Freehold Royalty Trust

Freehold Royalty Trust

February 27, 2008 18:02 ET

Freehold Royalty Trust Announces 2007 Fourth Quarter and Year End Results

CALGARY, ALBERTA--(Marketwire - Feb. 27, 2008) - Freehold Royalty Trust (Freehold or the Trust) (TSX:FRU.UN) today announced fourth quarter and full year results for the period ended December 31, 2007.


- Revenue was $40.5 million, up 26% from the fourth quarter of 2006.

- Net income rose 100% to $19.1 million ($0.39 per Trust Unit) including a future income tax recovery of $5.9 million.

- Funds generated from operations increased 19% to $32.6 million ($0.66 per Trust Unit).

- Distributions declared in the fourth quarter amounted to $0.57 per Trust Unit, including a $0.12 additional payment on December 15, 2007 due to increased income in 2007.

- Production averaged 8,591 barrels of oil equivalent (boe) per day, up 3% quarter over quarter.

- Price realizations averaged $50.57 per boe, 22% higher than the fourth quarter a year ago.

- Operating netback was $46.47 per boe, up 20% from last year.

- Land holdings increased 15% to 2.4 million gross acres, including 589,099 gross acres of undeveloped land independently valued at $30.3 million.

- Net reserve additions of approximately 3.1 million boe replaced 100% of annual production at an average cost of $32.15 per boe.

- Proved plus probable net reserves remained level year over year at approximately 28.0 million boe.

- At December 31, 2007, the present value of our net proved plus probable oil and gas reserves, discounted at 10% and before income taxes, was $711.6 million, contributing to a net asset value of $11.99 per Trust Unit.

Results at a Glance Three Months Ended Year Ended
December 31 December 31
------------------------- --------------------------
2007 2006 Change 2007 2006 Change
------------------------------------------------ --------------------------
Financial ($000s,
except as noted)
Gross revenue 40,511 32,214 26% 152,184 143,067 6%
Net income (loss)
($000s) 19,067 9,545 100% (1,192) 45,181 -103%
Per Trust Unit,
basic and diluted($) 0.39 0.19 105% (0.02) 0.92 -102%
Funds generated from
operations ($000s) 32,591 27,394 19% 121,008 119,849 1%
Per Trust Unit($) 0.66 0.56 18% 2.46 2.44 1%
Capital expenditures 3,901 3,766 4% 12,167 11,446 6%
Property and royalty
acquisitions (net) 26 - - 90,456 5,382 1581%
declared 28,096 23,594 19% 94,545 103,100 -8%
Per Trust Unit($)(1) 0.57 0.48 19% 1.92 2.10 -9%
Long-term debt,
period end 178,000 100,000 78% 178,000 100,000 78%
Unitholders' equity,
period end 251,106 344,448 -27% 251,106 344,448 -27%
Trust Units (000s)(2) 49,282 49,139 - 49,228 49,086 -
Average daily
production (boe/d) 8,591 8,313 3% 8,484 8,412 1%
Average price
realizations ($/boe) 50.57 41.44 22% 48.63 46.07 6%
Operating netback
($/boe) 46.47 38.57 20% 43.54 42.64 2%
(1) Based on the number of Trust Units issued and outstanding at each record
(2) Weighted average number of Trust Units outstanding during the period,

The next regular monthly distribution of $0.15 per Trust Unit will be paid on April 15, 2008, to Unitholders of record on March 31, 2008 (ex-distribution date March 27, 2008). Including the April 15, 2008 payment, 12-month trailing cash distributions total $1.92 per Trust Unit.

I am pleased to report another quarter of solid performance for the Trust. In the fourth quarter of 2007, oil prices demonstrated unparalleled strength as global supply struggled to keep pace with demand growth. However, the Canadian dollar also strengthened significantly, reducing Canadian dollar realizations. Natural gas prices remained under pressure due to North American supply and demand imbalances. Within this environment, our operating netbacks remained strong, at $46.47 per barrel of oil equivalent (boe), compared with $38.57 per boe in the fourth quarter of 2006, while production rose 3% quarter over quarter. On a per Trust Unit basis, funds generated from operations rose 19% and net income increased 100%.

