations and cash flow from (used by) operating activities for the three and nine months ended September 30, 2018 and 2017 is presented in the table below:

Three months ended

September 30

Nine months ended

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Cash flow used by operating activities









Change in non-cash working capital





Funds flow used by operations









These measures are not defined under IFRS and should not be considered in isolation or as an alternative to conventional IFRS measures. These measures and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of another entity. When these measures are used, they are defined as “Non IFRS” and should be given careful consideration by the reader as non-IFRS financial measures do not have a standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers.


Prospera is a Canadian natural resources corporation presently engaged in the acquisition, exploration and development of oil and gas properties in Western Canada.

The Corporation was incorporated on April 14, 2003, under the Canada Business Corporations Act ("CBCA"). The Corporation’s shares initially began trading on the TSX Venture Exchange under the trading symbol "ORR" on March 29, 2005 and on the Frankfurt Exchange under the trading symbol "OF6" on June 21, 2006. On August 25, 2008, the Corporation’s name was changed to "Georox Resources Inc." and the TSX Venture Exchange trading symbol changed to "GXR". On June 28, 2018 the Corporation changed its name to “Prospera Energy Inc. and the TSX Venture Exchange symbol changed to “PEI”.


Revenues from operations were $1,289,934 for Q3 2018 with royalty expenses of $127,051. The Corporation reported a loss of $11,926 for Q3 2018 as compared to a loss of $261,052 for Q3 2017. The reduction in the loss arose as a result of a gain on the disposition of property and equipment and revenues from the newly acquired properties at Cuthbert, Luseland and HeartsHill in June 2018. Total sales volumes for Q3 2018 were 22,212 BOEs (241 BOE per day) as compared to 7,200 BOEs (78 BOE per day) for Q3 2017, representing a 209% increase. The Corporation’s average selling price for Q3 2018 was $58.07 per BOE compared to $47.91 per BOE for Q3 2017, representing a 21% increase.

As at September 30, 2018, the Corporation had a working capital deficit of $7,481,828, including $5,234,776 of outstanding credit facilties. The Corporation’s loan matured on July 31, 2018. The Corporation is in discussions with its lender for an extension and expects to finalize an agreement soon.


Summary Information

As at

As at

As at

September 30

December 31

December 31




Working capital deficit




Property and equipment




Total assets




Total current liabilities




Total liabilities




Total shareholders’ equity




Three months ended

September 30

Nine months ended

September 30





Petroleum and gas revenue






Net loss and comprehensive loss





Net loss per share – basic and diluted





Funds flow used by operations





Weighted average number of common shares – basic and diluted





Selected Quarterly Information

The following table sets forth selected consolidated financial information of the Company for the periods presented.

Sept 30, 2018 $

June 30, 2018 $

Mar 31, 2018 $

Dec 31 2017 $

Sept 30, 2017 $

June 30, 2017 $

March 31, 2017 $

Dec 31, 2016 $










Loss for the period









Loss per share









Over the past eight quarters, the Corporations’s oil and gas revenues have fluctuated due to changes in production volumes and the price realized for the sale of the Corporation’s produciton. The fluctuation was also caused by an increase in production due to the acquisition of properties in June 2018.

Results of Operations

Three months ended

Nine months ended

September 30

September 30





Total sales volumes (BOE)





Daily sales volumes (BOE per day)






Oil and gas revenue ($)





Royalties ($)





Operating and transportion costs ($)





Operating netback ($)






Total production and sales for Q3 2018 and Q3 2017 was 22,212 BOEs and 7,200 BOEs, respectively, representing an increase of 209%. Average netback for Q3 2018 was $18.97 per BOE compared to $14.00 per BOE for Q3 2017. The increase in the Q3 2018 netback occurred because the Corporation operated its own wells at its Red Earth properties and did not use third party facilities for water disposal and oil processing. In addition, production volume from the newly acquired properties led to increased BOEs and revenues despite the fluctuation in prices and, with the price differential decreasing, the result was a Q3 2018 netback improvement.


