Masters Energy Inc.
TSX : MSY

Masters Energy Inc.

March 12, 2007 08:30 ET

Masters Energy Inc. Reports 2006 Results

CALGARY, ALBERTA--(CCNMatthews - March 12, 2007) - Masters Energy Inc. (TSX:MSY) ("Masters" or the "Company" is pleased to report financial and operating results for the year ended December 31, 2006. Several significant accomplishments were achieved during the year;

- Production increased 12 percent year over year to 1,408 boe per day and exited the 2006 year at 1,600 boe per day

- Added proved plus probable reserves at a finding and development and net acquisition cost, inclusive of future capital costs, of $14.32 per boe

- Proved plus probable reserve additions replaced 2.6 times the 2006 production

- Achieved a capital investment recycle ratio of 1.9 times

- Increased proved plus probable reserves 20 percent to 4.8 million boe and increased reserves per share to 30.8 boe per 100 shares



HIGHLIGHTS
Years ended December 31 2006 2005
---------------------------------------------------------------------------
Financial ($ thousands, except per share amounts)
Gross revenue 24,264 22,929

Funds generated by operations 11,439 12,159
Per share - basic 0.75 0.84
- diluted 0.72 0.81

Net earnings 1,858 3,611
Per share - basic 0.12 0.25
- diluted 0.12 0.24

Capital expenditures, net 18,289 27,533

Working capital deficit 2,156 5,013

Long-term debt 17,824 14,093

Operations
Production
Crude oil (bbls/d) 784 697
NGL (bbls/d) 10 11
Natural gas (mcf/d) 3,685 3,276
Total production (boe/d at 6:1) 1,408 1,254

Average sales price
Crude oil ($/bbl) 49.99 44.82
NGL ($/bbl) 63.33 55.19
Natural gas ($/mcf) 6.59 8.87


Presidents Message to the Shareholders

Masters Energy during 2006 made significant progress toward our long term goals by performing well in a number of aspects of our business. Building on our momentum in 2005 we experienced a high level of activity in 2006. We drilled 31 wells, acquired in excess of 11,000 net acres of undeveloped land and acquired a significant amount of 2D and 3D seismic in Masters core areas. The investments made in undeveloped land and seismic provided Masters with a large inventory of exploration and development opportunities which created value added growth in 2006.

Through our exploration and development activities we were able to add 1.3 million proved plus probable reserves, replacing 2.6 times our annual production. Based on net capital spending of $18.3 million the proved plus probable all-in finding and development and net acquisition cost, inclusive of future development costs, was $14.32 per boe. Our operating netback of $27.77 per boe resulted in a capital investment recycle ratio of 1.9 times. The finding and development and net acquisition cost and recycle ratio indicate outstanding capital efficiency which is particularly impressive given the cost pressures throughout the year.

Although Masters performed well in 2006, we were disappointed with the increase in daily average production volumes for the year. Daily average production increased 12 percent to 1,408 boe per day. The majority of the natural gas well tie-ins were carried out during the fourth quarter which was later than originally anticipated. Production for the fourth quarter of 2006 averaged 1,495 boe per day. At year end the production was 1,600 boe per day. Several tie-in projects in the North Peace River Arch area that were delayed in the last quarter of 2006 are expected to be completed before spring break up in 2007.

The oil and gas industry experienced some significant challenges during 2006. The robust activity levels at the beginning of the year created cost pressures on capital spending and operating expenses. Commodity prices fluctuated significantly with Bow River medium quality crude prices ranging from $34.27 to $66.08 per barrel and natural gas monthly spot prices ranging from $4.54 to $8.43 per thousand cubic feet. The Federal government's October 31, 2006 announcement to tax trusts created a great degree of uncertainty within the capital markets. During these challenging times Masters continued to add value to its asset base throughout the year.

Outlook

The acquisitions of the North Peace River Arch and Little Bow properties established a strong production base from which Masters can grow. With an experienced technical team, a large undeveloped land base (82,000 net acres) and a number of internally-generated prospects, we are well positioned for future growth. We believe Masters can deliver production averaging 1,800 - 2,000 boe/d in 2007. Plans are to spend $20 million to continue to add value to our core areas and to continue to build an inventory of exploration and development drilling opportunities outside our core areas. We anticipate this level of capital will allow us to drill 25 - 30 wells with an emphasis on pursuing natural gas prospects.

In addition to our ongoing exploration and development program, Masters will seek growth through acquisitions that are strategic and have the potential to add future shareholder value.

The current business environment for the oil and gas sector remains solid. Longer term commodity prices are strong, interest rates remain low, demand for energy is high and reasonable access to capital markets underpin the current strong business environment in the oil and gas sector. The demand for oilfield services and supplies and delays with respect to implementing field work have returned to historical levels of activity and timing. This allows us to pursue opportunities in a more cost effective and timely manner.

Masters is fortunate to employ 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. I am excited by the exploitation opportunities available to us in our core areas and the upside potential which exists in our inventory of high impact exploration prospects.

In summary, Masters has achieved many accomplishments since commencing operations. Our successful growth is the result of the solid collective effort of our experienced employees and support of our Board of Directors. I wish to thank all members of our team and other stakeholders for their strong effort and support this year.

Annual Meeting

The Company's Annual Meeting of shareholders is scheduled for 2:00 PM (Calgary Time) on Wednesday May 9, 2006 at The Calgary Telus Convention Centre - Exhibition Hall B1, 120, 9th Avenue SE Calgary, Alberta.

On behalf of the Board of Directors,

Geoff C. Merritt, President and Chief Executive Officer

March 12, 2007

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 9, 2007, should be read in conjunction with the audited financial statements and related notes for the years ended December 31, 2006 and 2005.

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. Masters 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.

Masters uses certain industry benchmarks such as operating netback and net asset value to analyze financial and operating performance. These benchmarks as presented do not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities.

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.

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 comprised 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.

During April 2006, Masters issued 1,000,000 common shares, on a flow-through basis, for total proceeds of $6.1 million. During the month of September 2006, Masters sold non-core properties for total proceeds of $6.2 million before final adjustments.

In 2006, Masters drilled 31 exploration and development wells, resulting in 17 natural gas wells for an overall success rate of 55 percent. During 2006, we spent $24.5 million, before the sale of non-core property proceeds, on our exploration and development program.



RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005

PRODUCTION
2006 2005
------------------------
Annual Production
Crude oil (bbls) 286,058 254,450
Natural gas liquids ("NGL") (bbls) 3,773 3,838
Natural gas (mcf) 1,345,114 1,195,641
Total (boe) 514,017 457,562
Daily Production
Crude oil (bbls/d) 784 697
NGL (bbls/d) 10 11
Natural gas (mcf/d) 3,685 3,276
Total (boe/d) 1,408 1,254


For the year ended December 31, 2006, total production increased 12 percent and averaged 1,408 boe/d (2005 - 1,254 boe/d) with oil production, including NGL, comprising 56 percent (2005 - 56 percent) and natural gas, 44 percent (2005 - 44 percent). Production increased during 2006 as a result of drilling and tying-in successful wells.

Based on drilling activity budgeted for 2007 and production expected from existing producing properties, Masters forecasts an average production rate of 1,800 - 2,000 boe/d comprised of 45 percent oil including NGL and 55 percent natural gas.



PRICES

2006 2005
-------------------------
Crude oil ($/bbl) 49.99 44.82
------------------------
------------------------
NGL ($/bbl) 63.33 55.19
------------------------
------------------------
Natural gas ($/mcf) 6.59 8.87
------------------------
------------------------


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 2006, 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 2006 increased US$9.50 to US$66.09. During 2006, the Canadian dollar strengthened relative to the US dollar with the average currency exchange rate for $1.00 Canadian increasing to US$0.88 (2005 - US$0.83). The higher exchange rate reduced the price received for delivery of crude within Canadian markets. The narrowing quality price differential postings on medium types of crude oil had a positive effect during 2006. The average differential between Edmonton light sweet crude postings and Hardisty Bow River medium crude decreased to approximately $22.00 per bbl (2005 - $25.00 per bbl).

