Freehold Royalty Trust
TSX : FRU.UN

Freehold Royalty Trust

August 10, 2005 13:22 ET

Freehold Royalty Trust Announces 2005 Second Quarter Results, Declares Second Quarter Top-up, and Increases Monthly Distribution

CALGARY, ALBERTA--(CCNMatthews - Aug. 10, 2005) - Freehold Royalty Trust (TSX:FRU.UN) (Freehold or the Trust) today announced results for the three months ended June 30, 2005.

SECOND QUARTER HIGHLIGHTS

- On May 10, 2005, Freehold completed the previously announced acquisition of royalty interests (Petrovera Partnership), for $352 million, acquiring 3,700 barrels of oil equivalent (boe) per day of royalty production.

- Production averaged 7,279 boe per day, up 26% from the second quarter of 2004.

- Price realizations averaged $42.42 per boe, 14% higher than a year ago.

- Operating netback averaged $39.61 per boe, up 18% from last year.

- Distributions to Unitholders totalled $0.41 per Trust Unit ($0.36 regular plus $0.05 top-up related to the first quarter of 2005.)

The board of directors has declared an extra distribution of $0.06 per Trust Unit (top-up related to the second quarter) and increased the regular monthly distribution by 17% from $0.12 to $0.14 per Trust Unit. The $0.06 top-up will be paid on September 15, 2005, along with the $0.14 regular monthly distribution (total of $0.20 per Trust Unit.) The record date is August 31, 2005, and the ex-distribution date is August 29, 2005. Including the September 15th payment, the 12-month trailing cash distributions total $1.75 per Trust Unit.



------------------------------------------------------------------------
Results at a Glance Three Months Ended Six Months Ended
June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Financial
($000s, except as noted)
Gross revenue 28,564 19,878 44% 48,423 37,829 28%
Operating income
Net income 10,858 9,515 14% 20,226 17,189 18%
Per Trust Unit,
diluted ($) 0.26 0.30 -13% 0.55 0.55 -
Funds generated from
operations (1) 24,344 16,407 48% 40,447 30,782 31%
Per Trust Unit ($) 0.59 0.52 13% 1.11 0.98 13%
Distributions to
Unitholders 17,981 12,593 43% 30,917 24,233 28%
Per Trust Unit (2) ($) 0.41 0.40 3% 0.82 0.77 6%
Long-term debt 120,000 17,000 606% 120,000 17,000 606%
Unitholders' equity 413,908 174,617 137% 413,908 174,617 137%
------------------------------------------------------------------------
Operating
Average daily
production (boe/d) 7,279 5,757 26% 6,395 5,667 13%
Average price
realizations ($/boe) 42.42 37.37 14% 41.16 36.20 14%
Operating netback
($/boe) 39.61 33.57 18% 38.14 32.39 18%
------------------------------------------------------------------------
Trust Units Outstanding
At period end (000s) 48,960 31,499 55% 48,960 31,499 55%
Weighted average (000s) 41,489 31,477 32% 36,544 31,466 16%
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Prior periods restated to conform to the current period's
presentation.
(2) Based on the number of Trust Units issued and outstanding at each
record date.


Message to Unitholders

In the second quarter of 2005, Freehold achieved record revenue, funds generated from operations (cash flow) and net income, fueled by a 26% boost to oil and gas production, and a 14% increase in average price realizations. Our production remained unhedged in the second quarter, and we have no plans to enter into any foreign currency or commodity price hedges at this time. This policy is subject to quarterly review by our board of directors.

Cash distributions declared totalled $18 million, or $0.41 per Trust Unit, representing a payout ratio of 74% of cash flow. In addition, we declared a quarterly top-up of $0.06 per Trust Unit relating to the second quarter. This top-up will be paid on September 15, along with the regular monthly distribution, which we are increasing to $0.14 per Trust Unit.

On May 10, we acquired the Petrovera Partnership - the largest acquisition in our history. The acquisition adds critical mass to enhance stability of our distributions over the long term, from royalty interest assets that are a very good fit with our existing portfolio. It doubles our royalty production and solidifies Freehold's position as the only oil and gas trust in Canada focused primarily on royalty interests. About 80% of our production now comes from royalty interests.

The properties acquired include interests in approximately 7,600 wells, of which 3,618 wells overlap with Freehold's current wells and production units. As a result, we have redrawn the boundaries of our royalty areas, adding two new areas: Peace River Arch and Ontario. The accompanying map at http://www2.ccnmatthews.com/database/fax/2000/810fru.jpg shows our new royalty areas within western Canada. (The map is also available on our website, www.freeholdtrust.com.)

The integration process is well underway, although it will take some time to transfer all of the lands into our name and ensure we receive the proper royalty payments directly. With Petrovera contributing royalty production for only 52 days, the positive impact of the acquisition was not fully reflected in our second quarter results. The third quarter will be more representative. With the benefit of Petrovera royalty production for the full period, both operating and general and administrative expenses will be lower in the third quarter, on a per boe basis. Synergies and economies of scale are expected to further reduce G&A expenses on a per boe basis, once the integration of assets is complete.

From an operational perspective, drilling activity on the Petrovera lands is ahead of expectations. We are pleased with the quality of the wells drilled to date in 2005, which have been generally oil prone. This compares with primarily shallow uphole-gas targets being drilled on Freehold's lands, and provides a balanced portfolio. There are currently 151 licensed drilling locations on our royalty lands, of which 66 are on Petrovera lands.

We have increased our estimate of 2005 cash distributions to $1.80 per Trust Unit, resulting in a payout ratio of approximately 75% in 2005. While this payout ratio is lower than our historical average of 83%, it does not signal a change in strategy. Rather, the increased royalty interest production has required a significant, one-time increase in our receivables, caused by the normal lag in receiving royalty revenue. Beyond 2005, we expect to maintain a payout ratio in line with our historical average.

I would like to acknowledge the very significant contribution of the employees of the Manager, who have worked exceptionally hard and put in many long hours over the last several months on the Petrovera acquisition.