Total royalties are the combination of royalties paid on crown lands, royalties paid on freehold lands, and gross overriding royalties. However, the overall corporate royalty rates under the Alberta Royalty Framework (“ARF”) are sensitive to both commodity prices and production levels. Therefore royalty rates and royalties under ARF will fluctuate with commodity prices, well production rates, production decline of existing wells and locations of new wells drilled. Royalty expense for Q3 2018 was $5.72 per BOE as compared $3.01 per BOE in Q3 2017. For the nine months ended 2018, the royalty cost was reduced to $4.64 per BOE compared to $5.09 in 2017 and is a result of increased production being spread over a smaller amount of cost in royalties.

Operating Costs

All activities associated with operating the wells and facilities are included in the operating expenses. They include such items as gathering, processing, treating, compression, hauling, lifting and production storage. The average operating cost per BOE for Q3 2018 was $18.97 as compared to Q3 2017 of $33.27 per BOE. In 2018, the average operating cost decreased due to an increased number of BOEs being spread over fixed and semi-fixed costs in general well servicing, water disposal, property taxes and processing fees. In 2018, the Corporation operated all of its wells in the Red Earth area, thereby incurring only minor costs for processing and water disposal fees. However, operating costs tended to fluctuate from month to month depending on the amount of well servicing required to maintain production levels. Management continues to monitor operating costs to minimize expenses where possible.

Transportation costs represent 5% of total revenue in Q3 2018. On a per BOE basis, the cost was $3.05 in Q3 2018 as compared to $5.04 per BOE in Q3 2017. For the nine months ended 2018 and 2017, the cost per BOE was $6.00 and $5.68 respectively. The increase in cost for the nine months in 2018 is largely due to higher volume of fluids being transported to longer distances to move marketable crude oil to selling points. Transportation costs included clean oil trucking and hauling, treating and processing fees, gathering and transmission, compression and marketing fees. There has been a small reduction in trucking costs due to system modifications and upgrades in the facilities. The transportation costs are dependent on a variety of factors such as the method of transportation, the distances covered, the rates charged by the carriers, quantities shipped, cost of fuel, the type of service offered, as well as ownership of the transportation facilities.

General and Administrative

The general and administrative (“G&A”) costs for Q3 2018 and Q3 2017 were $49,587 and $123,960, respectively. G&A costs represented 4% of sales in Q3 2018 as compared to 36% of sales in Q3 2017. Overall G&A costs were lower in Q3 2018 due to overhead recoveries and a decrease in marketing, consulting and office expenses for both Q3 2018 and the nine months ended 2018 as compared to 2017. G&A costs reflect the cost of managing the Corporation’s properties and associated activities and includes legal, transfer agent fees, reserve evaluation fees, audit and accounting and other professional fees. The Corporation directs significant efforts to maintaining or reducing its controllable costs.

Stock-based Compensation

Stock based compensation costs are non-cash charges which reflect the estimated value of stock options granted to officers, employees and consultants. The fair value of all stock options granted is recorded as a charge to operations over the period from the grant date to the vesting date of the option. For the options issued in 2017, 150,000 expire in 2 years, and 200,000 expire in 3 years. The 350,000 options granted in 2017 vest 1/3 immediately, 1/3 on June 30, 2018, and 1/3 on December 31, 2018. The 1,000,000 options granted in 2016 vested 1/4 immediately, 1/4 on April 7, 2017, 1/4 on October 7, 2017 and 1/4 on April 7, 2018 and all of these options expire in 5 years from the grant date. During the quarter ended September 30, 2018 no options of the Corporation were granted.

The Corporation recognized $4,584 of stock-based compensation expense in Q3 2018 as compared to $11,,654 in Q3 2017. For the nine months stock based compensation was $14,435 and $34,072 in 2018 and 2017 showing a reduction in cost in 2018 as a result of no additional options being issued for the nine months in 2018.

Depletion and Depreciation

The Q3 2018 rate of depletion and depreciation ("DDA") was at an average of $18 per BOE as compared to $17 per BOE in Q3 2017 with no significant change. For the nine months ended 2018 and 2017 the per BOE rate was $18.47 and $18.92. The small reduction in 2018 is due to increased depletion as a result of more wells but a significant increase in BOEs resulted in a slight reduction of the overall cost for the nine months. The Corporation uses proved and probable reserves for the calculation of DDA.

