Regal Energy Ltd.
TSX VENTURE : REG

Regal Energy Ltd.

January 25, 2007 16:30 ET

Regal Energy Ltd. Fiscal 2006 Financial and Operating Results

CALGARY, ALBERTA--(CCNMatthews - Jan. 25, 2007) -

NOT FOR DISTRIBUTION IN THE UNITED STATES OF AMERICA

Regal Energy Ltd. (TSX VENTURE:REG) ("Regal" or the "Corporation") announces its year-end September 30, 2006 Financial (audited) and Operating Results and its Fiscal 2007 Guidance.



FISCAL 2006 FINANCIAL AND OPERATING RESULTS

For the twelve For the twelve
months ended months ended
September 30, September 30,
2006 2005

Financial (1)
Petroleum and natural gas sales $ 1,166,262 $ n/a
Funds flow from operations (2) $ (618,011) $ 671,965
Earnings (loss) (3) $ (5,627,150) $ 397,526
Capital expenditures (4) $ 7,218,749 $ 846,251
Working capital surplus (deficiency) $ (1,244,560) $ 271,141
Total assets $ 9,484,850 $ 1,690,141
Shareholders' equity $ 7,277,130 $ 1,192,390

Shares outstanding as of Jan. 23, 2007 33,952,590
Shares issuable upon exercise of warrants
as of Jan. 23, 2007 2,640,232
Stock options outstanding as of Jan. 23, 2007 1,626,000

Operating (1)
Production:
Natural gas (Mcf) 76,958 n/a
Oil and NGLs (Bbl) 12,923 n/a
Total production (Boe) (5) 25,749 n/a

Natural gas (Mcf/d) 211 n/a
Oil and NGLs (Bbl/d) 35 n/a
Total production (Boe/d) (4) 71 n/a

Average selling price:
Natural gas ($/Mcf) 6.10 n/a
Oil and NGLs ($/Bbl) 53.93 n/a
Total production ($/Boe) (5) 45.29 n/a
Operating Netback ($/Boe) (5) 4.12 n/a

Reserves (1)(5)(6)
Proved plus probable:
Natural gas (MMcf) 1,906 n/a
Oil and NGLs (MBbl) 126 n/a
Total barrels of oil equivalent (MBoe) (5) 443 n/a
Net present value of future net revenues
before tax ($M): (7)
@ 10% discount rate 5,578 n/a
@ 15% discount rate 4,823 n/a

Notes:
(1) Effective with the takeover of Regal Energy Corp. on December 31, 2005,
the Corporation began receiving a revenue stream from crude oil and
natural gas sales. No comparative sales for fiscal 2005 or the first
quarter of fiscal 2006 are available.
(2) Funds flow before net change in non-cash operating working capital
balances does not conform to Generally Accepted Accounting Principles
(GAAP). Refer to the "Non-GAAP Measurements" and "Net Earnings and
Funds Flow from Operations" sections of the Management's Discussion and
Analysis.
(3) Includes a $4.2 million ceiling test write down as at September 30,
2006.
(4) Amounts reported do not include amounts charged to capital as a result
of the takeover of Regal Energy Corp. on December 31, 2005, non cash
capital recorded for asset retirement obligations and is net of
dispositions.
(5) Natural gas is converted to oil equivalent at 6 Mcf = 1 Bbl. A Boe
conversion ratio of 6 Mcf = 1 Bbl is based on an energy equivalency
conversion method and does not represent a value equivalency at the
wellhead; therefore Boe's may be misleading if used in isolation.
(6) As at September 30, 2006 as determined by GLJ Petroleum Consultants in
accordance with NI 51-101. Working interest share of reserves before
deduction of royalties. Forecast Prices and Costs.
(7) Proved plus probable reserves. Forecast Prices and Costs.


Regal's fiscal year ended September 30, 2006 was one of challenges and new opportunities. In December 2005 we closed a significant flow-through financing that provided us with the necessary capital to make farm-in and drilling commitments in several new areas. A total of nine wells were drilled to the end of our fiscal year resulting in six natural gas wells (5.2 net), two oil wells (1.6 net) and one abandoned well (0.6 net). Four of the gas wells were tied in and producing and the other two gas wells were waiting on completion and tie-in as of our fiscal year-end. The two oil wells initially produced at economic rates but were later suspended due to high operating costs. Our year-end results showed a loss, mainly due to a ceiling test writedown. It has taken more time than originally anticipated to get the desired momentum but we are pleased to report that we are now seeing this happen.

During our first quarter of fiscal 2007, as a result of a very active and successful drilling program, Regal established a strong platform for future growth. We are pleased to report that the flow-through commitments associated with our previous financings were completed in December 2006 and that the higher levels of activity and expenditures in the most recent quarter were met with successful wells. During the first quarter of fiscal 2007 a further eight wells (4.9 net) were drilled resulting in seven natural gas wells (4.6 net) and one abandoned well (0.3 net). We are presently scheduling the tie-in of production from three of the new gas wells completed to date.

One of Regal's stated business objectives is to pursue multi-section farm-ins to increase our land holdings. During calendar 2006 we were successful in achieving this objective through our farm-in and drilling activities at Garrington, Kaybob, Pica and Hanna in Alberta and Eight Mile in British Columbia.

The Garrington property located in west central Alberta was the Corporation's main area of focus during the year. In January 2006 we announced a significant farm-in at Garrington encompassing over 30 sections of mostly contiguous land. Subsequent to signing this agreement, Regal signed farm-in agreements with other companies covering some of the same lands and other lands where we identified exploratory prospects. Drilling operations commenced in March 2006 and three wells were drilled and cased as potential natural gas wells. Following an extended spring breakup, one additional gas well was drilled and cased in early June. The first three gas wells were completed in June and placed on stream in July. The fourth well was completed in August but the tie-in of this well was delayed until late November due to wet field conditions and delays in obtaining surface access. A fifth well was drilled and cased as a potential Mannville gas well in September.

Regal's activity level at Garrington accelerated in the fall of 2006 resulting in new gas reserves not included in our September year-end results and additional behind pipe gas production that is expected to commence in 2007. In October we completed a successful Mannville gas well that is scheduled for tie-in during January 2007 and we purchased interests in five sections of developed and undeveloped lands that included two producing natural gas wells. We also agreed in October to drill three further Mannville test wells to extend our initial farm-in agreement. Concurrently with this agreement, we secured a sub-participation and farm out agreement with a large oil and gas company to drill the three Mannville test wells on lands included in our initial farm-in agreement and on lands acquired by Regal. The first test well was recently drilled and cased and the remaining two test wells are scheduled to be drilled by the end of February 2007. We anticipate that Regal will earn 100% of the farmor's interest in approximately six sections of Edmonton gas rights as a result of the drilling of these wells, at no cost to Regal and we will also fulfill our second commitment obligation. In addition, one of the proposed test wells is located on a section where Regal currently holds a 40% working interest in the Mannville rights. If a successful Mannville well is drilled and completed, Regal will own a 12% working interest in the well, again at no cost to the Corporation.

In November 2006 at Garrington we tied-in one gas well and drilled and cased one potential gas well and in December 2006 we drilled and completed two additional gas wells. We now hold interests in 13.75 sections of land, six producing gas wells and four gas wells scheduled for tie-in during 2007 in the area. Regal is positioned at Garrington with an expanding land base for exploratory and development drilling activity operated by the Corporation and by our joint venture partners during 2007.

Subsequent to our fiscal 2006 year-end, Regal also announced new exploratory prospects at Eight Mile, located near Fort St. John in northeast British Columbia, Pica in northwest Alberta and Hanna in east central Alberta. A total of four commitment wells (1.7 net) were drilled and cased in these new areas prior to the end of December 2006. Regal will be participating in completion activities on these new wells during 2007. Upon completion of the wells Regal will earn interests in eight sections of land and have rolling options on a further 33 sections of land, including 17 sections at Eight Mile, five sections at Pica and 11 sections at Hanna.

FISCAL 2007 GUIDANCE

Regal exited calendar 2006 at a production rate of approximately 170 Boe/d comprised of 820 Mcf/d of natural gas and 33 Bbl/d of crude oil and NGLs. This was lower than our anticipated exit target of 400 Boe/d, however, we estimate that Regal now has sufficient behind pipe capacity from recently drilled wells to achieve our previous 400 Boe/d target during fiscal 2007. We anticipate Regal will average 300 barrels of oil equivalent per day of production during fiscal 2007 with a September 30, 2007 exit rate target of 400 Boe/d. Funds flow is expected to be approximately $1.7 million based on wellhead prices of $52.60 per barrel for oil and NGLs, and $6.75 per thousand cubic feet for natural gas.

Our capital budget for fiscal 2007 is currently forecast to be $7.1 million, including approximately $4.4 million spent during the first fiscal quarter ended December 31, 2006. Of the $2.7 million remaining to be spent during fiscal 2007, approximately 70% is allocated to complete and tie-in recently drilled wells, 20% to drilling and 10% to land and seismic. Only two additional wells are currently forecast to be drilled during the remainder of fiscal 2007 however, this number may increase as we follow up on our recent successful drilling program. Overall for fiscal 2007, under the current forecast, Regal will spend $3 million to drill, $1.8 million to complete and $1.4 million to equip a total of 10 (6.7 net) wells. This includes 8 wells (4.9 net) that were drilled during the first quarter of fiscal 2007. In addition, $0.4 million is allocated to land and seismic and $0.5 million to an acquisition at Garrington that was closed on October 5, 2006. Regal's net cash outlay for its capital expenditures during fiscal 2007 will be approximately $6.5 million after receiving $0.7 million from the sale of a seismic royalty interest in November 2006.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is management's discussion and analysis ("MD&A") of Regal Energy Ltd's. ("Regal" or "the Corporation") audited operating and financial results for the year ended September 30, 2006. This MD&A should be read in conjunction with Regal's audited financial statements for the year ended September 30, 2006. Additional information relating to Regal is available on SEDAR at www.sedar.com. The information provided in this MD&A is current as at January 23, 2007.