On behalf of the Board of Directors
of Freehold Resources Ltd.,

"signed"
David J. Sandmeyer
President & Chief Executive Officer


------------------------------------------------------------------------
Summary of Royalty
Assets Acquired Freehold Petrovera Combined
-------------------------------------------------- ---------- ----------
Production (year ended December 31, 2004)
Royalty production (%) 66 99 79
Oil (bbls/d) 3,594 2,005 5,599
NGL (bbls/d) 283 101 384
Natural gas (Mcf/d) 10,270 9,347 19,617
Total (boe/d) 5,588 3,663 9,251
-------------------------------------------------- ---------- ----------
Reserves (as at December 31, 2004)
Net proved (Mboe) 14,678 8,324 23,002
Net proved plus probable (Mboe) 21,163 12,889 34,052
Reserve life index (net proved
plus probable, years) 10.6 9.6 10.2
-------------------------------------------------- ---------- ----------
Land (as at December 31, 2004)
Gross (acres) 867,155 1,109,922 1,892,294
Gross undeveloped (acres) 246,177 386,509 623,366
-------------------------------------------------- ---------- ----------
-------------------------------------------------- ---------- ----------


Management's Discussion and Analysis (MD&A)

The following discussion is management's opinion about Freehold Resources Ltd. and Freehold Royalty Trust's (the "Trust") (collectively "Freehold"), operating and financial results for the three and six months ended June 30, 2005 and previous periods, and the outlook for Freehold based on information available as at August 10, 2005. The financial information contained herein has been prepared in accordance with Canadian generally accepted accounting principles (GAAP). All comparative percentages are between the quarters ended June 30, 2005 and June 30, 2004 and all dollar amounts are expressed in Canadian currency, unless otherwise noted. This discussion should be read in conjunction with the Trust's annual MD&A and audited financial statements for the years ended December 31, 2004 and 2003, together with the accompanying notes. These are included on pages 19 through 44 of the Trust's 2004 annual report to Unitholders.

FORWARD-LOOKING STATEMENTS

This MD&A offers our assessment of Freehold's future plans and operations as at August 10, 2005, and contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. You are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them.

SUPPLEMENTAL DISCLOSURE

We believe that distributions to Unitholders, cash flow and netback are useful supplemental measures. You are cautioned that distributions to Unitholders should not be construed as an alternative to net income as determined by GAAP. Cash flow, as used in this report, refers to funds generated from operations derived from our Consolidated Statements of Cash Flows. Cash flow represents cash provided by operating activities, before changes in non-cash working capital. We use cash flow to analyze operating performance, leverage and liquidity. Operating netback, which is calculated as average unit sales price less royalties and operating expenses; and investor netback, which deducts administrative and interest expense and income and capital taxes, represent the cash margin for product sold, calculated on a per boe basis. Distributions to Unitholders, cash flow and netback do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

CONVERSION OF NATURAL GAS TO OIL EQUIVALENT

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are mathematically converted to equivalent barrels of oil (boe). We use the international conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio approximates an equivalent energy value at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

RESULTS OF OPERATIONS

The table below is a summary of our performance for the second quarter of 2005, with comparative data for the preceding seven quarters. This presentation illustrates the fluctuations in pricing experienced over the past eight quarters, and the resultant effect on our financial results. In recent quarters, our results have benefited from strong commodity prices.



------------------------------------------------------------------------
Quarterly Results 2005
($000s, except as noted) Q2 Q1
------------------------------------------------------------------------
Financial
Revenue, net of royalty expense 27,922 19,170
Funds generated from operations (1) 24,344 16,103
Per Trust Unit ($) 0.59 0.51
Distributions to Unitholders 17,981 12,936
Per Trust Unit ($) 0.41 0.41
Payout ratio (%) 74 80
Net income (2) 10,858 9,368
Per Trust Unit, diluted ($) 0.26 0.30
Long-term debt 120,000 27,000
------------------------------------------------------------------------
Operating
Daily production (boe/d) 7,279 5,502
Average selling price ($/boe) 42.42 39.47
Operating netback ($/boe) 39.61 36.18
------------------------------------------------------------------------
Benchmark Prices
WTI crude oil (US$/bbl) 53.20 49.84
Exchange rate (Cdn$/US$) 0.8039 0.8150
Edmonton Par (Cdn$) 65.76 61.45
Light/heavy oil differential (Cdn$/bbl) 24.17 22.48
Bow River/Hardisty (Cdn$/bbl) 41.59 38.97
AECO natural gas (Cdn$/Mcf) 7.38 6.69
------------------------------------------------------------------------
Trading Performance
High ($) 17.63 18.49
Low ($) 14.25 15.50
Close ($) 15.99 16.10
Volume (000s) 8,311 2,418
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
Quarterly Results 2004
($000s, except as noted) Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Financial
Revenue, net of royalty expense 19,204 19,994 19,066 17,250
Funds generated from operations (1) 16,139 17,392 16,407 14,375
Per Trust Unit ($) 0.51 0.55 0.52 0.46
Distributions to Unitholders 15,449 14,808 12,593 11,640
Per Trust Unit ($) 0.49 0.47 0.40 0.37
Payout ratio (%) 96 85 77 81
Net income (2) 9,397 10,306 9,515 7,674
Per Trust Unit, diluted ($) 0.30 0.33 0.30 0.24
Long-term debt 27,000 17,000 17,000 18,000
------------------------------------------------------------------------
Operating
Daily production (boe/d) 5,575 5,447 5,757 5,577
Average selling price ($/boe) 38.37 40.96 37.37 35.00
Operating netback ($/boe) 34.67 36.85 33.57 31.18
------------------------------------------------------------------------
Benchmark Prices
WTI crude oil (US$/bbl) 48.28 43.88 38.31 35.14
Exchange rate (Cdn$/US$) 0.8195 0.7651 0.7357 0.7590
Edmonton Par (Cdn$) 57.70 56.25 50.60 45.60
Light/heavy oil differential
(Cdn$/bbl) 21.60 14.29 13.29 10.67
Bow River/Hardisty (Cdn$/bbl) 36.10 41.96 37.31 34.93
AECO natural gas (Cdn$/Mcf) 7.08 6.66 6.80 6.61
------------------------------------------------------------------------
Trading Performance
High ($) 18.42 16.97 15.80 16.30
Low ($) 15.75 14.57 14.65 14.02
Close ($) 17.45 16.25 15.00 14.75
Volume (000s) 4,252 1,768 3,149 2,399
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Quarterly Results 2003
($000s, except as noted) Q4 Q3
------------------------------------------------------------------------
Financial
Revenue, net of royalty expense 15,230 16,865
Funds generated from operations (1) 12,664 14,711
Per Trust Unit ($) 0.40 0.47
Distributions to Unitholders 12,575 12,545
Per Trust Unit ($) 0.40 0.40
Payout ratio (%) 99 85
Net income (2) 5,947 8,868
Per Trust Unit, diluted ($) 0.19 0.28
Long-term debt 18,000 17,500
------------------------------------------------------------------------
Operating
Daily production (boe/d) 5,768 5,909
Average selling price ($/boe) 29.51 32.15
Operating netback ($/boe) 25.88 28.61
------------------------------------------------------------------------
Benchmark Prices
WTI crude oil (US$/bbl) 31.18 30.20
Exchange rate (Cdn$/US$) 0.7600 0.7247
Edmonton Par (Cdn$) 39.55 40.92
Light/heavy oil differential (Cdn$/bbl) 11.02 10.13
Bow River/Hardisty (Cdn$/bbl) 28.53 30.79
AECO natural gas (Cdn$/Mcf) 5.59 6.29
------------------------------------------------------------------------
Trading Performance
High ($) 17.19 13.85
Low ($) 13.11 12.81
Close ($) 16.35 13.70
Volume (000s) 2,506 2,991
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Prior periods restated to conform to the current period's
presentation.
(2) 2003 restated.


