Masters Energy Inc.
TSX : MSY

Masters Energy Inc.

March 20, 2006 20:37 ET

Masters Energy Inc. Reports 2005 Results

CALGARY, ALBERTA--(CCNMatthews - March 20, 2006) - Masters Energy Inc. (TSX:MSY) ("Masters" or the "Company") is pleased to report financial and operating results for the year ended December 31, 2005. Several significant accomplishments were achieved during the year;

- Increased net asset value per share 74 percent to $4.86

- Production increased 48 percent year over year to 1,254 boe/d

- Proved plus probable reserve additions replaced 307 percent of annual production

- Drilled 22 wells with a 73 percent success ratio

- Capital investment resulted in a recycle ratio of 1.9 times

- Acquired a new core area in the North Peace River Arch area of Alberta



HIGHLIGHTS

Years ended December 31 2005 2004
------------------------------------------------------------------------
Financial ($ thousands, except per share amounts)
Gross revenue 22,929 11,978
Funds generated by operations 12,159 5,634
Per share - basic 0.84 0.42
- diluted 0.81 0.41
Net earnings 3,611 428
Per share - basic 0.25 0.03
- diluted 0.24 0.03
Capital expenditures 27,533 10,920
Working capital deficit 5,013 4,116

Long-term debt 14,093 -

Operations
Production
Crude oil (bbls/d) 697 558
NGL (bbls/d) 11 7
Natural gas (mcf/d) 3,276 1,706
Total production (boe/d at 6:1) 1,254 849

Average sales price
Crude oil ($/bbl) 44.82 36.51
NGL ($/bbl) 55.19 44.25
Natural gas ($/mcf) 8.87 6.59


Presidents Message to the Shareholders

Masters Energy continued to perform well in 2005 and made significant progress toward its goals. The Company experienced a very high level of activity in 2005 which we expect will continue in 2006. Specifically, we drilled 22 wells, acquired in excess of 15,000 net acres of undeveloped land and purchased an asset which has evolved into a core area for Masters. The investments made in 2004 and 2005 have provided the Company with a large inventory of exploration and development opportunities which we expect will provide economic growth in 2006.

Through exploration and development activities and the acquisitions of properties in North Peace River Arch we were able to add 1.6 million boes of proved plus probable reserves, replacing 307 percent of the annual production. In addition, 0.1 million boes of royalty interest reserves were acquired, resulting in 1.7 million boes of company interest reserves. Based on a total capital spending program of $27.5 million the proved and probable all-in finding and development cost, including future development costs, was $16.29 per boe. Based on our 2005 average operating netback of $30.74 per boe this resulted in an investment recycle ratio of 1.9 times.

In the southern core area the Company drilled 16 gross exploration and development wells resulting in six oil wells and six gas wells for an overall success rate of 75 percent. At Little Bow a total of 10 wells were drilled including six infill wells in the main producing pool. The battery and water handling facility was expanded during the year and a water injection well was drilled into the existing pool. In 2005 and the early part of 2006 several 3D seismic surveys were completed on exploratory lands which have resulted in several defined locations. Additional exploration concepts are being pursued in the southern core area.

The $7.2 million of property acquisitions in the North Peace River Arch created a second core producing area for Masters. The acquisitions provided 160 boe/d of production, 10,600 net undeveloped acres, ownership in several strategic field facilities and a large seismic data base. In addition to the acquisitions the Company spent $7.5 million to drill six wells (four of which were natural gas wells), acquire in excess of 10,000 net undeveloped acres, expand existing production facilities and shoot several large 3D seismic programs. In addition to the acquired undeveloped acreage the Company has option acreage of 19,200 acres under its control. At the end of 2005 and into the early part of 2006 Masters shot approximately 94 square miles of 3D seismic. This will provide the basis for an active drilling program in 2006.

Although the Company performed well in 2005, we were disappointed with the production volumes in the fourth quarter. Daily production briefly increased to 1,600 boe/d in the quarter before a natural gas well at Hector became uneconomic, was shut-in and reduced the average daily production. Masters had intended to drill 13 wells in the fourth quarter but was restricted to 10 wells due to lack of rig availability. In addition, several projects that were scheduled to start production in the period were delayed due to lack of equipment, services or surface access issues. These issues resulted in a delay with respect to timing of production additions. The Company expects that the production volumes anticipated in the fourth quarter of 2005 will be realized before spring break up in 2006.

Revised Guidance

In November 2005, Masters issued guidance which described expectations for 2006 to be 2,100 - 2,200 boe/d of production and $25 million of exploration and development capital expenditures in the period. The guidance at that time assumed $60.00(US) per WTI barrel oil price and $10.00(CDN) AECO per thousand cubic feet natural gas price. In light of the production addition deferral and the expectation for lower natural gas prices in 2006 we believe it is prudent to revise our expectations for the year. As a result, the Company is revising its 2006 guidance to an average production rate of 1,800 - 2,000 boe/d and capital expenditures, excluding acquisitions, of $21 million.

Annual and Special Meeting

The Company's Annual and Special Meeting of shareholders is scheduled for 2:00 PM (Calgary Time) on Wednesday May 3, 2006 at The Calgary Telus Convention Centre - Room 206, 120, 9th Avenue SE Calgary, Alberta.

Outlook

The strategy for 2006 is to continue to exploit our large undeveloped land base, build value within our core producing areas, continue to build our prospect inventory and pursue several high impact exploration plays outside of our core areas. The demand for acquisitions has been very strong recently and we expect the market to continue to be very competitive. Masters will continue to pursue acquisitions that are a strategic fit and add shareholder value.

The current business environment for the oil and gas sector remains attractive. Although gas prices are expected to be soft in the short term, longer term commodity prices are expected to be strong. Relatively low interest rates, high demand for energy and reasonable access to capital markets underpin a strong business environment in the oil and gas sector. The strong environment also creates challenges with respect to cost pressures. We expect that the demand for oilfield services and supplies will continue to be high and that delays with respect to implementing field work will continue and recognize we may need to adjust our timing expectations, accordingly.

Masters is fortunate to have a team of experienced, knowledgeable and talented people. The combination of our excellent team, significant investment opportunities, solid foundation of properties and attractive business fundamentals in the oil and gas sector creates a strong sense of optimism for the future.



On behalf of the Board of Directors,

Geoff C. Merritt
President and Chief Executive Officer
March 20, 2006


MANAGEMENT'S DISCUSSION AND ANALYSIS

ADVISORIES

Management's discussion and analysis ("MD&A") of Masters Energy Inc. ("Masters", the "company", "we" or "our"), provided as of March 20, 2006, should be read in conjunction with the audited financial statements presented within this annual report.

Basis of Presentation - The financial data presented below has been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar.

Non-GAAP Measurements - The MD&A contains the term 'funds generated by operations' and 'funds generated by operations per share', which should not be considered an alternative to, or more meaningful than, net earnings or cash flow from operating activities as determined in accordance with GAAP as an indicator of the company's performance. Masters' determination of funds generated by operations or funds generated by operations per share may not be comparable to that reported by other companies. Management uses funds generated by operations to analyze operating performance and leverage and considers funds generated by operations to be a key measure as it demonstrates the company's ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between net earnings and funds generated by operations can be found in the statements of cash flows in the audited financial statements. The company presents funds generated by operations per share, which is prohibited under GAAP. Per share amounts are calculated using weighted average shares outstanding consistent with the calculation of earnings per share.

Presentation of boe - Masters bases calculations of barrels of oil equivalent ("boe") on a conversion rate of six thousand cubic feet ("mcf") of natural gas to one barrel ("bbl") of crude oil. The boe unit may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf equals 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Forward Looking Information - This MD&A contains forward-looking or outlook information with regard to Masters within the meaning of applicable securities laws. Forward-looking statements may include estimates, plans, expectation, forecasts, guidance or other statements that are not statements of fact. Masters believes the expectations reflected in such forward-looking statements are reasonable. However, no assurance can be given that such expectations will prove to be correct. These statements are subject to certain risks and uncertainties and may be based on assumptions that could cause actual results to differ materially from those anticipated or implied in the forward looking statements. These risks include but are not limited to: crude oil and natural gas price volatility, exchange rate and interest rate fluctuations, availability of services and supplies, market competition, uncertainties in the estimates of reserves, the timing of development expenditures, production levels and the timing of achieving such levels, Masters' ability to replace and expand oil and natural gas reserves, the sources and adequacy of funding for capital investments, the company's future growth prospects and current and expected financial requirements, the cost of future reclamation and site restoration, Masters' ability to enter into or renew leases and to secure adequate product transportation, changes in environmental and other regulations and general economic conditions. These statements speak only as of the date of this MD&A and Masters does not undertake an obligation to update our forward-looking statements except as required by law.

Disclosure Controls and Procedures - Chief executive officer, Geoffrey C. Merritt, and chief financial officer, Randall P. Boyd, evaluated the effectiveness of Masters' disclosure controls and procedures as of December 31, 2005 and concluded that Masters' disclosure controls and procedures were effective to ensure that information the company is required to disclose in its annual and interim filings or other reports filed or submitted by it under provincial legislation is recorded, processed, summarized and reported within the time periods specified in the provincial securities legislation and to ensure that information required to be disclosed by Masters is accumulated and communicated to company management, including its chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

The evaluation took into consideration Masters' Disclosure Policy and the functioning of its executive officers, board of directors and board committees. In addition, the evaluation covered the company's processes, systems and capabilities relating to regulatory filings, public disclosures and the identification and communication of material information. All controls and procedures, no matter how well designed, have inherent limitations. These controls and procedures provide reasonable, but not absolute, assurance that financial information is accurate and complete.

CORPORATE OVERVIEW

Masters Energy Inc. was incorporated under the Alberta Business Corporations Act on August 28, 2003. During the fall of 2003 Masters completed a private placement of 17,752,000 special warrants for gross proceeds of $17.8 million. On December 22, 2003 Masters closed the acquisition of producing oil and gas properties in the Little Bow area of southern Alberta. At the time of acquiring the property, daily production was approximately 450 boe/d with a composition of 90 percent oil and 10 percent gas.

On February 26, 2004, Masters and Terraquest, a public company listed on the Toronto Stock Exchange, amalgamated and the combined company ("Amalco") continued under the name and management of Masters Energy Inc. The transaction saw Terraquest shareholders receive one Amalco common share for every 12 common shares of Terraquest and Masters shareholders received one Amalco common share for every two common shares of Masters. After giving effect to the transaction, Amalco had approximately 14.4 million common shares outstanding.

During 2005, Masters acquired oil and natural gas producing properties in the North Peace River Arch area for $7.2 million. At the time of the acquisitions the properties produced approximately 160 boe/d and provided ownership in one natural gas processing plant, five compressor stations and associated infrastructure.

In 2005, Masters drilled 22 exploration and development wells, resulting in six oil and 10 natural gas wells for an overall success rate of 73 percent. In addition, we drilled a water injection well at Little Bow to enhance oil recovery from the existing pool. During 2005, we spent $20.3 million on our exploration and development program.