Decommissioning Liabilities

The Corporation estimates the total inflation-adjusted undiscounted amount of cash flow required to settle its asset retirement obligations, before salvage proceeds at September 30, 2018 to be $13,360,355 and September 30, 2017 - $1,346,758 which will be incurred at various times over the next twenty years. The fair value of the decommissioning liability was calculated using the risk free rates ranging from 2.18% to 2.43% and an inflation factor of 2.0% (Sept. 30, 2017 – 10.75% to 2.01% and 2.0% respectively). Settlement of the obligations will be funded from general corporate funds at the time of retirement. As at September 30, 2018, no funds have been set aside to settle these obligations.

Business Combination

On June 11, 2018, pursuant to a purchase and sale agreement (the “Agreement”), the Corporation acquired a 100% working interest in producing properties located in southwest Saskatchewan and eastern Alberta (the “Assets”). The Corporation was the lead on the transaction, but was supported by an arm's-length private corporation participant who was responsible for 80% of the purchase price and was subsequently assigned an 80% interest in the Assets and in the rights and obligations under the Agreement. The Corporation is the operator of the Assets for a minimum period of 18 months from the date of closing and holds a 20% working interest in the Assets. Cash consideration of $900,000 was paid by the Corporation for its 20% interest plus $173,865 in adjustments for prepaid lease rentals paid by the vendor between the effective and closing dates.

The Corporation has an option until December 11, 2019 to acquire an additional 10% of the Assets for $1,250,000. Since June 11, 2018, the acquisition contributed $945,322 of petroleum and natural gas revenue and $212,120 of operating income (petroleum and natural gas revenue less royalties and operating expenses) to the Corporation.

The acquisition was accounted for as a business combination using the acquisition method of accounting as follows:

Preliminary fair value of net assets acquired:

Petroleum and natural gas assets



Prepaid lease rentals




Decommissioning liability








The Corporation originally reported a $990,918 gain on business combination and income of $737,885 in the statement of income (loss) and comprehensive income (loss) for the six months ended June 30, 2018. Had the business combination been accounted for as shown the preceding table, no gain would have been recognized and the Corporation would have reported a loss of $263,033 for the six months ended June 30, 2018. The results for the three months ended September 30, 2018 have been reported on this basis. There is no impact on cash flows in any of the current or previously reported periods.


The financial statements have been prepared on a going concern basis which assumes that the Corporation will be able to realize its assets and discharge its liabilities in the normal course of business for the foreseeable future. The Corporation expects to finance its working capital deficiency and its ongoing working capital requirements through cash and adjusted funds flow from operations. The continuing operations of the Corporation are dependent upon its ability to continue to raise adequate financing in the future.

Liquidity risk

The Corporation’s approach to managing liquidity risk is to ensure that it will have sufficient liquidity to meet its liabilities when due. As at September 30, 2018, the Corporation does not have sufficient cash equivalent to settle its $4,291,565 of trade and other payables (December 31, 2017 –­$2,276,006). The Corporation’s working capital deficiency at September 30, 2018 was $7,481,828 (December 31, 2017 – $7,204,444) . All of the Corporation’s trade and other payables have contractual maturities of 30 days or less, are subject to standard trade terms and are scheduled for payment within one year; the Corporation’s credit facilities are classified as current and the Corporation is not in compliance with the related financial covenants.

On May 28, 2018 the Corporation completed a non-brokered private placement (the "Private Placement") of 18,000,000 common shares on an oversubscribed basis for subscriptions of 19,700,000 common shares. The offering was $0.05 per share for aggregate gross proceeds of $985,000. The Private Placement proceeds were used for the payment of the acquisition of oil and gas assets that closed on June 11, 2018 and for general working capital. The Corporation incurred $58,500 of share issue costs comprised of a $52,500 finders fee paid in cash and 120,000 common shares at a deemed price of $0.05.

Credit Facilities


Derivative liabilty


Balance, December 31, 2017







Amounts advanced under Credit Facility B



Principal repayment



Expiry of warrants



Balance, September 30, 2018






As at September 30, 2018, $4,454,923 (December 31, 2017 - $4,662,922) was outstanding on Credit Facility A and $560,202 (December 31, 2017 – $387,180) was outstanding on Credit Facility B.