NET INCOME AND FUNDS GENERATED FROM OPERATIONS

Higher average selling prices and increased royalty production led to record income and funds generated from operations (cash flow) for the second quarter of 2005.



------------------------------------------------------------------------
Net Income and Three Months Ended Six Months Ended
Funds Generated June 30 June 30
From Operations ---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Net income ($000s) 10,858 9,515 14% 20,226 17,189 18%
Per Trust Unit ($) 0.26 0.30 -13% 0.55 0.55 -
------------------------------------------------ -----------------------
Funds generated from
operations ($000s) 24,344 16,407 48% 40,447 30,782 31%
Per Trust Unit ($) 0.59 0.52 13% 1.11 0.98 13%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------


DISTRIBUTIONS TO UNITHOLDERS

Distributions to Unitholders for the second quarter of 2005 were $18 million, or $0.41 per Trust Unit, up 3% from last year on a per Trust Unit basis. This represents a payout of 74% of cash flow. Since inception, our payout ratio has averaged 83%. Royalty income contributed 83% of distributions in the second quarter.

The board has declared an extra distribution of $0.06 per Trust Unit (top-up related to the second quarter) and increased the regular monthly distribution by 17% from $0.12 to $0.14 per Trust Unit. The $0.06 top-up will be paid on September 15, 2005, along with the $0.14 regular monthly distribution (total of $0.20 per Trust Unit.)



------------------------------------------------------------------------
Analysis of Distributions Three Months Ended Six Months Ended
to Unitholders June 30 June 30
($000s, except as noted) ---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Funds generated from
operations 24,344 16,407 48% 40,447 30,782 31%
Add (deduct):
Net reclamation fund
contribution (93) (82) 13% (141) (181) -22%
Provision for capital
expenditures (650) (650) - (2,300) (1,650) 39%
Debt additions
(repayment) 93,000 (1,000) 93,000 (1,000)
Proceeds from Trust Unit
issuance 258,935 - 258,935 -
Property and royalty
acquisitions (351,705) (330) (351,705) (330)
Changes in working
capital (5,850) (1,752) 234% (7,319) (3,388) 116%
------------------------------------------------ -----------------------
Distributions to
Unitholders 17,981 12,593 43% 30,917 24,233 28%
Per Trust Unit (1) ($) 0.41 0.40 3% 0.82 0.77 6%
------------------------------------------------ -----------------------
Payout ratio (2) 74% 77% -4% 76% 79% -4%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------

(1) Based on the number of Trust Units issued and outstanding at each
record date.
(2) Distributions to Unitholders as a percentage of cash flow.


NETBACK

Our second quarter operating netback was $39.61 per boe, 18% higher than last year. We have consistently delivered a superior netback, relative to our peer group, as we do not incur royalty or operating expenses on our royalty lands. We do not have any commodity price or foreign currency hedges in place.



------------------------------------------------------------------------
Operating Netback Three Months Ended Six Months Ended
($/boe) June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Gross revenue (1) 43.12 37.95 14% 41.83 36.68 14%
Royalty expenses (2) 0.97 1.55 -37% 1.15 1.47 -22%
Operating expenses 2.54 2.83 -10% 2.54 2.82 -10%
------------------------------------------------ -----------------------
Operating netback 39.61 33.57 18% 38.14 32.39 18%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------

(1) Gross revenue includes potash revenue, sulphur revenue and other.
(2) Net of Alberta Royalty Credit.


PRODUCTION

Average daily production volumes rose 26% in the second quarter. Royalty production volumes jumped 43%, with the Petrovera acquisition contributing approximately 3,700 boe per day of royalty production for the last 52 days of the quarter. Since production revenue from January 1 to May 9, 2005 was netted against the purchase price, the annualized production from this acquisition in 2005 will be approximately 2,300 boe per day. Working interest production declined 9%, as an early spring break-up and wet weather curtailed access and delayed the tie-in of some new wells.

In the second quarter of 2005, our boe production profile was 34% natural gas, 5% natural gas liquids (NGL), 22% light and medium oil, and 39% heavy oil. The Petrovera acquisition increases both the natural gas and heavy oil components of our production; in the third quarter, these are expected to be about 37% and 40%, respectively. Freehold's 2005 exit production rate is expected to be 9,300 boe per day.