In 2006, Masters' average field price for crude oil was $49.99 (2005 - $44.82) per bbl versus $73.25 (2005 - $69.18) per bbl for light sweet postings at Edmonton, Alberta. All crude revenues during 2006 were from sales to spot markets. Masters did not hedge any production during 2006. Masters' 2006 crude oil production was 84 percent medium and 16 percent lighter gravity crude.

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 2006 and 2005 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 2006 and 2005.

During the early portion of 2006, North America experienced some of the warmest weather on record causing the demand for natural gas to be down from historic winter levels. This resulted in record levels for natural gas supply in storage in the United States and Canada at the end of the withdrawal season. Storage levels at the end of the first quarter of 2006 were approximately 60 percent above the five-year averages. As a result of this large storage overhang, 2006 natural gas prices were weaker than the previous year.

Masters' average natural gas price in 2006 was $6.59 (2005 - $8.87) per mcf versus $6.38 (2005 - $8.69) per mcf for spot postings of the AECO reference price.

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



For 2007 Masters has entered into a fixed natural gas hedge as follows
which was outstanding at December 31, 2006;

Daily
Notional
Product Index Term Volume Price Received
---------------------------------------------------------------------------
Apr. 1/07 -
Gas Fixed AECO-C Oct. 31/07 1,500 GJ $7.54 per GJ


The forecasted commodity prices used for Masters' 2007 budget were $72.00 (US$61.00 WTI) per bbl of Edmonton light quality crude oil and Cdn$7.80 per GJ ($8.25 per mcf) for natural gas at AECO. Masters' 2007 budget uses a forecasted foreign currency exchange rate estimated to average US$0.85 per Cdn$1.00.



REVENUES

($ thousands, except as indicated) 2006 2005
---------------------------------------------------------------------------
Crude oil revenue 14,299 11,405
NGL revenue 239 211
Natural gas revenue 8,867 10,600
------------------------
Total petroleum and natural gas revenue 23,405 22,216
Royalty and other revenue 859 713
------------------------
Total revenue 24,264 22,929
------------------------
Total petroleum and natural gas revenue per boe($) 45.53 48.55
------------------------
------------------------
Total revenue per boe ($) 47.21 50.11
------------------------
------------------------


Petroleum and natural gas revenue for the 2006 year increased five percent to $23.4 million due to a 12 percent increase in production offset by a six percent decrease in realized commodity prices.

Royalty and other revenue increased by 20 percent to $0.9 million as a result of royalty interests receiving higher crude commodity prices throughout 2006.

Based on forecasted production volumes and commodity prices, Masters forecasts an increase in oil and natural gas revenues of approximately 45 - 55 percent during 2007.



ROYALTIES

($ thousands, except as indicated) 2006 2005
---------------------------------------------------------------------------
Crown 4,296 4,382
Alberta Royalty Tax Credit ("ARTC") (411) (500)
------------------------
Crown, net of ARTC 3,885 3,882
Freehold and gross overriding 509 813
------------------------
Total royalties 4,394 4,695
------------------------
------------------------
Per boe ($) 8.55 10.26
------------------------
------------------------
Average royalty rate (%)(1) 18.8 21.1
------------------------
------------------------

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


Royalties paid for the year ended December 31, 2006 decreased nine percent as a result of lower crown rates on natural gas sales and lower freehold and gross overriding royalties paid to third parties. Masters' average royalty rate decreased to 18.8 percent during 2006 (2005 - 21.1 percent). The 2006 royalty expense is comprised of 90 percent (2005 - 83 percent) paid to the crown with the remainder paid to freehold and gross overriding royalty owners. In 2006, Masters paid royalties amounting to $8.55 per boe (2005 - $10.26 per boe).

During the third quarter of 2006, the Alberta provincial government announced termination of the ARTC program at the end of the 2006 year. Masters anticipates forecasted royalty rates for 2007 will be moderately higher than our historical rates.



UNREALIZED GAIN ON COMMODITY CONTRACT

For 2007 Masters has entered into a fixed natural gas hedge as follows;


Daily
Notional
Product Index Term Volume Price Received
---------------------------------------------------------------------------
Apr. 1/07 -
Gas Fixed AECO-C Oct. 31/07 1,500 GJ $7.54 per GJ


An unrealized gain of $0.3 million on the commodity contract represents
the fair value of the contract at December 31, 2006.


OPERATING EXPENSES

($ thousands except as indicated) 2006 2005
---------------------------------------------------------------------------
Total operating expenses 5,600 4,168
------------------------
------------------------
Per boe ($) 10.89 9.11
------------------------
------------------------


In 2006, operating expenses per boe increased 20 percent to $10.89 per boe. Operating expenses were higher due to an adjustment in third party processing fees, increased electrical power rates, well maintenance and liquids transportation.

Masters expects 2007 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 any 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) 2006 2005
---------------------------------------------------------------------------
Oil and natural gas revenues 45.53 48.55
Royalty and other revenue 1.68 1.56
------------------------
47.21 50.11
Royalty expense, net of ARTC (8.55) (10.26)
Operating expenses (10.89) (9.11)
------------------------
Operating netback 27.77 30.74
------------------------
------------------------



GENERAL AND ADMINISTRATIVE

($ thousands, except as indicated) 2006 2005
---------------------------------------------------------------------------
Gross general and administrative 2,594 1,904
Operating recoveries (114) (78)
Capitalized expenses (813) (617)
------------------------

General and administrative expense, before
stock-based compensation 1,667 1,209
------------------------

Future stock-based compensation 533 227
Capitalized future stock-based compensation (211) -
------------------------
Net stock-based compensation expense 322 227
------------------------
Total general and administrative expense 1,989 1,436
------------------------
------------------------
General and administrative expense, before
stock-based compensation, per boe ($) 3.24 2.64
------------------------
------------------------
Total general and administrative expense
per boe ($) 3.87 3.14
------------------------
------------------------


On a per boe basis, total general and administrative expense in 2006 increased 23 percent to $3.87 per boe (2005 - $3.14 per boe). The 36 percent increase in gross general and administrative expenses 2006 to $2.6 million (2005 - $1.9 million), resulted mainly from increased temporary consultant fees, professional fees and results-based compensation. During 2006, 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 2006 include a non-cash provision of $0.3 million (2005 - $0.2 million) for the net future stock-based compensation.

We anticipate that total general and administrative expenses for 2007 will be similar to 2006. Based on forecasted production and capital spending, we estimate 2007 staff levels will be similar to 2006. As we bring new production on-stream, we anticipate a reduction in general and administrative costs per boe.



INTEREST EXPENSE

($ thousands except as indicated) 2006 2005
---------------------------------------------------------------------------
Total interest expense 1,014 414
------------------------
------------------------
Per boe ($) 1.97 0.91
------------------------
------------------------


Interest expense increased 145 percent to $1.0 million in 2006 (2005 - $0.4 million). This reflects an increase in average debt levels during the year as interest rates remained relatively stable. At year-end 2006, Masters had bank debt of $17.8 million (2005 - $14.1 million). Average debt outstanding during the year was approximately $17.6 million. Increased exploration and development activities during the first half of 2006 led to an increase in the year-end balance from the average annual borrowing level. Our average interest rate to borrow during the year was 5.75 percent.

Masters forecasts average bank debt and interest rates for 2007 will be approximately the same as 2006. For 2007, we anticipate that Masters' ratio of net debt to funds generated by operations will be approximately in the range of between 1.0 - 1.1 to one.