Results of operations for the years ended December 31, 2005 and 2004



PRODUCTION

2005 2004
----------------------
Annual Production
Crude oil (bbls) 254,450 204,049
Natural gas liquids ("NGL") (bbls) 3,838 2,550
Natural gas (mcf) 1,195,641 624,536
Total (boe) 457,562 310,688
Daily Production
Crude oil (bbls/d) 697 558
NGL (bbls/d) 11 7
Natural gas (mcf/d) 3,276 1,706
Total (boe/d) 1,254 849


For the year ended December 31, 2005 total production increased 48 percent and averaged 1,254 boe/d (2004 - 849 boe/d) with oil production including NGL comprising 56 percent (2004 - 66 percent) and natural gas, 44 percent (2004 - 34 percent). Production increased during 2005 as a result of drilling and tying in successful wells and the acquisition of producing properties in the North Peace River Arch area.

Based on drilling activity budgeted for 2006 and production expected from existing producing properties, Masters forecasts a total production rate of 1,800 - 2,000 boe/d comprised of 40 percent oil including NGL and 60 percent natural gas.



PRICES

2005 2004
----------------------
Crude oil - before hedging ($/bbl) 44.82 37.66
Hedging settlement ($/bbl) - (1.15)
----------------------
Crude oil - after hedging ($/bbl) 44.82 36.51
----------------------
----------------------
NGL ($/bbl) 55.19 44.25
----------------------
----------------------
Natural gas ($/mcf) 8.87 6.59
----------------------
----------------------


West Texas Intermediate ("WTI") is the benchmark for North American oil prices and is the crude oil type against which NYMEX futures contracts are priced. Canadian crude oil prices are based on refiners' postings at hubs such as Edmonton and Hardisty, Alberta. The basis for Canadian postings is the WTI price at Cushing, Oklahoma minus a transportation differential, adjusted for the US/Canadian currency exchange rate and for relative quality and regional market conditions.

During 2005, North America experienced historically high price levels for WTI crude oil due to concerns regarding supply. As a result, the average price for a barrel of WTI crude during 2005 increased more than US$15.00 to US$56.59. During 2005, the Canadian dollar strengthened relative to the US dollar with the average currency exchange rate for $1.00 Canadian increasing to US$0.83 (2004 - US$0.77). The higher exchange rate reduced the price received for delivery of crude within Canadian markets. Quality price differential postings on medium types of crude oil also experienced a negative effect during 2005. The average differential between Edmonton light sweet crude postings and Hardisty Bow River medium crude increased to approximately $25.00 per bbl (2004 - $15.00 per bbl).

In 2005, Masters' average field price for crude oil was $44.82 per bbl versus $69.18 per bbl for light sweet postings at Edmonton, Alberta. All crude revenues during 2005 were from sales to spot markets. Masters did not hedge any production during 2005. Overall, Masters' 2005 crude oil production was 84 percent medium and 16 percent lighter gravity crude.

The 2004 average crude price recorded in the above table is net of hedging settlements of $0.2 million. The acquisition of Terraquest Energy Corporation included a hedging contract. The loss in 2004 amounted to the balance in excess of the fair value of the hedging contract liability recorded at the time of the acquisition.

The typical reference for US natural gas prices is NYMEX at Henry Hub, Louisiana while the reference for Canadian prices is at Nova Inventory Transfer ("NIT") or the AECO Hub. Masters sold all natural gas produced during 2005 and 2004 to the spot market according to the AECO reference price. Masters did not enter into any fixed or hedged type natural gas sales contracts during 2005 and 2004.

Masters' average natural gas price in 2005 was $8.87 per mcf versus $8.69 per mcf for spot postings of the AECO reference price.

Masters' management complies with a Risk Management Policy approved by the company's board of directors. The objective of Masters' risk management activities is to reduce exposure to decreases in commodity prices that would materially impact the funds generated by operating activities which fund capital spending and, ultimately, affect Masters' growth. Any transactions entered would be with credit worthy purchasers and would be for less than one year. To ensure Masters has sufficient physical volumes available to meet the obligations of these transactions, Masters limits the volumes contracted to no more than 50 percent of forecasted production.

The forecasted average wellhead prices used for Masters' 2006 budget were $45.00 (US$60.00 WTI) per bbl of crude oil and Cdn$8.00 per mcf of natural gas. The 2006 forecasted foreign currency exchange rate is estimated to average US$0.85 per Cdn$1.00.



REVENUES

($ thousands, except as indicated) 2005 2004
------------------------------------------------------------------------
Crude oil revenue 11,405 7,685
Hedging charge - (234)
----------------------
Crude oil revenue, after hedging charge 11,405 7,451
NGL revenue 211 113
Natural gas revenue 10,600 4,116
----------------------
Total petroleum and natural gas revenue 22,216 11,680
Royalty and other revenue 713 298
----------------------
Total revenue 22,929 11,978
----------------------
Total petroleum and natural gas revenue per boe ($) 48.55 37.59
----------------------
----------------------
Total revenue per boe ($) 50.11 38.55
----------------------
----------------------


Petroleum and natural gas revenue for the 2005 year increased 90 percent to $22.2 million due to a 47 percent increase in production as well as a 29 percent increase in realized commodity prices. A $0.2 million loss recorded for the balance remaining on the hedge contract assumed through the acquisition of Terraquest partially offset crude oil revenues for 2004. That hedging contract expired on December 31, 2004.

Royalty and other revenue increased by 139 percent to $0.7 million as a result of royalty interests acquired with the North Peace River Arch acquisition as well as higher commodity prices throughout 2005.

Based on forecasted production volumes and commodity prices, Masters forecasts an increase in oil and natural gas revenues of approximately 35 - 45 percent during 2006.



ROYALTIES

($ thousands, except as indicated) 2005 2004
------------------------------------------------------------------------
Crown 4,382 2,122
Alberta Royalty Tax Credit ("ARTC") (500) (184)
----------------------
Crown, net of ARTC 3,882 1,938
Freehold and gross overriding 813 441
----------------------
Total royalties 4,695 2,379
----------------------
----------------------
Per boe ($) 10.26 7.66
----------------------
----------------------
Average royalty rate, before hedge charge (%)(1) 21.1 20.0
Average royalty rate, after hedge charge (%)(1) 21.1 20.4

(1) A percentage of total petroleum and natural gas revenue



Royalties paid for the year ended December 31, 2005 increased 97 percent. Masters' average royalty rate, before recording the effects of hedging charges, increased to 21.1 percent during 2005 (2004 - 20.0 percent). The average royalty rate, after recording the effects of hedging charges, increased to 21.1 percent (2004 - 20.4 percent). The 2005 royalty expense is comprised of 83 percent (2004 - 81 percent) paid to the crown with the remainder paid to freehold and gross overriding royalty owners. In 2005, Masters paid royalties amounting to $10.26 per boe (2004 - $7.66 per boe).

Masters anticipates forecasted royalty rates for 2006 will be consistent with historical rates.



OPERATING EXPENSES

($ thousands, except as indicated) 2005 2004
------------------------------------------------------------------------
Production expenses 4,168 2,816
Transportation costs - 37
----------------------
Total operating expenses 4,168 2,853
----------------------
----------------------
Per boe ($) 9.11 9.18
----------------------
----------------------


In 2005, operating expenses per boe decreased one percent to $9.11 per boe. Operating expenses were higher than anticipated due to third party processing fees associated with prior years' production and a one time increase in electrical power rates at our Little Bow facilities during the fourth quarter of 2005. In 2004, operating expenses included transportation costs incurred on contracted natural gas deliveries.

Masters expects 2006 operating expenses per boe to decrease as production volumes increase and fixed costs are spread over a larger production base from our core areas. However, we anticipate that increased industry activity may result in variable costs, such as utility and service fees, partially offsetting the decrease in fixed operating expenses per boe.



Netback Analysis

($ per boe) 2005 2004
------------------------------------------------------------------------
Oil and natural gas revenues, before hedge charge 48.55 38.35
Hedge charge - (0.75)
----------------------
Oil and natural gas revenues, after hedge charge 48.55 37.60
Royalty and other revenue 1.56 0.96
----------------------
50.11 38.56
Royalty expense, net of ARTC (10.26) (7.66)
Operating expenses (9.11) (9.18)
----------------------
Operating netback 30.74 21.72
----------------------
----------------------


GENERAL AND ADMINISTRATIVE

($ thousands, except as indicated) 2005 2004
------------------------------------------------------------------------
Gross general and administrative 1,904 1,529
Operating recoveries (78) (121)
Capitalized expenses (617) (504)
----------------------
General and administrative, before stock-based
compensation 1,209 904
Future stock-based compensation expense 227 173
----------------------
Total general and administrative expense 1,436 1,077
----------------------
----------------------
General and administrative expense, before
stock-based compensation, per boe ($) 2.64 2.91
----------------------
----------------------
Total general and administrative expense per boe ($) 3.14 3.47
----------------------
----------------------


On a per boe basis, total general and administrative expense in 2005 decreased 10 percent to $3.14 per boe (2004 - $3.47 per boe). The 25 percent increase in gross general and administrative expenses 2005 to $1.9 million (2004 - $1.5 million), resulted mainly from expenses for initial annual reporting and regulatory filing, as well as implementation of results-based compensation. During 2005, Masters capitalized approximately one-third of general and administrative costs associated with exploration and development activities. Masters capitalizes general and administrative expense directly related to exploration and development activities as these costs are associated with adding reserves. General and administrative expenses for 2005 and 2004 include a non-cash provision of $0.2 million for future stock-based compensation.

We anticipate that total general and administrative expenses for 2006 will be similar to 2005. Based on forecasted production and capital spending, we estimate 2006 staff levels will be similar to 2005. As we bring new production on stream, we anticipate a reduction in general and administrative costs per boe.




INTEREST EXPENSE

($ thousands, except as indicated) 2005 2004
------------------------------------------------------------------------
Total interest expense 414 112
----------------------
----------------------
Per boe ($) 0.91 0.36
----------------------
----------------------


Interest expense increased 270 percent to $0.4 million in 2005 (2004 - $0.1 million). This reflects an increase in average debt levels during the year as interest rates remained relatively stable. At year-end 2005, Masters had bank debt of $14.1 million (2004 - $3.4 million). Average debt outstanding during the year was approximately $9.5 million. Increased exploration and development activities during the latter half of 2005 led to a change in the year-end balance from the average annual borrowing level. Our average interest rate to borrow during the year was 4.36%.

Masters forecasts average bank debt and interest rates for 2006 will moderately increase from 2005. For 2006, we anticipate that Masters' ratio of debt to funds generated by operations will be approximately one to one.