------------------------------------------------------------------------
Average Daily Production Three Months Ended Six Months Ended
June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Royalty lands
Oil (bbls/d) 3,156 2,157 46% 2,633 2,175 21%
NGL (bbls/d) 288 232 24% 261 216 21%
Natural gas (Mcf/d) 12,915 9,092 42% 10,462 8,181 28%
Oil equivalent (boe/d) 5,596 3,904 43% 4,637 3,755 23%
------------------------------------------------ -----------------------
Working interest properties
Oil (bbls/d) 1,279 1,368 -7% 1,332 1,436 -7%
NGL (bbls/d) 53 80 -34% 58 63 -8%
Natural gas (Mcf/d) 2,104 2,428 -13% 2,210 2,477 -11%
Oil equivalent (boe/d) 1,683 1,853 -9% 1,758 1,912 -8%
------------------------------------------------ -----------------------
Total Trust
Oil (bbls/d) 4,435 3,526 26% 3,965 3,611 10%
NGL (bbls/d) 341 311 10% 319 280 14%
Natural gas (Mcf/d) 15,019 11,520 30% 12,672 10,659 19%
Oil equivalent (boe/d) 7,279 5,757 26% 6,395 5,667 13%
------------------------------------------------ -----------------------
Number of days in period
(days) 91 91 - 181 182 -1%
Total volumes during
period (Mboe) 662 524 26% 1,158 1,031 12%
------------------------------------------------ -----------------------
Potash production (tonnes/d) 9.8 9.9 -1% 9.6 8.4 14%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------


BENCHMARK PRICES

In the second quarter, WTI crude oil prices rose 39%, while Edmonton Par prices rose 30%, reflecting a stronger Canadian dollar. Heavy grades of crude oil sell at a discount to light oil. A global surplus of heavy oil and a lack of upgrading capacity significantly amplified light/heavy oil price differentials in the first half of the year, and differentials reached unprecedented levels in the second quarter of 2005. AECO natural gas prices were up 9% in the quarter and 5% for the year to date.



------------------------------------------------------------------------
Average Benchmark Prices Three Months Ended Six Months Ended
June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
WTI crude oil (US$/bbl) 53.20 38.31 39% 51.52 36.73 40%
US$/Cdn$ exchange rate 0.8039 0.7357 9% 0.8095 0.7474 8%
Edmonton Par crude oil
(Cdn$/bbl) 65.76 50.60 30% 63.61 48.10 32%
Light/heavy oil
differential (Cdn$/bbl) 24.17 13.29 82% 23.33 11.98 95%
Bow River/Hardisty
(Cdn$/bbl) 41.59 37.31 11% 40.28 36.12 12%
AECO natural gas
(Cdn$/Mcf) 7.38 6.80 9% 7.03 6.71 5%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------



REALIZED PRICES

At $42.42 per boe, our average price realization is 14% higher than the second quarter last year. However, the increase in light/heavy oil differential prices resulted in a lower average price for our oil production relative to the benchmark WTI price. The differential is significant for Freehold, as approximately 59% of our oil production (39% of our total boe production) is heavy oil. In addition, the cost of purchased condensate, used as a diluent and blending agent for transport of heavy oil, has also risen dramatically.



------------------------------------------------------------------------
Average Selling Prices Three Months Ended Six Months Ended
June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Oil ($/bbl) 41.92 37.23 13% 40.90 35.60 15%
NGL ($/bbl) 44.29 34.78 27% 43.69 34.12 28%
------------------------------------------------ -----------------------
Oil and NGL ($/bbl) 42.09 37.03 14% 41.10 35.49 16%
Natural gas ($/Mcf) 7.17 6.34 13% 6.88 6.29 9%
Oil equivalent ($/boe) 42.42 37.37 14% 41.16 36.20 14%
------------------------------------------------ -----------------------
Potash ($/tonne) 212.65 162.81 31% 207.89 157.35 32%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------


DEVELOPMENT ACTIVITIES

ROYALTY INTEREST LANDS

An early spring break-up, extended road bans, and record rainfall and flooding on the southern Prairies in June, slowed industry drilling activity in the second quarter. In western Canada, just over 3,900 wells were drilled in the quarter, short of the 5,100 that industry experts had anticipated. Nevertheless, 141 wells were drilled on our royalty lands in the quarter, including 66 unit wells in which we have very small royalty interests. On an equivalent net basis, this is 4.4 net wells, up from 2.1 net wells in the second quarter of 2004. These wells were drilled at no cost to Freehold.

Drilling activity on the Petrovera lands in 2005 is ahead of expectations and we are pleased with the quality of the wells drilled to date, which have been generally oil prone. This compares with primarily shallow uphole-gas targets being drilled on Freehold's lands, and provides a balanced portfolio.

In the third quarter, the industry has resumed its record-setting pace, and we anticipate a strong second half. There are currently 151 (7.7 equivalent net) licensed drilling locations on our royalty lands, compared with 73 (4.1 equivalent net) locations at this time last year. Of this number, 66 (3.6 equivalent net) locations are on Petrovera lands.



------------------------------------------------------------------------
Royalty Three Months Ended June 30 Six Months Ended June 30
Interest Lands -------------------------- ----------------------------
Drilling 2005 2004 2005 2004
Summary(1) Gross Net(2) Gross Net(2) Gross Net(2) Gross Net(2)
------------------------------------------- ----------------------------
Oil 22 0.7 32 0.3 85 2.7 71 1.2
Natural gas 75 0.5 122 0.6 295 2.7 305 1.5
Service and other 44 3.2 22 1.2 84 4.9 36 1.6
Dry and abandoned - - - - 1 0.1 1 -
------------------------------------------- ----------------------------
Total 141 4.4 176 2.1 465 10.4 413 4.3
------------------------------------------- ----------------------------
------------------------------------------- ----------------------------

(1) Includes drilling on the Petrovera lands from January 1, 2005
(the effective date of the acquisition), but excludes any wells
drilled in Ontario. Gross wells excludes common wells.
(2) Equivalent net wells are the aggregate of the numbers obtained by
multiplying each gross well by the Trust's royalty interest
percentage.


------------------------------------------------------------------------
Summary of Royalty Wells Drilled Six Months Ended June 30, 2005
------------------------------------
Freehold Petrovera Combined(1)
------------------------------------------------- ---------- -----------
Gross wells 401 165 465
Equivalent net wells (2) 5.6 4.8 10.4
Net success rate (%) 99% 98% 99%
------------------------------------------------- ---------- -----------
------------------------------------------------- ---------- -----------

(1) Combined gross wells excludes common wells.
(2) Equivalent net wells are the aggregate of the numbers obtained by
multiplying each gross well by the Trust's royalty interest
percentage.