DEPLETION, DEPRECIATION AND ACCRETION

($ thousands except as indicated) 2006 2005
---------------------------------------------------------------------------
Depletion 9,260 6,502
Depreciation 10 11
Accretion on asset retirement obligations 130 114
------------------------
Total depletion, depreciation and
accretion expense 9,400 6,627
------------------------
------------------------
Depletion, depreciation and accretion
expense per boe ($) 18.29 14.48
------------------------
------------------------


During 2006, depletion, depreciation and accretion expense increased 42 percent to $9.4 million (2005 - $6.6 million). This increase is the result of Masters' increase in production and cost for reserve additions. Depletion, depreciation and accretion increased 26 percent to $18.29 per boe during 2006 (2005 - $14.48 per boe) as a result of 2006 finding and development costs attributed to proved reserves additions being comparable to the historical carrying values of assets eligible for depletion.

Masters performs an annual and quarterly ceiling test in accordance with the Canadian Institute Chartered Accountants' full cost accounting guidelines, using forecasted prices determined by the independent qualified reserves evaluator who evaluates Masters' reserves. At December 31, 2006, the impairment recognition portion of the ceiling test indicated the estimated undiscounted future cash flows from proved 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) 2006 2005
---------------------------------------------------------------------------
Future 334 1,975
Capital - 3
------------------------
Total income taxes 334 1,978
------------------------
------------------------
Effective tax rate (%) 18.0 35.4
------------------------
------------------------


Income taxes, future and capital decreased 86 percent in 2006 to $0.3 million (2005 - $2.0 million). The decrease in 2006 future tax expense is due to lower earnings before taxes and a reduction in the federal and provincial income tax rates that were substantially enacted during 2006. Based on available tax pools, forecasted capital spending levels and commodity prices, Masters does not expect to be currently taxable for the 2007 year.

Masters has approximately $49.0 million in tax pools, reduced by $5.3 million of 2006 flow-through expenditures that were renounced February 2007, to shelter taxable income in the future years.



The table below shows estimated 2006 tax pools.

($thousands) 2006
---------------------------------------------------------------------------
Canadian Exploration Expense 8,083
Canadian Development Expense 8,485
Canadian Oil and Gas Property Expense 14,186
Undepreciated Capital Cost 17,425
Other 774
------------------------
Total 48,953
------------------------
------------------------


NET EARNINGS

In 2006, net earnings decreased 45 percent to $1.9 million (2005 - $3.6 million), primarily from increased depletion, depreciation and accretion expense. Net earnings decreased in 2006 to $3.61 per boe (2005 - $7.89 per boe) while funds generated by operating activities decreased in 2006 to $22.56 per boe (2005 - $27.19 per boe).



Earnings Ratios
($ thousands, except as indicated) 2006 2005
------------------------
Net earnings 1,858 3,611
Earnings ratios (%)
Return on capital (1) 4.9 10.1
Return on investment (2) 4.4 9.5
Return on shareholder equity (3) 5.2 12.2


(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) 2006 2005
------------------------
Total revenues 47.21 50.11
Royalties (8.55) (10.26)
Operating expenses (10.89) (9.11)
------------------------
Net operating income 27.77 30.74
General and administrative (excluding
stock-based compensation expense) (3.24) (2.64)
Interest expense (1.97) (0.91)
------------------------
Funds generated by operating activities 22.56 27.19
Depletion, depreciation and accretion (18.29) (14.48)
Stock-based compensation (0.63) (0.50)
Taxes and other (0.03) (4.32)
------------------------
Net earnings 3.61 7.89
------------------------
------------------------


SHARE CAPITAL

During 2006, Masters issued 1,046,666 common shares (2005 - 159,666) on a flow-through basis and on the employees exercise of stock options. Stock options and special warrants granted to employees during the year amounted to 469,000 common shares (2005 - 50,000 common shares).

During November 2006, Masters announced a normal course issuer bid which is in effect for one year. At December 31, 2006, Masters had acquired and cancelled 30,000 common shares through the issuer bid process.

The weighted average common shares outstanding, for the three month period ended December 31, 2006 was 15,558,669 basic (15,974,141 diluted). For the year ended December 31, 2006 the basic weighted average shares outstanding was 15,255,640 (2005 - 14,420,197) and the diluted average shares outstanding was 15,887,870 (2005 - 15,090,130). Common shares issued and outstanding, as at December 31, 2006, were 15,539,979 (2005 - 14,523,313).

As of the date of this MD&A and since the 2006 year-end, 70,000 common shares have been acquired and cancelled through the normal course issuer bid.



Outstanding Common Shares (thousands) 2006 2005
------------------------
Weighted average outstanding common shares
- Basic 15,256 14,420
- Diluted 15,888 15,090
Outstanding common shares at December 31
- Common shares (basic) 15,540 14,523
- Common share options 1,451 1,127
- Common share warrants 885 870
- Common shares outstanding (diluted) 17,876 16,520

($ thousands except as indicated)
Per Share Information
Net earnings 1,858 3,611
Net earnings per share ($)
- Basic 0.12 0.25
- Diluted 0.12 0.24
Funds from operating activities 11,439 12,159
Funds from operating activities per share ($)
- Basic 0.75 0.84
- Diluted 0.72 0.81
Total asset book value 70,275 60,016
Total asset book value per share(1) ($)
- Basic 4.52 4.13
- Diluted 3.93 3.63
Book value (shareholders' equity) (1) 39,921 31,791
Book value per share ($)
- Basic 2.57 2.19
- Diluted 2.23 1.92
Proved plus probable reserves (mboe) 4,790 3,986
Reserves per 100 shares (boe) (1)
- Basic 30.8 27.4
- Diluted 26.8 24.1
Annual production (mboe) 514 458
Production per 100 shares (boe) (1)
- Basic 3.3 3.2
- Diluted 2.9 2.8

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


Net Asset Value

Masters' net asset value per share at December 31, 2006 decreased by nine percent to $4.44 (2005 - $4.86) per basic share and by eight percent to $4.28 (2005 - $4.63) per diluted share.




($ thousands, except as indicated) 2006 2006 2005
---------------------------------------------------------------------------
Constant Forecast Forecast
Price Price(1) Price(1)
Proved plus probable reserves value
(10% discount before tax) 68,917 76,736 74,761
Undeveloped acreage (2) 12,233 12,233 14,965
Net debt (19,980) (19,980) (19,106)
------------------------------
Basic net asset value 61,170 68,989 70,620
Projected proceeds on exercise of options
and warrants 7,470 7,470 5,847
------------------------------
Diluted net asset value 68,640 76,459 76,467
------------------------------
------------------------------
Common shares outstanding (thousands)
- Basic 15,540 15,540 14,523
- Diluted 17,876 17,876 16,520
Net asset value per common share ($)
- Basic (3) 3.94 4.44 4.86
- Diluted (3) 3.84 4.28 4.63

(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 future commodity price
forecast, then in effect.
(2) The land values are determined using an estimated value in 2006 of $150
(2005 - $150) per undeveloped acre.
(3) Calculated using outstanding common shares, options and warrants at
year-end.


CAPITAL EXPENDITURES

Total net capital expenditures during 2006, after the disposal of oil and natural gas property interests for proceeds of $6.2 million, were $18.3 million (2005 - $27.5 million). The 2005 expenditures included the $7.8 million for the acquisition of producing oil and natural gas properties in the North Peace River Arch area. The 2006 exploration and development activity resulted in 31 (2005 - 22) gross exploration and development wells drilled, acquisition of 11,683 (2005 - 15,648) net acres of undeveloped crown land, completion of several 3D seismic programs to acquire 150 (2005 - 179) square kilometers of data and over 100 kilometers of 2D seismic data. In 2006, Masters' exploration and development capital allocation was approximately $6.3 (2005 - $12.8) million in southern Alberta and $18.2 (2005 - $7.5) million in northern and central Alberta.