DEPLETION, DEPRECIATION AND ACCRETION

($ thousands, except as indicated) 2005 2004
------------------------------------------------------------------------
Depletion 6,502 4,283
Depreciation 11 13
Accretion on asset retirement obligations 114 171
----------------------
----------------------
Total depletion, depreciation and accretion expense 6,627 4,467
----------------------
----------------------
Depletion, depreciation and accretion expense
per boe ($) 14.48 14.38
----------------------
----------------------


During 2005, depletion, depreciation and accretion expense increased 48 percent to $6.6 million (2004 - $4.5 million). This increase is primarily the result of Masters' increase in production. Depletion, depreciation and accretion marginally increased to $14.48 per boe during 2005 (2004 - $14.38 per boe) as a result of 2005 finding and development costs attributed to reserves additions being comparable to the historical carrying values of assets eligible for depletion.

Masters performs an annual ceiling test in accordance with the Canadian Institute Chartered Accountants' full cost accounting guidelines, using forecasted prices determined by the independent qualified reserves evaluation firm that evaluates Masters' reserves. As well, Masters performs a quarterly ceiling test using adjusted prices received at period end. At December 31, 2005, the impairment recognition portion of the ceiling test indicated the estimated undiscounted future cash flows from proven reserves exceeded the carrying values of producing petroleum and natural gas properties and, therefore, a ceiling test adjustment was not required.



INCOME TAXES

($ thousands, except as indicated) 2005 2004
------------------------------------------------------------------------
Future 1,975 662
Capital 3 -
----------------------
Total income taxes 1,978 662
----------------------
----------------------
Effective tax rate (%) 35.4 60.7
----------------------
----------------------


Income taxes, future and capital increased 199 percent in 2005 to $2.0 million (2004 - $0.7 million). Increased earnings before taxes, as a result of higher commodity prices and increased production volumes, were the main reason for the increase in total income taxes. Based on available tax pools, forecasted capital spending levels and commodity prices, Masters does not expect to be currently taxable for the 2006 year.

Masters has approximately $46.6 million in tax pools to shelter taxable income in the future years. The table below shows estimated 2005 tax pools.



($thousands) 2005
------------------------------------------------------------------------
Canadian Exploration Expense $ 8,988
Canadian Development Expense 6,773
Canadian Oil and Gas Property Expense 20,596
Undepreciated Capital Cost 9,371
Other 824
----------------------
Total $46,552
----------------------
----------------------


NET EARNINGS

In 2005, net earnings increased 654 percent to $3.6 million (2004 - $0.4 million), primarily from increased revenues driven by higher commodity prices and larger production volumes. Net earnings increased in 2005 to $7.06 per boe (2004 - $1.38 per boe) while funds generated by operating activities increased in 2005 to $27.20 per boe (2004 - $18.45 per boe).



Earnings Ratios
($ thousands, except as indicated) 2005 2004
----------------------
Net earnings 3,611 428
Earnings ratios (%)
Return on capital (1) 10.1 2.3
Return on investment (2) 9.5 2.0
Return on shareholder equity (3) 12.2 1.9

(1) Net earnings plus after-tax financing charges on debt divided by
average of opening and closing capital employed. Capital employed
is a total of equity and bank debt.
(2) Net earnings plus after-tax financing charges on debt divided by
average net investment. Net investment is total assets less
current liabilities. Return on investment is calculated using the
average opening and closing net investment.
(3) Net earnings are divided by average of opening and closing
shareholders' equity.


Net Earnings per boe

($/boe) 2005 2004
------------------------------------------------------------------------
Total revenues (after hedge charges) 50.11 38.55
Royalties (10.26) (7.65)
Operating expenses (9.11) (9.18)
----------------------
Net operating income 30.74 21.72
General and administrative (excluding stock-based
compensation expense) (2.64) (2.91)
Interest expense (0.91) (0.36)
----------------------
Funds generated by operating activities 27.19 18.45
Depletion, depreciation and accretion (14.48) (14.38)
Stock-based compensation (0.50) (0.56)
Taxes (4.32) (2.13)
----------------------
Net earnings 7.89 1.38
----------------------
----------------------


SHARE CAPITAL

During 2005, Masters issued 159,666 common shares (2004-nil) on the exercise of stock options and performance warrants by employees. Stock options granted to employees during the year amounted to 50,000 common shares (2004 - 670,000 common shares).

The weighted average common shares outstanding, for the three month period ended December 31, 2005 was 14,490,650 basic (15,481,767 diluted). For the year ended December 31, 2005 the basic weighted average shares outstanding was 14,420,197 (2004 - 13,521,707) and the diluted average shares outstanding was 15,090,130 (2004 - 13,716,226). Shares issued and outstanding, as at December 31, 2005, were 14,523,313 (2004 - 14,363,647). As of the date of the MD&A, the number of shares issued and outstanding had not changed from 2005 year-end.



2005 2004
----------------------
Outstanding Common Shares (thousands)
Weighted average outstanding common shares
- Basic 14,420 13,522
- Diluted 15,090 13,716
Outstanding common shares at December 31
- Common shares (basic) 14,523 14,364
- Common share options 1,127 1,255
- Common share warrants 870 1,000
- Common shares outstanding (diluted) 16,520 16,619

($ thousands except as indicated)
Per Share Information
Net earnings 3,611 428
Net earnings per share ($)
- Basic 0.25 0.03
- Diluted 0.24 0.03
Funds from operating activities 12,159 5,634
Funds from operating activities per share ($)
- Basic 0.84 0.42
- Diluted 0.81 0.41
Total asset book value 60,016 37,291
Total asset book value per share(1) ($)
- Basic 4.13 2.60
- Diluted 3.63 2.24
Book value (shareholders' equity) (1) 31,791 27,570
Book value per share ($)
- Basic 2.19 1.92
- Diluted 1.92 1.66
Proved plus probable reserves (mboe) 3,986 2,834
Reserves per 100 shares (boe) (1)
- Basic 27.4 19.7
- Diluted 24.1 17.1
Annual production (mboe) 458 311
Production per 100 shares (boe) (1)
- Basic 3.2 2.2
- Diluted 2.8 1.9

(1) Calculated using outstanding common shares, options and
warrants at year-end.


Net Asset Value

Masters' net asset value per share at December 31, 2005 increased by 74 percent to $4.86 per basic share (2004 - $2.80 per share) and by 65 percent to $4.63 per diluted share (2004 - $2.80 per share).



($ thousands, except as indicated) 2005 2005 2004
------------------------------------------------------------------------
Constant Forecast Forecast
Price Price(1) Price(1)
Proved plus probable reserves value
(10% discount before tax) 78,173 74,761 36,127
Undeveloped acreage (2) 14,965 14,965 8,245
Net debt (19,106) (19,106) (4,116)
--------------------------------
Basic net asset value 74,032 70,620 40,256
Projected proceeds on exercise of
options and warrants 5,847 5,847 6,309
--------------------------------
Diluted net asset value 79,879 76,467 46,565
--------------------------------
--------------------------------
Common shares outstanding (thousands)
- Basic 14,523 14,523 14,364
- Diluted 16,520 16,520 16,619
Net asset value per common share ($)
- Basic (3) 5.10 4.86 2.80
- Diluted (3) 4.84 4.63 2.80
(1) The reserves values are based on before tax future cash flows as
evaluated by the Company's independent qualified reserves
evaluators, McDaniel & Associates Consultants Ltd. using their
future commodity price forecast, then in effect.
(2) The land values are determined using an estimated value in 2005 of
$150 (2004 - $100) per undeveloped acre.
(3) Calculated using outstanding common shares, options and performance
warrants at year-end.


CAPITAL EXPENDITURES

Total capital expenditures during 2005 were $27.5 million which included $20.3 million for exploration and development expenditures and $7.2 million for the acquisition of producing oil and natural gas properties in the North Peace River Arch area. The 2005 exploration and development activity resulted in 22 (gross) exploration and development wells drilled, acquisition of 15,648 net acres of undeveloped crown land and completion of several 3D seismic programs to acquire 70 square miles of data. In 2005, Masters' exploration and development capital allocation was approximately $12.8 million in southern Alberta and $7.5 million in northern and central Alberta.



($ thousands) 2005 2004
-----------------
Land 2,401 889
Geological and geophysical 3,037 620
Drilling and completions 10,430 6,652
Equipping and facilities 4,390 2,757
Other 31 2
-----------------
Total exploration and development capital 20,289 10,920
Producing property acquisitions 7,244 -
Terraquest Energy Corporation - 19,584
-----------------
Total capital expenditures 27,533 30,504
-----------------
-----------------


Undeveloped Land Holdings

Masters' undeveloped land increased by 20 percent to 99,766 net acres and we have access to approximately 19,200 acres of option lands or control of approximately 119,000 total acres. In 2005 Masters acquired 15,648 net acres through crown land sales and approximately 10,600 net undeveloped acres through the North Peace River Arch acquisitions. At December 31, 2005, in the North Peace River Arch core area, Masters had 19,200 gross acres with an option to earn an interest. Masters will earn an interest in these option lands upon performing certain activities. The term on these lands extends through to the end of December 31, 2006. The average working interest of the undeveloped lands Masters owned at December 31, 2005 was 45 percent.



Alberta (acres) 2005 2004
-------------------------------------
Gross Net Gross Net
-------------------------------------
Southern 32,367 24,298 28,813 20,432
Northern and Central 190,411 75,468 129,043 62,994
-------------------------------------
Total owned undeveloped land 222,778 99,766 157,856 83,426
-------------------------------------
-------------------------------------
Total controlled option land 19,200 -
-------------------------------------
-------------------------------------


Finding and Development Costs

During 2005, our exploration and development program resulted in total proved reserves additions, after prior year revisions, of 860,000 boe, or 1,110,000 boe on a proved plus probable basis. Masters' total finding and development costs were $23.59 per proved boe and $18.28 per proved plus probable boe. After adding in the change in future development capital, finding and development costs were $24.54 per proved boe and $19.05 per proved plus probable boe. Total finding and development and net acquisition costs were $21.44 per proved boe and $15.80 per proved plus probable boe.

The combined 2003 to 2005 capital programs including the acquisitions of Little Bow, Terraquest and North Peace River Arch resulted in finding and development costs of $17.14 per proved boe and $13.39 per proved plus probable boe. After adding in the change to estimated future development capital, finding and development costs were $17.40 per proved boe and $13.61 per proved plus probable boe.

The reserves disclosed for 2005 and 2004 conform with the requirements of National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities.