INTRODUCTION AND LIMITATIONS

BASIS OF PRESENTATION

The financial data presented herein has been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and in accordance with specific accounting policies as set out in Note 2 to the Corporation's audited financial statements for the year ended September 30, 2006. During fiscal 2005, the Corporation was a private company and quarterly reports were not required nor were they prepared, therefore comparative results by quarter have not been included. Annual comparative results have been presented where appropriate. Also during 2005, the Corporation underwent a change of business direction from technology to oil and gas exploration and development.

NON-GAAP FINANCIAL MEASUREMENTS

The Corporation has used certain measures of financial reporting that are commonly used benchmarks within the oil and natural gas industry in this MD&A that are considered to be non GAAP measures. The measures used and referenced in this document include "operating netback" and "funds flow from operations". Operating netback is a benchmark used in the oil and gas industry to measure the contribution of crude oil and natural gas sales after deducting royalties and operating costs. Regal determines funds flow from operations to be the cash flow before changes in non-cash working capital. Management believes that in addition to net earnings, funds flow from operations is a useful supplemental measure to assess the financial performance and ability of Regal to finance future spending. These measures are not defined under GAAP and should not be considered in isolation or as an alternative to conventional GAAP measures. These non-GAAP measures may not necessarily be comparable to similarly titled measures used by other entities and readers of this MD&A are cautioned in attempting to make such comparisons.

OTHER MEASUREMENTS

The reporting and measurement currency of this MD&A is the Canadian dollar. For the purposes of calculating unit costs, natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. (This conversion conforms to NI 51-101). References to natural gas liquids ("NGLs") in this MD&A include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe).

ADVISORY REGARDING FORWARD LOOKING STATEMENTS

Certain information set forth in this MD&A, that are not historical facts, including management's assessment of Regal's future plans and operations, contains "forward looking statements". All estimates and statements that describe the Corporation's objectives, goals, or future, including management's assessment of future plans and operations, production estimates and expected production rates, timing of tie-ins and the effect of delays in tieing-in wells and the effects of third party compressor issues and other infrastructure issues, levels of decline rates and the effects thereof, expected royalty rates, expected general and administrative expenses and other expenses, effects of the results of successful wells, expected levels of capital expenditures and the method of funding them, the ability to incur qualifying expenditures renounceable to purchasers of flow-through shares and the expected levels of activities and results of operations of Regal may constitute forward looking information under securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals, the impact of general economic conditions and industry conditions, the lack of availability of qualified personnel or management, stock market volatility and the ability to access sufficient capital from internal and external sources.

As a consequence Regal's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward looking statements and, accordingly no assurance can be given that any events anticipated by the forward looking statements will transpire or occur, or, if any of them do so, what benefits Regal will derive there from. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could effect Regal's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and Regal's website (www.regalenergy.ca). Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward looking statements. Furthermore, the forward looking statements contained in this MD&A are made as at the date of this MD&A and Regal does not undertake any obligation to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

THE CORPORATION

The Corporation was incorporated pursuant to the Canada Business Corporations Act on August 7, 1998 as "3519309 Canada Incorporated". On September 28, 2002, 3519309 Canada Incorporated amalgamated to form SiberCore Technologies Incorporated. The Corporation at that time was a semiconductor company developing high value-added standard chips for intelligent hardware based switching and routing platforms.

The shareholders of the Corporation approved a change of business direction on December 17, 2004 that resulted in the distribution of cash and technology assets to shareholders as a return of capital, the consolidation of the common shares of the Corporation on the basis of 1 for 30,000, conversion of the preferred shares of the Corporation on the basis of 0.012 common shares for each preferred share, and a change in the name of the Corporation from SiberCore Technologies Incorporated to Azeri Capital Inc. ("Azeri").

On December 30, 2004 the Corporation entered into a seismic joint venture agreement (the "Seismic JV") with Divestco Seismic Limited Partnership ("Divestco") and Spectrum Seismic Processors Ltd. The seismic underlying the Seismic JV is the majority of the proprietary seismic data of a senior Canadian integrated oil and gas company which consists of over 32,000 km of 2D data covering several areas throughout Alberta and Saskatchewan that was acquired by Divestco. Pursuant to the Joint Venture, the Corporation agreed to fund the estimated cost of reprocessing the seismic data of $1,375,000, and in exchange, the Corporation acquired for its own use a fully reprocessed copy of this seismic data as well as certain other geological and geophysical software usage, and a residual royalty on sales of the entire reprocessed database and individual line by line data sales. On November 9, 2006, this residual royalty was sold for $675,000. On December 30, 2004, the Corporation completed a private placement of 226,464 shares issued on a "flow-through" basis for aggregate gross proceeds of $1.36 million.

On December 31, 2005, the Corporation acquired, by way of a Plan of Arrangement, all of the issued and outstanding shares of Regal Energy Corp., a public company listed on the TSX Venture Exchange, and changed the Corporation's name to Regal Energy Ltd. Pursuant to the Arrangement, the Corporation reorganized its share capital whereby the issued and issuable shares were split on a 7.37 for one basis. Shareholders of Regal Energy Corp. received one share of the Corporation for each five shares of Regal Energy Corp. previously held.

The Corporation was continued under the Business Corporations Act. (Alberta) on December 31, 2005. As the acquisition occurred on December 31, 2005, results from Regal Energy Corp.'s operations are included in the Corporation's financial statements from January 1, 2006 forward.

The principal and head office of the Corporation is located at Suite 1520, Life Plaza 734 - 7th Avenue S.W., Calgary, Alberta T2P 3P8. The registered office of the Corporation is located at Suite 1600, Dome Tower, 333 - 7th Avenue S.W., Calgary, Alberta T2P 2Z1.

The Corporation has no subsidiaries.

Regal Energy Ltd.'s common shares are listed and posted for trading on the TSX Venture Exchange under the symbol REG.

During the year ended September 30, 2005, which is the annual comparative period that results are compared to 2006 results, the Corporation was positioning itself to become a full cycle operating public oil and gas company. For the period October 1, 2004 to December 17, 2004 when the Corporation underwent a change in business direction, results of operations were from technology, an unrelated business from the sector the Corporation currently operates in. The primary events that occurred during the period December 18, 2004 to September 30, 2005 were the signing of the Seismic JV and a private placement financing. The Corporation expended $921,249 of capital reprocessing seismic data during fiscal 2005.

On October 19, 2005, the Corporation entered into a farm-in agreement with Regal Energy Corp. to participate in the drilling of four wells. During the period from entering into the agreement until the takeover of Regal Energy Corp. was completed on December 31, 2005, approximately $856,800 was expended on this farm-in. As well as the above activity during fiscal 2005 the Corporation's focus was to ready itself to acquire a publicly traded oil and gas company. This was achieved on December 31, 2005 and all annual results reported for producing oil and gas assets are only for the nine month period January 1, 2006 to September 30, 2006 as a result of this acquisition. In fiscal 2005, the Corporation had operating income during the period October 1, 2004 to December 17, 2004 of $339,577 and an operating loss from the oil and gas segment of $145,651. Total operating income before tax for fiscal 2005 was $193,926.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by Regal Energy Ltd. are disclosed in Note 2 to the Financial Statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Changes in these judgments and estimates may have a material impact on the Corporation's financial results and condition. The following discusses such accounting policies and is included in this MD&A to aid the reader in assessing the critical accounting policies and practices of the Corporation and the likelihood of materially different results being reported. Regal's management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies is not meant to be exhaustive. The Corporation might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

Oil and Gas Reserves

Under NI 51-101, "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable (it is likely that the actual remaining quantities recovered will exceed the estimated Proved reserves). In accordance with this definition, the level of certainty targeted by the reporting company should result in at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated reserves. In the case of "Probable" reserves, which are obviously less certain to be recovered than Proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves. With respect to the consideration of certainty, in order to report reserves as Proved plus Probable, the reporting company must believe that there is at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.

The implementation of NI 51-101 has resulted in a more rigorous and uniform standardization of Reserve evaluation. Proved plus Probable reserves as defined in NI 51-101 are viewed by many industry participants as being comparable to the "Established" reserves definition that was used historically. The oil and gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the Corporation's plans. The reserve estimates are also used in determining the Corporation's borrowing base for its credit facilities and may impact the same upon revisions or changes to the reserves estimates. The effect of changes in proved oil and gas reserves on the financial results and position of the Corporation is described as follows under the heading "Full Cost Accounting for Oil and Gas Activities".

Full Cost Accounting for Oil and Gas Activities

Depletion Expense

The Corporation follows the full cost method of accounting for oil and natural gas operations whereby all costs relating to the acquisition, exploration and development of oil and natural gas reserves, including asset retirement costs, are initially capitalized into a single Canadian cost centre. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, related production equipment costs, asset retirement costs and overhead charges directly related to the acquisition, exploration and development activities. Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such sale would result in a greater than 20% change in the depletion rate.

Depletion of petroleum and natural gas properties and depreciation of production equipment is provided for using the unit-of-production method based upon estimated proven petroleum and natural gas reserves as determined by independent engineers and updated internally on an intra-period basis. Petroleum and natural gas reserves and production are converted to equivalent barrels of oil using a ratio of six thousand cubic feet of natural gas to one barrel of oil.

An increase in estimated proved oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense.