($ thousands) 2006 2005
---------------------
Land 1,669 2,401
Geological and geophysical 3,305 3,037
Drilling and completions 11,892 10,430
Equipping and facilities 7,623 4,390
Other - 31
---------------------

Total exploration and development capital 24,489 20,289
Producing property acquisitions - 7,844
Disposal of property (6,200) (600)
---------------------
Total capital expenditures 18,289 27,533
---------------------
---------------------


Land Holdings

During 2006, Masters' undeveloped land decreased by 18 percent to 82,000 net acres. The decrease is due to a combination of expiries and undeveloped land converted to developed land as a result of drilling wells. In 2006 Masters acquired 11,683 net acres through crown land sales. The average working interest of the undeveloped lands Masters owned at December 31, 2006 was 42 percent.



The following table sets out our developed and undeveloped land holdings as
at December 31, 2006.

DEVELOPED UNDEVELOPED TOTAL
-----------------------------------------------------
Gross Net Gross Net Gross Net
-----------------------------------------------------
(acres)
Alberta - Northern 58,399 17,256 170,812 63,373 229,211 80,629
-----------------------------------------------------
Alberta - Southern 26,178 17,825 24,546 18,179 50,724 36,004
-----------------------------------------------------
Total 84,577 35,081 195,358 81,552 279,935 116,633
-----------------------------------------------------
-----------------------------------------------------


The following table sets out our developed and undeveloped land holdings as
at December 31, 2005.

DEVELOPED UNDEVELOPED TOTAL
-----------------------------------------------------
Gross Net Gross Net Gross Net
-----------------------------------------------------
(acres)
Alberta - Northern 34,104 9,463 190,411 75,468 224,515 84,931
-----------------------------------------------------
Alberta - Southern 23,319 15,495 32,367 24,298 55,686 39,793
-----------------------------------------------------
Total 57,423 24,958 222,778 99,766 280,201 124,724
-----------------------------------------------------
-----------------------------------------------------


Finding and Development Costs

During 2006, our exploration and development program resulted in total proved reserves additions, after prior year revisions, of 954,000 boe, or 1,318,000 boe on a proved plus probable basis. Masters' total finding and development and net acquisition costs were $19.17 per proved boe and $13.88 per proved plus probable boe. After adding in the change in future development capital, finding and development and net acquisition costs were $19.27 per proved boe and $14.32 per proved plus probable boe.

The combined 2004 to 2006 capital programs, including the acquisitions of Terraquest and North Peace River Arch, resulted in finding and development and net acquisition costs of $17.47 per proved boe and $13.43 per proved plus probable boe. After adding in the change to estimated future development capital, finding and development and net acquisition costs were $17.70 per proved boe and $13.71 per proved plus probable boe.

The reserves disclosed for 2006 and 2005 conform with the requirements of National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities.



2006 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 24,489 758 32.31 1,299 18.85
---------------------------------------------------------------------------
---------------------------------------------------------------------------
F&D exploration and
development program
after revisions (a) 24,489 954 25.67 1,318 18.58
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Change in proved
future development
capital (b) 91 n/a n/a n/a n/a
---------------------------------------------------------------------------
Change in proved plus
probable future
development capital (c) 579 n/a n/a n/a n/a
---------------------------------------------------------------------------
Proved F&D including
change in future
development capital
(d)=(a+b) 24,580 954 25.77 n/a n/a
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Proved plus probable
F&D including change
in future development
capital (e)=(a+c) 25,068 n/a n/a 1,318 19.02
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net acquisition/
(disposition)
activity (f) (6,200) - n/a - n/a
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 2006 FD&A costs
before future
development
costs (a+f) 18,289 954 19.17 1,318 13.88
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 2006 proved
FD&A costs including
future development
costs (d+f) 18,380 954 19.27 n/a n/a
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 2006 proved
plus probable FD&A
costs including
future development
costs (e+f) 18,868 n/a n/a 1,318 14.32
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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/
(disposition)
activity (f)
reserves 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 development
costs (d+f) 28,352 1,284 22.08 n/a n/a
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 2005 proved
plus probable FD&A
costs including
future development
costs (e+f) 28,386 n/a n/a 1,743 16.29
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Combined 2004 to 2006 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 2004 to 2006 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 55,698 1,803 30.89 2,661 20.93
---------------------------------------------------------------------------
---------------------------------------------------------------------------
F&D exploration and
development program
after revisions (a) 55,698 2,386 23.34 3,016 18.47
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Change in proved
future development
capital (b) 1,088 n/a n/a n/a n/a
---------------------------------------------------------------------------
Change in proved plus
probable future
development capital (c) 1,720 n/a n/a n/a n/a
---------------------------------------------------------------------------
Proved F&D including
change in future
development capital
(d)=(a+b) 56,786 2,386 23.80 n/a n/a
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Proved plus probable
F&D including change
in future development
capital (e)=(a+c) 57,418 n/a n/a 3,016 19.04
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net acquisition/
(disposition)
activity (f) 27,638 2,385 11.59 3,190 8.66
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 2004 to 2006
FD&A costs before
future development
costs (a+f) 83,336 4,771 17.47 6,206 13.43
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 2004 to 2006
proved FD&A costs
including future
development costs
(d+f) 84,424 4,771 17.70 n/a n/a
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 2004 to 2006
proved plus probable
FD&A costs including
future development
costs (e+f) 85,056 n/a n/a 6,206 13.71
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Reserves Replacement

Masters' 2006 capital expenditure program replaced production by a factor of 1.9 times on a proved basis and 2.6 times on a proved plus probable basis.



2006 2005
---------------------------------------------------------------------------
Production (mboe) 514 458
Proved reserves additions after revisions (mboe) 954 1,169
Proved replacement ratio 1.86 2.55
Proved plus probable reserves additions after
revisions (mboe) 1,318 1,610
Proved plus probable replacement ratio 2.56 3.52


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 by comparing the operating netback per boe to that year's finding and development and net acquisition costs per boe.



2006 2005
---------------------------------------------------------------------------
Operating netbacks ($/boe) 27.77 30.74
Proved FD&A costs after revisions and including the
change in future development cost ($/boe) 19.27 22.08
Proved reinvestment efficiency ratio 1.4 1.4
Proved plus probable FD&A costs after revisions and
including the change in future development cost
($/boe) 14.32 16.29
Proved plus probable reinvestment efficiency ratio 1.9 1.9


Drilling Results

During 2006, Masters drilled 31 (2005 - 22) exploration and development wells resulting in nil (2005 - 6) oil wells and 17 (2005 - 10) natural gas wells for an overall success rate of 55 (2005 - 73) percent. Of the total wells drilled, 27 (2005 - 6) were in northern and central Alberta and the remaining four (2005 - 16) were in southern Alberta.



2006 2005
--------------------------------------------
(wells) Gross Net Gross Net
---------------------------------------------------------------------------
Oil - - 6 6.0
Natural gas 17 7.0 10 7.2
Dry and abandoned 14 7.1 6 4.4
--------------------------------------------
Total 31 14.1 22 17.6
--------------------------------------------
--------------------------------------------
Success rate (%) 55 50 73 75
--------------------------------------------
--------------------------------------------


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. As at the date of this MD&A Masters has committed to drill two wells. Masters estimates a work commitment amount to approximately $0.6 million. Masters has this commitment scheduled in 2007 capital expenditures program currently approved by the board of directors at $20.0 million.

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

The table below shows payments due within the periods indicated.