WORKING INTEREST PROPERTIES

In the second quarter of 2005, we spent $1.2 million on facilities and the drilling of 6 (0.7 net) wells, resulting in 3 oil wells and 3 natural gas wells, for a 100% success rate.

Most of our 2005 development activity will occur during the third quarter. Drilling programs are currently underway at Hayter (11 gross /2.6 net wells), Pembina Cardium Unit #9 (20 gross /2.0 net wells), Pouce Coupe (3 gross /0.6 net wells), and Lashburn (2 gross /1.6 net wells).



------------------------------------------------------------------------
Working Interest Three Months Ended Six Months Ended
Properties June 30 June 30
Drilling Summary ------------------------- ------------------------
2005 2004 2005 2004
Gross Net Gross Net Gross Net Gross Net
----------------------------------------------- ------------------------
Oil 3 0.7 1 0.1 10 0.8 10 0.3
Natural gas 3 0.0 3 0.1 21 0.2 24 0.5
----------------------------------------------- ------------------------
Total 6 0.7 4 0.2 31 1.0 34 0.8
----------------------------------------------- ------------------------
----------------------------------------------- ------------------------


REVENUE

We receive revenue from about 200 industry operators. Gross revenue of $28.6 million for the second quarter of 2005 was up 44% from a year ago, fuelled by higher commodity prices and increased royalty production volumes. The accompanying table demonstrates the net effect of price and volume variances on gross revenues.



------------------------------------------------------------------------
Gross Revenue Three Months Ended Six Months Ended
Variances June 30 June 30
($000s) --------------------------- ----------------------------
2005 vs. 2004 2004 vs. 2003 2005 vs. 2004 2004 vs. 2003
------------------------------------------------------------------------
Oil and NGL
Production
increase
(decrease) 3,598 (54) 2,764 (139)
Price increase
(decrease) 1,766 2,079 3,974 16
------------------------------------------- ----------------------------
Net increase
(decrease) 5,364 2,025 6,738 (123)
------------------------------------------- ----------------------------
Natural gas
Production
increase
(decrease) 2,284 95 2,434 (520)
Price increase
(decrease) 871 (54) 1,132 (1,086)
------------------------------------------- ----------------------------
Net increase
(decrease) 3,155 41 3,566 (1,606)
------------------------------------------- ----------------------------
Other 167 (43) 290 (51)
------------------------------------------- ----------------------------
Gross revenue
increase
(decrease) 8,686 2,023 10,594 (1,780)
------------------------------------------- ----------------------------
------------------------------------------- ----------------------------


EXPENSES

ROYALTIES PAID

Royalty expenses are tied directly to commodity prices and production volumes. In the second quarter, we paid royalty expenses of $4.19 per boe relating to ownership in working interest production. On a total Trust basis, royalty expenses declined 37%, reflecting the increase in royalty production volumes, which have no royalty expenses.



------------------------------------------------------------------------
Royalty Expenses Three Months Ended Six Months Ended
(net of Alberta June 30 June 30
Royalty Credit) 2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Working interest
properties ($000s) 642 812 -21% 1,331 1,513 -12%
Per boe ($) 4.19 4.82 -13% 4.18 4.35 -4%
------------------------------------------------ -----------------------
Royalty interest
lands (1) ($000s) - - - - - -
Per boe ($) - - - - - -
------------------------------------------------ -----------------------
Total royalty
expenses ($000s) 642 812 -21% 1,331 1,513 -12%
Total Trust ($/boe) 0.97 1.55 -37% 1.15 1.47 -22%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------

(1) We do not incur royalty expenses on production from our royalty
lands; as the royalty owner, we receive the royalty as income from
other companies.


OPERATING EXPENSES

Operating expenses on our working interest properties were $11.00 per boe for the second quarter, up 25% from 2004. The increase relates to lower working interest production volumes, compounded by access issues caused by wet spring conditions. On a total Trust basis, operating costs per boe were 10% lower than last year, as a higher percentage of our production was from royalties, which have no operating costs. Our overall operating expenses per boe will decline further in the third quarter, with the benefit of Petrovera royalty production for the full period.



------------------------------------------------------------------------
Operating Expenses Three Months Ended Six Months Ended
June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Working interest
properties ($000s) 1,685 1,480 14% 2,939 2,907 1%
Per boe ($) 11.00 8.78 25% 9.23 8.35 11%
------------------------------------------------ -----------------------
Royalty interest
lands (1) ($000s) - - - - - -
Per boe ($) - - - - - -
------------------------------------------------ -----------------------
Total operating
expenses ($000s) 1,685 1,480 14% 2,939 2,907 1%
Total Trust ($/boe) 2.54 2.83 -10% 2.54 2.82 -10%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------

(1) We do not incur operating expenses on production from our
royalty lands.


GENERAL AND ADMINISTRATIVE EXPENSES (G&A)

G&A expenses for the second quarter of 2005 rose 27%. The increase in G&A relates to higher staff levels, and rising costs associated with regulatory compliance, reserve report preparation, and financial reporting, as well as administrative expenses relating to the Petrovera acquisition. On a per boe basis, G&A expenses were level compared with the second quarter of last year, and will decline in the third quarter, as volumes increase. Synergies and economies of scale resulting from the Petrovera acquisition are expected to further reduce G&A expenses on a per boe basis, once the integration of assets is complete.



------------------------------------------------------------------------
G&A Expenses Three Months Ended Six Months Ended
June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
G&A expenses ($000s) 943 740 27% 2,206 1,907 16%
Per boe ($) 1.42 1.41 1% 1.91 1.85 3%
As a percentage
of revenue 3% 4% -25% 5% 5% -
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------


MANAGEMENT FEES

The Manager of the Trust receives its management fee in Trust Units. For the second quarter, the Manager received 30,017 Trust Units, with an ascribed value of $479,972 ($15.99 per Trust Unit) compared with 22,500 Trust Units with an ascribed value of $337,500 ($15.00 per Trust Unit) in the second quarter of 2004. The issue of 17.4 million Trust Units in May resulted in a pro-rata increase in the management fee, in accordance with the management contract. Effective July 1, 2005, the management fee will increase to 35,654 Trust Units per quarter. In connection with the Petrovera acquisition, an acquisition fee of $5.3 million was paid to the Manager, in accordance with the management contract.