Withheld Costs

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

Full Cost Accounting Ceiling Test

The Corporation applies a two-stage ceiling test to capitalized costs to ensure that such costs do not exceed the undiscounted future net revenues from production of proved reserves. Undiscounted future net revenues are calculated based on an independent petroleum engineer's best estimate of forward indexed prices applied to estimated future production of proved reserves plus anticipated proceeds from the sale of undeveloped properties, less estimated future operating costs, royalties, future capital development costs and abandonment costs. When the carrying amount of a cost centre is not recoverable, the second stage of the process will determine the impairment amount, whereby the carrying value of the cost centre would be written down to its fair value. The second stage of the calculation requires a comparison between the carrying value and the discounted future net revenues from proved plus probable reserves using the Corporation's risk free interest rate plus the cost of undeveloped land, net of any impairment. The fair value is estimated using accepted present value techniques, which incorporate risks and other uncertainties when determining expected net revenues.

Asset Retirement Obligations

The Corporation recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred and when a reasonable estimate of the fair value can be made, and records a corresponding increase in the carrying value of the related long-lived asset. The fair value is determined through a review of engineering studies, industry guidelines, and management's estimate on a site by site basis. The liability is subsequently adjusted for the passage of time, which is recognized as an accretion expense in the statement of operations and deficit. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. Actual costs incurred upon settlement of the asset retirement obligations are charged against the asset retirement obligation to the extent of the liability recorded.

Income Tax Accounting

The Corporation follows the liability method of accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between financial reporting and income tax bases of assets and liabilities, and are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change is substantively enacted. A valuation allowance is recorded against a future income tax asset if it is considered to be more likely than not that the asset will not be realized.

Intangible Assets

Pursuant to the acquisition of Regal Energy Corp. on December 31, 2005, an intangible asset has been recognized on the balance sheet of $500,000 that represents the value placed on the management team under contract and the public listing of Regal Energy Corp. The cost of intangible assets are periodically tested for impairment and are excluded from the depletion calculation. Intangible assets are being amortized over a period of three years.

Legal, Environmental Remediation and Other Contingent Matters

The Corporation is required 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 must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstance.

CORPORATE DEVELOPMENTS

On December 15, 2005 the Corporation completed a private placement of 737,000 common shares at a price of $0.88 per share for gross proceeds of $650,000. In addition, on December 15, 2005, the Corporation completed a flow-through share financing on a private placement basis of 8,217,550 common shares at a price of $0.98 per share for gross proceeds of $8,028,000. In connection with these private placements, there were 817,923 agents warrants issued that entitle the holder to acquire one common share of the Corporation for each warrant held at a price of $0.88 until June 30, 2007.

On December 31, 2005, the Corporation acquired, by way of a Plan of Arrangement, all of the issued and outstanding shares of Regal Energy Corp., a public company listed on the TSX Venture Exchange, and changed the Corporation's name to Regal Energy Ltd. The Corporation was continued under the Business Corporations Act. (Alberta) on December 31, 2005. As the acquisition occurred on December 31, 2005, results from Regal Energy Corp.'s operations are included in the Corporation's financial statements from January 1, 2006 forward.

On January 13, 2006, the Corporation executed a multi-well farm-in and option agreement with a public company encompassing over 30 sections in the Garrington area of west central Alberta. The majority of the farm-in lands are contiguous and rights vary to the base of the Mannville zone which is approximately 2,600 metres in depth. Under the terms of the agreement, the Corporation committed to drill and complete (or abandon) a minimum of six wells by August 1, 2006. This time frame was extended to December 2006, subject to surface accessibility. As at the date of this report the Corporation has fulfilled its commitment under this obligation.

Pursuant to the farm-in agreement, Regal pays 100% of the farmor's share of drilling and completion costs to earn 50% of the farmor's working interest. Following completion of the first six wells the farmor elected to convert its interest in these wells to a non-convertible gross overriding royalty of 15% on the farmor's pre-farmout working interest. The Corporation has agreed to utilize the farmor's facility infrastructure to gather and process its gas on a custom process fee basis whenever possible. Regal also agreed to utilize the farmor's field operators to contract operate the Corporation's wells.

On March 6, 2006 Regal executed a second farm-in agreement encompassing four sections of land at Garrington. This farm-in agreement included partial interests in four sections that were also included under the Corporation's initial farm-in and option agreement. The terms of this farm-in agreement allow for the farmor to receive an overriding royalty of 12% on production on a well by well basis until payout, at which time the farmor converts to a working interest equivalent to 50% of their pre-farmout working interest. The Corporation satisfied its commitment under this agreement through the drilling of four Edmonton zone gas wells during March and June 2006.

On March 10, 2006, the Corporation executed a third farm-in and option agreement in the Garrington area. Under the terms of the agreement, the Corporation committed to drill and complete (or abandon) one well. The terms of this farm-in agreement allow for the farmor to receive an overriding royalty of 12% on production from the well until payout, at which time the farmor converts to a working interest equivalent to 50% of their pre-farmout working interest. The Corporation satisfied its commitment under this agreement through the drilling of a gas well in November 2006.

On March 16, 2006 Regal announced a new gas well at Kaybob, Alberta in which the Corporation holds a 61.5 percent working interest. The well commenced natural gas and NGLs production in June 2006 through third party processing facilities.

Effective August 1, 2006 the Corporation sold its minor working interest in the Morinville, Alberta property for a price of $408,910. The Morinville property was producing approximately 8 Bbl/d of crude oil net to the Corporation.

On September 25, 2006 the Corporation agreed to participate at a 25% working interest in a Mannville zone natural gas test well at Garrington that was drilled and subsequently abandoned in October 2006.

On October 5, 2006, the Corporation purchased certain developed and undeveloped lands in the Garrington area. The acquisition was effective September 1, 2006 and included a 100% interest in two producing gas wells and varying interests in 5.25 sections of land.

On October 12, 2006 the Corporation agreed to participate in a natural gas prospect located in northeast British Columbia by way of farm-in. The Corporation entered into an area of mutual interest ("AMI") covering 35 square miles of land in northeast British Columbia, located south of Fort St. John, called the Eight Mile Prospect. The Corporation agreed to drill and complete two wells in the initial program. The two commitment wells were drilled and cased in November and December 2006. The Corporation will earn interests in four sections of land following completion of the wells. Regal expects to have a series of option wells in order to continue earning lands through drilling additional wells. The farmor holds a 100% interest in 21 sections within the AMI and the majority of the farm-out lands are contiguous.

On October 19, 2006 the Corporation announced its intention to proceed with a rights offering to shareholders (the "Rights Offering") by way of a rights offering circular and the Corporation announced its intention to issue up to 4,583,333 flow-through shares at $0.24 per flow-through share, and a minimum of 5,000,000 common shares at $0.20 per share (the "Private Placements") with Nova Bancorp Securities Ltd. acting as Agent (the "Agent") for the Offering. In addition, in the event the Rights Offering resulted in gross proceeds of less than $1 million, the Agent would have an over allotment option to sell an additional amount of common shares equal to the difference between $1 million and the gross proceeds of the Rights Offering.

On November 3, 2006, the Corporation agreed to drill three additional Mannville test wells by the end of February 2007 to extend its initial farm-in and option agreement in the Garrington area. Upon completion of the drilling of the three test wells, the Corporation will have the right to continue earning option lands by electing to drill additional option wells on a 90 day, well by well, rolling option basis. Concurrent with the above commitment, on the same day, the Corporation also entered into a sub-participation and farmout letter agreement with a Canadian exploration and production company ("ExploreCo") encompassing certain lands and rights within its initial farm-in and option agreement and certain lands acquired by the Corporation. ExploreCo agreed to drill three Mannville test wells on the Corporation's initial farm-in lands and the Corporation's owned lands within the same timeframe as the Corporation's commitments under its initial farm-in agreement. Each test well will earn certain rights in one section and an adjoining section of land excluding certain shallow rights which have been excluded to the benefit of the Corporation. Upon completion of the drilling of the three test wells, ExploreCo will have the right to continue earning option lands by electing to drill additional wells on a 90 day, well by well, rolling option basis. The first test well was drilled and cased in January 2007 and the remaining two test wells are scheduled to be drilled by the end of February 2007. Management estimates that as the date of this report, approximately $2.9 million remained to be spent to fulfill this commitment. Management has essentially passed on this commitment amount to ExploreCo and therefore the Corporation does not expect to incur any costs relating to fulfilling this commitment.

On November 9, 2006 the Corporation sold certain royalty interests relating to its 32,000 km 2D seismic database for the sum of $675,000.

On November 20, 2006 the Corporation announced that it had received conditional approval from the Securities Regulatory Authorities in each of the provinces of Ontario, Alberta and British Columbia to conduct the Rights Offering in these provinces and certain jurisdictions outside of Canada excluding the United States (the "Qualifying Jurisdictions"). Pursuant to the terms of the Rights Offering, shareholders of the Corporation residing in the Qualifying Jurisdictions as at November 28, 2006 were granted rights (the"Rights") evidenced by transferable Rights certificates to purchase up to 5,677,294 common shares in the capital of the Corporation. The Rights expired at 4:00 p.m. (Calgary time) on December 20, 2006.

On November 24, 2006 Regal entered into a farm-in agreement at Garrington covering one section of land. Regal committed to drill a well by the end of 2006 by paying 100% of the costs to earn 100% of the farmor's interest, subject to a 15% overriding royalty on production from the well before payout, and 50% of the farmor's pre-farmout working interest after payout. The Corporation satisfied its commitment under this agreement through the drilling and completion of a gas well in December 2006.

Three gas wells were placed on production at Garrington in July 2006, two producing wells were purchased in October 2006 and a gas well was placed on production in late November 2006 bringing the Corporation's total producing well count at Garrington to six wells. One gas well completed during October 2006 is scheduled to be tied-in during January 2007. Three additional natural gas wells were drilled during November and December 2006 and are expected to be placed on production in 2007.