Less
than 1 1 - 3 4 - 5 After 5
($ thousands) Total Year Years Years Years
---------------------------------------------------------------------------
Farm-in commitments 620 620 - - -
Firm transportation commitments 1,340 334 504 430 72
Operating leases 114 114 - - -
Office lease 331 87 244 - -
------------------------------------------
Total contractual obligations 2,405 1,155 748 430 72
------------------------------------------
------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Total capitalization at December 31, 2006 was $78.6 million (2005 - $118.4 million) with the market value of common shares representing 67 percent of total capitalization. Net debt represented 25 percent and asset retirement obligations plus future income taxes accounted for eight percent.



Total Market Capitalization
($ thousands except as indicated) 2006 % 2005 %
---------------------------------------------------------------------------
Common shares outstanding (thousands) 15,540 14,523
Closing share price at December 31 ($) 3.40 6.47
--------------------------
Total market capitalization 52,836 67 93,966 79
--------------------------
Working capital deficiency, excluding bank debt 2,156 5,013
Bank debt 17,824 14,093
--------------------------
Net debt 19,980 25 19,106 16
--------------------------
Asset retirement obligations 3,527 5 3,316 3
Future income taxes 2,283 3 2,005 2
--------------------------
Total capitalization 78,626 100 118,393 100
--------------------------
--------------------------
Net debt to total capitalization 25% 16%
--------------------------
--------------------------


At December 31, 2006 Masters had borrowed approximately $17.8 (2005 - $14.1) million and had a working capital deficit of $2.2 (2005 - $5.0) million amounting to total net debt of $20.0 (2005 - $19.1) million. Net debt for 2006 represents approximately 1.7 (2005 - 1.6) times funds generated by operating activities of $11.4 (2005 - $12.2) million and approximately 1.0 to 1.1 times budgeted 2007 funds generated by operating activities.

Masters has a bank revolving term facility of $22 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 semi-annually in April and October. As at December 31, 2006, Masters had drawn $17.8 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 collects sales revenues in an organized manner. Management 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, 2006 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. Masters processes invoices within a 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

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



2006 2005
------------------------------------------------------------
Operations Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
------------------------------------------------------------
Production
Oil (bbl/d) 749 791 781 813 707 688 715 678
NGL (bbl/d) 10 10 13 9 10 15 11 6
Natural gas
(mcf/d) 4,417 2,897 3,543 3,888 3,619 3,872 3,055 2,538
Total (boe/d) 1,495 1,284 1,384 1,470 1,320 1,349 1,236 1,107
Pricing
Oil ($/bbl) 42.31 58.03 59.65 39.82 42.50 56.92 41.64 38.14
NGL ($/bbl) 71.65 62.71 61.62 56.87 60.85 59.56 49.56 46.12
Natural gas
($/mcf) 7.07 5.61 5.91 7.41 11.29 9.09 7.34 6.83
Total ($/boe) 42.57 48.92 49.34 41.97 54.18 55.84 42.71 39.28
Financial
($ thousands,
except as
indicated)
Total revenue 5,955 5,971 6,545 5,788 6,908 7,175 4,836 4,010
Funds from
operating
activities 2,202 3,144 3,553 2,542 2,915 4,476 2,699 2,069
Net earnings 26 815 800 217 630 1,781 643 557
Per share -
basic 0.00 0.05 0.05 0.02 0.04 0.12 0.04 0.04
Per share -
diluted 0.00 0.05 0.05 0.01 0.04 0.12 0.04 0.04
Capital
spending
Exploration
and
development 6,022 5,625 4,487 8,355 11,570 2,805 2,806 3,108
Acquisitions/ - (6,200) - - 31 (339) 7,552 -
(dispositions)
Total assets 70,275 65,176 66,533 64,228 60,016 51,142 48,130 38,830
Working
capital
(deficiency) (2,156) (1,904) (1,496) (7,477) (5,013) 1,381 323 (5,155)
Long-term
debt 17,824 14,467 18,584 17,442 14,093 11,911 13,137 -
Shareholders'
equity 39,921 39,861 38,940 32,064 31,791 31,033 28,884 28,184
Common Shares
Weighted
average
common shares
outstanding
(thousands)
- basic 15,559 15,570 15,356 14,523 14,491 14,462 14,364 14,364
- diluted 15,974 16,093 16,052 15,433 15,482 15,146 14,931 14,801
Trading
Activity
Volume
(thousands)
- total 865 773 804 1,757 2,351 2,467 3,096 4,149
- daily 14 12 13 27 38 39 48 67
Price ($ per
share)
- high 4.08 4.28 5.39 6.75 6.95 4.70 3.80 4.20
- low 3.00 3.25 3.56 4.25 4.60 3.62 3.05 2.31
- closing 3.40 3.35 3.80 4.89 6.47 4.55 3.64 3.40


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 per day 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 per day 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 since that time 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 evaluators 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. Funds generated by operating activities, bank debt and the issuance of common shares primarily funded capital spending.

FOURTH QUARTER ANALYSIS



% Change % Change
Q4 2006 Q4 2006
Q4 Q3 Q4 vs vs
2006 2006 2005 Q3 2006 Q4 2005
-------------------------------------------
Operations Results
Production
Crude oil (bbls/d) 749 791 707 (5) 6
NGL (bbls/d) 10 10 10 - -
Natural gas (mcf/d) 4,417 2,897 3,619 53 22
Total (boe/d) 1,495 1,284 1,320 16 13
Pricing (after hedging)
Crude oil ($/bbl) 42.31 58.03 42.50 (27) -
NGL ($/bbl) 71.65 62.71 60.85 14 18
Natural gas ($/mcf) 7.07 5.61 11.29 26 (37)
Selected Financial Results
($ thousands except as
indicated)
Total revenue 5,955 5,971 6,908 6 (9)
Royalties (1,147) (733) (1,815) 56 (37)
Operating expense (1,842) (1,453) (1,471) 27 25
General and administrative (549) (253) (398) 117 38
Funds generated by operating
activities 2,202 3,144 2,915 (30) (26)
Depletion, depreciation and
accretion 2,503 2,033 2,184 23 15
Net earnings 26 815 630 (97) (96)
per share -basic ($) 0.00 0.05 0.04
per share - diluted ($) 0.00 0.05 0.04
Capital spending
exploration and development 6,022 5,625 11,570 8 (47)
acquisitions/(dispositions) - (6,200) 31 - -
Total capital spending 6,022 (575) 11,604 1,057 (47)
Working capital deficiency 2,156 1,904 5,013 13 (57)
Long-term debt 17,824 14,467 14,093 23 26
Shareholders' equity 39,921 39,861 31,791 - 26
Weighted average common
shares outstanding (thousands)
- basic 15,559 15,570 14,491
- diluted 15,974 16,093 15,482


PRODUCTION

Production for the fourth quarter 2006 increased 16 percent to 1,495 boe/d compared to the 2006 third quarter at 1,284 boe/d and increased 13 percent compared to the 2005 fourth quarter. The production increase in the 2006 fourth quarter occurred when we brought 10 wells on-stream. During the month of December 2006 production averaged 1,600 boe/d. Production increases since the 2005 fourth quarter are due to placing successful wells on-stream.

REVENUES

Revenues for the 2006 fourth quarter remained unchanged at $6.0 million compared to the 2006 third quarter and decreased 14 percent from the 2005 fourth quarter. In the quarter ended December 31, 2006, Edmonton Par postings were lower for crude oil compared to the third quarter. Natural gas spot prices increased in the fourth quarter 2006 compared to the third quarter 2006, but were down 37 percent compared with the 2005 fourth quarter.

