Masters Energy Inc.
TSX : MSY

Masters Energy Inc.

October 26, 2005 17:17 ET

Masters Energy Inc. Reports Third Quarter 2005 Interim Results

CALGARY, ALBERTA--(CCNMatthews - Oct. 26, 2005) - Masters Energy Inc. (TSX:MSY) ("Masters" or the "Company") is pleased to report financial and operating results for the three and nine months periods ended September 30, 2005. Several significant accomplishments were achieved during the period;

- Increased year to date 2005 natural gas production 115 percent in comparison to the similar period in 2004.

- Year to date cash flow from operations for 2005 increased 133 percent to $9.2 million compared to 2004.

- Cash flow per share of $0.31 in the third quarter 2005 increased 63% over the second quarter 2005.

- Drilled a total of 12 wells resulting in 3 (3.0 net) oil and 8 (5.8 net) gas wells for an overall success rate of 92%.

- Closed acquisitions of properties in the Peace River Arch which provides the Company with a second core area.



HIGHLIGHTS Three Months Ended Nine Months Ended
September 30, September 30,
2005 2004 2005 2004
------------------------------------------------------------------------
(Unaudited)
Financial ($ thousands, except
per share amounts)
Gross revenue 6,928 3,258 15,644 8,208

Cash flow from operations 4,476 1,513 9,244 3,960
Per share - basic 0.31 0.11 0.64 0.30
- diluted 0.30 0.10 0.62 0.30

Net earnings 1,781 79 2,981 552
Per share - basic 0.12 0.01 0.21 0.04
- diluted 0.12 0.01 0.20 0.04

Capital expenditures 2,466 2,531 15,932 7,680

Working capital (deficiency) 1,381 (2,551) 1,381 (2,551)

Long-term debt 11,911 - 11,911 -

Operations
Production
Crude oil (bbls/d) 688 597 694 547
NGL (bbls/d) 15 5 11 5
Natural gas (mcf/d) 3,872 1,980 3,160 1,472
Total production
(boe/d at 6:1) 1,349 932 1,231 798

Average sales price
Crude oil ($/bbl) 56.92 38.15 45.62 36.45
NGL ($/bbl) 59.56 40.20 53.50 38.70
Natural gas ($/mcf) 9.09 6.24 7.93 6.48


Presidents Message to the Shareholders

In the first nine months of 2005, Masters successfully drilled 11 wells, at a 92 percent success rate, and acquired producing properties in the Peace River Arch area of Alberta. The results of the drilling program are:

- at Little Bow three (3.0 net) oil wells were drilled and brought onstream validating the independent reservoir simulation study completed in 2004. In addition, two (1.5 net) natural gas wells were drilled and tied in during the second quarter.

- at Hector two (2.0 net) natural gas wells were drilled and completed during the second quarter and tied in during the month of October.

- one natural gas well (0.3 net) at Roche was drilled and put onstream.

- at Tangent three (2.0 net) natural gas wells were drilled and completed. Two of the wells were tied in during the month of October 2005.

Operationally, in the third quarter of 2005, Masters focused its efforts on recompletion opportunities and facility expansion at the recently acquired Tangent property and an expansion of the battery and water handling capacity at Little Bow. One (1.0 net) well was drilled in the third quarter and an active drilling program is currently underway. In the fourth quarter, Masters expects to drill 13 (10.0 net) wells in the following areas:

- four development wells at Little Bow

- two development wells at Grand Forks

- two exploration wells in Southern Alberta

- five exploration/development wells at Tangent.

Total capital expenditure in the fourth quarter is estimated to be $9.0 million. As a result of the increase in drilling activity levels, the 2005 exploration and development budget, excluding acquisitions, has been increased to $18 million from $12 million. Masters plans to shoot several large 3D seismic programs prior to year-end, which should provide additional drilling activity in 2006.

Production for the third quarter of 2005 averaged 1,349 boe per day, an increase of 45 percent over the 2004 third quarter production and an increase of nine percent over the second quarter of 2005. Currently, total corporate production is approximately 1,400 boe per day (50% natural gas).

Commodity prices have been extremely strong and are expected to remain strong. In particular, the wellhead price Masters received for crude oil increased from $41.64 per barrel in the second quarter to $56.92 in the third quarter and is currently at approximately $51 per barrel. The natural gas price received at the wellhead increased 24 percent from $7.34 per mcf in the second quarter to $9.09 per mcf in the third quarter and is currently at approximately $13 per mcf. Increased prices combined with higher production volumes resulted in significant increases in the cash flow per share in each quarter of 2005, as follows:

- first quarter - $0.14 per share

- second quarter - $0.19 per share

- third quarter - $0.31 per share.

In the fourth quarter 2005, the Company anticipates commodity prices to remain high, production volumes to increase and cash flow per share to be strong.

OUTLOOK

For 2005, the Company anticipates production to average 1,300 - 1,400 boe per day (50 percent natural gas) and forecasts an exit rate of 1,900 boe per day (60 percent natural gas). At the beginning of the fourth quarter 2005 Masters had approximately 450 boe per day of production capability behind pipe. Approximately 250 boe per day will be tied in during the month of October 2005 and approximately 300 boe per day from the fourth quarter drilling program is expected to be onstream prior to year end. The remaining behind pipe production (200 boe per day) is expected to be tied in during the first quarter of 2006.