Principal repayments on Credit Facility A of $50,000 per month shall begin on the last day of the month following the repayment of Credit Facility B. Credit Facility A has a maturity date of July 31, 2018 and has an interest rate of 10% per annum, increasing to 19% per annum in the event of default.

Principal repayments on Credit Facility B are $30,000 per month commencing November 30, 2017, increasing to $50,000 commencing January 31, 2018. Credit Facility B has a maturity date of July 31, 2018 and has an interest rate of 12% per annum, increasing to 19% per annum in the event of default.

On March 27, 2018, the Corporation amended Credit Facility B to add additional security of a promissory note for $125,000 and to increase the sum of the first supplemental debenture to $7,500,000 from $4,000,000. The amount available under Credit Facility B has increased to $725,000 (from $600,000) and was to be used for the purpose of funding a waterflood project and paying outstanding property taxes at the Corporation’s Red Earth property.

The Credit Facilities A and B (collectively, the “Amended Credit Facilities”) are secured by promissory notes for $4,622,945 and $600,000, a $25,000,000 fixed and floating charge debenture, a general security agreement on the assets of the Corporation and a $4,000,000 debenture from the Corporation providing a security interest in all present and after-acquired personal property, a fixed charge on all the oil and gas assets and a floating charge over all other present and after-acquired real property.

On September 8, 2017, the Corporation entered into a Forbearance Agreement and a Quitclaim with the Lender.

Participation fee

Per the terms of the Amended Credit Facilities, the Lender may be entitled to a participation fee on the 2018 net revenues (defined as total revenues less royalties) up to a cumulative amount of $500,000.


At September 30, 2018, the Corporation was in breach of all the covenants except for maintaining an LLR of 1.5 or greater. As of the date of this MD&A, the Corporation and the Lender are negotiating the terms of the lending arrangement and the Amended Credit Facilities, including the participation fee, covenants and related default interest,if any.


Common shares

Stock options



Balance, December 31, 2017





Issued/granted 2018





Balance, September 30, 2018 and date of MD&A






The Corporation has no off-balance sheet arrangements.


During the nine months ended September 30, 2018, $50,000 (September 30, 2017 - $40,000) was expensed for legal services provided by a law firm of which a director of the Corporation is a partner. Included in trade and other payables at September 30, 2018 is $66,000 (September 30, 2017 - $63,014) owing to this law firm.

During the nine months ended September 30, 2018, management, consulting and engineering fees of $105,182 (September 30, 2017 - $78,000), included in general and administrative expenses, were charged by two officers of the Corporation and by a Corporation controlled by an director. Included in trade and other payables at September 30, 2018 is $32,122 (September 30, 2017 - $24,000) owing to these officers.

The above transactions with related parties are in the normal course of business.


Key management personnel include executive officers and non‑executive directors. Executive officers are paid a salary and participate in the Corporation’s stock option program. The executive officers include the Chief Executive Officer and Chief Financial Officer. Non‑executive directors also participate in the Corporation’s stock option program. Key management personnel compensation is comprised of the following:

Three months ended

September 30

Nine months ended

September 30





Salaries and short-term benefits









Stock-based compensation













During the nine months ended September 30, 2018, 75,000 DSU’s were granted to directors of the Corporation (September 30, 2017 – 336,818), with a fair value of $3,750 (September 30, 2017 - $17,500) which is included in general and administration expense. As at September 30, 2018, 1,145,420 DSU’s (December 31, 2017 – 933,241), were outstanding and the fair value of the DSU’s of $73,750 (December 31, 2017 - $70,000) is included in trade and other payables.


The Corporation has not declared or paid any dividends. Any decision to pay dividends on any of its shares will be made by the Board of Directors of the Corporation on the basis of earnings, financial requirements and other conditions existing at the time.


The Corporation has signed a consent judgment with respect to a long standing dispute with the operator of its Red Earth properties, pursuant to which the Corporation accrued a contingency amount in trade and other payables in its 2017 financial statements. The Corporation has now paid $150,000 in full settlement of this debt of the $501,000 held in trade payables. On November 26, 2018, the Corporation received notice that the former operator’s writ of enforcement and security agreement in respect of the these properties were discharged

On November 26, 2018, the Corporation received notice that the operator’s writ of enforcement and security agreement in respect of the Corporation’s Red Earth properties were discharged. The Corporation has paid $150,000 in full settlement of this debt.