ROYALTIES

Royalties for the 2006 fourth quarter increased 56 percent to $1.1 million compared to $0.7 million in the 2006 third quarter and decreased 37 percent from the 2005 fourth quarter. The majority of royalty expense incurred during the quarters was payable to the crown. Royalties for the period ended December 31, 2006 decreased from the same period in 2005 as a result of lower 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 2006 fourth quarter increased 27 percent to $1.8 million from $1.5 million in the 2006 third quarter. Several one-time charges increased the operating costs in the quarter. An unusually large ($190,000) third party processing charge adjustment and abnormally high electrical power rates (approximately $150,000 higher than normal) pushed operating expenses higher than anticipated in the 2006 fourth quarter. For the three months ended December 31, 2006 operating expenses increased 25 percent from the same period in 2005 as result of the previously noted exceptions and higher production. Masters forecasts operating costs will average approximately $9.50 per boe during 2007.

GENERAL AND ADMINISTRATIVE

The 2006 fourth quarter general and administrative expense increased 107 percent to $0.5 million from the 2006 third quarter and 32 percent from the 2005 fourth quarter. General and administrative expenses averaged $3.81 per boe for the 2006 fourth quarter compared to $2.14 per boe in the 2006 third quarter and $3.28 per boe in the 2005 fourth quarter. The 2006 fourth quarter general and administrative expenses include provisions for the annual audit and reserves reports ($150,000). Masters forecasts 2007 general and administrative expenses, including a non-cash provision for future stock-based compensation of approximately $1.0 million, at approximately $2.80 per boe.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion, depreciation and accretion expense for the 2006 fourth quarter was $2.5 million compared to $2.0 million for the 2006 third quarter and $2.2 million for the 2005 fourth quarter. Depletion, depreciation and accretion provision for the 2006 fourth quarter was $18.19 per boe compared to $17.20 per boe in the 2006 third quarter and $17.98 per boe for the 2005 fourth quarter. The depletion rate per boe for the 2006 fourth quarter reflected the disproportionate amount of 2006 equipment and facility installation activities that occurred during the fourth quarter.

INCOME TAXES

The future income tax recovery provision for the 2006 fourth quarter was $0.1 million compared to $0.4 million expense for the 2006 third quarter and $0.3 million expense for the 2005 fourth quarter. The increase for the fourth quarter 2006 recovery of taxes is due to a loss before taxes recovered.

NET EARNINGS

Net earnings for the 2006 fourth quarter were $nil compared to $0.8 million for the 2006 third quarter and $0.6 million during the 2005 fourth quarter. The decrease in net earnings recorded in the 2006 fourth quarter compared to 2006 third quarter is mainly due to higher royalty and operating expenses. For the three months ended December 31, 2006, the decrease in net earnings compared to the 2005 fourth quarter is due to higher depletion, depreciation and accretion expense.

CAPITAL EXPENDITURES

During the 2006 fourth quarter, Masters spent $6.0 million on exploration and development capital including $0.2 million in land, $0.4 million in seismic, $2.6 million in drilling and completions and $2.8 million in facilities. During the quarter ended December 31, 2006, five wells were drilled resulting in four natural gas wells, acquired 640 net acres of undeveloped land; and installed natural gas facilities to bring on-stream 10 natural gas wells.

Capital spending during the 2006 fourth quarter was $6.0 million compared to $5.8 million in the 2006 third quarter and to $11.6 million in the 2005 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, 2006
CONSTANT PRICES AND COSTS

RESERVES
---------------------------------------------------
LIGHT AND NATURAL
MEDIUM OIL GAS LIQUIDS NATURAL GAS TOTAL
---------------------------------------------------
RESERVES CATEGORY Gross Gross Gross Gross
---------------------------------------------------------------------------
(mbbls) (mbbls) (mmcf) (mboe)
PROVED
Developed Producing 1,779 9 4,490 2,537
Developed Non-Producing 289 12 3,209 835
Undeveloped - - - -
---------------------------------------------------
TOTAL PROVED 2,068 20 7,699 3,371

PROBABLE 711 9 4,258 1,430
---------------------------------------------------

TOTAL PROVED PLUS
PROBABLE 2,779 29 11,956 4,801
---------------------------------------------------
---------------------------------------------------


NET PRESENT VALUES OF FUTURE NET REVENUE
---------------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (percent per year)
---------------------------------------------------
RESERVES CATEGORY 0 5 10 15 20
---------------------------------------------------------------------------
($mm) ($mm) ($mm) ($mm) ($mm)
PROVED
Developed Producing 59.3 48.1 40.8 35.7 31.9
Developed
Non-Producing 15.5 12.9 11.1 9.8 8.7
Undeveloped - - - - -
---------------------------------------------------
TOTAL PROVED 74.8 61.1 51.9 45.5 40.6

PROBABLE 33.5 22.8 17.0 13.4 11.0
---------------------------------------------------

TOTAL PROVED
PLUS PROBABLE 108.3 83.9 68.9 58.8 51.6
---------------------------------------------------
---------------------------------------------------


Reserves Data - Forecast Prices and Costs

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2006
FORECAST PRICES AND COSTS

RESERVES
---------------------------------------------------
LIGHT AND NATURAL
MEDIUM OIL GAS LIQUIDS NATURAL GAS TOTAL
---------------------------------------------------
RESERVES CATEGORY Gross Gross Gross Gross
---------------------------------------------------------------------------
(mbbls) (mbbls) (mmcf) (mboe)
PROVED
Developed Producing 1,779 9 4,501 2,538
Developed Non-Producing 288 11 3,210 835
Undeveloped - - - -
---------------------------------------------------
TOTAL PROVED 2,067 20 7,711 3,373

PROBABLE 710 9 4,187 1,417
---------------------------------------------------

TOTAL PROVED PLUS
PROBABLE 2,778 29 11,898 4,790
---------------------------------------------------
---------------------------------------------------


NET PRESENT VALUES OF FUTURE NET REVENUE
---------------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (percent per year)
---------------------------------------------------
RESERVES CATEGORY 0 5 10 15 20
---------------------------------------------------------------------------
($mm) ($mm) ($mm) ($mm) ($mm)
PROVED
Developed Producing 61.2 50.3 43.0 37.9 34.0
Developed Non-Producing 18.6 15.5 13.3 11.7 10.4
Undeveloped - - - - -
---------------------------------------------------
TOTAL PROVED 79.8 65.9 56.4 49.5 44.4

PROBABLE 40.1 27.4 20.4 16.0 13.1
---------------------------------------------------

TOTAL PROVED PLUS
PROBABLE 120.0 93.3 76.7 65.6 57.5
---------------------------------------------------
---------------------------------------------------


SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2006
FORECAST PRICES AND COSTS

NATURAL
OIL(1) GAS
----------------------------------------------------
Edmonton Bow River
WTI Par Price Medium
Cushing 40 degrees 25 degrees AECO Gas
Year Oklahoma API API Price
---------------------------------------------------------------------------
($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/GJ)
Forecast
2007 62.50 70.80 49.30 6.85
2008 61.20 69.30 49.60 7.05
2009 59.80 67.70 49.80 7.40
2010 58.40 66.10 49.30 7.50
2011 56.80 64.20 47.90 7.70
Thereafter + 2.0%/yr + 2.0%/yr + 2.0%/yr + 2.0%/yr

NATURAL
GAS LIQUIDS
--------------
INFLATION EXCHANGE
Year Edmonton Mix RATES(1) RATE(2)
---------------------------------------------------------------------------
(percent per
($Cdn/bbl) year) ($US/$Cdn)
Forecast
2007 50.80 2.0 0.87
2008 50.10 2.0 0.87
2009 49.50 2.0 0.87
2010 48.60 2.0 0.87
2011 47.60 2.0 0.87
Thereafter + 2.0%/yr + 2.0%/yr 0.87