The current commodity price environment in the oil and gas sector gives the Company a high degree of optimism, but, we remain mindful that we also face certain challenges such as increasing cost pressures, access to oil and gas services and availability of skilled personnel. Masters believes that those challenges can be met by remaining disciplined and by careful planning of capital expenditures.

Besides the ongoing exploration and development program, Masters has a strong desire to grow through acquisitions and will continue to seek acquisitions that are strategic to the Company. Acquisition prices have been extremely high recently but we will continue to seek appropriate acquisition candidates.

In summary, the Company is very optimistic about the future and remains confident that we can continue to add shareholder value through an effective and efficient use of capital.



On behalf of the Board of Directors,


Geoff C. Merritt
President and Chief Executive Officer
October 26, 2005


MANAGEMENT'S DISCUSSION AND ANALYSIS

ADVISORIES

Management's discussion and analysis ("MD&A") of Masters Energy Inc. ("Masters or the Company"), provided as of October 26, 2005, should be read in conjunction with the unaudited financial statements presented for the three and nine months ended September 30, 2005 and 2004 and the audited financial statements for the year ended December 31, 2004.

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 cash flow from operations and cash flow 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 cash flow from operations and cash flow per share may not be comparable to that reported by other companies. The reconciliation between net earnings and cash flow from operations can be found in the statements of cash flows in the audited financial statements. The Company presents cash flow from 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.

BOE Presentation - 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.

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, the Company's ability to replace and expand oil and gas reserves, the sources and adequacy of funding for capital investments, future growth prospects and current and expected financial requirements of the Company, the cost of future reclamation and site restoration, the Company's ability to enter into or renew leases, the Company's ability 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 the Company does not undertake an obligation to update our forward-looking statements except as required by law.



PRODUCTION

Production Summary

Three Months Ended Nine Months Ended
September 30, September 30,
2005 2004 2005 2004
-----------------------------------------
Total Production
Crude oil (bbl) 63,334 54,933 189,431 149,971
Natural gas liquids
("NGL") (bbl) 1,370 411 2,955 1,372
Natural gas (mcf) 356,203 182,148 862,631 403,199
Total equivalent (boe) 124,071 85,702 336,158 218,543
Daily Production
Crude oil (bbl/d) 688 597 694 547
NGL (bbl/d) 15 5 11 5
Natural gas (mcf/d) 3,872 1,980 3,160 1,472
Total equivalent (boe/d) 1,349 932 1,231 798


Production volume for the third quarter ended September 30, 2005 averaged 1,349 boe per day, an increase of 45 percent in comparison with the third quarter of 2004. Oil and NGL production for the third quarter of 2005 increased 17 percent to 703 barrels per day from 602 barrels per day in the same period in 2004. Natural gas production for the third quarter ended September 30, 2005 increased 95 percent to 3.9 mmcf per day from 2.0 mmcf per day for the three months ended September 30, 2004. Year to date production for the first nine months of 2005 of 1,231 boe per day, increased 54 percent in comparison to the same period for 2004. Production increased during 2005 as a result of successful wells being drilled and tied-in and the acquisitions of the Peace River Arch properties in June and September 2005.



PRICES

Commodity Prices

Three Months Ended Nine Months Ended
September 30, September 30,
2005 2004 2005 2004
-----------------------------------------
Crude oil ($/bbl) 56.92 38.15 45.62 36.45
-----------------------------------------
-----------------------------------------
NGL ($/bbl) 59.56 40.20 53.50 38.70
-----------------------------------------
-----------------------------------------
Natural gas ($/mcf) 9.09 6.24 7.93 6.48
-----------------------------------------
-----------------------------------------


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

During the third quarter of 2005 North America continued to see historically high price levels for WTI crude oil primarily due to concerns over supply. As a result, the average price for a barrel of WTI crude during the period increased over $19.27(US) to $63.18(US) from the third quarter of 2004. The average price for a barrel of WTI crude during the first nine months of 2005 increased $16.33(US) or 42 percent to $55.46(US) from the first nine months of 2004. The Canadian dollar strengthened relative to the US dollar during the course of the year. The average currency exchange rate for $1.00 Canadian increased from $0.753(US) in the first nine of 2004 to $0.817(US) in the similar period of 2005. As a result, this lowered the effective price received for delivery of crude expressed in Canadian dolloars.. The quality price differential postings on medium type crudes also experienced a negative effect during 2005. The average differential between Edmonton light sweet crude postings and Hardisty Bow River medium crude was approximately $24.38 per bbl in the third quarter of 2005 versus $14.97 per bbl in the third quarter of 2004. The widening differential has impacted Masters' oil revenues and cash flow, as the majority of the Company's crude oil production is medium gravity crude. Masters' average field price received for crude during the first nine months of 2005 was $45.62 per barrel versus $68.46 per barrel for light sweet postings at Edmonton, Alberta.

The Company's crude oil field price for the third quarter of 2005 increased 49 percent to $56.92 per barrel from the average price received in the third quarter of 2004. For the first nine months of 2005 the crude field price increased 25 percent to $45.62 per barrel from the average price received during the comparable period in 2004.

US natural gas prices are typically referenced off NYMEX at Henry Hub, Louisiana while Canadian prices are referenced at Nova Inventory Transfer ("NIT") or the AECO Hub. Most of Masters' natural gas is sold to the spot market according to the AECO reference price. Masters did not enter into any fixed or hedged type gas sales contracts during 2004 or 2005. The average natural gas price received during the third quarter of 2005 was $9.09 per mcf, an increase of 46 percent from the price received in the same period of 2004. The average natural gas price received for the first nine months of 2005 was $7.93 per mcf, an increase of 22 percent from the price received in the first nine months of 2004.