The fair values of the Corporation’s cash and cash equivalents, funds held in trust, trade and other receivables, investments, bank indebtedness, trade and other payables and credit facilities approximate their carrying amounts due to the short-term nature of these financial instruments.

The Corporation’s accounts receivable are primarily with industry partners and are subject to standard industry credit risks. The Corporation extends unsecured credit to these entities, and therefore, the collection of any receivables may be affected by changes in the economic environment or other conditions. Management believes the risk is mitigated by the financial position of the entities. To date, the Corporation has not participated in any risk management contracts or commodity price contracts.


The risks in the oil and gas industry are varied and wide-ranging:

  • Going Concern
  • The Corporation's business is capital intensive and additional capital is required on a periodic basis. Specifically, continuing operations, as intended, are dependent on management’s ability to raise required funding through future equity issuances, credit facilities, asset sales or a combination thereof, which is not assured, especially in the current uncertain financial and commodity price environment. The sharp decline in commodity prices during the latter half of 2014 through to the second quarter ended June 30, 2017, negatively affected the Corporation's ability to access additional capital on terms acceptable to the Corporation, which is required for liquidity purposes and to fund commitments on the Corporation's properties. The current world-wide economic environment relating to the oil and gas industry has made access to capital challenging for many companies, including the Corporation. This has resulted in liquidity challenges and unless the Corporation is able to raise additional capital or renegotiate its commitments, it does not anticipate meeting all of its anticipated 2018 capital commitments. Furthermore, there is potential that future commodity prices and the world-wide economic environment relating to the oil and gas industry, in general, will remain relatively stagnate in its current position for an extended period of time and the Corporation will need to negotiate with its creditors to improve payment terms and/or pursue some form of asset sale, equity financing or other capital raising effort in order to fund its operations during the next twelve months. To that end, the Corporation is currently, and will continue, on an ongoing basis, examining alternative sources of capital, including potential debt and equity financing and ways to monetize its assets, including, without limitation, asset sales or swaps, joint ventures, corporate mergers or acquisitions, farmouts or other transactions with industry partners, all with a view to enhancing liquidity and meet commitments. The need to raise capital or defer expenditures to fund ongoing operations creates uncertainty that may cast doubt over the Corporation's ability to continue as a going concern. There is no certainty that these and other strategies will be sufficient to permit the Corporation to continue as a going concern.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field-operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut in of connected wells for various reasons including access issues resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical issues. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

A material change in prices of commodities may affect the Corporation’s borrowings, ultimately affecting the raising of equity capital by the Corporation.

Global Financial Crisis

Recent market events and conditions, including disruptions in the international credit markets and to the financial systems, and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions are continuing in 2018 causing a loss of confidence in the broader Canadian and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate. These factors have negatively impacted corporate valuations and will impact the performance of the global economy going forward.

Commodity Price Risk

The nature of the Corporation’s operations results in exposure to commodity fluctuations. The Corporation closely monitors commodity prices to determine the appropriate course of action to be taken by the Corporation. A material change in prices of commodities affected the Corporation’s borrowings, ultimately affecting the raising of equity financing. The Corporation does not hedge commodity price risk and has no physical forward price or financial derivative sales contracts as at or during the quarter ended Sepember 30, 2018. Although improved, petroleum prices are expected to remain volatile for the near future as a result of the market uncertainties over the supply and demand of these commodities due to the current state of the world economies, OPEC actions, regional conflicts and the ongoing global credit and liquidity concerns.

Operational Dependence

Other companies operate various producing wells in which the Corporation holds interests except for the two wells that the Corporation operates in the Pouce Coupe property, nine wells in its Red Earth property and over one hundred and ten wells in its recent acquisition. The Corporation has limited ability to exercise influence over the non-operated assets or their associated costs, which could adversely affect the Corporation’s financial performance. The Corporation’s return on assets operated by others therefore depends upon a number of factors that may be outside of the Corporation’s control, including the timing and amount of capital expenditures, the operator’s expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

Regulatory Compliance

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Such regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase the Corporation’s costs, any of which may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. In order to conduct oil and gas operations, the Corporation will require licenses from various government authorities. There can be no assurance that the Corporation will be able to obtain all of the licenses and permits that may be required to conduct operations that it may wish to undertake.