On November 30, 2006, the Corporation completed the sale of 4,583,333 flow-through shares at $0.24 per share and 5,000,000 common shares at $0.20 for gross proceeds of $2,100,000 under its previously announced Private Placements. In connection with the Private Placements, there were 916,666 agents warrants issued that entitle the holder to acquire one common share of the Corporation for each warrant held at a price of $0.20 until May 30, 2008. Concurrent with this financing, the Corporation restructured its board of directors by adding Richard M. Wlodarczak to the board as Chairman. Mr. Douglas M. Stuve and Mr. Owen C. Pinnell resigned from the board effective that date. This transaction is considered to be a related party transaction as Mr. Richard M. Wlodarczak and Mr. Harry L. Knutson, directors of the Corporation are also directors, officers and shareholders of Nova Bancorp Securities Ltd, the Agent for the Private Placements.

On December 1, 2006 the Corporation agreed to participate in the drilling of a well in the Hanna area of east central Alberta by way of farm-in. The Corporation entered into an area of mutual interest covering three separate land blocks including the farmor's interests in 13 separate sections of land. Regal committed to drill and complete (or abandon) one well by the end of 2006 by paying 50% of the costs to earn 42.5% of the farmor's interest, subject to a 10% overriding royalty before payout, and 25.5% of the farmor's interest after payout in two sections. The well was drilled and cased in December 2006 and completed in January 2007. As a result the Corporation has fulfilled its commitment under this obligation. Following this earning well, the Corporation has ongoing rolling options to drill further wells to earn additional lands under its farm-in agreement.

On December 7, 2006 the Corporation agreed to participate in the drilling of a well in the Pica area of northwest Alberta by way of farm-in. The Corporation entered into an area of mutual interest covering 7.25 sections of land. Regal committed to drill and complete (or abandon) one well by the end of 2006 by paying 37.5% of the costs to earn a 27.15% working interest subject to a 16% overriding royalty before payout, and a 23.43% working interest after payout in two sections. The well was drilled and cased in December 2006 as a potential Gething zone gas well.

On December 21, 2006 the Corporation completed the sale of 1,660,078 common shares at $0.20 per share under the Rights Offering for gross proceeds of $332,015.

On December 22, 2006 the Agent under the previously announced Private Placements informed the Corporation of its intent to exercise its over allotment option to sell up to an additional 3,339,000 common shares at a price of $0.20 per share for gross proceeds of up to $667,800 by the end of January 2007, representing the difference between $1 million and the amount of gross proceeds raised through the Rights Offering.

On January 22, 2007 the Corporation entered into an agreement with its lender to increase its revolving operating demand facility from $2,000,000 to $2,750,000 and increase its non-revolving acquisition/development facility from $500,000 to $825,000.

RESULTS OF OPERATIONS

Oil and Gas Reserves

Regal's proved reserves totaled 261,000 barrels of oil equivalent as at September 30, 2006. Proved plus probable reserves totaled 443,000 barrels of oil equivalent.

All of Regal's reserves as at September 30, 2006, were evaluated by GLJ Petroleum Consultants. The reserve estimates contained in the following table are working interest reserves before and after deduction of royalties.



Summary of Oil and Gas Reserves, Forecast Prices and Costs as at September
30, 2006

Natural
Reserves Light and Gas Oil
Category Medium Oil Heavy Oil Natural Gas Liquids Equivalent
---------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
MBbls MBbls MBbls MBbls MMcf MMcf MBbls MBbls MBoe MBoe
---------------------------------------------------------------------------
Proved
Developed
Producing 24 21 1 1 959 687 19 11 204 147
Developed
Non-producing 0 0 0 0 166 115 4 2 31 21
Undeveloped 0 0 26 26 0 0 0 0 26 26
-- -- -- -- -- -- -- -- -- --
Total Proved 24 21 27 27 1,125 802 23 13 261 194
---------------------------------------------------------------------------
Probable 17 15 11 11 782 559 23 13 181 132
---------------------------------------------------------------------------
Total Proved
plus Probable 41 35 39 38 1,906 1,362 46 26 443 326
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Note: Columns may not add due to rounding

Net Present Values of Future Net Revenue, Forecast Prices and Costs as at
September 30, 2006

Before Income Taxes
Reserves Category Discounted at (%per year)
---------------------------------------------------------------------------
($M) 0 5 10 15 20
---------------------------------------------------------------------------
Proved
Developed Producing 3,727 3,348 3,043 2,792 2,584
Developed Non-producing 517 458 408 366 329
Undeveloped 497 447 405 367 334
--- --- --- --- ---
Total Proved 4,741 4,253 3,855 3,525 3,247
---------------------------------------------------------------------------
Probable 3,622 2,414 1,722 1,298 1,021
---------------------------------------------------------------------------
Total Proved plus Probable 8,362 6,667 5,578 4,823 4,268
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Note: Columns may not add due to rounding. "Gross" refers to the
Corporation's working interest share before deduction of royalty interests
and "Net" refers to the Corporation's working interest share after
deduction of royalty interests.


Additional reserve disclosure tables, as required under NI 51-101, are contained in the Statement of Reserves Data and Other Oil and Gas Information FORM 51-101F1 filed on SEDAR.

Operating Netback

Effective with the takeover of Regal Energy Corp. on December 31, 2005, the Corporation began receiving a revenue stream from crude oil and natural gas sales. The Corporation had no oil and gas reserves or production during fiscal 2005 or the first quarter of fiscal 2006, thus no comparative results are available.



Three Months Ended Total
---------------------------------------------------------------------------
Dec. 31, Mar. 31, Jun. 30, Sept. 30,
Per Boe 2005 2006 2006 2006 2006
---------------------------------------------------------------------------
Revenue $ - $ 41.75 $ 52.59 $ 44.10 $ 45.29
Royalties - (7.07) (5.99) (8.43) (7.38)
Operating Costs - (27.82) (65.23) (20.81) (33.79)
---------------------------------------------------------------------------
Operating Netback $ - $ 6.86 $ (18.63) $ 14.86 $ 4.12
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Working Interest Sales

Three Months Ended Total
---------------------------------------------------------------------------
Dec. 31, Mar. 31, Jun. 30, Sept. 30,
Sales $ 2005 2006 2006 2006 2006
---------------------------------------------------------------------------
Natural Gas $ - $ 133,072 $ 101,179 $ 235,059 $ 469,310
Crude Oil & NGLs - 241,888 219,842 235,222 696,952
---------------------------------------------------------------------------
Total $ - $ 374,960 $ 321,021 $ 470,281 $ 1,166,262
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Three Months Ended Total
---------------------------------------------------------------------------
Dec. 31, Mar. 31, Jun. 30, Sept. 30,
Sales Volumes 2005 2006 2006 2006 2006
---------------------------------------------------------------------------
Natural Gas (Mcf) - 17,756 15,932 43,270 76,958
Crude Oil & NGLs
(Bbls) - 6,023 3,449 3,451 12,923
Total Oil
Equivalent (Boe) - 8,982 6,104 10,663 25,749
---------------------------------------------------------------------------
Total (Boe/d) - 100 67 116 71
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Three Months Ended Total
---------------------------------------------------------------------------
Dec. 31, Mar. 31, Jun. 30, Sept. 30,
Sales Price Per Unit 2005 2006 2006 2006 2006
---------------------------------------------------------------------------
Natural Gas ($/Mcf) - 7.49 6.35 5.43 6.10
Crude Oil & NGLs
($/Bbl) - 40.16 63.74 68.16 53.93
---------------------------------------------------------------------------
Total Blended
($/Boe) - 41.74 52.58 44.11 45.29
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Regal's sales volumes during 2006 totaled 12,923 Bbls of crude oil and NGL's and 76,958 Mcf of natural gas for a total of 25,749 Boe (average of 71 Boe/d). As the Corporation had no production from the first fiscal quarter, the annual sales Boe/d volumes were reduced from the 94 Boe/d that the Corporation averaged for the nine months. During the year, the Corporation had significant operating difficulties at its heavy oil producing field at Atlee Buffalo which led to a decision during the third fiscal quarter not to expend further maintenance or development capital in the area in favor of more economic projects. The heavy oil wells in the area are prolific producers, however costs associated with production were unacceptably high as evidenced by the operating costs in the third quarter. Management is of the opinion that our main Glauconite heavy oil pool at Atlee Buffalo is an exploitable resource although several technical issues relating to sand production need to be resolved before development can resume.



Producing properties of the Corporation during 2006 include:

2006 Average Production Rate


Working Gas Oil & NGLs Boe
Interest
Area (%) (Mcf/d) (Bbl/d) (Boe/d)
---------------------------------------------------------------------------
Atlee Buffalo 50-100 62 12 23
Garrington 85-100 67 1 12
Kaybob 62 25 1 5
Morinville (1) 5-10 0 5 5
Sounding Lake (2) 100 0 3 3
Viking Kinsella 20 57 0 10
Veteran 30-50 0 12 12
Judy Creek 5 0 1 1
---------------------------------------------------------------------------
Total 211 35 71
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Notes: (1) Property sold effective August 1, 2006
(2) Well abandoned September 2006


COMMODITY PRICES

The average prices received for Regal's oil and NGLs, and natural gas sales during 2006 were $53.93/Bbl and $6.10/ Mcf respectively. Average crude oil and NGLs prices received during the year increased on a quarter over quarter basis throughout the year, while natural gas prices decreased on the same basis. The Corporation historically has not hedged any of its sales of commodities. The Corporation essentially takes all of its production in-kind and sells that production through various third party marketing arrangements. Prices received for crude oil, natural gas liquids and natural gas are at the prevailing market prices adjusted for quality and applicable tariffs.