These strong quarterly results contributed to record cash flow for 2007 as funds generated from operations reached $121.0 million ($2.46 per Trust Unit). Net income for the year was reduced to a loss of $1.2 million ($0.02 per Trust Unit) reflecting a $47.6 million future income tax expense related to the trust taxation legislation that takes effect in 2011. This provision was a non-cash expense relating to temporary differences between accounting versus tax rates and had no impact on our cash flows or our cash available for distribution.

Distributions in the fourth quarter totalled $0.57 per Trust Unit ($1.92 for the year), including an additional payment of $0.12 per Trust Unit paid on December 15, 2007. The additional payment was due to increased income in 2007 as a result of high oil prices and higher production volumes in the fourth quarter stemming from royalty interest properties acquired during the third quarter.


Our 2007 capital and acquisition program was successful in replacing 100% of our production for the year. We spent $12.2 million on development activities, adding 0.6 million boe of net proved plus probable reserves at an average cost of $14.38 per boe. In addition, we spent $90.5 million on royalty acquisitions, acquiring 2.5 million boe of net proved plus probable reserves at an average cost of $36.57 per boe. These royalty assets have a high value because they are unencumbered by capital or operating costs. Overall, these activities contributed to a three-year average recycle ratio of 1.7.

At December 31, 2007, our land holdings encompassed nearly 2.4 million gross acres, up 15% from the previous year. Our undeveloped land, totalling 589,099 gross acres, was independently valued at $30.3 million. The present value of our net proved plus probable oil and gas reserves, discounted at 10%, was $711.6 million, contributing to a net asset value of $11.99 per Trust Unit.

Since formation of the Trust in late 1996, operators leasing our royalty lands have drilled a total of 6,187 wells - activity that has helped to offset the depletion of our production and reserves - at no cost to us. This "free drilling" gives us the freedom to maintain a disciplined valuation approach to ensure that our acquisitions are accretive to present and future Unitholders.


Although drilling on our royalty lands declined 8% year over year, we fared better than industry in general, which experienced an overall 19% decline in drilling activity in 2007. And while drilling in unitized areas was down significantly, the decline in non-unitized drilling was a modest 5%. Considering the current industry slowdown, we are very encouraged by the tangible evidence of ongoing development potential on our royalty lands. There are currently 92 (4.1 equivalent net) licensed drilling locations on our royalty lands, compared with 119 (6.1 equivalent net) locations at this time last year. We are also seeing an increase in uphole recompletions in wells that have produced out in lower formations. We count among our active lessees some of the largest oil and gas producers in the industry. These companies have chosen certain of our royalty areas as key to their operations and we believe they will continue to be active in those areas.


Our distribution remains fixed at $0.15 per month subject to quarterly review by our Board. Our distribution policy takes into consideration forecasted cash provided by operating activities, debt levels, and capital expenditures. We have a declining asset base, and ongoing development activities and acquisitions are necessary to replace production and add additional reserves. The success of these activities, along with commodity prices, are the main factors influencing the sustainability of our distributions.

As a result of acquisitions completed in the third quarter, our net debt at the end of the year was $166.8 million, equal to about 1.4 times our 2007 cash flow from operating activities. We believe that having a strong balance sheet provides maximum flexibility for future transactions. Therefore, we plan to reduce debt as we are able with cash available after funding monthly distributions, reclamation fund contributions, and capital expenditures. We plan to invest $10.6 million on development of our working interest properties in 2008, and with our recent acquisitions also contributing to our results, we expect production this year to average 8,200 boe per day.

Continued geopolitical uncertainty and strong global demand growth are expected to keep crude oil prices high, while storage levels and weather will be the key demand factors for natural gas prices.

In western Canada, drilling activity is anticipated to decline further in the short term in response to continued weakness in natural gas markets, high operating costs, and the strength of the Canadian dollar. As well, the new Alberta Crown royalty structure that takes effect next year could significantly change the economics of future exploration and development activities in the province. Already, a number of large exploration and production companies have announced reduced capital spending plans and scaled back drilling programs, especially in gas-prone areas of Alberta.