2005 Finding & Development (F&D) and Net Acquisition (FD&A) Costs

Proved
plus Proved
Proved Probable plus
Capital Reserves Proved Reserves Probable
Expenditures Additions Costs Additions Costs
------------------------------------------------------------------------
($ thousands) (mboe)($/boe) (mboe) ($/boe)

F&D exploration and
development programs
before revisions 20,289 702 28.90 942 21.54
------------------------------------------------------------------------
------------------------------------------------------------------------
F&D exploration and
development program
after revisions (a) 20,289 860 23.59 1,110 18.28
------------------------------------------------------------------------
------------------------------------------------------------------------
Change in proved future
development capital (b) 819 n/a n/a n/a n/a
------------------------------------------------------------------------
Change in proved plus
probable future
development capital (C) 853 n/a n/a n/a n/a
------------------------------------------------------------------------
Proved F&D including
change in future
development capital
(d)=(a+b) 21,108 860 24.54 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Proved plus probable F&D
including change in
future development
capital (e)=(a+c) 21,142 n/a n/a 1,110 19.05
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition activity,
working interest reserves 5,244 309 16.97 500 10.49
------------------------------------------------------------------------
Net acquisition activity,
royalty interest reserves 2,000 115 17.39 133 15.04
------------------------------------------------------------------------
Total net acquisition
activity, company
interest reserves(f) 7,244 424 17.08 633 11.44
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2005 FD&A costs
before future
development costs (a+f) 27,533 1,284 21.44 1,743 15.80
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2005 proved FD&A
costs including future 28,352 1,284 22.08 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
development costs (d+f)
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2005 proved plus
probable FD&A costs
including future
development costs (e+f) 28,386 n/a n/a 1,743 16.29
------------------------------------------------------------------------
------------------------------------------------------------------------


2004 Finding & Development (F&D) and Net Acquisition (FD&A) Costs

Proved
plus Proved
Proved Probable plus
Capital Reserves Proved Reserves Probable
Expenditures Additions Costs Additions Costs
------------------------------------------------------------------------
($ thousands) (mboe)($/boe) (mboe) ($/boe)
F&D exploration and
development programs
before revisions 10,920 343 31.84 420 26.00
------------------------------------------------------------------------
------------------------------------------------------------------------
F&D exploration and
development program
after revisions (a) 10,920 572 19.09 588 18.57
------------------------------------------------------------------------
------------------------------------------------------------------------
Change in proved future
development capital (b) 178 n/a n/a n/a n/a
------------------------------------------------------------------------
Change in proved plus
probable future
development capital (C) 288 n/a n/a n/a n/a
------------------------------------------------------------------------
Proved F&D including
change in future
development capital
(d)=(a+b) 11,098 572 19.40 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Proved plus probable F&D
including change in
future development
capital (e)=(a+c) 11,208 n/a n/a 588 19.06
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition activity,
working interest reserves 19,584 840 23.31 1,149 17.04
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition activity,
royalty interest reserves - - - - -
------------------------------------------------------------------------
------------------------------------------------------------------------
Total net acquisition
activity, company
interest reserves(f) 19,584 840 23.31 1,149 17.04
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2004 FD&A costs
before future
development costs (a+f) 30,504 1,412 21.60 1,737 17.56
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2004 proved FD&A
costs including future
development costs (d+f) 30,682 1,412 21.73 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2004 proved plus
probable FD&A costs
including future
development costs (e+f) 30,792 n/a n/a 1,737 17.73
------------------------------------------------------------------------
------------------------------------------------------------------------

Combined 2003 to 2005 Finding & Development (F&D)
and Net Acquisition (FD&A) Costs


Masters Energy Inc. commenced operations December 22, 2003 with the
acquisition of the Little Bow property in southern Alberta. The combined
2003 to 2005 results are more representative of management's efforts as
presented in the table below.

Proved
plus Proved
Proved Probable plus
Capital Reserves Proved Reserves Probable
Expenditures Additions Costs Additions Costs
------------------------------------------------------------------------
($ thousands) (mboe)($/boe) (mboe) ($/boe)
F&D exploration and
development programs
before revisions 31,592 1,045 30.23 1,362 26.91
------------------------------------------------------------------------
------------------------------------------------------------------------
F&D exploration and
development program
after revisions (a) 31,592 1,432 22.06 1,698 19.22
------------------------------------------------------------------------
------------------------------------------------------------------------
Change in proved future
development capital (b) 997 n/a n/a n/a n/a
------------------------------------------------------------------------
Change in proved plus
probable future
development capital (C) 1,141 n/a n/a n/a n/a
------------------------------------------------------------------------
Proved F&D including
change in future
development capital
(d)=(a+b) 32,589 1,432 22.76 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Proved plus probable F&D
including change in
future development
capital (e)=(a+c) 32,733 n/a n/a 1,698 19.28
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition activity,
working interest reserves 31,838 2,270 14.03 3,057 10.41
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition activity,
royalty interest reserves 2,000 115 17.39 133 15.04
------------------------------------------------------------------------
------------------------------------------------------------------------
Total net acquisition
activity, company
interest reserves(f) 33,838 2,385 14.19 3,190 10.61
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 to 2005 FD&A
costs before future
development costs (a+f) 65,430 3,817 17.14 4,888 13.39
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 to 2005 proved
FD&A costs including
future development
costs (d+f) 66,427 3,817 17.40 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 to 2005 proved
plus probable FD&A
costs including future
development costs (e+f) 66,571 n/a n/a 4,888 13.61
------------------------------------------------------------------------
------------------------------------------------------------------------


Reserves Replacement

Masters' 2005 capital expenditure program replaced production by a factor of 2.6 times on a proved basis and 3.5 times on a proved plus probable basis.



2005 2004
------------------------------------------------------------------------
Production (mboe) 458 311
Proved reserves additions after revisions (mboe) 1,169 572
Proved replacement ratio 2.55 1.84
Proved plus probable reserves additions after
revisions (mboe) 1,610 588
Proved plus probable replacement ratio 3.52 1.89


Recycle Ratio

Recycle ratio is a measure for evaluating the effectiveness of a company's re-investment in its exploration and development program. The ratio measures the efficiency of capital investment. It accomplishes this by comparing the operating netback per barrel of oil equivalent to that year's finding and development costs per boe.



2005
------------------------------------------------------------------------
Operating netbacks ($/boe) 30.74
Proved FD&A costs after revisions and including
the change in future development cost ($/boe) 22.08
Proved reinvestment efficiency ratio 1.4
Proved plus probable FD&A costs after revisions
and including the change in future development cost ($/boe) 16.29
Proved plus probable reinvestment efficiency ratio 1.9


Drilling Results

During 2005, Masters drilled 22 exploration and development wells resulting in six oil wells and 10 natural gas wells for an overall success rate of 73 percent. Of the total wells drilled, 16 were in southern Alberta and the remaining six were in northern and central Alberta.


2005 2004
------------------------------------------------------------------------
(wells) Gross Net Gross Net
------------------------------------------------------------------------
Oil 6 6.0 - -
Natural gas 10 7.2 6 3.5
Dry and abandoned 6 4.4 8 5.7
------------------------------------------------------------------------
Total 22 17.6 14 9.2
------------------------------------------------------------------------
------------------------------------------------------------------------
Success rate (%) 73 75 43 38
------------------------------------------------------------------------
------------------------------------------------------------------------


CONTRACTUAL OBLIGATIONS

As part of our land acquisition strategy in our core areas, Masters will commit to industry partners to drill wells, shoot seismic programs or tie-in previously drilled wells to earn interests in undeveloped land. Masters has committed to drill four wells and tie-in a suspended oil and natural gas well to earn lands. Masters estimates these work commitments amount to approximately $1.5 million. These commitments are scheduled in Masters' 2006 capital expenditures program currently approved by the board of directors at $21 million.

Masters has contractual obligations on operating leases of field equipment. The operating leases are considered short term and due within one year, if demanded.

The table below shows payments due within the periods indicated.



Total Less than 1 - 3 4 - 5 After 5
($ thousands) 1 Year Years Years Years
------------------------------------------------------------------------
Bank debt 14,093 - 14,093 - -
Farm-in commitments 1,500 1,500 - - -
Operating leases 114 114 - - -
Office lease 418 87 269 62 -
------------------------------------------
Total contractual
obligations 16,125 1,701 14,362 62 -
------------------------------------------
------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Total capitalization at December 31, 2005 was $118.9 million (2004 - $44.5 million) with the market value of common shares representing 79 percent of total capitalization. Net debt represented 16 percent and asset retirement obligations plus future income taxes accounted for five percent.



Total Market Capitalization
($ thousands except as indicated) 2005 % 2004 %
------------------------------------------------------------------------
Common shares outstanding (thousands) 14,523 14,364
Closing share price at December 31 ($) 6.47 2.60
--------------------------------
Total market capitalization 93,966 79 37,346 84
--------------------------------
Working capital deficiency,
excluding bank debt 5,013 692
Bank debt 14,093 3,424
--------------------------------
Net debt 19,106 16 4,116 9
--------------------------------
Asset retirement obligations 3,316 3 3,044 7
Future income taxes 2,005 2 30 -
--------------------------------
Total capitalization 118,393 100 44,536 100
--------------------------------
--------------------------------
Net debt to total capitalization 16% 9%
--------------------------------
--------------------------------


At December 31, 2005 Masters had borrowed approximately $14.1 million (2004 - $3.4 million) and had a working capital deficit of $5.0 million (2004 - $0.7 million) amounting to total net debt of $19.1 million (2004 - $4.1 million). Net debt for 2005 represents approximately 1.6 times (2004 - 0.7 times) funds generated by operating activities of $12.2 million (2004 - $5.6 million) and approximately 1.1 to 1.3 times budgeted 2006 funds generated by operating activities.

The company has a bank revolving term facility of $18 million to fund future activities. The facility is a borrowing base facility determined by Masters' latest reserves assessment, results of operations, current and forecasted commodity prices and the prevailing economic market. The facility is reviewed annually in April. As at December 31, 2005, Masters had drawn $14.1 million of the revolving term facility.

The capital intensive nature of our activities can create a negative working capital position in quarters with high levels of exploration and development capital spending.

The industry has a pre-arranged monthly settlement day for payment of revenues from all buyers of crude and natural gas. This occurs on the 25th day following the month in which the production is sold. As a result Masters' sales revenues are collected in an organized manner. The company monitors purchaser credit positions to mitigate any potential credit losses. To the extent Masters has joint interest activities with industry partners we must collect, on a monthly basis, partners' share of capital and operating expenses. These collections are subject to normal industry risk. Masters collects in advance for significant amounts related to partners' share of capital expenditures in accordance with the industry operating procedures. At December 31, 2005 Masters had no material accounts receivable deemed uncollectible.

Accounts payable consists of invoices payable to trade suppliers relating to office and field operating activities and our capital spending program. Invoices are processed within Masters' normal payment period.

We continually manage Masters' capital spending program by monitoring forecasted production, commodity prices and anticipated cash flow. Should circumstances arise that negatively affect cash flow, Masters is capable of reducing the level of future capital spending.

We will fund our future investing activities, which consist primarily of capital expenditures on oil and natural gas activities, with working capital, cash flow from operations, a limited amount of bank debt and possibly, from the issuance of new equity


SELECTED QUARTERLY INFORMATION

This financial data presented below has been prepared in accordance with Canadian generally accepted accounting principles. The reporting and measurement currency is the Canadian dollar.