SUMMARY OF PRICING ASSUMPTIONS
as of December 31, 2006
CONSTANT PRICES AND COSTS

NATURAL NATURAL GAS
OIL GAS LIQUIDS
---------------------------------------------------------------------
Edmonton Bow River
Par Price Medium Alberta
WTI, 40 degrees 25 degrees Average Gas Edmonton EXCHANGE
Year NYMEX API API Price Mix RATE(1)
---------------------------------------------------------------------------
($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/bbl) ($US/$Cdn)

2007+ 61.05 67.06 49.66 5.93 48.10 0.8581


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, 2005 1,837 526 2,362 22 9 31

Discoveries/
Extensions 237 178 415 - - -
Improved Recovery - - - - - -
Technical Revisions 279 7 287 2 - 2
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - - - - - -
Production (286) - (286) (4) - (4)
-------------------------------------------------------

December 31, 2006 2,067 710 2,778 20 9 29
-------------------------------------------------------
-------------------------------------------------------

ASSOCIATED AND NON-
ASSOCIATED GAS
---------------------------
Proved
Plus
FACTORS Proved Probable Probable
----------------------------
(mmcf) (mmcf) (mmcf)
December 31, 2005 6,446 3,109 9,556

Discoveries/
Extensions 3,126 2,180 5,306
Improved Recovery - - -
Technical Revisions (516) (1,102) (1,619)
Acquisitions - - -
Dispositions - - -
Economic Factors - - -
Production (1,345) - (1,345)
----------------------------

December 31, 2006 7,711 4,187 11,898
----------------------------
----------------------------



Masters Energy Inc.
Balance Sheets
As at December 31,
---------------------------------------------------------------------------
---------------------------------------------------------------------------
($ thousands) 2006 2005

Assets

Current assets
Accounts receivable $ 4,283 $ 3,608
Prepaid expenses and deposits 281 190
------------ ------------
4,564 3,798

Property and equipment (note 2) 65,711 56,218
------------ ------------
$ 70,275 $ 60,016
------------ ------------
------------ ------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 6,720 $ 8,811
Long-term bank debt (note 3) 17,824 14,093
Asset retirement obligations (note 4) 3,527 3,316
Future income taxes (note 8) 2,283 2,005
------------ ------------
30,354 28,225
------------ ------------
Shareholders' Equity
Share capital (note 5) 33,314 27,469
Contributed surplus (note 6) 820 393
Retained earnings 5,787 3,929
------------ ------------
39,921 31,791
------------ ------------
Commitments (notes 5 and 9)
Subsequent events (note 5)
$ 70,275 $ 60,016
------------ ------------
------------ ------------
See accompanying notes to the financial statements.


Masters Energy Inc.
Statements of Earnings and Retained Earnings
For the years ended December 31, 2006 and 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------
($ thousands except share and per share amounts)
2006 2005
Revenue
Petroleum and natural gas revenue $ 23,405 $ 22,216
Royalty and other revenue 859 713
------------ ------------
24,264 22,929
Royalties, net of Alberta Royalty Tax Credit (4,394) (4,695)
------------ ------------
19,870 18,234
Unrealized gain on commodity contract (note 10) 325 -
------------ ------------
20,195 18,234
------------ ------------
Expenses
Operating 5,600 4,168
General and administrative 1,989 1,436
Interest - long-term debt 1,014 322
- short-term debt - 92
Depletion, depreciation and accretion 9,400 6,627
------------ ------------
18,003 12,645
------------ ------------
Earnings before taxes 2,192 5,589
Taxes (note 8)
Capital - 3
Future 334 1,975
------------ ------------
334 1,978
------------ ------------
Net earnings 1,858 3,611
Retained earnings, beginning of year 3,929 318
------------ ------------
Retained earnings, end of year $ 5,787 $ 3,929
------------ ------------
------------ ------------
Earnings per share (note 7)
Basic $ 0.12 $ 0.25
------------ ------------
------------ ------------
Diluted $ 0.12 $ 0.24
------------ ------------
------------ ------------
Weighted average number of shares outstanding
(note 7)
Basic 15,255,640 14,420,197
------------ ------------
------------ ------------
Diluted 15,887,870 15,090,130
------------ ------------
------------ ------------
See accompanying notes to the financial statements.


Masters Energy Inc.
Statements of Cash Flows
For the years ended December 31, 2006 and 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------
($ thousands)
Cash provided by (used for):
2006 2005
------------ ------------
Operating activities
Net earnings $ 1,858 $ 3,611
Add (deduct) non-cash items
Depletion, depreciation and accretion 9,400 6,627
Future income tax expense 334 1,975
Stock-based compensation expense 322 227
Unrealized gain on commodity contract (325) -
Settlement of performance warrants (52) -
Settlement of asset retirement costs (98) (281)
------------ ------------
11,439 12,159
Changes in non-cash working capital (1,865) 3,087
------------ ------------
9,574 15,246
------------ ------------
Financing activities
Increase in bank debt 3,731 10,669
Proceeds on share issuance 6,100 -
Proceeds on exercise of options and warrants 99 383
Purchase of shares for cancellation (102) -
Share issuance costs (446) -
------------ ------------
9,382 11,052
------------ ------------
Investing activities
Petroleum and natural gas properties
Exploration and development (24,489) (20,289)
Producing property acquisitions - (7,844)
Disposal of property 6,200 600
------------ ------------
(18,289) (27,533)
Changes in non-cash working capital (667) 1,235
------------ ------------
(18,956) (26,298)
------------ ------------
Change in cash and cash equivalents - -
Cash and cash equivalents, beginning of year - -
------------ ------------
Cash and cash equivalents, end of year $ - $ -
------------ ------------
------------ ------------
Supplemental Cash Flow Information
Interest income received $ 1 $ 6
Interest paid $ 1,014 $ 470
Capital taxes paid $ 3 $ -
---------------------------------------------------------------------------
See accompanying notes to the financial statements.


Masters Energy Inc.
Notes to the Financial Statements
For the years ended December 31, 2006 and 2005
(Tabular amounts in $ thousands except share and per share amounts)


Description of business

Masters Energy Inc. ("Masters" or the "Company") 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 affect 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 percent or more.

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

(d) Joint operations

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 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 income 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 and employees as described in note 6. 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 incorporates an estimated forfeiture rate of ten percent for stock options and performance warrants that will not vest.

(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, estimated future tax assets and liabilities are determined based upon differences between the carrying amount as reported on the balance sheet and the tax basis of assets and liabilities. 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. A valuation allowance is recognized against any future income tax assets if it is considered more likely than not that the asset will not be realized.

(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) Derivative financial instruments

Derivative financial instruments are used by Masters to manage economic exposure to market risks relating to commodity prices. The Company's policy is not to utilize derivative financial instruments for speculative purposes.

Financial contracts are recorded following the fair value method whereby instruments are recorded in the balance sheet as either as asset or liability with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives related to commodity prices are recognized in natural gas and crude revenues as related sales occur. Unrealized gains or losses are recognized in revenues at the end of each respective reporting period. The estimated fair value of derivative instruments is based on quoted market prices.



2. Property and equipment

Accumulated
Depletion
and Net Book
As at December 31, 2006 Cost Depreciation Value
---------------------------------------------------------------------------

Petroleum and natural gas
properties and well equipment $ 85,756 $ 20,080 $ 65,676
Office equipment 73 38 35
------------------------------------------
$ 85,829 $ 20,118 $ 65,711
------------------------------------------
------------------------------------------
As at December 31, 2005
------------------------------

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


The value of undeveloped lands excluded from costs subject to depletion was $7.6 million at December 31, 2006 (December 31, 2005 - $8.7 million).

As at December 31, 2006, $1.0 (December 31, 2005 - $0.6) million of general and administrative costs were capitalized.