Most of Freehold's gas-prone lands are located in south-eastern Alberta and south-western Saskatchewan, where productivity per well is low, relative to other areas of the Western Canada Sedimentary Basin. In these areas, natural gas pricing has the most influence on producers' drilling decisions. A dramatic, prolonged reduction in industry drilling would likely be reflected on our royalty lands, but it is not possible to predict what the potential impact might be on Freehold's future production and reserves.

The Alberta Crown royalty changes will have little impact on Freehold's current producing wells, given the mature nature of most of our producing assets. As well, the new royalty rates will only apply to our working interest production on Alberta Crown lands, which is about 900 boe per day or 11% of our total production. Our royalty interest production in Alberta is not affected.

In October 2006, the federal government unexpectedly announced its plan to impose a tax on distributions from publicly-traded, specified income flow-through (SIFT) entities beginning January 1, 2011. In response to the SIFT tax changes, we continue to evaluate the options available to us, but in the interim we plan to retain the flow-through advantage of our trust structure unless there is a compelling reason for a faster transition to an alternative structure.

On February 26, 2008, the Minister of Finance delivered the federal government's 2008 budget. Rather than a flat provincial rate of 13% as previously announced, the budget proposes that the provincial component of the SIFT tax will be based on actual provincial corporate tax rates under the formula giving equal weight to province-by-province payrolls and revenues. This is a positive development for Alberta-based income trusts.

We remain committed to maximizing sustainable cash distributions over the long term by actively managing our large portfolio of oil and gas royalty interests, successfully developing our working interest properties to sustain production and extend reserve life, and acquiring appropriate assets to provide long-term growth in the value of the Trust. Going forward, we will continue to focus on the successful execution of this strategy.

On January 31, 2008, Tullio Cedraschi retired as President and CEO of the CN Investment Division. His successor, Russell J. Hiscock, will become one of the two Manager-appointed directors of Freehold at our Annual Meeting on May 7, 2008 to replace Mr. Cedraschi. We look forward to welcoming Mr. Hiscock as a director. The Board is pleased to announce that Mr. Cedraschi has agreed to stand for election at Freehold's Annual Meeting as an independent director.


Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2007. The evaluation was conducted in accordance with National Instrument 51-101 (NI 51-101), with reserves calculated on a net basis (our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands). Our Reserves Committee met with Trimble to review the findings and procedures, and the reserves report has been accepted by our Board. A summary of reserves, on a before-tax basis, is provided below. Complete NI 51-101 reserves disclosure, including after-tax reserve values, reserves by major property, and abandonment costs, will be included in our annual information form (AIF), which will be filed in March 2008.

Acquisitions and extensions replaced 100% of 2007 production, leaving net proved plus probable reserves unchanged at approximately 28 million boe. In 2007, reserves were assigned to 23,590 wells. Two thirds of our reserves are in the proved category, and 99% of our proved reserves are producing, which is high by industry standards. On a boe basis, our reserves profile is 37% natural gas, 5% natural gas liquids (NGL), 22% light and medium oil, and 36% heavy oil. Our reserve life index is 9.5 years, compared with 9.6 years at the end of 2006.

Under National Instrument 51-101, royalty interests cannot be included under gross reserves. Freehold is unique in that the majority of our assets are royalty interests, and this causes our gross reserves to be lower than our net reserves. This anomaly hinders an investor's ability to compare our reserves with others in our industry. We believe the most appropriate measure of reserves for Freehold is net reserves.

Oil and Gas
Reserves as Light and
at December Medium Natural Natural Gas Oil
31, 2007 (1) Crude Oil Heavy Oil Gas Liquids Equivalent
Gross Net Gross Net Gross Net Gross Net Gross Net
Reserves (2) (3) (2) (3) (2) (3) (2) (3) (2) (3)
Category (Mbbl)(Mbbl)(Mbbl) (Mbbl)(MMcf) (MMcf)(Mbbl)(Mbbl)(Mboe) (Mboe)
------------------------ ------------ ------------- ---------- ------------
producing 2,074 4,230 1,350 6,238 5,638 40,438 266 937 4,629 18,144
non-producing 0 0 0 0 104 79 3 2 20 15
Undeveloped 0 0 0 135 0 145 0 0 0 159
------------------------ ------------ ------------- ---------- ------------
------------------------ ------------ ------------- ---------- ------------
Total proved 2,074 4,230 1,350 6,373 5,742 40,662 269 939 4,649 18,318
Probable 736 1,899 651 3,837 2,969 20,719 134 455 2,016 9,645
------------------------ ------------ ------------- ---------- ------------
------------------------ ------------ ------------- ---------- ------------
Total proved
probable 2,810 6,129 2,001 10,210 8,711 61,381 403 1,394 6,665 27,963
------------------------ ------------ ------------- ---------- ------------
(1) Columns may not add due to rounding