2005 2004
---------------------------------------------------------
Operations Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
---------------------------------------------------------
Production
Oil (bbl/d) 707 688 715 678 588 597 556 488
NGL (bbl/d) 10 15 11 6 13 5 9 2
Natural gas
(mcf/d) 3,619 3,872 3,055 2,538 2,406 1,980 1,653 800
Total (boe/d) 1,320 1,349 1,236 1,107 1,002 932 841 619
Pricing
Oil, before
hedging ($/bbl) 42.50 56.92 41.64 38.14 36.91 42.40 37.10 33.60
Hedging costs - - - - (0.01) (4.25) - -
---------------------------------------------------------
Oil, after
hedging
($/bbl) 42.50 56.92 41.64 38.14 36.90 38.15 37.10 33.60
NGL ($/bbl) 60.85 59.56 49.56 46.12 50.72 40.20 36.86 45.11
Natural gas
($/mcf) 11.29 9.09 7.34 6.83 6.62 6.24 6.51 7.35
Total ($/boe) 54.18 55.84 42.71 39.28 38.09 37.90 37.95 35.82
Financial
($ thousands,
except as
indicated)
Total revenue 6,908 7,175 4,836 4,010 3,679 3,319 2,952 2,028
Funds from
operating
activities 2,915 4,476 2,699 2,069 1,676 1,513 1,391 1,055
Net earnings
(loss) 630 1,781 643 557 (124) 79 (49) 521
Per share -
basic 0.04 0.12 0.04 0.04 (0.01) 0.01 - 0.05
Per share -
diluted 0.04 0.12 0.04 0.04 (0.01) 0.01 - 0.05
Capital spending
Exploration and
development 11,570 2,805 2,806 3,108 3,240 2,531 2,761 2,388
Acquisitions/
(dispositions) 31 (339) 7,552 - - - - 20,174
Total assets 60,016 51,142 48,130 38,830 37,291 35,518 34,833 34,271
Working capital
(deficiency) (5,013) 1,381 323 (5,155)(4,116)(2,551)(1,533) (163)
Long-term debt 14,093 11,911 13,137 - - - - -
Shareholders'
equity 31,791 31,033 28,884 28,184 27,570 27,639 27,504 27,508
Common Shares
Weighted average
common shares
outstanding
(thousands)
- basic 14,491 14,462 14,364 14,364 14,364 14,364 14,364 10,987
- diluted 15,482 15,146 14,931 14,801 14,614 14,553 14,505 11,184
Trading Activity
Volume
(thousands)
- total 2,351 2,467 3,096 4,149 2,858 910 868 220
- daily 38 39 48 67 45 14 14 12
Price
($ per share)
- high 6.95 4.70 3.80 4.20 2.85 2.77 2.69 3.25
- low 4.60 3.62 3.05 2.31 2.30 2.25 2.00 2.45
- closing 6.47 4.55 3.64 3.40 2.60 2.70 2.40 2.55


Factors that caused variations over the quarters

- Masters completed four significant acquisitions since its initial financing in the fourth quarter of 2003 which have impacted production growth:

- The acquisition of the Little Bow property in southern Alberta on December 22, 2003 added approximately 450 boe/d consisting of approximately 90 percent crude oil production. Proved plus probable reserves acquired were approximately 1.4 million boe with an estimated reserves life index of 8.6 years.

- The acquisition of Terraquest Energy Corporation on February 26, 2004 added production of approximately 400 boe/d consisting of approximately 60 percent natural gas. Proved plus probable reserves acquired were approximately 1.1 million boe with an estimated reserves life index of 7.9 years based on production at the time of acquisition.

- The two acquisitions of producing properties in the North Peace River Arch area of northwest Alberta on June 3, 2005 and September 12, 2005 added approximately 160 boe per day consisting primarily of natural gas production. Proved plus probable reserves acquired were approximately 0.5 million boe with an estimated reserves life index of 7.0 years.

- Production growth, other than the acquisitions, is a result of Masters' exploration and development activities. Timing of production is subject to timing of drilling and facility construction.

- Growth in revenue and cash flow is the combination of increased production and strong commodity prices. Generally, commodity prices were consistently strong throughout 2004 and 2005. Oil prices for medium grade quality crude experienced a large drop in the latter portion of the 2004 fourth quarter due to wider than historical quality differentials. This impacted the prices Masters received during the fourth quarter of 2004 and throughout 2005 as a majority of our crude production is medium quality.

- Depletion, depreciation, accretion and future income taxes influence net earnings. Masters estimates reserves internally every quarter based on acquisition and drilling activities. Independent qualified reserves evaluation engineers determine annual reserves, the results of which can affect fourth quarter reserves additions. Enacted changes to federal and provincial income tax rates for the oil and gas industry impact future income taxes.

- The development of future drilling prospects and seasonal field conditions influence capital spending. Cash flow and bank debt primarily funded capital spending.



FOURTH QUARTER ANALYSIS

% Change % Change
Q4 2005 Q4 2005
Q4 Q3 Q4 vs vs
2005 2005 2004 Q3 2005 Q4 2004
---------------------------------------
Operations Results
Production
Crude oil (bbls/d) 707 688 588 3 20
NGL (bbls/d) 10 15 13 (33) (23)
Natural gas (mcf/d) 3,619 3,872 2,406 (7) 50
Total (boe/d) 1,320 1,349 1,002 (2) 32
Pricing (after hedging)
Crude oil ($/bbl) 42.50 56.92 36.90 (25) 15
NGL ($/bbl) 60.85 59.56 50.72 2 20
Natural gas ($/mcf) 11.29 9.09 6.62 24 71
Selected Financial Results
($ thousands except as
indicated)
Total revenue 6,908 7,175 3,679 (4) 88
Royalties (1,815)(1,271) (824) 43 120
Operating expense (1,471)(1,000) (809) 47 82
General and administrative (398) (312) (334) 28 20
Funds generated by operating
activities 2,915 4,476 1,676 (35) 74
Depletion, depreciation
and accretion 2,184 1,728 1,309 26 67
Net earnings (loss) 630 1,781 (124) (86) 298
per share -basic ($) 0.04 0.12 (0.01) (83) 300
per share - diluted ($) 0.04 0.12 (0.01) (83) 300
Capital spending
exploration and
development 11,570 2,805 3,240 313 257
acquisitions/(dispositions) 31 (339) - 109 100
Total capital spending 11,604 2,466 3,240 371 258
Working capital (deficiency) (5,013) 1,381 (4,116) (463) 22
Long-term debt 14,093 11,911 - 18 100
Shareholders' equity 31,791 30,996 27,570 3 15
Weighted average common
shares outstanding
(thousands)
- basic 14,491 14,462 14,364 - 1
- diluted 15,482 15,146 14,614 2 6


PRODUCTION

Production for the fourth quarter 2005 decreased two percent to 1,320 boe/d compared to the third quarter at 1,349 boe/d but increased 32 percent compared to the fourth quarter of 2004. The production decrease in the fourth quarter occurred when final installation of new water handling facilities at Little Bow temporarily suspended production for several days. Also, surface access delays and lack of rig availability delayed new production additions. Production briefly reached 1,600 boe/d during the 2005 fourth quarter. However, a natural gas well at Hector watered-out prematurely, became uneconomic and was shut-in which adversely affected average daily production for that period. Production increases since the 2004 fourth quarter resulted from successful drilling coming on stream and acquisition of producing properties in the North Peace River Arch area during 2005 second and third quarters.

REVENUES

Revenues for the 2005 fourth quarter decreased four percent to $6.9 million compared to $7.2 million in the 2005 third quarter and increased 88 percent from the 2004 fourth quarter. In the quarter ended December 31, 2005, Edmonton Par postings were lower for crude oil as compared to the third quarter. Record widening of the quality differential for medium types of crude oil to a difference of approximately $28.69 per bbl between the Edmonton Par posting for lighter quality crude and Hardisty Bow River medium crude negatively impacted Masters' 2005 fourth quarter revenues. However, revenues for the 2005 fourth quarter increased over the same period in 2004 as a result of both higher total production and stronger commodity prices.

ROYALTIES

Royalties for the 2005 fourth quarter increased 43 percent to $1.8 million compared to $1.3 million in the 2005 third quarter and increased 120 percent from the 2004 fourth quarter. The majority of royalty expense incurred during the quarters was payable to the crown. Masters' November 2005 price received for natural gas was significantly less than the Alberta reference price resulting in higher than normal crown royalties relative to revenue received. In addition, Masters maximized its ARTC claim on eligible crown royalties during the 2005 fourth quarter and, therefore, the amount of royalties paid to the crown increased compared to the 2005 third quarter. Royalties for the period ended December 31, 2005 increased from the same period in 2004 as a result of higher oil and natural gas revenues. We anticipate the future average royalty rate relative to oil and natural gas revenues will be consistent with historical royalty rates.

OPERATING EXPENSES

Operating expenses for the 2005 fourth quarter increased 47 percent to $1.5 million from $1.0 million in the 2005 third quarter. Third party processing charges for production in prior periods and higher than normal electrical power rates at the Little Bow facility pushed operating expenses higher than anticipated in the 2005 fourth quarter. For the three months ended December 31, 2005 operating expenses increased 82 percent from the same period in 2004 as result of the previously noted exceptions and higher production. Masters forecasts operating costs will average approximately $8.50 per boe during 2006.

GENERAL AND ADMINISTRATIVE

The 2005 fourth quarter general and administrative expense increased 28 percent to $0.4 million from the 2005 third quarter and 20 percent from the 2004 fourth quarter. General and administrative expenses averaged $3.28 per boe for the 2005 fourth quarter compared to $2.51 per boe in the 2005 third quarter and $3.62 per boe in the 2004 fourth quarter. The 2005 fourth quarter general and administrative expenses include provisions for the annual audit and reserves reports. Masters forecasts 2006 general and administrative expenses, including a non-cash provision for future stock-based compensation of approximately $0.2 million, at approximately $2.20 per boe.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion, depreciation and accretion expense for the 2005 fourth quarter was $2.2 million compared to $1.7 million for the 2005 third quarter and $1.3 million for the 2004 fourth quarter. Depletion, depreciation and accretion provision for the 2005 fourth quarter was $17.98 per boe compared to $13.93 per boe in the 2005 third quarter and $14.27 per boe for the 2004 fourth quarter. The depletion rate per boe for the 2005 fourth quarter reflected the disproportionate amount of 2005 exploration and development activities that occurred during the fourth quarter. The increase in the depletion rate since the 2004 fourth quarter was due to acquisition of the North River Arch properties and elevated exploration and development activities throughout 2005.

INCOME TAXES

The future income tax provision for the 2005 fourth quarter was $0.3 million compared to $0.9 million for the 2005 third quarter and $0.5 million for the 2004 fourth quarter. This resulted in an effective tax rate of 29 percent for the 2005 fourth quarter compared to 35 percent for the 2005 third quarter. The effective rate for the 2005 fourth quarter decreased due to higher than anticipated provincial credits on crown royalties claimed during the period.