REVENUES

Revenue Summary

Three Months Ended Nine Months Ended
($ thousands, except September 30, September 30,
as indicated) 2005 2004 2005 2004
------------------------------------------------------------------------
Crude oil revenue 3,605 2,096 8,642 5,466
NGL revenue 81 16 158 53
Natural gas revenue 3,237 1,136 6,838 2,651
-----------------------------------------
Total resource revenue 6,923 3,248 15,638 8,170
Interest and other revenue 5 10 6 38
-----------------------------------------
Total revenue 6,928 3,258 15,644 8,208
-----------------------------------------
-----------------------------------------
Total revenue per boe ($) 55.84 38.02 46.54 37.56
-----------------------------------------
-----------------------------------------


Resource revenues for the third quarter of 2005 increased 113 percent to $6.9 million from the similar period in 2004 as commodity prices remained strong and production volumes continued to grow. The oil and natural gas revenue for the first nine months of 2005 was $15.6 million an increase of 91 percent over the same period of 2004. Sales from operations in 2004 included Terraquest from the effective date of the acquisition on February 26, 2004.

Interest and other income earned on surplus cash totaled $38 thousand during 2004. During 2004 surplus cash was invested in exploration and development capital spending and acquisitions and as a result there is a minor amount of interest income earned during 2005.



ROYALTIES

Royalties Summary

Three Months Ended Nine Months Ended
($ thousands, except September 30, September 30,
as indicated) 2005 2004 2005 2004
------------------------------------------------------------------------
Crown 1,186 603 2,716 1,440
ARTC (153) (51) (382) (94)
-----------------------------------------
Crown, net of ARTC 1,033 552 2,334 1,346
-----------------------------------------
Gross overriding royalties
- expense 183 55 396 95
- income (247) (61) (378) (91)
-----------------------------------------
- net (64) (6) 18 4
-----------------------------------------
Freehold and other 55 49 149 114
-----------------------------------------
Net royalties 1,024 595 2,501 1,464
-----------------------------------------
-----------------------------------------
Per boe ($) 8.26 6.94 7.44 6.70
-----------------------------------------
-----------------------------------------
Average royalty rate, before
ARTC and GORR income (%) 20.6 21.8 20.9 20.2
-----------------------------------------
-----------------------------------------
Average royalty rate - net (%) 14.8 18.3 16.0 17.9
-----------------------------------------
-----------------------------------------



For the three months ended September 30, 2005, royalties, net of Alberta royalty tax credit and GORR income, totaled $1.0 million for an average royalty rate relative to oil and gas revenues of 15 percent. The decrease in the net average royalty rate is due to increased GORR income as result of the Peace River properties acquired June 2005. On a boe basis, royalties for the period were $8.26 per boe. For the similar period in 2004 the net royalty rate averaged 18 percent of oil and gas revenues or $6.94 per boe. The average royalty rate, before ARTC and GORR income, remained relatively constant at approximately 21 percent.

For the nine months ended September 30, 2005 net royalties totaled $2.5 million for an average royalty rate of 16 percent or $7.44 per boe. For the comparable period in 2004 the net royalty rate averaged 18 percent or $6.70 per boe. The average royalty rate, before ARTC and GORR income, remained relatively constant at approximately 21 percent.

Forecasted royalty rates for 2005, before ARTC and GORR income, are anticipated to be consistent with 2004 rates. The Company anticipates maximizing its ARTC claim on Crown royalties during 2005.



OPERATING EXPENSES

Operating Expense Summary

Three Months Ended Nine Months Ended
($ thousands, except September 30, September 30,
as indicated) 2005 2004 2005 2004
------------------------------------------------------------------------
Production expenses 1,000 869 2,697 2,007
-----------------------------------------
Transportation costs - 21 - 37
-----------------------------------------
Total operating expenses 1,000 890 2,697 2,044
-----------------------------------------
-----------------------------------------
Per boe ($) 8.06 10.38 8.02 9.35
-----------------------------------------
-----------------------------------------


Operating expenses for the three months ended September 30, 2005 was $1.0 million, an increase of 12 percent compared to $0.9 million during the same period in 2004 primarily as a result of higher production. On a boe basis, the 2005 third quarter operating expenses decreased 22 percent to an average cost of $8.06 per boe produced from $10.38 per boe in the same period in 2004. Operating expenses per boe in the first nine months of 2005 have decreased 14 percent compared to the average boe operating expense for the 2004 year primarily due to higher volumes produced through existing facilities.

Operating expenses per boe for the balance of 2005 are anticipated to remain consistent with the year to date results.



Netback Analysis

Three Months Ended Nine Months Ended
September 30, September 30,
($ per boe) 2005 2004 2005 2004
------------------------------------------------------------------------
Oil and gas revenues 55.84 38.02 46.54 37.56
Royalties, net of ARTC (8.26) (6.94) (7.44) (6.70)
Operating expenses (8.06) (10.38) (8.02) (9.35)
-----------------------------------------
Netback 39.52 20.70 31.08 21.51
-----------------------------------------
-----------------------------------------


Operating income netback per boe for the third quarter of 2005 has increased 91 percent due to a combination of higher commodity prices received on oil and natural gas production and lower operating expenses. For the first nine months of 2005 the operating netback has increased 44 percent in comparison to the same period for 2004.