(2) Gross reserves are our share of working interest properties before
deduction of royalties payable to others. Gross reserves exclude royalty

(3) Net reserves are our share of working interest properties minus
royalties payable to others, plus royalties receivable on our royalty

Total Future Net Revenue (undiscounted)
as at December 31, 2007 Reserves Category
Forecast Prices and Costs Proved Plus
($000s) Proved Probable
Royalty Income 797,803 1,320,480
Revenue from Working Interest Properties 356,533 528,280
Royalty expense on Working Interest Properties (22,618) (39,339)
Operating costs (109,442) (161,334)
Development costs (576) (4,271)
Well abandonment and reclamation costs (7,267) (8,506)
Future net revenue before income taxes 1,014,433 1,635,310
Future income taxes (201,283) (358,076)
Future net revenue after income taxes 813,150 1,277,234

Proved Total Proved Plus
Reserve Life Index (1) Producing Proved Probable
Net reserves (Mboe) 18,144 18,318 27,963
Net production (Mboe) 2,560 2,587 2,932
Reserve life index (years) 7.1 7.1 9.5

(1) Calculated by dividing the Trimble forecast of 2008 net production into
the remaining net reserves.

Net Present Value (1) (2)
Before tax, discounted at
($000s) 0% 5% 10% 15%
Developed producing 1,004,362 675,806 523,299 434,964
Developed non-producing 439 386 343 307
Undeveloped 9,632 7,013 5,713 4,936
Total proved 1,014,433 683,205 529,355 440,207
Probable 620,878 290,017 182,269 132,936
Proved plus probable 1,635,311 973,222 711,624 573,143

(1) Columns may not add due to rounding.

(2) Forecast prices and costs, before tax. Based on the December 31, 2007
escalated oil and gas price forecasts by an independent qualified
reserves evaluator.

Reconciliation of Proved Plus
Oil and Gas Reserves (1) Proved Probable Probable
(Mboe) Gross(2) Net(3) Gross(2) Net(3) Gross(2) Net(3)
------------------------------------------ ---------------- ----------------
December 31, 2006 5,275 18,722 1,867 9,290 7,142 28,012
------------------------------------------ ---------------- ----------------
Extensions 81 329 86 288 167 616
Improved recovery - - - - - -
Technical revisions 124 684 71 (681) 195 3
Discoveries - - - - - -
Acquisitions - 1,696 - 778 - 2,473
Dispositions - - - - - -
Economic factors 32 30 18 15 49 45
Production (4) (862) (3,142) (26) (44) (888) (3,186)
------------------------------------------ ---------------- ----------------
December 31, 2007 4,650 18,318 2016 9,646 6,665 27,963
------------------------------------------ ---------------- ----------------
Change over prior year (625) (404) 149 356 (477) (49)
------------------------------------------ ---------------- ----------------
(1) Numbers may not add due to rounding.

(2) Gross reserves are our share of working interest properties before
deduction of royalties payable to others. Gross reserves exclude royalty

(3) Net reserves are our share of working interest properties minus
royalties payable to others, plus royalties receivable on our royalty

(4) Production estimated by Trimble.