------------------------------------------------------------------------
Management Fees Three Months Ended Six Months Ended
($000s, except as noted) June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Management fees
(paid in Trust Units)(1) 480 337 42% 842 669 26%
Per boe ($) 0.73 0.64 13% 0.73 0.65 12%
------------------------------------------------ -----------------------
Acquisition fees (2) 5,306 5 5,306 5
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------

(1) The ascribed value of the management fees is based on the closing
Trust Unit price at the end of each quarter.
(2) The Manager earns an acquisition fee of 1.5% of the purchase price
of oil and gas properties that we acquire. This fee is charged to
capital assets as part of the properties acquired.


INTEREST EXPENSES

In the second quarter, interest expenses totalled $0.7 million, or $0.01 per Trust Unit. The increase relates to additional debt assumed in May to finance the Petrovera acquisition.



------------------------------------------------------------------------
Interest Expenses Three Months Ended Six Months Ended
($000s, except as noted) June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
Net interest expense 690 147 369% 935 318 194%
Per boe ($) 1.04 0.28 271% 0.81 0.31 161%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------


LIQUIDITY AND CAPITAL RESOURCES

On May 10, 2005, we acquired Petrovera Resources, a general partnership, for $351.7 million, net of adjustments. The purchase price was funded with a combination of equity and debt, as described below. The acquisition was accounted for using the purchase method of accounting, with results of operations included from May 10, 2005.

In conjunction with the Petrovera acquisition, we expanded our credit facilities from $65 million to $165 million. These credit facilities were used to fund $93 million of the purchase price for the acquisition, inclusive of transaction costs.

We have a $15 million extendible revolving operating facility and a $150 million extendible revolving term credit facility. The borrowing base was $65 million before the acquisition and became $165 million concurrent with completion of the acquisition on May 10, 2005. The credit facilities bear interest at the lenders' prime rate, bankers' acceptances or LIBOR rates plus applicable margins ranging from 85 to 140 basis points and standby fees. They are secured with $300 million demand debentures over our petroleum and natural gas assets.

The increased royalty interest production from the Petrovera acquisition has required a significant, one-time increase in our receivables, caused by the normal lag in receiving royalty revenue. This increase resulted in a change to working capital of $5.9 million at June 30, 2005.

At the end of the second quarter, we had no short-term debt outstanding and long-term debt was $120 million. We had working capital of $11.5 million, resulting in net debt of $108.5 million. The Trust's ratio of net debt (long-term debt less positive working capital) to trailing cash flow was 1.5:1, higher than our historical average. By year-end, this ratio should improve to about 1.1:1, as the uplift in production revenue from the Petrovera properties is reflected in higher cash flows.



------------------------------------------------------------------------
As at June 30
Debt Analysis -------------------------
($000s) 2005 2004 Change
------------------------------------------------------- -------- -------
Long-term debt 120,000 17,000 606%
Short-term debt - - -
Less: working capital 11,454 7,755 48%
------------------------------------------------------- -------- -------
Net debt obligations 108,546 9,245 1074%
------------------------------------------------------- -------- -------
------------------------------------------------------- -------- -------


------------------------------------------------------------------------
As at June 30
Financial Leverage and Coverage Ratios (1) -------------------------
2005 2004 Change
------------------------------------------------------- -------- -------
Net debt to cash flow (times) 1.5 0.2 650%
Net debt to distributions (times) 1.8 0.2 800%
Distributions to interest expense (times) 49 73 -33%
Net debt to net debt plus equity (%) 21% 5% 320%
------------------------------------------------------- -------- -------
------------------------------------------------------- -------- -------
(1) Cash flow, distributions and interest expense are 12-months
trailing.


CAPITAL EXPENDITURES

Capital expenditure obligations are deducted from funds generated from operations, before determining distributions to Unitholders. As we do not incur any capital expenditures on our royalty properties, our capital requirements are modest, relative to most energy trusts. Capital expenditures on working interest properties totalled $1.2 million in the second quarter (2004 - $0.7 million) and $2.3 million for the first six months of 2005 (2004 - $1.7 million). Capital expenditures for the last six months of 2005 will be approximately $4.3 million, funded from cash flow.

TRUST UNITS OUTSTANDING

As at June 30, 2005 and August 10, 2005, there were 48,960,273 Trust Units outstanding. There are no options outstanding under the Trust Unit option plan. In connection with the Petrovera acquisition, we issued 17,363,520 Trust Units at $15.55 per Trust Unit on May 10, 2005. On June 30, 2005, we issued 30,017 Trust Units in payment of the management fee.


------------------------------------------------------------------------
Trust Units Outstanding Three Months Ended Six Months Ended
(000s) June 30 June 30
---------------------- -----------------------
2005 2004 Change 2005 2004 Change
------------------------------------------------ -----------------------
At period end 48,960 31,499 55% 48,960 31,499 55%
Weighted average 41,489 31,477 32% 36,544 31,466 16%
------------------------------------------------ -----------------------
------------------------------------------------ -----------------------


DISTRIBUTION OUTLOOK

The Petrovera acquisition, combined with continued strength in commodity pricing, leads us to increase our estimate of cash distributions for 2005 to $1.80 per Trust Unit, up 8% from our earlier guidance of $1.66 per Trust Unit. In keeping with our stated practice, a portion of any excess income available for distribution may be directed toward repayment of long-term debt and improvements to working capital, and extra distributions may be declared from time to time at the board's discretion.

Our assumptions, which are provided below, include average production volumes of 7,895 boe per day for the full year, with contribution of approximately 3,700 boe per day of production from the Petrovera assets from May 10, 2005 (2,300 boe per day annualized for 2005). We have increased our WTI price, and reduced the light/heavy oil differential slightly. As well, we have assumed $3 million in debt repayment during the last half of this year. This results in a payout ratio of approximately 75% in 2005. Beyond 2005, we expect to maintain a payout ratio in line with our historical average.