GENERAL and ADMINISTRATIVE

General and Administrative Expense Summary

Three Months Ended Nine Months Ended
($ thousands, except September 30, September 30,
as indicated) 2005 2004 2005 2004
------------------------------------------------------------------------
Gross general and administrative 427 374 1,416 1,072
Operating recoveries (28) (29) (64) (71)
Capitalized expenses (144) (135) (485) (375)
-----------------------------------------
General and administrative
expense, before stock
based compensation 255 210 867 626
Future stock based
compensation expense 57 56 171 117
-----------------------------------------
Total general and
administrative expense 312 266 1,038 743
-----------------------------------------
-----------------------------------------
General and administrative
expense, before stock based
compensation, per boe ($) 2.06 2.45 2.58 2.86
-----------------------------------------
-----------------------------------------
Total general and
administrative expense
per boe ($) 2.51 3.10 3.09 3.40
-----------------------------------------
-----------------------------------------


During the third quarter of 2005, net general and administrative costs before stock based compensation increased over the third quarter 2004 as a result of consulting expenses associated with the producing property acquisitions and the moving of the head office. The increase in the year to date 2005 general and administrative costs compared to the first nine months of 2004 is mainly due to the Company performing its first annual public reporting and regulatory filing during the period, as well as performance-based compensation paid during the first quarter of 2005. General and administrative expense, per boe, has decreased 19% in the third quarter of 2005 versus the third quarter of 2004.

Total general and administrative expenses for the remainder of 2005 are anticipated to be similar to 2004. Based on forecasted production and capital spending, 2005 staff levels are anticipated to be similar to 2004.



INTEREST EXPENSE

Interest Expense Summary


Three Months Ended Nine Months Ended
($ thousands, except September 30, September 30,
as indicated) 2005 2004 2005 2004
------------------------------------------------------------------------
Total interest expense 135 38 268 75
-----------------------------------------
-----------------------------------------
Per boe ($) 1.09 0.45 0.80 0.35
-----------------------------------------
-----------------------------------------


Interest expense for the three months ended September 30, 2005 was $0.1 million, an increase of 255 percent compared to the same period in 2004 due to higher debt levels. On a boe basis, the 2005 third quarter interest expenses increased 142 percent to an average cost of $1.09 per boe produced from $0.45 per boe in the same period in 2004. Interest expense per boe in the first nine months of 2005 have increased 129 percent compared to the average boe interest expense for the 2004 year as a result of increased debt for capital invested in exploration, development and acquisition activities.



DEPLETION, DEPRECIATION and ACCRETION

Depletion, Depreciation and Accretion Summary

Three Months Ended Nine Months Ended
($ thousands, except September 30, September 30,
as indicated) 2005 2004 2005 2004
------------------------------------------------------------------------
Depletion 1,697 1,227 4,352 3,023
Depreciation 4 3 8 9
Accretion on asset retirement
obligations 27 45 83 120
-----------------------------------------
Total depletion, depreciation
and accretion expense 1,728 1,275 4,443 3,152
-----------------------------------------
-----------------------------------------
Depletion, depreciation and
accretion expense per boe ($) 13.93 14.88 13.22 14.42
-----------------------------------------
-----------------------------------------


For the third quarter of 2005, depletion, depreciation and accretion expense increased 36 percent to $1.7 million from $1.3 million for the same period in 2004. The increase is due to higher production in 2005. On a boe basis depletion, depreciation and accretion for the third quarter of September 2005 decreased six percent to $13.93 from $14.88 in the same period in 2004. The decrease in boe depletion charges is a result of the lower cost of reserve additions during 2005.

For the nine months ended September 30, 2005, depletion, depreciation and accretion expense increased 41 percent to $4.4 million from $3.2 million for the same period in 2004 primarily due higher production. For the first nine months of 2005 the depletion, depreciation and accretion per boe decreased eight percent to $13.22 per boe as result of the lower cost for reserve additions during 2005.

At September 30, 2005, the ceiling test calculation indicated that the estimated undiscounted future cash flows from proven reserves exceeded the carrying values of producing petroleum and natural gas properties and therefore a ceiling test adjustment was not required.



INCOME TAXES

Income Tax Summary

Three Months Ended Nine Months Ended
($ thousands, except September 30, September 30,
as indicated) 2005 2004 2005 2004
------------------------------------------------------------------------
Future income taxes 948 115 1,716 178
Capital taxes - - - -
-----------------------------------------
Total income taxes 948 115 1,716 178
-----------------------------------------
-----------------------------------------
Effective tax rate (%) 34.7 - 36.5 -
-----------------------------------------
-----------------------------------------


The future income tax expense provision for the three months ended September 30, 2005 increased to $0.9 million from a future tax expense of $0.1 million in the same period in 2004. For the nine months ended September 30, 2005 future income tax expense increased to $1.7 million from $0.2 million in the comparable period in 2004. The increase in 2005 future tax expense was primarily due to higher earnings before taxes. In 2004, an one percent reduction to the Alberta corporate income tax rate was recognized.

As at September 30, 2005, the Company has approximately $38.7 million in tax pools to shelter taxable income in the future years.