ROYALTIES

Royalties, which include crown, freehold and overriding royalties paid on oil, natural gas liquids and gas production and net of Alberta Royalty Tax Credits (ARTC), amounted to $189,942 during fiscal 2006. Average royalties amounted to $7.38 per Boe or 16.3% of sales. The province of Alberta has announced that the ARTC program will end effective January 1, 2007. During fiscal 2006 the ARTC recorded in our accounts amounted to $34,400 or 15.3% of before ARTC royalty amounts. The elimination of the ARTC combined with a larger portion of our production being subject to overriding royalties as a result of the activity on numerous farm-in agreements entered into during the year will increase the Corporation's effective royalty rate in the future.



OPERATING EXPENSES

Three Months Ended Total
---------------------------------------------------------------------------
Dec. 31, Mar. 31, Jun. 30, Sept. 30,
Operating Expense 2005 2006 2006 2006 2006
---------------------------------------------------------------------------
Crude Oil & Natural
Gas $ - 249,913 398,170 221,896 869,979
---------------------------------------------------------------------------
Per Boe $ - 27.82 65.23 20.81 33.79
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Total operating costs for fiscal 2006 amounted to $869,979 or $33.79 per Boe. During the third quarter ended June 30, 2006 the Corporation performed three separate workovers in the Atlee Buffalo area in an attempt to restore production from its major producing heavy oil well. The workover attempts were unsuccessful and the Corporation elected not to spend any further maintenance or development capital in the area in favor of more economically attractive projects. During the year, 51% of the total operating costs were spent in the Atlee Buffalo area. On a go-forward basis, the Corporation expects that operating expense on a per Boe basis will trend downwards and be more in line with industry acceptable norms.

OTHER INCOME

During the year, Regal had $75,160 of other income compared to $70,528 in fiscal 2005. In the current year the components of other income include interest income of $70,864 and rental of owned equipment to third party projects in the amount of $4,296. The $70,528 of other income earned in 2005 was all interest income. Of the $70,528 of interest income earned in 2005, $57,155 relates to the technology business segment (October 1, 2004 to December 17, 2004) and $13,373 relates to the period from December 17, 2004 to September 30, 2005 after the change of business direction to an oil and gas company occurred. The interest incomes in both fiscal periods represent the returns on funds invested that were excess to the Corporation's current working capital needs as a result of equity issues that occurred.



GENERAL AND ADMINISTRATIVE

During 2006, general and administrative costs totaled $576,196 or
$22.38/Boe (2005 - $159,024 in the oil and gas business segment and
$280,320 in the technology segment) as follows:

Three Months Ended
---------------------------------------------------------------------------
Oil and Gas Dec. 31 Mar. 31 June 30 Sept. 30 Total Total
Segment 2005 2006 2006 2006 2006 2005
---------------------------------------------------------------------------
Salaries &
Benefits (1) $ - $ 113,240 $ 113,318 $ 86,438 $ 312,996 $100,000
Office Costs &
Miscellaneous 55 39,304 41,901 38,510 119,770 59,024
Legal, Audit,
& Engineering
Fees 47,876 39,811 32,052 42,258 161,997 -
Other
Consulting - 22,495 19,705 25,510 67,710 -
Shareholder
Services 3,963 24,162 5,218 3,771 37,114 -
Capital/
Operating
Recoveries - (59,859) (43,437) (20,097) (123,393) -
---------------------------------------------------------------------------
$51,894 $ 179,153 $ 168,757 $ 176,390 $ 576,194 $159,024
---------------------------------------------------------------------------
Technology
Segment - - - - - 280,320
---------------------------------------------------------------------------
Total $51,894 $ 179,153 $ 168,757 $ 176,390 $ 576,194 $439,344
---------------------------------------------------------------------------
Note: (1) After $49,800 of salary expenses capitalized in 2006


Total salary expense for 2006 amounted to $312,996 as compared to $100,000 for 2005. Effective June 30, 2006 the Corporation's Vice President, Exploration & Land and the Corporation's Vice President, Engineering & Operations resigned. At the date of this report, these individuals, have not been replaced. Consulting staff have been retained on an as required basis to assume the resigned individuals job functions. During 2005, $100,000 was paid to the President of the Corporation for services provided from December 17, 2004 to September 30, 2005. At the date of this report, the Corporation has three full-time employees, and retains consultants in the engineering, geology, accounting and land departments on an as required basis.

Total office and miscellaneous costs amounted to $119,770 during 2006, primarily spread over the three quarters after the takeover of Regal Energy Corp. was completed. The major components of office and miscellaneous costs include rent, stationary and supplies, postage and courier, insurance and software subscriptions.

Total legal, audit and engineering fees amounted to $161,997 during the year as compared to $Nil in 2005. These costs are primarily required to fulfill the statutory reporting obligations of a publicly traded entity. It is expected this level of cost is the minimum to be expected in this category on a go-forward basis.

Total shareholder services in fiscal 2006 amounted to $37,114 ($Nil in 2005). These costs are, again, primarily required to fulfill the statutory reporting obligations of a publicly traded corporation. These costs are expected to increase on a go-forward basis due to increasing corporate governance requirements for publicly traded Corporations.

Total recoveries of overhead on capital and operating expenses amounted to $123,393 during the year as compared to $Nil in 2005. As operator of capital projects, a Corporation is allowed to charge overhead (usually as a percentage of project cost) in order to recover costs that are not directly chargeable to projects. During 2006 the Corporation recovered $101,836 in capital overhead. In similar fashion on producing properties operated by the Corporation, it is allowed to charge overhead (usually on a per well basis or fixed percentage of facility operating costs) that are not directly chargeable to operations. During fiscal 2006 the Corporation recovered $21,557 of operating overhead.

INTEREST AND BANK CHARGES

Total interest and bank charges for 2006 were $223,318. Of this total, $212,397 has been accrued to recognize interest payable to the Canada Revenue Agency on amounts unexpended on the Corporation's flow-through share commitments from February 1, 2006 to September 30, 2006.

During 2005, the Corporation incurred $491,249 of interest expense on the preferred shares outstanding at the date of the corporate re-organization. The preferred shares outstanding at this date had cumulative dividend rights at 8% accruing daily and compounding annually and the attributes of the redeemable preferred shares resulted in the classification as debt and the dividends as interest expense. The authorized and issued preferred shares were eliminated with the business reorganization that occurred on December 17, 2004.

STOCK BASED COMPENSATION

The Corporation accounts for its stock-based compensation program using the fair-value method. Under this method, compensation expense related to this program is recorded in the statement of operations over the vesting terms of the options. During the first quarter, as a result of the acquisition of Regal Energy Corp. and the replacement employee options that were issued to officers, directors and employees that continued with Regal Energy Ltd., $128,000 of expense was recognized as a part of the cost of acquisition.

In addition, on January 1, 2006, 1,671,000 options were granted to directors, officers and employees of the Corporation. Under the terms of the option agreements, options granted to directors (851,000) vest immediately while those options granted to officers and employees (820,000) vest one-third on the date of grant and one third on each of the first and second anniversaries of the date of grant. During the year, $645,257 of stock based compensation expense was recognized.

On September 30, 2006 a total of 460,000 options previously issued to the Corporation's former Vice President, Exploration & Land and the Corporation's former Vice President, Engineering & Operations expired reducing the total outstanding options on that date to 1,626,000.



DEPLETION, DEPRECIATION AMORTIZATION AND ACCRETION

Three Months Ended
---------------------------------------------------------------------------
Dec. 31 Mar. 31 June 30 Sept. 30 Total
2005 2006 2006 2006 2006
---------------------------------------------------------------------------
Depletion $- $265,573 $172,921 $419,048 $857,542
Depletion per Boe - 29.57 28.33 39.30 33.30
Depreciation - 3,367 4,178 4,465 12,010
Ceiling Test Write down - - - 4,200,000 4,200,000
---------------------------------------------------------------------------
Total Depletion and
Depreciation - $268,940 $177,099 $4,623,512 $5,069,552
---------------------------------------------------------------------------
Amortization of
Intangible Asset - 41,700 41,700 191,660 275,060
Accretion - 5,526 6,945 6,799 19,270
---------------------------------------------------------------------------
Total Depletion,
Depreciation
Amortization
and Accretion $- $316,166 $225,744 $4,821,972 $5,363,882
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Depletion of petroleum and natural gas properties and depreciation of production equipment is provided for using the unit-of-production method based on estimated proven petroleum and natural gas reserves as determined by independent engineers and updated internally on an intra-period basis. Other miscellaneous tangible assets are depreciated over their estimated useful life. Total depletion expense for the year amounted to $857,542 or $33.30 per Boe. The Corporation experienced a negative reserve adjustment at Atlee Buffalo that contributed to the high annual depletion rate. In addition, approximately one half of the total reserve additions at Garrington are considered by the Corporation's independent reserve evaluators as "probable reserves" which cannot be used in the depletion calculation. The Corporation is confident that with the success of the first quarter fiscal 2007 drilling and additional work at Garrington, the probable reserves will be reclassified as proven reserves with a corresponding reduction of our per unit depletion rate. Total depreciation expense for 2006 was $12,010.

The Corporation applies a two-stage ceiling test to capitalized costs to ensure that such costs do not exceed the undiscounted future net revenues from production of proved reserves. Undiscounted future net revenues are calculated based on an independent petroleum engineer's best estimate of forward indexed prices applied to estimated future production of proved reserves plus anticipated proceeds from the sale of undeveloped properties, less estimated future operating costs, royalties, future capital development costs and abandonment costs. When the carrying amount of a cost centre is not recoverable, the second stage of the process will determine the impairment amount, whereby the carrying value of the cost centre would be written down to its fair value. The second stage of the calculation requires a comparison between the carrying value and the discounted future net revenues from proved plus probable reserves using the Corporation's risk free interest rate plus the cost of undeveloped land, net of any impairment. The fair value is estimated using accepted present value techniques, which incorporate risks and other uncertainties when determining expected net revenues. In applying the ceiling test at September 30, 2006 it was determined that a ceiling test write down of $4,200,000 was required.