The benchmark and Company prices on which the December 31, 2006 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)

2007 49.30 48.84 6.85 7.07 50.80 62.90
2008 49.60 48.68 7.05 7.33 50.10 62.99
2009 49.80 48.46 7.40 7.68 49.50 61.48
2010 49.30 47.58 7.50 7.98 48.60 64.08
2011 47.90 46.03 7.70 8.18 47.60 61.56


Prices increase at a rate of approximately 2.0 percent per year for oil, natural gas and natural gas liquids after 2011. 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.

3. Long-term debt

The Company has access to a revolving term credit facility with a Canadian chartered bank to a maximum of $22.0 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 revolving term credit facility is available for a period of 364 days until April 30, 2007. Up to 60 days prior to April 30, 2007 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, 2007. The nature of the lending facility is such that it is recognized as a long-term liability. In the event that the facility was not reviewed on April 30, 2007 the entire amount would be repayable on May 1, 2008.

As of December 31, 2006, $17.8 million (December 31, 2005 - $14.1 million) has been drawn against the revolving term credit facility.

The Company has available a $2.5(US) 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. No amount has been drawn at December 31. 2006.

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.

4. Asset retirement obligations

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



2006 2005
-------------------------
Asset retirement obligations, beginning of year $ 3,316 $ 3,044
Adjustments (122) (256)
Liabilities acquired - 305
Liabilities incurred 301 390
Settlement of asset retirement costs (98) (281)
Accretion expense 130 114
-------------------------
Asset retirement obligations, end of year $ 3,527 $ 3,316
-------------------------
-------------------------


The total estimated, undiscounted cash flows required to settle the obligations as at December 31, 2006, before considering salvage, is $4.9 (2005 - $4.6) million which has been discounted using a weighted average credit-adjusted risk-free interest rate of 6.0 percent. The Company expects these obligations to be settled in approximately 1 to 14 years.

5. 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
-------------------------
Common Shares, December 31, 2004 14,363,647 $ 27,042

Exercise of stock options 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

Issue of flow-through shares 1,000,000 6,100

Exercise of stock options 46,666 99






Shares repurchased and cancelled (30,000) (67)

Share issue costs (net of future tax
benefit of $140,000) - (306)

Transfer from contributed surplus for
exercise of options and warrants - 19
-------------------------

Common Shares, December 31, 2006 15,539,979 $ 33,314
-------------------------
-------------------------


(c) On April 18, 2006 the Company issued, through a private placement, 1,000,000 common shares on a "flow-through" basis at a price of $6.10 per share for net proceeds (after share issue costs of $434,000) of $5,666,000. The Company is obligated to incur $6.1 million of qualifying expenditures prior to December 31, 2007. As at December 31, 2006, the remaining obligation was approximately $0.8 million.

(d) In November 2006, the Company received regulatory approval under the Canadian securities laws to purchase and cancel up to 1,300,000 common shares under a normal course issuer bid. The issuer bid will terminate on November 6, 2007. During 2006, the Company purchased 30,000 common shares for total consideration of $102,000. Of the amount paid, $67,000 was charged to share capital and $35,000 was charged to contributed surplus. Subsequent to the 2006 year-end, the Company has purchased 70,000 common shares under the issuer bid for total consideration of $202,400.

6. Stock - based compensation plans

The Company's stock-based compensation 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 limited to 10 percent of the issued and outstanding 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 volume weighted average trading price of the common shares for the five trading days prior to 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, 2006.



Weighted
Average
Exercise
Number of Options Price ($)
--------------------------------
Balance, December 31, 2004 1,255,000 2.19
Granted 50,000 3.80
Cancelled (83,334) 2.14
Exercised (94,666) 2.09
-------------------
Balance, December 31, 2005 1,127,000 2.28
Granted 404,000 4.62
Cancelled (33,334) 2.09
Exercised (46,666) 2.12
-------------------
Balance, December 31, 2006 1,451,000 2.94
-------------------
-------------------


As of December 31, 2006, 814,665 stock options (2005 - 490,320) have vested
at an average exercise price of $2.21 per option (2005 - $2.11).


Options Weighted Average
Exercise Price per Share ($) Outstanding Years to Expiry
---------------------------------------------------------------------------
2.00 400,000 2.0
2.35 572,000 2.3
2.60 25,000 3.0
3.80 50,000 3.5
4.70 150,000 4.3
4.58 254,000 4.4
---------------------------------------------------------------------------
Weighted average 2.94 1,451,000 2.8
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The Company has recorded compensation expense of $0.3 million as at December 31, 2006, (2005 - $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 five 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)
May 11, 2006 319,000 44 4.0 577

April 10, 2006 150,000 42 3.7 266

July 26, 2005 50,000 46 3.8 78

December 23, 2004 25,000 33 3.4 21

April 26, 2004 655,000 26 3.4 455


(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, 2006, 885,000 (2005 - 870,000) Performance Warrants have been granted, expiring December 22, 2008, with the following exercise prices.



Weighted
Performance Average
Warrants Exercise
Outstanding and Price per
Exercisable Warrant ($)
------------------------------

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
Granted 65,000 4.58
Settled (50,000) 3.66
-----------------
Balance, December 31, 2006 885,000 3.62
-----------------
-----------------


(c) Contributed surplus

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

2006 2005
------------------------
Balance, beginning of year $ 393 $ 210
Stock-based compensation expense 322 227
Capitalized stock-based compensation 211 -
Exercise of options and performance warrants (19) (44)
Settlement of performance warrants (52) -
Reacquisition and cancellation of common
shares (35) -
------------------------
Balance, end of year $ 820 $ 393
------------------------
------------------------


7. Per share amounts

Earnings per share has been calculated using the basic weighted average number of common shares outstanding of 15,255,640 (2005 - 14,420,197) during the year ended December 31, 2006. As at December 31, 2006, a total of 632,230 (2005 - 669,933) were added to the total to take into account the dilutive effect of the options for the year.

8. 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 34.5 percent (2005 - 37.62 percent) to income before income taxes. The difference results from the following:



2006 2005
------------------------
Expected income tax expense $ 756 $ 2,103

Increase (decrease) resulting from:
Non-deductible crown payments 469 928
Resource allowance (402) (907)
Effect of change in income tax enacted (461) -
Stock based compensation expense 111 85
Other (139) (234)
Capital tax - 3
------------------------
Tax expense $ 334 $ 1,978
------------------------
------------------------


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


2006 2005
------------------------
Carrying value of property and equipment
in excess of available tax deductions $ 3,718 $ 3,582
Asset retirement obligation (1,036) (1,076)
Share issuance costs (227) (286)
Attributed Canadian Royalty Income (172) (215)
------------------------
$ 2,283 $ 2,005
------------------------
------------------------


As at December 31, 2006, the Company has income tax pools of approximately $49.0 million (2005 - $46.6 million) available for deduction against future taxable income.

9. Commitments

The table below shows commitments due within the periods indicated.




Less
than 1 1 - 3 4 - 5 After 5
Total Year Years Years Years
---------------------------------------------------------------------------
Farm-in commitments $ 620 $ 620 $ - $ - $ -
Firm transportation
commitments 1,340 334 504 430 72
Operating leases 114 114 - - -
Office lease 331 87 244 - -
---------------------------------------------------------------------------
Total contractual obligations $ 2,405 $ 1,155 $ 748 $ 430 $ 72
---------------------------------------------------------------------------
---------------------------------------------------------------------------


10. Financial instruments

(a) Derivative 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.

The Company uses derivative instruments to reduce its exposure to fluctuations in commodity prices. The following table summarizes the derivative contract in place at December 31, 2006:



Unrealized
Daily Notional Price Gain
Product Index Term Volume Received ($ thousands)
---------------------------------------------------------------------------
Gas Apr. 1/07 -
Fixed AECO-C Oct. 31/07 1,500 GJ's $7.54 per GJ 325


(b) 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. The Company's long-term debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.

(c) 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.

(d) 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