NET EARNINGS and CASH FLOW FROM OPERATIONS

Net earnings increased to $1.8 million for the three months ended September 30, 2005 compared to $0.1 million during the same period in 2004. The increase was mainly due to higher production and commodity prices per boe received over the same period in 2004. Net earnings per basic and diluted share for the quarter was $0.12 compared to $0.01 per basic and diluted share during the same quarter in 2004.

For the nine months ended September 30, 2005, net earnings increased 446 percent to $3.0 million compared to $0.6 million during the comparable period in 2004. The increase in net earnings was mainly due to production and higher commodity prices received and lower expenses per boe.

Cash flow from operations increased 200 percent to $4.5 million for the three months ended September 31, 2005 compared to $1.5 million during the same period in 2004. For the first nine months of 2005 cash flow from operations increased 133 percent to $9.2 million compared to $4.0 million during the first nine months of 2004. The increase in cash flow is primarily due to higher production and commodity prices.

CAPITAL EXPENDITURES

During the first three quarters of 2005 the Company spent approximately $8.1 million in exploration and development capital expenditures compared to $7.7 million spent in the same period of 2004. The Company drilled 12 wells (9.8 net) with a success rate of 92 percent and added over 10,200 net undeveloped acres during the period. For the first nine months ended September 30, 2005 the total capital expenditures were $15.9 million comprising of $8.1 million spent on exploration and development expenditures and $7.8 million to acquire the properties in the Peace River Arch area of Alberta. The acquisitions provided production of 0.9 mmcf per day of natural gas and 10 barrels per day of lighter quality crude, interests in several strategic field facilities, 10,600 net acres of undeveloped land and a large seismic data base associated with the acquired properties. Total capital expenditures during the nine months ended September 30, 2004 were $27.3 million that included $7.7 million spent on exploration and development expenditures and $19.6 million for the acquisition and merger of Terraquest Energy Corporation on February 26, 2004.



Three Months Ended Nine Months Ended
September 30, September 30,
($ thousands) 2005 2004 2005 2004
------------------------------------------------------------------------
Land 503 71 1,142 427
Geological and geophysical 202 101 525 338
Drilling and completions 1,088 1,496 5,129 4,844
Equipping and facilities 989 863 1,894 2,069
Other 23 - 29 2
Disposal of property (600) - (600) -
-----------------------------------------
Total exploration and
development capital 2,205 2,531 8,119 7,680
Terraquest Energy Corporation - - - 19,584
Producing property acquisition 261 - 7,813 -
-----------------------------------------
Total capital expenditures 2,466 2,531 15,932 27,264
-----------------------------------------
-----------------------------------------


Drilling Results

During the third quarter of 2005 the Company drilled one well resulting in a natural gas well for a success rate of 100 percent. For the first nine months of 2005, the Company drilled 12 wells resulting in three oil wells, eight natural gas wells and one dry and abandoned well for an overall success rate of 92 percent.



Three Months Ended Nine Months Ended
September 30, 2005 September 30,2005
(wells) Gross Net Gross Net
------------------------------------------------------------------------
Oil - - 3 3.0
Natural Gas 1 1.0 8 5.8
Dry - - 1 1.0
-----------------------------------------
Total 1 1.0 12 9.8
-----------------------------------------
-----------------------------------------
Success rate (%) 100 100 92 90
-----------------------------------------
-----------------------------------------


CONTRACTUAL OBLIGATIONS

Effective September 1, 2005, the Company is committed under a lease on its office premises expiring August 31, 2010 for future annual minimum rental payments, excluding estimated operating costs, of $87,096 for the first three years and $92,892 for the remainder of the lease term. The Company has the option to terminate the office lease at the end of the second year, subject to a termination payment of $69,000.

There are no commodity hedge contracts outstanding as at September 30, 2005.

LIQUIDITY and CAPITAL RESOURCES

The Company's total capitalization at September 30, 2005 was $81.6 million with the market value of common shares representing 81 percent of total capitalization. Net debt represented 13 percent and asset retirement obligations and future income taxes accounted for six percent.



Total Market Capitalization
($ thousands except as indicated) 2005 %
------------------------------------------------------------------------
Common shares outstanding (thousands) 14,470
Share price, September 30, 2005 ($ per share) 4.55
-------------------
Total market capitalization 65,840 81
-------------------
Working capital (1,381)
Bank debt 11,911
-------------------
Net debt 10,530 13
-------------------
Asset retirement obligation 3,556 4
Future income taxes 1,679 2
-------------------
Total capitalization 81,605 100
-------------------
-------------------
Net debt to total capitalization 0.13:1
-------------------
-------------------


At September 30, 2005 the Company had borrowed approximately $11.9 million and had working capital of $1.4 million totaling $10.5 million of total net debt. This net debt amount represents approximately 0.6 times the annualized third quarter 2005 cash flow from operations.

The Company has a bank revolving term facility of $16.0 million to fund future activities. The facility is a borrowing base facility that is determined by the Company's latest reserve assessment, results of operations, current and forecasted commodity prices and the prevailing market conditions. The facility is reviewed semi-annually with the next date October 31, 2005. As at September 30, 2005, the Company had drawn $11.9 million of the revolving term facility and the amount is recorded as a long-term liability.

The Company's future investing activities, which consist primarily of capital expenditures on oil and gas activities, will be funded with working capital, cash flow from operations and a limited amount of bank debt.

As at October 25, 2005 the issued and outstanding common shares of the Company were 14,470,313, options outstanding were 1,180,000 and performance warrants outstanding of 935,000.