NET EARNINGS

Net earnings for the 2005 fourth quarter were $0.6 million compared to $1.8 million for the 2005 third quarter and a loss of $0.1 million during the 2004 fourth quarter. The decrease in net earnings for 2005 fourth quarter compared to 2005 third quarter is mainly due to higher royalty and operating expenses. For the three months ended December 31, 2005, the increase in net earnings compared to the same period in 2004 is due to higher revenues from increased production and stronger commodity prices.

CAPITAL EXPENDITURES

During the 2005 fourth quarter Masters spent $11.6 million on exploration and development capital including $1.3 million in land, $2.5 million in seismic, $5.3 million in drilling and completions and $2.5 million in facilities. During the quarter ended December 31, 2005, we drilled 10 wells resulting in three oil and two natural gas wells, acquired 5,448 net acres of undeveloped land; completed several 3D seismic programs over exploration acreage in North Peace River Arch and MacGregor and expanded water handling facilities at Little Bow.

Capital spending during the 2005 fourth quarter was $11.6 million compared to $2.8 million in the 2005 third quarter and to $3.2 million in the 2004 fourth quarter.

RESERVES DATA

Reserves Data - Constant Prices and Costs

Summary of oil and gas reserves and net present values of future net revenue as of December 31, 2005.



Reserves
-------------------------------------------
Natural
Light And Gas Natural
Medium Oil Liquids Gas Total
------------ --------- --------- -------
Gross Gross Gross Gross
Reserves Category (mbbls) (mbbls) (mmcf) (mboe)
--------------------------- ------------ --------- --------- -------

Proved
Developed Producing 1,750 11 4,064 2,438
Developed Non-Producing 51 11 2,329 451
Undeveloped 36 - 54 45
------------ --------- --------- -------
Total Proved 1,837 22 6,447 2,934

Probable 526 9 3,111 1,053
------------ --------- --------- -------

Total Proved Plus Probable 2,363 31 9,559 3,987
------------ --------- --------- -------
------------ --------- --------- -------


Net Present Values Of Future Net Revenue
------------------------------------------
Before Income Taxes Discounted At
(percent per year)
------------------------------------------
0 5 10 15 20
Reserves Category ($mm) ($mm) ($mm) ($mm) ($mm)
--------------------------- ------- ----- ----- ----- -----

Proved
Developed Producing 63.5 53.9 47.0 41.9 37.9
Developed Non-Producing 15.6 12.5 10.4 8.9 7.8
Undeveloped 4.0 3.2 2.7 2.3 2.0
------- ----- ----- ----- -----
Total Proved 83.1 69.6 60.0 53.0 47.7

Probable 33.1 23.7 18.1 14.5 12.0
------- ----- ----- ----- -----

Total proved plus probable 116.2 93.3 78.2 67.6 59.7
------- ----- ----- ----- -----
------- ----- ----- ----- -----


Reserves Data - Forecast Prices and Costs

Summary of oil and gas reserves and net present values of future net
revenue as of December 31, 2005.

Reserves
-------------------------------------------
Natural
Light And Gas Natural
Medium Oil Liquids Gas Total
------------ --------- --------- -------
Reserves Category Gross Gross Gross Gross
--------------------------- ------------ --------- --------- -------
(mbbls) (mbbls) (mmcf) (mboe)

Proved
Developed Producing 1,749 11 4,063 2,437

Developed Non-Producing 51 11 2,329 451
Undeveloped 36 - 54 45
------------ --------- --------- -------
Total Proved 1,837 22 6,446 2,933

Probable 526 9 3,109 1,053
------------ --------- --------- -------
Total Proved
Plus Probable 2,362 31 9,556 3,986
------------ --------- --------- -------
------------ --------- --------- -------


Net Present Values Of Future Net Revenue
------------------------------------------
Before Income Taxes Discounted At
(percent per year)
------------------------------------------
Reserves Category 0 5 10 15 20
--------------------------- ------- ----- ------ ------ ------
($ millions)
Proved
Developed Producing 63.9 54.8 48.3 43.4 39.6
Developed Non-Producing 12.2 9.9 8.4 7.3 6.5
Undeveloped 3.9 3.2 2.7 2.3 2.0
------- ----- ------ ------ ------
Total Proved 80.0 67.9 59.3 52.9 48.0

Probable 29.3 20.5 15.5 12.3 10.2
------- ----- ------ ------ ------
Total Proved Plus Probable 109.3 88.4 74.8 65.3 58.3
------- ----- ------ ------ ------
------- ----- ------ ------ ------


Summary Of Pricing And Inflation Rate Assumptions
as of December 31, 2005
Forecast Prices And Costs


Oil Natural Gas
---------------------------------------------- -------------
WTI Edmonton Bow River
Cushing Par Price Medium AECO Gas
Year Oklahoma 40 degrees API 25 degrees API Price
----------- ----------- ---------------- ---------------- -------------
($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/GJ)
Forecast
2006 57.50 66.60 45.70 10.05
2007 55.40 64.20 45.30 9.05
2008 52.50 60.70 44.00 8.05
2009 49.50 57.20 42.60 7.00
2010 46.90 54.10 40.30 6.55
Thereafter + 2.5%/yr + 2.5%/yr + 2.5%/yr + 2.5%/yr


Natural Gas
Liquids
--------------
INFLATION EXCHANGE
Year Edmonton Mix RATES(1) RATE
-------------- ------------------ -----------
($Cdn/bbl) (percent per year) ($US/$Cdn)
Forecast
2006 51.40 2.5 0.85
2007 48.90 2.5 0.85
2008 45.80 2.5 0.85
2009 42.60 2.5 0.85
2010 40.20 2.5 0.85
Thereafter + 2.5%/yr + 2.5%/yr 0.85


Summary Of Pricing Assumptions
as of December 31, 2005
Constant Prices And Costs
Natural
Natural Gas
Oil Gas Liquids
----------------------------- ----------- ---------
Edmonton Bow River
Par Price Medium
40 25 Alberta
WTI, degrees degrees Average Edmonton Exchange
Year NYMEX API API Gas Price Mix Rate
---------- -------- ---------- --------- ----------- --------- ---------
($US/bbl) ($Cdn/bbl)($Cdn/bbl)($Cdn/mmbtu)($Cdn/bbl)($US/$Cdn)
Historical
2005+ 61.04 68.46 36.71 9.80 56.30 0.8577


Reconciliation Of Corporation Gross Reserves
By Principal Product Type
Forecast Prices And Costs


Light And Medium Oil Natural Gas Liquids
---------------------------- ----------------------------
Proved Proved
Plus Plus
Factors Proved Probable Probable Proved Probable Probable
------------- -------- --------- --------- -------- --------- ---------
(mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mbbls)

December 31,
2004 1,383 342 1,725 24 8 32

Extensions - - - - - -
Improved
Recovery - - - - - -
Technical
Revisions 202 51 253 2 1 3
Discoveries 494 132 626 - - -
Acquisitions 12 1 13 - - -
Dispositions - - - - - -
Economic
Factors - - - - - -
Production (254) - (254) (4) - (4)
------------------------------------------------------------------------

December 31,
2005 1,837 526 2,363 22 9 31
------------------------------------------------------------------------
------------------------------------------------------------------------


Associated And Non-Associated Gas
----------------------------------
Proved
Plus
Factors Proved Probable Probable
----------------------------------
(mmcf) (mmcf) (mmcf)
December 31, 2004 4,892 1,571 6,463

Extensions - - -
Improved Recovery - - -
Technical Revisions (272) (254) (526)
Discoveries 1,239 652 1,891
Acquisitions 1,783 1,140 2,923
Dispositions - - -
Economic Factors - - -
Production (1,196) - (1,196)
----------------------------------
December 31, 2005 6,446 3,109 9,555
----------------------------------
----------------------------------


Masters Energy Inc.
Balance Sheets
As at December 31,
------------------------------------------------------------------------
------------------------------------------------------------------------
($ thousands) 2005 2004

Assets
Current assets
Accounts receivable $ 3,608 $ 2,116
Prepaid expenses and deposits 190 415
----------------------
3,798 2,531

Property and equipment (note 3) 56,218 34,760
----------------------
$ 60,016 $ 37,291
----------------------
----------------------
Liabilities

Current liabilities
Accounts payable and accrued liabilities $ 8,811 $ 3,223
Bank debt (note 4) - 3,424
----------------------
8,811 6,647

Long-term bank debt (note 4) 14,093 -

Asset retirement obligations (note 5) 3,316 3,044

Future income taxes (note 9) 2,005 30
----------------------
28,225 9,721
----------------------

Shareholders' Equity
Share capital (note 6) 27,469 27,042
Contributed surplus (note 7) 393 210
Retained earnings 3,929 318
----------------------
31,791 27,570
----------------------
$ 60,016 $ 37,291
----------------------
----------------------

See accompanying notes to the financial statements.


Masters Energy Inc.
Statements of Earnings and Retained Earnings
For the years ended December 31, 2005 and 2004
------------------------------------------------------------------------
------------------------------------------------------------------------
($ thousands except share and per share amounts)
2005 2004
Revenue
Petroleum and natural gas revenue $ 22,216 $ 11,680
Royalty and other revenue 713 298
---------- ---------
22,929 11,978
Royalties, net of Alberta Royalty Tax Credit (4,695) (2,379)
---------- ---------
18,234 9,599
---------- ---------
Expenses
Operating 4,168 2,853
General and administrative 1,436 1,077
Interest - long-term debt 322 -
- short-term debt 92 112
Depletion, depreciation and accretion 6,627 4,467
---------- ---------
12,645 8,509
---------- ---------
Earnings before taxes 5,589 1,090

Taxes (note 9)

Capital 3 -

Future 1,975 662
---------- ---------

1,978 662
---------- ---------
Net earnings 3,611 428

Retained earnings (deficit), beginning of year 318 (110)
---------- ---------

Retained earnings, end of year $ 3,929 $ 318
---------- ---------
---------- ---------
Earnings per share (note 8)

Basic $ 0.25 $ 0.03
---------- ---------
---------- ---------

Diluted $ 0.24 $ 0.03
---------- ---------
---------- ---------

Weighted average number of shares outstanding
(note 8)

Basic 14,420,197 13,521,707
---------- -----------
---------- -----------

Diluted 15,090,130 13,716,226
---------- -----------
---------- -----------

See accompanying notes to the financial statements.