Pursuant to the acquisition of Regal Energy Corp. on December 31, 2005, an intangible asset has been recognized on the balance sheet of $500,000 that represented the value placed on the management team under contract and the public listing of Regal Energy Corp. The cost of intangible assets are excluded from the depletion calculation and are being amortized over a period of three years. At September 30, 2006 an impairment in the amount of $149,960 of this intangible asset was recognized due to the resignation of two senior officers of the Corporation. The Corporation will continue to amortize the remaining balance of the intangible asset over the remaining useful life not to exceed three years.

Accretion expense is the increase in the present value of the asset retirement obligation for the current period and the amount of this expense will increase commensurate with the asset retirement obligation as new wells are drilled or acquired through acquisitions. During the year, the Corporation recorded $19,270 of accretion expense.



INCOME TAXES

The Corporation has approximately $65,198,500 of tax pools available as
detailed in the following table.

Non Non Other
Refundable Capital Tax
Expiry date SR&ED ITC's Losses Pools Total
---------------------------------------------------------------------------
2007 $ - $ - $ 4,656,000 $ - $ 4,656,000
2008 - - 10,295,000 - 10,295,000
2009 - 231,000 9,766,000 - 9,997,000
2010 - 340,000 5,720,000 - 6,060,000
2011 - 1,032,000 - - 1,032,000
2012 - 876,000 - - 876,000
2013 - 196,000 - - 196,000
2014 - 45,000 4,672,000 - 4,717,000
2015 - - 1,898,000 - 1,898,000
2016 - - 1,287,000 1,287,000
No expiry
date 18,899,500 - - 5,285,000 24,184,500
---------------------------------------------------------------------------
$18,899,500 $2,720,000 $ 38,294,000 $5,285,000 $65,198,500
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The future tax benefit of the non-capital losses being carried forward has not been recognized in these financial statements as the criteria for recognition has not been met. The research and development cost pool will be reduced by the amount of any investment tax credits utilized. The future tax benefit of $300,000 of the research and development pools has been recognized in these financial statements as the criteria for recognition has been met.

Canada Revenue Agency has conducted an audit of transfer pricing on international transactions between SiberCore Technologies Incorporated and its United States subsidiary, SiberCore America Inc. for the years 2000, 2001 and 2002. SiberCore Technologies Incorporated was the predecessor company of Azeri and ultimately Regal Energy Ltd. The Corporation has received a proposed settlement letter from CRA that would result in a reduction of tax pools in the amount of $1,501,453. CRA has also proposed to charge a cash penalty of 10% of the adjustments. The Corporation has responded to the proposed settlement letter and provided further information supporting management's view that CRA's position has no merit. The outcome of this audit is uncertain at this time.



NET EARNINGS AND FUNDS FLOW FROM OPERATIONS

Three Months Ended
---------------------------------------------------------------------------
Dec. 31, Mar. 31, June 30, Sept. 30, Total
2005 2006 2006 2006 2006
---------------------------------------------------------------------------
Weighted Average
Shares
Outstanding 9,023,881 22,709,179 22,709,179 22,709,179 19,259,734
---------------------------------------------------------------------------
Net Income
(Loss) $(44,460) $ (20,112) $(611,937) $(4,950,641) $(5,627,150)
---------------------------------------------------------------------------
Per Share Basic
and Diluted $ (0.00) $ (0.00) $ (0.03) $ (0.22) $ (0.29)
---------------------------------------------------------------------------
Funds Flow From
Operations (1) $(44,460) $(151,075) $(340,001) $ (82,475) $ (618,011)
---------------------------------------------------------------------------
Per Share Basic
and Diluted $ 0.00 $ 0.00 $ (0.01) $ 0.00 $ (0.03)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Three Months Ended
---------------------------------------------------------------------------
Dec. 31, Mar. 31, June 30, Sept. 30, Total
2004 (2) 2005 (2) 2005 (2) 2005 (2) 2005
---------------------------------------------------------------------------
Weighted Average
Shares Outstanding n/a n/a n/a n/a 5,495,897
---------------------------------------------------------------------------
Net Income (Loss)
Oil and Gas
Segment n/a n/a n/a n/a $ (145,651)
---------------------------------------------------------------------------
Net Income (Loss)
Technology
Segment n/a n/a n/a n/a 339,577
---------------------------------------------------------------------------
Total Net
Income (Loss) n/a n/a n/a n/a $ 193,926
---------------------------------------------------------------------------
Per Share Basic
and Diluted n/a n/a n/a n/a $ 0.04
---------------------------------------------------------------------------
Funds Flow From
Operations Oil
and Gas (1) n/a n/a n/a n/a $ (362,461)
---------------------------------------------------------------------------
Funds Flow From
Operations
Technology (1) n/a n/a n/a n/a $1,034,426
---------------------------------------------------------------------------
Total Funds Flow From
Operations n/a n/a n/a n/a $ 671,965
---------------------------------------------------------------------------
Per Share Basic and
Diluted n/a n/a n/a n/a $ 0.12
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Notes:
(1) Funds flow from operations has been presented for information purposes
only and should not be considered an alternative to, or more meaningful
than, cash flow from operating activities as determined in accordance
with GAAP. The Corporation considers funds flow from operations to be
a key measure as it demonstrates the Corporation's ability to generate
the cash necessary to repay debt and to fund future growth through
capital investment. The determination of Regal's funds flow from
operations may not be comparable to the same reported by other
companies. The reconciliation of net earnings and funds flow from
operations can be found in the statements of cash flow in the
consolidated financial statements. Funds flow from operations per
share was calculated using the same weighted average shares
outstanding used in calculating net earnings per share.
(2) As the Corporation was private during fiscal 2005, quarterly financial
statements were not prepared and information is not available.


The net loss for 2006 amounted to $5,627,150 or $0.29 per share as compared to net income of $193,926 for 2005. The weighted average number of shares outstanding during the year was 19,259,734 compared to 5,495,897 outstanding for fiscal 2005. The majority of the net loss is attributable to non-cash items - namely a ceiling test write down in the amount of $4,200,000, an impairment and amortization of intangible assets in the amount of $275,060 and stock compensation expense during the year in the amount of $645,257. In addition, during the year the Corporation spent considerable funds on its heavy oil operations at Atlee Buffalo attempting to maintain production from two of its major producing wells. Attempting to maintain this production through continual workovers on the wells not only significantly increased ongoing operating costs, but also resulted in a loss of sales revenue while the workovers were being conducted. During the third quarter, management made a decision not to spend any further maintenance or development capital in the Atlee Buffalo area and to focus its resources in areas where better returns would be experienced. During the fourth quarter, operating expenses dropped to $20.81 per Boe. The Corporation is confident that as additional production is brought on stream operating costs will continue to decrease to levels more consistent with industry norms.

Funds flow from operations (non-GAAP measure) for 2006 amounted to $(618,011) or $(0.03) per share compared to $671,965 or $0.12 per share in 2005. As described above, the major reasons for the negative funds flow from operations during the current year were the difficulties encountered in the Atlee Buffalo area.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2006 the Corporation had a working capital deficiency of $1,244,560. In order to fulfill the Corporation's remaining flow through obligation of $2,939,300 prior to December 31, 2006, a number of steps were required including the sale of a minor property at Morinville, effective August 1, 2006 ($408,910), the sale of a royalty interest on the Corporation's seismic database ($675,000), Private Placements of shares ($2,100,000) and the Rights Offering to existing shareholders ($332,015). With these measures taken, the Corporation fulfilled its flow-through share obligation for calendar year 2006. The Private Placements completed on November 30, 2006 included $1,100,000 of flow-through common shares. The Corporation must expend this amount on qualified drilling and completion activities by December 31, 2007 and will use a combination of funds flow and increased bank lines to fulfill this obligation. On January 22, 2007 the Corporation entered into an agreement with its lender to increase its revolving operating demand facility from $2,000,000 to $2,750,000 and increase its non-revolving acquisition/development facility from $500,000 to $825,000. As a result of the completion of additional wells drilled during the first quarter of fiscal 2007, the Corporation's lender may consider further increases to its lending facilities.

CAPITAL EXPENDITURES

During 2006, Regal recorded $7,218,749 of capital expenditures compared to $846,251 in fiscal 2005. Details of the capital expenditures by major category follow. Amounts reported in the following table do not include non-cash capital recorded for asset retirement obligation in the amount of $66,902 (2005 - $Nil) and amounts charged to capital as a result of the takeover of Regal Energy Corp. on December 31, 2005 in the amount of $5,146,851.



2006 2005
---------------------------------------------------------------------------
Geological, Geophysical and Seismic $ 253,654 $ 846,251
Drilling and Completions 6,213,967 -
Equipping and tie-ins 986,616 -
Property Acquisition / (Disposition) (408,910) -
Furniture and Fixtures 16,604 -
Capitalized Salaries 49,800 -
Miscellaneous Oilfield Equipment 107,018 -
---------------------------------------------------------------------------
$ 7,218,749 $ 846,251
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The following table summarizes the Corporation's drilling activity for the
year ended September 30, 2006.