------------------------------------------------------------------------
2005 Distribution Outlook August 10, 2005 May 11, 2005
------------------------------------------------------- ----------------
Estimated cash distributions
($ per Trust Unit) 1.80 1.66
------------------------------------------------------- ----------------
2005 Assumptions
Average daily production (boe/d) 7,895 7,895
Average WTI oil price (US$/bbl) 53.00 49.00
Average AECO natural gas price
(Cdn$/Mcf) 7.00 7.00
Average light/heavy oil price
differential (Cdn$/bbl) 24.00 25.00
Average exchange rate (Cdn$/US$) 0.81 0.80
Capital expenditures ($ millions) 6.6 6.6
Long-term debt at year end ($ millions) 117 117
Weighted average Trust Units
outstanding (thousands) 42,812 42,815
------------------------------------------------------- ----------------
------------------------------------------------------- ----------------


For Canadian residents, approximately 20% of distributions to Unitholders will be tax-deferred in 2005 and 80% will be taxable as other income, as high commodity prices have resulted in record cash flows.

Recognizing the cyclical nature of our industry, we caution that significant changes in production rates, commodity prices, interest rates or foreign exchange rates (positive or negative) will result in adjustments to the distribution level. Freehold is particularly vulnerable to swings in the light/heavy oil price differential, as approximately 40% of our total boe production is heavy oil. An analysis of the potential impact of key variables on distributable income is provided on page 34 of the Trust's 2004 annual report to Unitholders.



Consolidated Balance Sheets

($000s) June 30, 2005 December 31, 2004
------------------------------------------------------------------------
(unaudited)
Assets
Current assets:
Cash $ 215 $ 66
Accounts receivable 21,707 12,797
------------------------------------------------------------------------
21,922 12,863
Reclamation fund 1,787 1,646
Petroleum and natural gas interests,
net of accumulated depletion and
depreciation of $200,245
(2004 - $180,919) 528,201 193,492
------------------------------------------------------------------------
$ 551,910 $ 208,001
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Unitholders' Equity
Current liabilities:
Distributions payable to
Unitholders $ 5,875 $ 3,785
Accounts payable and accrued
liabilities 4,593 4,950
------------------------------------------------------------------------
10,468 8,735
Asset retirement obligation (note 5) 4,027 3,937
Long-term debt (note 3) 120,000 27,000
Future income tax liability 3,507 3,507

Unitholders' equity:
Unitholders' capital (note 4) 558,713 298,936
Accumulated earnings 184,326 164,100
Accumulated distributions (329,131) (298,214)
------------------------------------------------------------------------
413,908 164,822
------------------------------------------------------------------------
$ 551,910 $ 208,001
------------------------------------------------------------------------
------------------------------------------------------------------------


Consolidated Statements of Income and Accumulated Earnings

Three Months Ended Six Months Ended
(unaudited) June 30 June 30
($000s, Except per Unit Data) 2005 2004 2005 2004
------------------------------------------------------------------------

Revenue:
Royalty income and
working interest sales $ 28,564 $ 19,878 $ 48,423 $ 37,829
Royalty expense (net of ARC) (642) (812) (1,331) (1,513)
------------------------------------------------------------------------
27,922 19,066 47,092 36,316
------------------------------------------------------------------------

Expenses:
Operating 1,685 1,480 2,939 2,907
General and administrative 943 740 2,206 1,907
Interest on long-term debt 690 147 935 318
Depletion and depreciation 12,957 6,479 19,326 12,772
Accretion of asset
retirement obligation 61 57 122 113
Management fee 480 337 842 669
------------------------------------------------------------------------
16,816 9,240 26,370 18,686
------------------------------------------------------------------------

Net income before taxes 11,106 9,826 20,722 17,630
Income and capital taxes 248 271 496 376
Future income tax provision - 40 - 65
------------------------------------------------------------------------
Net income $ 10,858 $ 9,515 $ 20,226 $ 17,189

Accumulated earnings
- beginning of period 173,468 134,882 164,100 127,208
------------------------------------------------------------------------
Accumulated earnings
- end of period $ 184,326 $ 144,397 $ 184,326 $ 144,397
------------------------------------------------------------------------
------------------------------------------------------------------------
Net income per Trust
Unit, basic and diluted $ 0.26 $ 0.30 $ 0.55 $ 0.55
------------------------------------------------------------------------
------------------------------------------------------------------------


Consolidated Statements of Cash Flows

Three Months Ended Six Months Ended
(unaudited) June 30 June 30
($000s) 2005 2004 2005 2004
------------------------------------------------------------------------

Cash provided by (used in):
Operating:
Net income $ 10,858 $ 9,515 $ 20,226 $ 17,189
Items not involving cash:
Depletion and depreciation 12,957 6,479 19,326 12,772
Future income tax provision - 40 - 65
Accretion of asset
retirement obligation 61 57 122 113
Trust Units issued in lieu
of management fee 480 337 842 669
Expenditures on reclamation (12) (21) (69) (26)
------------------------------------------------------------------------
Funds generated from
operations 24,344 16,407 40,447 30,782
Changes in non-cash
working capital (7,301) (1,235) (9,267) (2,984)
------------------------------------------------------------------------
17,043 15,172 31,180 27,798
Financing:
Issue of Trust Units, net
of issue costs 258,935 - 258,935 -
Long-term debt 93,000 (1,000) 93,000 (1,000)
Distributions paid (15,896) (12,590) (28,828) (24,228)
------------------------------------------------------------------------
336,039 (13,590) 323,107 (25,228)
Investing:
Property and royalty
acquisitions (351,705) (330) (351,705) (330)
Development expenditures (1,215) (710) (2,292) (1,650)
Increase in reclamation fund (93) (82) (141) (181)
------------------------------------------------------------------------
(353,013) (1,122) (354,138) (2,161)
------------------------------------------------------------------------
Increase in cash 69 460 149 409
Cash, beginning of period 146 6 66 57
------------------------------------------------------------------------
Cash, end of period $ 215 $ 466 $ 215 $ 466
------------------------------------------------------------------------
------------------------------------------------------------------------


Notes to Interim Consolidated Financial Statements

For the period ended June 30, 2005

1. SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of Freehold Royalty Trust ("Freehold") have been prepared by management in accordance with Canadian generally accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2004, unless otherwise identified. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Freehold's annual report for the year ended December 31, 2004.