Masters Energy Inc.
Statements of Cash Flows
For the years ended December 31, 2005 and 2004
------------------------------------------------------------------------
------------------------------------------------------------------------
($ thousands)

Cash provided by (used for): 2005 2004

Operating activities
Net earnings $ 3,611 $ 428
Add (deduct) non-cash items

Depletion, depreciation and accretion 6,627 4,467
Future income tax expense 1,975 662
Stock-based compensation expense 227 172
Settlement of asset retirement costs (note 5) (281) (95)
---------- ----------
Funds generated by operations 12,159 5,634

Changes in non-cash working capital 3,087 731
---------- ----------
15,246 6,365
---------- ----------

Financing activities
Increase (decrease) in bank debt (notes 2 and 4) 10,669 (7,032)
Proceeds on share issuance 383 -
---------- ----------

11,052 (7,032)
Changes in non-cash working capital - 3,424
---------- ----------
11,052 (3,608)
---------- ----------
Investing activities
Petroleum and natural gas properties
Exploration and development (20,289) (10,920)
Producing property acquisitions (7,244) -
Costs related to the acquisition of Terraquest
(note 2) - (295)
---------- ----------
(27,533) (11,215)
Changes in non-cash working capital 1,235 (1,057)
---------- ----------
(26,298) (12,272)
---------- ----------
Decrease in cash and cash equivalents - (9,515)

Cash and cash equivalents, beginning of year - 9,515
---------- ----------

Cash and cash equivalents, end of year $ - $ -
---------- ----------
---------- ----------

Supplemental Cash Flow Information
-----------------------------------
Interest income received $ 6 $ 28
Interest paid $ 470 $ 56
Capital taxes paid $ - $ 34

------------------------------------------------------------------------

See accompanying notes to the financial statements.


Masters Energy Inc.
Notes to the Financial Statements
For the years ended December 31, 2005 and 2004
(Tabular amounts in $ thousands except share and per share amounts)


Description of business

Masters Energy Inc. is engaged in the exploration, development and production of petroleum and natural gas in Western Canada.

1. Significant accounting policies

(a) Basis of presentation

The financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian generally accepted accounting principles.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that effect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

(b) Cash and cash equivalents

Cash and cash equivalents consisted of amounts on deposit with banks and term deposits with original maturities of less than 90 days.

(c) Property and equipment

The Company follows the full cost method for accounting for petroleum and natural gas operations whereby all costs related to the exploration for and the development of petroleum and natural gas reserves are capitalized. Costs capitalized include land acquisition costs, geological and geophysical expenditures, rentals on undeveloped properties, costs of drilling productive and non-productive wells, together with overhead directly related to exploration and development activities and production and well equipment.

Costs capitalized together with future capital costs are depleted and depreciated using the unit-of-production method based upon gross proved petroleum and natural gas reserves as determined by independent qualified reserves evaluators at future prices and costs. Production and reserves of petroleum and natural gas are converted to common units of measure based on their relative energy content, where one barrel of oil is equivalent to six thousand cubic feet of natural gas.

The cost of significant unproved properties is excluded from the depletion and depreciation base until it is determined whether proved reserves are attributable to the properties, or impairment has occurred.

The Company performs a ceiling test for impairment for each cost centre in a two-stage test undertaken at least annually.

(i) Impairment is recognized if the carrying value of the petroleum and natural gas properties, less accumulated depletion and depreciation, exceeds the estimated future cash flows from proved oil and natural gas reserves, on an undiscounted basis, using forecast prices and costs and the lower of cost and fair value of unproven properties. Future cash flows are calculated before interest, general and administrative expenses and income taxes.

(ii) If impairment is indicated by applying the calculations described in (i) above, the Company will measure the amount of the impairment by comparing the carrying value of the petroleum and natural gas properties less accumulated depletion and depreciation to the estimated future cash flows from the proved and probable oil and natural gas reserves, discounted at a risk-free rate of interest, using forecast prices and costs and the lower of cost and fair value of unproven properties. Any impairment recognized is recorded as additional depletion and depreciation expense.

Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless such a disposition would alter the rate of depletion and depreciation by 20% or more.

The costs of corporate and other office equipment are amortized at rates approximating their useful life on a declining balance basis of 30 percent per year.

(d) Joint ventures

Substantially all of the Company's exploration and production activities are conducted jointly with others and, accordingly, these financial statements reflect only the Company's proportionate interest in such activities.

(e) Asset retirement obligations

The Company recognizes the liability for retirement obligations associated with the abandonment of petroleum and natural gas wells, related facilities, compressors and plants, removal of equipment from leased acreage and returning such land to its original condition. The fair value of each asset retirement obligation is recorded in the period a well or related asset is drilled, constructed or acquired. Fair value is estimated using the present value of the estimated future cash outflows to abandon the asset at the Company's credit-adjusted risk-free interest rate. The obligation is reviewed regularly by Company management based on current regulations, costs, technologies and industry standards. The discounted obligation is initially capitalized as part of the carrying amount of the related oil and natural gas properties, and a corresponding liability is recognized. This component of the increase in petroleum and natural gas properties is depleted and depreciated on the same basis as the remainder of the petroleum and natural gas properties. The liability is adjusted for accretion charged to income until the obligation is settled or sold and for revisions to the estimated cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability.

(f) Flow-through shares

From time to time, the Company issues flow-through shares to finance a portion of its capital expenditure program. Pursuant to the terms of the flow-through share agreements, the tax deductions associated with the expenditures are renounced to the subscribers. Accordingly, share capital is reduced and a future tax liability is recorded equal to the estimated amount of future income taxes payable by the Company as a result of the renunciations, when the expenditures are renounced.

(g) Stock-based compensation

The Company issues stock options and performance warrants to directors, officers, employees and other service providers as described in note 7. Compensation cost, attributable to stock options and performance warrants granted, is measured by the fair value method of accounting at the date of grant and expensed over the vesting period with a corresponding increase in contributed surplus. When stock options or performance warrants are exercised, the cash proceeds together with the amount previously recorded as contributed surplus are recorded as share capital. The Company does not incorporate an estimated forfeiture rate for stock options and performance warrants that will not vest, but accounts for forfeitures as they occur.

(h) Revenue recognition and operating expenses

Revenue from the sale of oil and natural gas is recognized based on volumes delivered to customers at contractual delivery points and rates. The costs associated with the delivery, including operating and maintenance costs, transportation and production-based royalty expenses are recognized in the same period in which the related revenue is earned and recorded.

(i) Income taxes

Future income taxes are accounted for using the liability method of income tax allocation. Under the liability method, income tax assets and liabilities are recorded to recognize future tax income inflows and outflows arising from the settlement or recovery of assets and liabilities at the carrying values. Income tax assets are also recognized for the benefits from tax losses and deductions that cannot be identified with particular assets or liabilities, provided those liabilities are more likely than not to be realized. Future income tax assets and liabilities are determined based on the income tax laws and rates that are anticipated to apply in the period of reversal.

(j) Per share amounts

Basic per share amounts are calculated using the weighted average number of common shares outstanding during the year. The Company utilizes the treasury stock method for the calculation of diluted per share amounts. This method assumes that the proceeds from the exercise of in-the-money stock options and warrants plus the unamortized stock-based compensation are used to repurchase Company shares at the weighted average market price during the period.

(k) Measurement uncertainty

The amounts recorded for depletion and depreciation of oil and gas properties, the asset retirement obligation and the ceiling test are based on estimates. These estimates include proved and probable reserves, production rates, future petroleum and natural gas prices, future costs and other relevant assumptions.

The amounts disclosed relating to the fair value of stock options and performance warrants issued and the resulting income effect are based on estimates of the future volatility of the Company's share price, expected lives of the options, expected dividends and other relevant assumptions.

By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material.

(l) Financial instruments

The Company has a price risk management program whereby the commodity price associated with a portion of its future production can be fixed. The Company is able to sell forward a portion of its future production through a combination of fixed price sale contracts with customers and commodity swap agreements with financial counterparties. The forward and future contracts are subject to market risk from fluctuating commodity prices and exchange rates; however, gains or losses on the contracts are offset by changes in the value of the Company's production and recognized in income in the same period and category as the hedged item.

(l) Reclassification

Certain information provided for the prior year has been reclassified to conform to the presentation adopted in 2005.

2. Business combination

On February 26, 2004, Masters Energy Inc. ("the Company"), a private company incorporated under the Alberta Business Corporations Act on August 28, 2003 and Terraquest Energy Corporation, a public company listed on the Toronto Stock Exchange, amalgamated and the combined company ("Amalco") continued under the name and management of Masters Energy Inc. After giving effect to the transaction, Amalco had approximately 14.4 million Common Shares outstanding, of which former Masters' securityholders owned approximately 62 percent and former Terraquest shareholders owned approximately 38 percent.

The business combination has been accounted for using the purchase method as a reverse takeover of Terraquest by the Company and earnings of Terraquest are recognized from the acquisition closing date of February 26, 2004.

The Terraquest purchase was valued based on the discounted proved plus probable reserves acquired as determined by an independent reserves evaluation. Land cost values were estimated by Masters staff. The share consideration value of acquiring Terraquest was based on Masters common share fair value at the date of amalgamation. The purchase price was allocated as follows:




Property and equipment $ 19,584
Future income tax recoverable 903
Working capital deficiency (694)
Fair value of hedging commitment (199)
Bank debt (7,032)
Asset retirement obligations (1,770)
----------
$ 10,792
----------
----------
Purchase price
Share consideration $ 10,497
Acquisition costs 295
----------
$ 10,792
----------
----------


3. Property and equipment
Accumulated
Depletion
and Net Book
As at December 31, 2005 Cost Depreciation Value
------------------------------------------------------------------------

Petroleum and natural gas
properties and well
equipment $ 66,992 $ 10,820 $ 56,172
Office equipment 73 27 46
-----------------------------------------
$ 67,065 $ 10,847 $ 56,218
-----------------------------------------
-----------------------------------------

As at December 31, 2004

Petroleum and natural gas
properties and well
equipment $ 39,052 $ 4,317 $ 34,735
Office equipment 42 17 25
-----------------------------------------
$ 39,094 $ 4,334 $ 34,760
-----------------------------------------
-----------------------------------------


The value of undeveloped lands excluded from costs subject to depletion was $8.7 million at December 31, 2005 ($5.5 million - December 31, 2004).

As at December 31, 2005, $0.6 million ($0.5 million - December 31, 2004) of general and administrative costs were capitalized.

The benchmark and Company prices on which the December 31, 2005 ceiling test for impairment is based, are as follows:



Oil Natural Gas Natural Gas Liquids
-------------------- --------------------- ----------------------
Bow River AECO
Medium Spot Edmonton
Benchmark Company Benchmark Company Benchmark Company
($/bbl) ($/bbl) ($/GJ) ($/mcf) ($/bbl) ($/bbl)

2006 45.70 46.73 10.05 10.52 51.40 60.05
2007 45.30 46.46 9.05 9.47 48.90 57.71
2008 44.00 44.50 8.05 8.39 45.80 53.55
2009 42.60 42.51 7.00 7.48 42.60 54.89
2010 40.30 39.89 6.55 6.92 40.20 51.87


Prices increase at a rate of approximately 2.5 percent per year for oil, natural gas and natural gas liquids after 2010. Adjustments were made to the benchmark prices, for purposes of the ceiling test, to reflect varied delivery points and quality differentials in the products delivered.