2006
------------------------
Gross Wells Net Wells
---------------------------------------------------------------------------
Oil 2 1.60
Natural Gas 6 5.22
Dry & Abandoned 1 0.60
---------------------------------------------------------------------------
Total 9 7.42
---------------------------------------------------------------------------
---------------------------------------------------------------------------


During fiscal 2006 Regal participated in the drilling of a total of 9 wells (7.4 net) resulting in 6 natural gas wells (5.2 net), 2 oil wells (1.6 net) and 1 D&A well (0.6 net). Of the 6 natural gas wells drilled during fiscal 2006, four were tied in and producing as of September 30, 2006, one well was tied in and producing at the end of November 2006 and one well is scheduled to be placed on stream during January 2007. Of the two oil wells drilled during 2006, one well at Atlee Buffalo produced 7,190 Barrels of crude oil (4,314 Bbl net) to the end of April 2006 and was subsequently shut in due to high operating costs, and one well drilled at Sounding Lake produced 1,190 Barrels of crude oil (1,190 Bbl net) to September 2006 and was abandoned due to high water cuts. One D&A well (0.6 net) was drilled at Atlee Buffalo where the Corporation was targeting Bow Island gas. The well encountered the Bow Island zone but the zone only produced formation water during its completion.

Subsequent to the end of fiscal 2006, during the first quarter of fiscal 2007, the Corporation participated in the drilling of 8 wells (4.9 net) resulting in 7 natural gas wells (4.6 net) and one D&A well (0.3 net).

The following table summarizes the Corporation's land holdings as at September 30, 2006.



Gross Acres Net Acres
---------------------------------------------------------------------------
Garrington 4,959 3,655
Kaybob 960 714
Atlee Buffalo 2,720 1,648
Viking Kinsella 1,280 256
Veteran 1,794 544
Sounding Lake 160 160
Medicine Lodge 3,200 256
Judy Creek 160 8
Other 640 16
---------------------------------------------------------------------------
Total 15,873 7,257
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The Corporation held an average working interest of 46% in a total of 15,873 acres of developed and undeveloped lands as at September 30, 2006. Of the total 7,257 net acres of land, 5,180 acres (71% of the total) were developed acres. All of the properties were located in the province of Alberta.

Subsequent to the end of fiscal 2006, the Corporation added developed and undeveloped lands totaling approximately 4,960 gross acres and 4,880 net acres as a result of its acquisition and drilling activities at Garrington during the first quarter of fiscal 2007, and expects to add a further 5,120 gross acres and 1,538 net acres as a result of completion activities on two wells recently drilled at Eight Mile, British Columbia, one well at Pica, Alberta and one well at Hanna, Alberta.

LENDING FACILITY

The Corporation has established a revolving operating demand facility of $2,750,000 that bears interest at the bank prime rate plus 1/2%. Repayments of the facility are not required provided the amounts borrowed no not exceed $2,750,000 or an amount to be determined from time to time. The Corporation also has a non-revolving acquisition/development facility in the amount of $825,000 which bears interest at the bank prime rate plus 1.0%. At September 30, 2006 there was $325,000 drawn on the operating demand facility. The lending facilities are subject to an interim review by the bank, scheduled for April 30, 2007 and an annual review no later than January 31, 2008.

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Crude oil and natural gas operations involve certain risks and uncertainties. These risks include, but are not limited to, commodity prices, foreign exchange rates, interest rates, credit, operational and safety and environmental. Operational risks are managed through a comprehensive insurance program designed to protect the Corporation from significant losses arising from risk exposures. Risks associated with commodity prices, interest and exchange rates are generally beyond the control of the Corporation. Various hedging products may be considered to reduce the risk in these areas. The Corporation has no hedging contracts or fixed-price physical contracts in place at this time.

Safety and environmental risks are addressed by compliance with government regulations. The Corporation currently has an Environmental and Safety Policy that provides a clear roadmap to follow in the event of a safety or environmental incident occurring. Having the policy in place minimizes the Corporation's exposure and risk.

The Corporation is exposed to concentration of credit risk as substantially all the Corporation's accounts receivable are with customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. The Corporation mitigates these risks by entering into transactions with reputable partners. The Corporation has a policy to issue cash calls to industry partners on operated joint ventures on all capital projects.

The Corporation is exposed to interest rate risk on its revolving demand loan facility.



EQUITY CAPITAL

Common share continuity 2006:
Shares Amount
---------------------------------------------------------------------------
Balance, September 30, 2005 7,466,576 $ 59,640,080
December 2005 private placements issued for cash 737,000 650,000
December 2005 private placements issued for cash
on a flow-through basis 8,217,506 8,028,000
Tax impact of flow through share issue - (2,700,000)
Share issuance costs - (804,912)
Shares issued on acquisition of Regal Energy
Corp. 6,147,469 5,225,349
Share issued as success fee on transaction 140,628 133,596
---------------------------------------------------------------------------
Shares outstanding September 30, 2006 22,709,179 $ 70,172,113
---------------------------------------------------------------------------

Common share continuity 2005:
Shares Amount
---------------------------------------------------------------------------
Balance, September 30, 2004 16,553 $ 52,321,930
Return of capital - (50,000)
Distribution of technology assets as return of
capital - (89,033)
Dissenting shareholder repayments - (1,962)
Conversion of preferred shares 5,443,563 6,124,712
Elimination of fractional shares (369) -
---------------------------------------------------------------------------
Balance after reorganization 5,459,747 $ 58,305,647
Issue of flow through shares 1,669,040 1,358,796
Tax effect of flow through shares - (219,000)
Issue costs - (95,761)
Tax benefit of issue costs - 15,400
Shares issued for resource assets 337,789 274,998
---------------------------------------------------------------------------
Balance September 30, 2005 7,466,576 $ 59,640,080
---------------------------------------------------------------------------


The above common share schedules give effect to the consolidation affected December 17, 2004 on the basis of one common share for 30,000 common shares outstanding, the conversion of the preferred shares on the basis of .012 post consolidation common shares for each preferred share as well as the common share split of 7.37 to 1 effected December 31, 2005. Fractional shares were eliminated.



Preferred share continuity 2005 and 2006:
Shares Amount
---------------------------------------------------------------------------
Balance September 30, 2004 61,550,942 $ 22,178,433
Capitalization of interest and accretion of
issue costs - 491,249
Return of capital - (5,950,000)
Distribution of technology assets as a return
of capital - (10,594,970)
Conversion of preferred shares into common
shares (61,550,942) (6,124,712)
---------------------------------------------------------------------------
Balance September 30, 2005 and 2006 - $ -
---------------------------------------------------------------------------


The preferred shares had cumulative dividend rights at 8% accruing daily and compounding annually. The secured dividends were capitalized and removed as a result of the reorganization. The authorized and issued preferred shares were also eliminated with the reorganization. The attributes of the redeemable preferred shares resulted in the classification as debt and the dividends as interest expense.



Warrants:
Number of Number of
Warrants Shares Amount
---------------------------------------------------------------------------
Balance September 30, 2004 and 2005 - - -
December 15, 2005 private placement 817,923 817,923 $ 188,000
Warrants issued as success fee on
acquisition of Regal Energy Corp. 905,643 905,643 218,300
---------------------------------------------------------------------------
Warrants outstanding September 30, 2006 1,723,566 1,723,566 $ 406,300
---------------------------------------------------------------------------
Total common shares and warrants ("Equity
Instruments") outstanding
September 30, 2006 $70,578,413
---------------------------------------------------------------------------


In connection with the private placement of common and flow-through common shares on December 15, 2005, the Corporation issued 817,923 warrants that entitle the holder to purchase one common share of the Corporation for each warrant held at a price of $0.88 until June 30, 2007. The fair value of the warrants was determined using the Black-Scholes option pricing model and assumes an expected volatility of 50%, a risk free rate of return of 3.5% and a weighted average life of 1.5 years.

In connection with the acquisition of Regal Energy Corp. the Corporation issued 905,643 warrants as a success fee that entitle the holder to purchase one common share of the Corporation for each warrant held at a price of $0.95 per share until December 31, 2007. The fair value of the warrants was determined using the Black-Scholes option pricing model and assumes an expected volatility of 50%, a risk free rate of return of 3.5% and a weighted average life of 2.0 years.



Options:
Number of Exercise
Options Price Expiry Date
---------------------------------------------------------------------------
Balance September 30, 2005(1) - - -
Replacement employee options issued
Dec. 31, 2005 86,000 $ 1.00 Dec. 31, 2007
Replacement employee options issued
Dec. 31, 2005 196,000 1.00 Jan. 30, 2009
Replacement employee options issued
Dec. 31, 2005 50,000 0.90 Aug. 17,2009
Replacement employee options issued
Dec. 31, 2005 83,000 1.00 Apr. 13, 2010
Issued to directors January 1, 2006 851,000 0.95 Jan. 1, 2011
Issued to officers and employees
January 1, 2006 820,000 0.95 Jan. 1, 2011
Options forfeited(2) (100,000) 1.00 Jan 30, 2009
Options forfeited(2) (20,000) 1.00 Apr. 13, 2010
Options forfeited(2) (340,000) 0.95 Jan. 1, 2011
---------------------------------------------------------------------------
Balance September 30, 2006 1,626,000
---------------------------------------------------------------------------
Exercisable at September 30, 2006 1,306,000
---------------------------------------------------------------------------
Note:
(1) With the change in business direction that occurred on
December 17, 2004, all outstanding stock options to existing employees
were cancelled.
(2) Options previously issued to former officers of the Corporation.


The Corporation has a stock option plan under which directors, employees and consultants are eligible to receive grants. Options granted under the plan to outside independent directors vest immediately. Options granted to employees of the Corporation vest one-third on the date of grant, and one third each on the first and second anniversaries of the date of grant. The replacement employee options issued as a result of the December 31, 2005 transaction with Regal Energy Corp. vested 100% as the change of control provision of the option plan was triggered. The following table summarizes the status of the Corporation's stock option plan and the activity from September 30, 2005 to date. On January 1, 2006, 1,671,000 options were granted at a price of $0.95 exercisable until January 1, 2011 to directors, officers and employees of the Corporation. On September 30, 2006 a total of 460,000 options previously issued to the Corporation's former Vice President, Exploration & Land and the Corporation's former Vice President, Engineering & Operations expired reducing the total outstanding options on that date to 1,626,000.