2. BUSINESS COMBINATION

On May 10, 2005, Freehold closed the acquisition of Petrovera Resources, a general partnership which owns certain royalty, mineral and working interests. The acquisition cost of $351.7 million (net of adjustments) was funded partially with a concurrent bought-deal equity financing consisting of 13.5 million Trust Units at $15.55 per Trust Unit and a private placement to the vendor of 3.9 million Trust Units at $15.55 per Trust Unit for net proceeds of $258.9 million. The remaining cost of $92.8 million was financed utilizing Freehold's credit facilities. The acquisition was accounted for using the purchase method of accounting with the results of operations being included from May 10, 2005.



The fair value of the acquisition costs are allocated as follows:

($000s)
------------------------------------------------------------------------
Petroleum and natural gas interests 351,705
Asset retirement obligations (19)


3. LONG-TERM DEBT

Freehold has a $150.0 million extendible revolving term credit facility, extendible annually, on which $120.0 million was drawn at June 30, 2005. In the event that the lender does not consent to an extension, the revolving credit facility will revert to a two-year, non-revolving term facility with equal quarterly principal repayments. The first quarterly payment would commence on January 1 of the year following the end of the revolving period. In addition Freehold has available a $15.0 million extendible revolving operating facility. Borrowings under the facilities bear interest at the Bank's prime lending rate, bankers' acceptance or LIBOR rates plus applicable margins, ranging from 85 to 140 basis points and standby fees. The facilities are secured with $300.0 million demand debentures over Freehold's petroleum and natural gas assets.

Cash interest paid during the six months ended June 30, 2005 was $1,109,000 (2004 - $316,000) and for the current quarter was $864,000 (2004 - $145,000).



4. UNITHOLDERS' CAPITAL

------------------------------------------------------------------------
June 30, 2005 December 31, 2004
------------------------------------------------------------------------
Units Amount Units Amount
($000s) ($000s)
------------------------------------------------------------------------
Balance,
beginning of
period 31,544,236 298,936 31,454,236 297,508
Issued for cash 17,363,520 270,003 - -
Less: Issue
expenses - (11,068) - -
Issued in lieu
of management fee 52,517 842 90,000 1,428
------------------------------------------------------------------------
Balance, end of
period 48,960,273 558,713 31,544,236 298,936
------------------------------------------------------------------------
------------------------------------------------------------------------


The weighted average number of Trust Units outstanding for the six months ended June 30, 2005 was 36,544,253 (2004 - 31,465,733 and for the current quarter was 41,489,077 (2004 - 31,476,983).

5. ASSET RETIREMENT OBLIGATION

Freehold has no asset retirement obligations (ARO) on its royalty income properties. Freehold's ARO results from its responsibility to abandon and reclaim its net share of all working interest properties. The net present value of Freehold's total ARO is estimated to be $3.9 million, with the undiscounted value being $9.8 million. Payments to settle the obligations are expected to occur continuously over the next 50 years, with the majority of obligations being over 15 years away. A credit adjusted risk free rate of 6.25% was used to calculate the present value of the ARO.



------------------------------------------------------------------------
------------------------------------------------------------------------
June 30, December 31,
($000s) 2005 2004
------------------------------------------------------------------------
Balance, beginning of period $ 3,937 $ 3,606
Liabilities incurred 18 156
Liabilities added upon acquisition 19 -
Liabilities settled (69) (57)
Accretion expense 122 232
------------------------------------------------------------------------
Balance, end of period $ 4,027 $ 3,937
------------------------------------------------------------------------
------------------------------------------------------------------------


6. RELATED PARTY TRANSACTIONS

For the quarter, Freehold issued 30,017 Trust Units in payment for the management fee to Rife Resources Management Ltd. ("the Manager"). The total for the six months ended June 30, 2005 was 52,517 Trust Units.

For the six months ended June 30, 2005, the Manager charged the Trust $1,543,000 in general and administrative costs. At June 30, 2005, there was $470,000 in accounts payable relating to these costs. As well, the Manager earns a fee of 1.5% of the purchase price of oil and gas properties acquired by Freehold, with fees being $5,304,000 for the six months ended June 30, 2005.

7. COMPARATIVE FIGURES

Certain comparative figures have been restated to conform to the current year's financial statement presentation.



8. DISTRIBUTIONS TO UNITHOLDERS

------------------------------------------------------------------------
(unaudited) Three Months Ended Six Months Ended
($000s, Except June 30 June 30
per Unit Data) 2005 2004 2005 2004
------------------------------------------------------------------------

Funds generated
from operations $ 24,344 $ 16,407 $ 40,447 $ 30,782
Net reclamation
fund contribution (93) (82) (141) (181)
Provision for
capital expenditures (650) (650) (2,300) (1,650)
Debt additions
(repayment) 93,000 (1,000) 93,000 (1,000)
Proceeds from
Trust Unit issuance 258,935 - 258,935 -
Property and royalty
acquisitions (351,705) (330) (351,705) (330)
Changes in working
capital (5,850) (1,752) (7,319) (3,388)
------------------------------------------------------------------------
Distributions
to Unitholders 17,981 12,593 30,917 24,233
Accumulated
distributions,
beginning of period 311,150 255,364 298,214 243,724
------------------------------------------------------------------------
Accumulated
distributions -
end of period $ 329,131 $ 267,957 $ 329,131 $ 267,957
------------------------------------------------------------------------
------------------------------------------------------------------------
Distributions
per Trust Unit $ 0.41 $ 0.40 $ 0.82 $ 0.77
Accumulated
distributions
per Trust Unit,
beginning of period 10.69 8.92 10.28 8.55
------------------------------------------------------------------------
Accumulated
distributions
per Trust Unit,
end of period $ 11.10 $ 9.32 $ 11.10 $ 9.32
------------------------------------------------------------------------
------------------------------------------------------------------------


Contact Information

  • Freehold Royalty Trust
    David Sandmeyer
    President & CEO
    (403) 221-0848
    or
    Freehold Royalty Trust
    Joe Holowisky
    Vice-President, Finance & CFO
    (403) 221-0855
    or
    Freehold Royalty Trust
    Karen Taylor
    Manager, Investor Relations
    (403) 221-0891
    or
    Freehold Royalty Trust
    (403) 221-0802 or toll free in Canada/U.S. 1-888-257-1873
    (403) 221-0888 (FAX)
    E-mail: ir@freeholdtrust.com
    Website: www.freeholdtrust.com