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. The Company commenced oil and gas operations after acquiring the Little Bow property on December 22, 2003.



(Unaudited) 2005 2004
--------------------------------------------------------
Operations Q3 Q2 Q1 Q4 Q3 Q2 Q1
---------- --------------------------------------------------------
Production
- Oil (bbl/d) 688 715 678 588 597 556 488
- NGL (bbl/d) 15 11 6 13 5 9 2
- Natural Gas
(mcf/d) 3,872 3,055 2,538 2,406 1,980 1,653 800
- Equivalent
(boe/d) 1,349 1,236 1,107 1,002 932 841 619
Pricing
- Oil, before
hedging ($/bbl) 56.92 41.64 38.14 36.91 42.40 37.10 33.60
- Hedging costs - - - (0.01) (4.25) - -
--------------------------------------------------------
- Oil, after
hedging ($/bbl) 56.92 41.64 38.14 36.90 38.15 37.10 33.60
- NGL ($/bbl) 59.56 49.56 46.12 50.72 40.20 36.86 45.11
- Natural Gas
($/mcf) 9.09 7.34 6.83 6.62 6.24 6.51 7.35
- Equivalent
($/boe) 55.84 42.71 39.28 38.09 37.90 37.95 35.82

Financial
---------
($ thousands except
share and per
share amounts)
Total revenue 6,928 4,802 3,914 3,501 3,258 2,922 2,028
Cash flow from
operations 4,476 2,699 2,069 1,676 1,513 1,391 1,055
Net earnings
(loss) 1,781 643 557 (124) 79 (49) 521
- basic per
share 0.12 0.04 0.04 (0.01) 0.01 0.00 0.05
- diluted per
share 0.12 0.04 0.04 (0.01) 0.01 0.00 0.05
Capital spending
- Exploration
and development 2,205 2,806 3,108 3,240 2,531 2,761 2,388
- Acquisitions 261 7,552 - - - - 20,174
Total assets 51,142 48,130 38,830 37,291 35,518 34,833 34,271
Working capital
(deficiency) 1,381 323 (5,155) (4,116) (2,551) (1,533) (163)
Long-term debt 11,911 13,137 - - - - -
Shareholders'
equity 31,033 28,884 28,184 27,570 27,639 27,504 27,508
Weighted average
common shares
outstanding
(thousands)
- basic 14,462 14,364 14,364 14,364 14,364 14,364 10,987
- diluted 15,146 14,931 14,801 14,614 14,553 14,505 11,184
Share trading
activity
- volume
(thousands)
-- total 2,467 3,096 4,149 2,858 910 868 220
-- daily 39 48 67 45 14 14 12
- price
($ per share)
-- high 4.70 3.80 4.20 2.85 2.77 2.69 3.25
-- low 3.62 3.05 2.31 2.30 2.25 2.00 2.45
-- closing 4.55 3.64 3.40 2.60 2.70 2.40 2.55


Factors that caused variations over the quarters -

- The Company completed four 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 and probable reserves acquired were approximately 1.4 million boe with an estimated reserve 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 and probable reserves acquired were approximately 1.1 million boe with an estimated reserve life index of 7.9 years based on the production at the time of acquisition.

- The two acquisitions of producing properties in the 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 and probable reserves acquired were approximately 0.5 million boe with an estimated reserve life index of 7.0 years.

- Production growth subsequent to the acquisitions is a result of the Company's exploration, development and exploitation activities. The timing of production is subject to timing of drilling and facility construction.

- The 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 fourth quarter 2004 due to wider than historical quality differentials. This impacted the prices received by Masters during the fourth quarter of 2004 and throughout 2005 as a majority of the crude production is of medium quality.

- The net earnings are impacted by depletion, depreciation, accretion and future income taxes. The Company estimates its reserves every quarter based on its acquisition and drilling activities. The annual reserves are determined by independent reservoir engineers, the results of which can affect fourth quarter reserve additions. Future income taxes have been impacted with the enacted changes to the federal and provincial income tax rates for the oil and gas industry.

- Capital spending is influenced with the development of future drilling prospects and seasonal field conditions. The capital spending was funded through cash flow and bank debt.



Masters Energy Inc.
Balance Sheets

September December 31,
($ thousands) 30, 2005 2004
---------------------------------------------------------------------
---------------------------------------------------------------------
(Unaudited) (Audited)
Assets

Current assets

Cash $ 1,340 $ -
Accounts receivable 2,766 2,116
Prepaid expenses and deposits 208 415
-------- ---------
4,314 2,531

Property and equipment (note 2) 46,828 34,760
-------- ---------
$ 51,142 $ 37,291
-------- ---------
-------- ---------
Liabilities

Current liabilities

Accounts payable and accrued
liabilities $ 2,933 $ 3,223
Bank debt (note 3) - 3,424
-------- ---------
2,933 6,647

Long-term bank debt (note 3) 11,911 -

Asset retirement obligations (note 4) 3,556 3,044

Future income taxes (note 8) 1,746 30
-------- ---------
20,146 9,721
-------- ---------
Shareholders' Equity

Share capital (note 5) 27,346 27,042
Contributed surplus (note 6) 351 210
Retained earnings 3,299 318
-------- ---------
30,996 27,570
-------- ---------
$ 51,142 $ 37,291
-------- ---------
-------- ---------

See accompanying notes to the financial statements.