On November 30, 2006, the Corporation completed the sale of 4,583,333 flow-through shares at $0.24 per share and 5,000,000 common shares at $0.20 for gross proceeds of $2,100,000 under its previously announced Private Placements. In connection with the Private Placements, there were 916,666 agents warrants issued that entitle the holder to acquire one common share of the Corporation for each warrant held at a price of $0.20 until May 30, 2008. On December 21, the Corporation completed the sale of 1,660,078 common shares at $0.20 per share under the Rights Offering for gross proceeds of $332,015.60.



As of the date of this MD&A, the Corporation has the following outstanding
equity instruments:

Shares outstanding 33,952,590
Shares issuable upon exercise of warrants 2,640,232
Stock options outstanding 1,626,000
------------
Total equity instruments outstanding 38,218,822


On December 22, 2006 the Agent under the previously announced Private Placements informed the Corporation of its intent to exercise its over allotment option to sell up to an additional 3,339,000 common shares at a price of $0.20 per share for gross proceeds of up to $667,800 by the end of January 2007, representing the difference between $1 million and the amount of gross proceeds raised through the Rights Offering.

LIQUIDITY AND COMMITMENTS

The Corporation, as a result of a flow-through financing that occurred during December, 2005, had a significant obligation to fulfill by December 31, 2006. At September 30, 2006, the Corporation was required to complete additional exploratory drilling and completion expenditures in the amount of $2,939,300. By the third quarter of fiscal 2006, it was determined that the financial condition of the Corporation was not adequate to fulfill this obligation so a number of steps were taken including:

- Sale of a minor property at Morinville, Alberta producing approximately 8 Bbl/d of oil for $408,910;

- Sale of a residual royalty interest on the Corporation's 32,000 km 2D seismic database for $675,000;

- Sale of 4,583,333 flow-through common shares at $0.24 per share for gross proceeds of $1,100,000 and 5,000,000 common shares at $0.20 per share for gross proceeds of $1,000,000 through Private Placements; and

- Sale of 1,660,078 common shares at $0.20 per share for gross proceeds of $332,015 under the Rights Offering to existing shareholders.

With the completion of the above steps, the Corporation was able to fulfill its flow-through share commitment for the 2006 calendar year by December 31, 2006. The drilling of exploratory prospects conducted during the first fiscal quarter ended December 31, 2006 was successful, and although tie-ins of these wells will not occur until later in fiscal 2007, the Corporation's lender, on January 22, 2007, agreed to increase the Corporation's revolving operating demand facility from $2,000,000 to $2,750,000. In addition, the Corporation's lender also increased the availability of the Corporation's non-revolving acquisition/development facility from $500,000 to $825,000. The Corporation plans to utilize the acquisition/development facility for the tie-in of up to four wells during fiscal 2007 and when completed, the Corporation will request a further increase of its revolving operating facility.

The Corporation currently has the following obligations to fulfill:

- Expend $1,100,000 of eligible expenditures under the flow-through share issue in November, 2006. It is estimated that approximately $500,000 of this commitment has been fulfilled at the date of this report;

- Complete one well in the Eight Mile area of northeast British Columbia at a projected cost to the Corporation of $160,000; and

- Complete one well in the Pica area of northwest Alberta at a projected cost to the Corporation of $80,000.

The Corporation believes that with the increases in its banking facilities, additional equity and additional funds flow from successful drilling it will have the financial resources to complete its capital program for fiscal 2007 and the remainder of calendar 2007. In the event that commodity prices, interest or exchange rates negatively impact funds flow, the proposed capital program will be adjusted so that the Corporation's debt remains within its existing banking facilities. The Corporation may also consider the issuance of further equity, if required, to maintain or expand its capital program.

Projections are based average wellhead prices of $52.60/Bbl for oil and NGLs, and $6.75/Mcf for natural gas. In addition, the following projections make assumptions regarding the timing of tie-ins of wells and deliverabilities of wells that Management considers appropriate. In the event that any of the assumptions are proven to be inaccurate, the capital program will be adjusted accordingly.

The following table shows a projection of fiscal 2007 results outlining the Corporation's expected working capital position at September 30, 2007.



Working capital surplus (deficiency) September 30, 2006 $ (1,244,600)
Divestments - sale of royalty on seismic database 675,000
Private Placements (net of costs) 2,187,000
Additional private placement expected to close by the end of
January 2007 (net of costs) 620,000
Expected funds flow October 1, 2006 - September 30, 2007 1,700,000
Acquisitions - Garrington property, closed October 5, 2006 (535,000)
Projected capital expenditures October 1, 2006 - September
30, 2007 (6,530,000)
---------------------------------------------------------------------------
Expected working capital (deficiency) September 30, 2007 (1) $ (3,127,600)
---------------------------------------------------------------------------

Note:

(1) Total available banking facilities as at the date of this report -
$3,575,000


RELATED PARTY TRANSACTIONS

During 2006, the Corporation had the following related party transactions;

a) During the year ended September 30, 2006, the Corporation incurred fees (including GST) of $177,045 in legal and associated fees from a legal firm in which a partner is also a director of the Corporation ($Nil in 2005); and

b) A Corporation controlled by a director of the Corporation subscribed for $2,520,000 of flow-through common shares in the December 2005 private placement at the same prices as offered to the other participants in this offering.

All related party transactions are in the normal course of operations and have been measured at the agreed to exchange amount, which is the amount of consideration established and agreed to by the related parties and which is similar to those that would be negotiated with third parties.

SUMMARY OF SHARE TRADING DURING 2006



On January 19, 2006 Regal's shares commenced trading on the TSX Venture
Exchange under the symbol "REG".

Price
High Range Low Close Volume Value
Period of 2006 ($) ($) ($) Traded ($)
---------------------------------------------------------------------------
First Quarter ----------------Not Publicly Traded-----------
Second Quarter 1.40 0.60 0.60 969,217 795,667
Third Quarter 0.74 0.38 0.495 718,439 431,444
Fourth Quarter 0.42 0.17 0.19 1,197,762 355,748
---------------------------------------------------------------------------
Total 1.40 0.17 0.19 2,885,418 1,582,859


DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Corporation is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure. The Corporation's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of September 30, 2006, that the Corporation's disclosure controls and procedures are effective to provide reasonable assurance that material information related to Regal, is made known to them by employees or third party consultants working for the Corporation. It should be noted that while the Corporation's Chief Executive Officer and Chief Financial Officer believe that our disclosure controls and procedures will provide a reasonable level of assurance and that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control system are met.

INTERNAL CONTROL OVER FINANCIAL REPORTING

The Chief Executive Officer and Chief Financial Officer of Regal are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. With the assistance of an independent third party, we assessed the design of our internal control over financial reporting as of September 30, 2006. During this process, management identified certain material weaknesses in internal controls over financial reporting which are as follows:

a) Due to the limited number of staff of Regal, it is not possible to achieve a segregation of duties; and

b) Due to the limited number of staff, Regal does not have technical accounting expertise and knowledge to address all complex and non-routine accounting transactions that may arise.

These weaknesses in Regal's internal controls over financial reporting result in a more than remote likelihood that a material misstatement would not be prevented or detected. Management and the board of directors work to mitigate the risk of a material misstatement in financial reporting by segregating duties as much as possible under the current circumstances. In addition, when complex accounting and technical issues arise during preparation of monthly and quarterly financial statements outside consulting expertise is engaged. In spite of management's best efforts, there can be no assurance that this risk can be reduced to less than a remote likelihood of a material misstatement.

ADDITIONAL INFORMATION REGARDING REGAL ENERGY LTD.

We encourage interested parties to access copies of the Corporation's 2006 Financial Statements, and 2006 Annual Report on the internet at www.sedar.com or Regal's website at www.regalenergy.ca

ADVISORY REGARDING FORWARD LOOKING STATEMENTS

Certain information regarding Regal in this news release, that are not historical facts, including management's assessment of Regal's future plans and operations may consitute "forward looking statements". All estimates and statements that describe the Corporation's objectives, goals, or future, including management's assessment of future plans and operations, production estimates and expected production rates, timing of tie-ins and the effect of delays in tieing-in wells and the effects of third party compressor issues and other infrastructure issues, levels of decline rates and the effects thereof, expected royalty rates, expected general and administrative expenses and other expenses, effects of the results of successful wells, expected levels of capital expenditures and the method of funding them, the ability to incur qualifying expenditures renounceable to purchasers of flow-through shares and the expected levels of activities and results of operations of Regal may constitute forward looking information under securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals, the impact of general economic conditions and industry conditions, the lack of availability of qualified personnel or management, stock market volatility and the ability to access sufficient capital from internal and external sources. As a consequence Regal's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward looking statements and, accordingly no assurance can be given that any events anticipated by the forward looking statements will transpire or occur, or, if any of them do so, what benefits Regal will derive there from. Readers are cautioned that the foregoing list of factors is not exhaustive. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward looking statements.

Issued and Outstanding Common Shares: 33,952,590

The TSX Venture has not reviewed and does not accept any responsibility for the adequacy or accuracy of this release.

Contact Information

  • Regal Energy Ltd.
    Douglas O. McNichol
    President and Chief Executive Officer
    (403) 509-2581
    Email: dmcnichol@regalenergy.ca
    or
    Regal Energy Ltd.
    Wayne R. Wilson
    Vice President Finance and Chief Financial Officer
    (403) 509-2584
    Email: wwilson@regalenergy.ca
    or
    Regal Energy Ltd.
    Suite 1520, Life Plaza
    734 - 7th Avenue S.W.
    Calgary, Alberta T2P 3P8