All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge. Although the Corporation believes that it will be in material compliance with current applicable environmental regulations no assurance can be given that environmental laws will not result in a curtailment of production or a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on the Corporation and its operations and financial condition.

Substantial Capital Requirements

The Corporation anticipates making capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future in order to replace reserves. If the Corporation’s revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. In addition, uncertain levels of near term industry activity exposes the Corporation to additional access to capital risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes including repayment of loan facilities when due or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. The inability of the Corporation to access sufficient capital for its operations and capital requirements could have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects.


The Corporation may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Corporation which may be dilutive.

Conflicts of Interest

Certain directors of the Corporation are also directors of other oil and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if any, will be subject to the procedures and remedies of the CBCA. See "Directors and Officers – Conflicts of Interest".


The Corporation reviews legal, environmental remediation and other contingent matters to both determine whether a loss is probable based on judgment and interpretation of laws and regulations, and determine that the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. The Corporation’s management monitors known and potential contingent matters and makes appropriate provisions by charges to earnings when warranted by circumstances.


On January 1, 2018, the Corporation retrospectively adopted IFRS 9 Financial Instruments (“IFRS 9”) which includes new requirements for the classification and measurement of financial assets, a new credit loss impairment model and new model to be used for hedge accounting for risk management contracts. The Corporation does not currently have any risk management contracts. The adoption of IFRS 9 did not have a material impact on the Corporation’s unaudited condensed interim financial statements and management applied the provision matrix practical expedient as part of the adoption of the standard. The additional disclosures required by IFRS 9 are detailed in Note 5 to the Corporations’ unaudited September 30, 2018 condensed interim financial statements.

On January 1, 2018, the Corporation adopted IFRS 15 Revenue from Contracts with Customers (“IFRS 15”) using the retrospective method of adoption. The adoption of IFRS 15 did not have a material impact on the Corporation’s unaudited condensed interim financial statements and as a result, the Corporation did not apply any practical expedients as part of the adoption of IFRS 15. The additional disclosures required by IFRS 15 are detailed in Note 12 to the Corporations’ unaudited September 30, 2018 condensed interim financial statements.


IFRS 16 Leases issued on January 13, 2016 by the IASB replaces IAS 17 Leases. The new standard introduces a single recognition and measurement model for leases, which would require the recognition of assets and liabilities for most leases with a term of more than twelve months. The new standard is effective for annual periods beginning on or after January 1, 2019. The Corporation continues to assess this new standard, but does not expect it to have a significant impact.


The preparation of consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amount of assets, liabilities, income and expenses. Actual results may differ materially from estimated amounts. Estimates and their underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and for any future years affected.

Detailed disclosures on the Corporation’s use of critical judgments in applying accounting policies and key sources of estimation uncertainty can be found in Note 3(d) to the Corporation’s audited December 31, 2017 financial statements.


The information provided in this MD&A and the Corporation’s financial statements is the responsibility of management. In the preparation of this information, estimates are sometimes necessary to make a determination of future values for certain assets or liabilities. Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying financial statements.

Management maintains a system of internal controls to provide reasonable assurance that the Corporation’s assets are safeguarded and to facilitate the preparation of relevant and timely disclosure information.


Burkhard Franz, Kelowna, BC, Canada

Daryl Fridhandler, Calgary, AB, Canada

Lorraine McVean, Calgary, AB, Canada


Daryl Fridhandler, Chairman

Burkhard Franz, President & CEO

Savi Franz, Chief Financial Officer


Corporate Office:

Ste 700, 1300-8 Street SW, Calgary, AB T2R 1B2


MNP LLP,800-700 6th Avenue, S.W., Calgary, Alberta T2P 0T8

Legal Counsel:

Burnet, Duckworth & Palmer LLP,

Suite 2400, 525-8th Avenue S.W., Calgary, Alberta, Canada T2P 1G1

Transfer Agent:

Computershare Trust Company of Canada,

100 University Ave., 11th Fl., South Tower, Toronto, ON M5J 2Y1


ATB Financial

102 – 8th AVE. S.W. Calgary, Alberta T2P 1B3