Approved on behalf of the board,


"signed" "signed"
---------------------------- ----------------------------
William R. Stedman, Director Douglas H. Mitchell, Director


Masters Energy Inc.
Statements of Earnings and Retained Earnings
(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
($ thousands except share and
per share amounts) 2005 2004 2005 2004
-----------------------------------------------------------------------
-----------------------------------------------------------------------

Revenue
Petroleum and natural gas
sales $ 6,928 $ 3,258 $ 15,644 $ 8,208
Royalties, net of Alberta
Royalty Tax Credit (1,024) (595) (2,501) (1,464)
-------- -------- --------- --------
5,904 2,663 13,143 6,744
-------- -------- --------- --------
Expenses
Operating 1,000 890 2,697 2,044
General and administrative 312 266 1,038 743
Interest 135 38 268 75
Depletion, depreciation and
accretion 1,728 1,275 4,443 3,152
-------- -------- --------- --------
3,175 2,469 8,446 6,014
-------- -------- --------- --------

Earnings before taxes 2,729 194 4,697 730
Future income taxes (note 8) 948 115 1,716 178
-------- -------- --------- --------
Net earnings 1,781 79 2,981 552
Retained earnings (deficit),
beginning of period 1,518 363 318 (110)
-------- -------- --------- --------
Retained earnings, end of
period $ 3,299 $ 442 $ 3,299 $ 442
-------- -------- --------- --------
-------- -------- --------- --------

Earnings per share (note 7)
- basic $ 0.12 $ 0.01 $ 0.21 $ 0.04
-------- -------- --------- --------
-------- -------- --------- --------
- diluted $ 0.12 $ 0.01 $ 0.20 $ 0.04
-------- -------- --------- --------
-------- -------- --------- --------
Weighted average number of
shares outstanding
- basic 14,462,088 14,363,647 14,396,821 13,242,084
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
- diluted 15,146,239 14,552,837 14,959,585 13,413,871
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

See accompanying notes to the financial statements.


Masters Energy Inc.
Statements of Cash Flows
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
($ thousands) 2005 2004 2005 2004
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Cash provided by (used for):

Operating activities
Net earnings $ 1,781 $ 79 $ 2,981 $ 552
Add (deduct) non-cash items
Depletion, depreciation and
accretion 1,728 1,275 4,443 3,152
Settlement of asset
retirement costs (38) (12) (67) (40)
Future income tax expense 948 115 1,716 178
Stock-based compensation
expense 57 56 171 117
-------- -------- --------- --------
4,476 1,513 9,244 3,960
Changes in non-cash working
capital 308 (290) (1,557) (15)
-------- -------- --------- --------
4,784 1,223 7,687 3,945
-------- -------- --------- --------
Financing activities
Increase (decrease) in bank
debt (1,226) - 8,487 (7,032)
Proceeds on share issuance 274 - 274 -
-------- -------- --------- --------
(952) - 8,761 (7,032)
Changes in non-cash working
capital - 1,056 - 2,111
-------- -------- --------- --------
(952) 1,056 8,761 (4,921)
-------- -------- --------- --------
Investing activities
Petroleum and natural gas
properties
Exploration and development (2,205) (2,531) (8,119) (7,680)
Producing property
acquisition (261) - (7,813) -
Costs related to the acquisition
of Terraquest - - - (295)
-------- -------- --------- --------
(2,466) (2,531) (15,932) (7,975)
Changes in non-cash working
capital (26) 234 824 (461)
-------- -------- --------- --------
(2,492) (2,297) (15,108) (8,436)
-------- -------- --------- --------
Increase (decrease) in cash 1,340 (18) 1,340 (9,412)

Cash and cash equivalents,
beginning of period - 121 - 9,515
-------- -------- --------- --------
Cash and cash equivalents,
end of period $ 1,340 $ 103 $ 1,340 $ 103
-------- -------- --------- --------
-------- -------- --------- --------

Supplemental Cash Flow
Information
Interest income received $ 5 $ 1 $ 5 $ 21
Interest paid $ 135 $ 17 $ 268 $ 25
Capital taxes paid $ - $ - $ - $ 34
------------------------------------------------------------------------

See accompanying notes to the financial statements.


Masters Energy Inc.
Notes to the Financial Statements
(Unaudited)


1. Accounting Policies

The interim financial statements of Masters Energy Inc. ("the Company") have been prepared following the same accounting policies and methods of computation as the financial statements of the Company for the year ended December 31, 2004. The disclosures provided below are incremental to those included with the annual financial statements. These interim financial statements should be read in conjunction with the financial statements and notes disclosed in the Company's annual report for the year ended December 31, 2004.

The Company is engaged in the exploration, development and production of petroleum and natural gas in Western Canada. The financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian generally accepted accounting principles.



2. Property and equipment

($ thousands) Accumulated
Depletion and Net Book
As at September 30, 2005 Cost Depreciation Value
-------------------------------------
Petroleum and natural gas
properties and well equipment $ 55,450 $ 8,670 $ 46,780
Office equipment 72 24 48
-------------------------------------
$ 55,522 $ 8,694 $ 46,828
-------------------------------------
-------------------------------------

As at December 31, 2004 (Audited)

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


The value of undeveloped lands excluded from costs subject to depletion was $7.6 million at September 30, 2005 ($5.5 million - December 31, 2004).

During the nine months ended September 30, 2005, $0.5 million ($0.4 million - September 30, 2004) of general and administrative costs were capitalized.