4. Bank debt

The Company has access to a revolving term credit facility with a Canadian chartered bank to a maximum of $18.0 million. The credit facility may be drawn with advances or bankers' acceptances or repaid. Direct advances bear interest at the bank's prime lending rate and the bankers' acceptances bear interest at the applicable bankers' acceptance rate plus a stamping fee.

The Company has available a $2.5(USD) million demand swap facility, to assist in financing the contingent exposure of settlement for financial commodity swaps. The facility bears interest at a US base rate per annum on amounts drawn.

The revolving term credit facility is available for a period of 364 days until April 30, 2006. Up to 60 days prior to April 30, 2006 the Company may request an extension of the revolving facility for a period of another 364 days, subject to the bank's approval. If the Company does not request the extension or the bank does not agree to the extension, the credit facility principal borrowed will be repaid in full with a single payment 366 days subsequent to April 30, 2006. The nature of the lending facility is such that it is recognized as a long-term liability. The credit facility will revolve until April 30, 2006, at which time a review of the facility will occur.

As of December 31, 2005, $14.1 million ($3.4 million - December 31, 2004) has been drawn against the revolving term credit facility.

As at December 31, 2004 the Company had access to a demand revolving credit facility of $8.5 million of which $3.4 million had been drawn against the facility.

Security pledged for the facilities consists of a general assignment of book debts, a $40.0 million demand debenture, secured by a first floating charge over all the assets of the Company. The Company is not in breach of any covenants under its credit facility.

5. Asset retirement obligations

The following table summarizes changes in the asset retirement obligation for the years ended December 31, as indicated:



2005 2004
-------------------
Asset retirement obligations, beginning of year $ 3,044 $ 1,198
Adjustments (256) (119)
Liabilities acquired 305 1,770
Liabilities incurred 390 119
Settlement of asset retirement costs (281) (95)
Accretion expense 114 171
-------------------
Asset retirement obligations, end of year $ 3,316 $ 3,044
-------------------
-------------------


The total estimated, undiscounted cash flows required to settle the obligations as at December 31, 2005, before considering salvage, is $4.6 million ($4.4 million - 2004) which has been discounted using a weighted average credit-adjusted risk-free interest rate of 5.9 percent. The Company expects these obligations to be settled in approximately 1 to 14 years.

6. Share capital

(a) Authorized

Unlimited number of voting common shares, without nominal or par value

Unlimited number of preferred shares, issuable in series, with rights and privileges to be determined at the time of issuance by the Board of Directors



(b) Issued

Number Amount
Warrants and Common Shares Balance,

December 31, 2003 17,752,001 $ 16,545

Warrants and shares exchanged per plan of
arrangement (17,752,001) -

Issued to Masters Energy Inc. shareholders
on reverse takeover of Terraquest (Note 2) 8,876,000 -

Issued to Terraquest shareholders at date
of acquisition (Note 2) 5,487,647 10,497
----------------------
Common Shares, December 31, 2004 14,363,647 27,042

Exercise of stock and performance warrants 159,666 383

Transfer from contributed surplus for exercise
of options and warrants - 44
----------------------
Common Shares, December 31, 2005 14,523,313 $ 27,469
----------------------
----------------------


On October 28 and November 25, 2003, the Company closed private placements of 16,002,000 common special warrants and 1,750,000 flow-through special warrants for gross proceeds of $17.8 million. Both the common special warrants and flow-through special warrants were issued at $1.00 per special warrant, were convertible to common shares at a rate of one warrant to one common share at no additional cost upon either demand, or the Company obtaining a public listing. Effective February 26, 2004, all special warrants were converted into common shares.

7. Stock - based compensation plans

On February 26, 2004, the Company's stock - based compensation plans were revised to conform with the one for two share consolidation related to the acquisition of Terraquest Energy Corporation. This had the effect of halving the number of options that had been issued and doubling their exercise price. The plans are described below:

(a) Stock options

The Company's stock option plan allows for options to be granted to employees, officers, directors and other service providers. The number of shares which may be issued, and that have been reserved, under the plan is 1,435,042 common shares. The maximum number of shares that may be reserved for issuance to any one person under the plan is limited to five percent per year of the issued and outstanding Common Shares and Special Warrants for employees, officers and directors and two percent for other service providers. The plan also provides that the price at which options may be granted cannot be less than the market price of the common shares at the date of grant. Options granted under the plan have a maximum life of five years and vest at an equal amount over three years on the anniversary date of the grant or as determined by the Board of Directors.

The following tables summarizes information about the Company's stock options outstanding at December 31, 2005:


Weighted Average
Number of Options Exercise Price ($)
-------------------------------------
Balance, December 31, 2003 575,000 2.00
Granted, April 26, 2004 655,000 2.35
Granted, December 23, 2004 25,000 2.60
----------
Balance, December 31, 2004 1,255,000 2.19
Granted, July 26, 2005 50,000 3.80
Cancelled (83,334) 2.14
Exercised (94,666) 2.09
----------
Balance, December 31, 2005 1,127,000 2.28
----------
----------


As of December 31, 2005, 490,320 stock options (2004 - 191,667) have vested at an average exercise price of $2.11 per option (2004 - $2.00).



Options Weighted Average
Exercise Price per Share ($) Outstanding Years to Expiry
2.00 455,000 3.0
2.35 597,000 3.3
2.60 25,000 4.0
3.80 50,000 4.5
------------
2.00 - 3.80 1,127,000 3.2
------------
------------


The Company has recorded compensation expense of $0.2 million as at December 31, 2005, (2004 - $0.2 million) for options and warrants vested during the period. Using the Black-Scholes model, assuming the expected life of the options and warrants are 5 years and no expected future dividends, the following table summarizes the total fair value of options and warrants granted.




Options and
Warrants Expected Risk-free Total Fair
Grant Date Granted Volatility Interest Rate Value
------------------------------------------------------------------------
(%) (%) ($ thousands)

July 26, 2005 50,000 46 3.8 78

December 23, 2004 25,000 33 3.40 21

April 26, 2004 655,000 26 3.40 455

December 22, 2003 1,575,000 nil 3.95 207


(b) Performance warrants

The Company's Performance Warrants Plan allows for Performance Warrants to be granted to employees, officers and directors. The maximum number of shares which may be issued, and that have been reserved, under the plan is 1,000,000 common shares. Performance Warrants granted under the plan have a five year life, vest immediately and have no performance criteria other than the escalating exercise price. As at December 31, 2005, 870,000 Performance Warrants have been granted, expiring December 22, 2008, with the following exercise prices:



Performance
Warrants
Outstanding and Average Exercise
Exercisable Price per Warrant ($)
---------------------------------------
100,000 2.00
100,000 2.50
150,000 3.00
150,000 3.50
250,000 4.00
250,000 4.50
----------
Balance, December 31, 2004 1,000,000 3.55

Exercised (65,000) 2.85

Unallocated (65,000) -
----------

Balance, December 31, 2005 870,000 3.55
----------
----------



(c) Contributed surplus

The following table reconciles the Company's contributed surplus for the years ended December 31, as indicated.



2005 2004
---------- ----------
---------- ----------
Balance, beginning of year $ 210 $ 38
Stock-based compensation expense 227 172
Exercise of options and performance warrants (44) -

---------- ----------
Balance, end of year $ 393 $ 210
---------- ----------
---------- ----------


8. Per share amounts

Earnings per share has been calculated using the basic weighted average number of common shares outstanding of 14,420,197 (13,521,707 - 2004) during the year ended December 31, 2005. As at December 31, 2005, a total of 669,933 (194,519 - 2004) were added to the total to take into account the dilutive effect of the options for the year.

9. Income taxes

(a) The provision for income tax expense differs from that which would be expected from applying the combined effective Canadian federal and provincial income tax rate of 37.62% (38.62% - 2004) to income before income taxes. The difference results from the following:



2005 2004
---------- ----------
---------- ----------
Expected income tax expense $ 2,103 $ 423

Increase (decrease) resulting from:
Non-deductible crown payments 928 565
Resource allowance (907) (480)
Change in effective income tax rate applied - (111)
Stock based compensation expense 85 67
Other (234) 198
Capital tax 3 -

---------- ----------
Tax expense $ 1,978 $ 662
---------- ----------
---------- ----------


(b) The components of the future income tax liability at December 31 are
as follows:


2005 2004
---------- ----------
---------- ----------
Carrying value of property and equipment
in excess of available tax deductions $ 3,582 $ 2,141
Asset retirement obligation (1,076) (987)
Non-capital loss carry forwards - (640)
Share issuance costs (286) (484)
Attributed Canadian Royalty Income (215) -
---------- ----------
$ 2,005 $ 30
---------- ----------
---------- ----------


As at December 31, 2005, the Company has tax pools of approximately $46.6 million ($31.9 million - 2004) available for deduction against future taxable income.

10. Commitments

As at December 31, 2005, the Company is committed under a lease on its office premises expiring August 2010. Future annual minimum rental payments excluding estimated operating costs for the remaining term of the lease are: 2006 - $87,000; 2007 - $87,000; 2008 - $89,000; 2009 - $93,000; 2010 - $62,000.

11. Financial instruments

(a) Fair values

The fair values of the Company's accounts receivable, accounts payable and accrued liabilities approximate their carrying values due to their short-term maturity.

(b) Credit risk

The Company's credit risk is limited to the carrying amount of its accounts receivable, which are due primarily from other entities involved in the oil and gas industry. These amounts are subject to the same risks as the industry as a whole.

(c) Interest rate risk

The Company is exposed to interest rate risk to the extent the changes in market interest rates will impact the Company's debts that have a floating interest rate.

Masters Energy Inc. is an Alberta based corporation engaged in the business of acquiring or exploring for and developing oil and natural gas reserves in western Canada. Masters' common shares are listed on the Toronto Stock Exchange under the trading symbol "MSY".

Additional information regarding Masters may be viewed on the SEDAR website (www.sedar.com) or the Company's website (www.mastersenergy.com).

ADVISORIES

The calculations of barrels of oil equivalent ("boe") are based on a conversion rate of six thousand cubic feet ("mcf") of natural gas to one barrel ("bbl") of crude oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf : 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Certain information regarding the Company, including management's assessment of future plans and operations, may constitute forward-looking statements under applicable securities law and necessarily involve risks associated with oil and gas exploration, production, marketing and transportation such as loss of market, volatility of commodity prices, currency fluctuations, uncertainties of reserve estimates, environmental risks, competition from other producers and ability to access sufficient capital from internal and external sources: as a consequence, actual results may differ materially from those anticipated. The Company assumes no obligation to update the forward-looking statements contained herein or to update the reasons why actual results could differ from those contemplated by the forward-looking statements, unless so required by applicable securities law.


Contact Information

  • Masters Energy Inc.
    Geoff Merritt
    President and CEO
    (403) 290-1785
    or
    Masters Energy Inc.
    Randall Boyd
    Chief Financial Officer
    (403) 290-1785
    Website: www.mastersenergy.com