3. Bank debt

The Company has access to a revolving term credit facility with a Canadian chartered bank. As of May 27, 2005 the Company increased its bank debt facility to a maximum of $16.0 million. The credit facility may be drawn or repaid directly or with bankers' acceptances. Direct advances bear interest at the bank's prime lending rate and the bankers' acceptances bear interest at the applicable bankers' acceptance rate plus a stamping fee.

The Company has available a $2.5(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.

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

As of September 30, 2005, $11.9 million ($3.4 million - December 31, 2004) has been drawn against the revolving credit facility.

Security pledged for the facilities consists of a general assignment of book debts, a $40.0 million demand debenture, secured by a first floating charge over all the assets of the Company. The next review of the credit facility is to occur on or before October 31, 2005.

4. Asset retirement obligation

The following table summarizes changes in the asset retirement obligation for the periods ended as indicated:



Nine Months Ended Year Ended
($ thousands) September 30, 2005 December 31, 2004
------------------------------------------------------------------------
(Audited)
Asset retirement obligation,
beginning of period $ 3,044 $ 1,198
Adjustments - (119)
Liabilities acquired 284 1,770
Liabilities incurred 212 119
Asset retirement expenditures (67) (95)
Accretion expense 83 171
------------------------------------------
Asset retirement obligation,
end of period $ 3,556 $ 3,044
------------------------------------------
------------------------------------------


The total estimated, undiscounted cash flows required to settle the obligations, before considering salvage, is $4.9 million as at September 30, 2005 ($4.4 million - December 31, 2004) which has been discounted using a weighted average credit-adjusted risk-free interest rate of 6.9 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) Common shares issued

($ thousands, except share number) Number Amount
------------------------------------------------------------------------
Balance, December 31, 2004 14,363,647 $ 27,042
Exercise of stock options and performance
warrants 106,666 274
Transfer from contributed surplus from
exercise of options and performance
warrants - 30
------------------------------------------
Balance, September 30, 2005 14,470,313 $ 27,346
------------------------------------------
------------------------------------------


6. Stock-based Compensation

(a) Stock options

The following table sets forth reconciliation of the stock option plan activity for the nine months ended September 30, 2005:



Weighted average
Number of options exercise price($)
------------------------------------------------------------------------
Balance, December 31, 2004 1,255,000 $2.19
Granted, July 26, 2005 50,000 3.80
Cancelled (83,334) 2.14
Exercised (41,666) 2.14
----------
Balance, September 30, 2005 1,180,000 $2.27
----------
----------


The fair value of the options granted during the period was estimated on the date of the grant using the Black-Scholes option pricing model with weighted average assumptions and resulting value for the grant as follows:


Nine months ended
September 30, 2005
------------------------------------------------------------------------
Risk-free interest rate (%) 3.8
Expected life (years) 5.0
Expected volatility (%) 46
Weighted average fair value per option granted ($) 1.73


(b) Performance warrants

The following table sets forth reconciliation of the performance warrant plan activity for the nine months ended September 30, 2005:



Number of
performance Weighted average
warrants price per warrant($)
------------------------------------------------------------------------
Balance, December 31, 2004 1,000,000 $3.55
Exercised (65,000) 2.85
----------
Balance, September 30, 2005 935,000 $3.60
----------
----------


(c) Contributed surplus

The following table reconciles the Company's contributed surplus for the
nine months ended September 30, 2005:


($ thousands)
------------------------------------------------------------------------
Balance, December 31, 2004 $ 210
Stock-based compensation expense 171
Exercise of options and performance warrants (30)
-------
Balance, September 30, 2005 $ 351
-------
-------


7. Per share amounts

Per share amounts have been calculated using the basic weighted average number of common shares outstanding of 14,462,088 and 14,396,821 during the three and nine months periods ended September 30, 2005 (13,242,084 - nine months ended September 30, 2004). For the three month period ended September 30, 2005, a total of 684,151 (189,190 - 2004) were added to the total to take into account the dilutive effect of the options and warrants for the period. A total of 562,764 common shares were added to take into account the dilutive effect during the nine months period ended September 30, 2005 (171,787 - 2004).

8. Future income taxes

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



Three Months Ended Nine Months Ended
September 30 September 30
($ thousands) 2005 2004 2005 2004
------------------------------------------------------------------------
Expected income tax expense $1,026 $ 75 $1,767 $ 282

Increase (decrease) resulting
from:
Non-deductible crown payments 126 165 504 401
Resource allowance (269) (117) (608) (308)
Impact in effective tax rate
applied (35) (93) (15) (238)
Stock based compensation expense 17 21 60 45
Other 83 64 8 (4)
-----------------------------------------
Total future tax expense $ 948 $ 115 $1,716 $ 178
-----------------------------------------
-----------------------------------------


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

($ thousands) September 30, 2005 December 31, 2004
------------------------------------------------------------------------
Carrying value of property
and equipment in excess of
available tax deductions $ 3,258 $ 2,141
Asset retirement obligation (1,155) (987)
Non-capital loss carryforwards - (640)
Share issuance costs (357) (484)
-----------------------------------------
$ 1,746 $ 30
-----------------------------------------
-----------------------------------------


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".

ADVISORY

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 prices, currency fluctuations, impression 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 or to update the reasons why actual results could differ from those contemplated by the forward-looking statements.

The Toronto Stock Exchange has neither approved nor disapproved of the information contained herein.

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