Analysis of Development and
Acquisition Costs, Net Three-Year
Reserves 2007 2006 2005 Results
Development expenditures ($000s) 12,167 11,446 7,982 31,595
Change in future development
capital estimates ($000s) (3,305) (2,549) 235 (5,619)
Net reserve additions by
development (Mboe) 616 1,146 945 2,708
Development costs ($/boe) (1) 14.38 7.76 8.70 9.59
Acquisition expenditures ($000s) 90,456 5,382 351,705 447,543
Net reserve additions by
acquisition (Mboe) 2,473 376 12,889 15,738
Acquisition costs ($/boe) 36.57 14.33 27.29 28.44
Total expenditures ($000s) 102,623 16,828 359,687 479,138
Change in future development
capital estimates ($000s) (3,305) (2,549) 235 (5,619)
Net reserve additions (Mboe) 3,090 1,522 13,834 18,445
Development and acquisition costs
($/boe) 32.15 9.38 26.02 25.67

(1) Development expenditures plus change in future capital, divided by
reserves added.

Recycle Statistics, Net Reserves Three-Year
($ per boe, except as noted) 2007 2006 2005 Results
Operating netback (1) (4) 43.63 42.64 45.49 43.87
Development and acquisition
costs (2) (4) 32.15 9.38 26.02 25.67
Recycle ratio (times) (3) 1.4 4.5 1.8 1.7

(1) Total revenue, less operating costs and royalty expenses (net of Alberta
Royalty Credit in 2005 and 2006).

(2) Development expenditures, plus change in future capital, plus
acquisition costs; divided by net reserves added through development and
acquisition activities.

(3) Operating netback divided by the average cost of acquiring and
developing new reserves.

(4) Operating netback is based on gross production, while development and
acquisition costs are based on net reserves.


At December 31, 2007, our land holdings encompassed approximately 2.4 million gross acres, more than 90% of which are royalty interests.

Summary of Land Holdings December 31, 2007 December 31, 2006
----------------------- -----------------------
(gross acres) (1) Total Undeveloped Total Undeveloped
Mineral title lands (2) 549,758 160,034 550,636 164,199
Gross overriding royalty
(GORR) lands (3) 1,526,878 360,832 1,218,700 365,381
Royalty assumption
lands (4) 96,072 19,648 96,082 19,620
Total royalty lands 2,172,708 540,514 1,865,418 549,200
Working interest
properties 207,428 48,585 203,952 49,035
Total land holdings 2,380,136 589,099 2,069,370 598,235

(1) Gross acres represents the total number of acres in which we have an

(2) The royalties received from the sale of oil, natural gas and potash
produced from the leased mineral title lands are determined by the
individual lease agreements. Mineral title lands are held in perpetuity.

(3) Gross overriding royalty lands consist of properties owned by a number
of third party oil and gas companies in respect of which varying
royalties or net profits interests have been reserved to Freehold.

(4) Mineral title properties owned by a number of third party oil and gas
companies in respect of which gross overriding royalties varying from
4.7% to 6.5% have been reserved to Freehold.

Acquisitions during 2007 increased land holdings by 15%. Approximately 63%
of our land is in Alberta, 21% is in Saskatchewan, 12% is in Ontario, and 3%
is in British Columbia.

Land Holdings by Province As at December 31
(gross acres) (1) 2007 2006 Change
------------------------------------------------------- ---------- -------
Alberta 1,488,098 1,218,097 22%
Saskatchewan 505,223 464,977 9%
Ontario 296,109 296,109 -
British Columbia 82,423 81,904 1%
Manitoba 8,283 8,283 -
Total 2,380,136 2,069,370 15%

(1) Gross acres represents the total number of acres in which we have an


At December 31, 2007, the present value of our net proved plus probable oil and gas reserves, discounted at 10%, before tax, was $711.6 million, up from $636.3 million one year ago. The improvement came from reserve additions of 3.1 million boe during the year and higher forecast prices at the end of 2007. Our net asset value was $11.99 per Trust Unit, up from $11.74 at the end of 2007. In addition to the increase in the value of oil and gas reserves, the major changes year over year were a $78 million increase in bank debt, a $10.9 million increase in the value of undeveloped land, and a $3.8 million increase in the value of potash reserves.


Net Asset Value
as at December 31, 2007(1) Before tax, discounted at
($000s, except unit data) 0% 5% 10% 15%
Present value of oil and
gas reserves (2) 1,635,310 973,222 711,624 573,143
Present value of potash
reserves (3) 62,261 25,648 14,317 9,753
Undeveloped land (4) 30,252 30,252 30,252 30,252
Reclamation fund 1,788 1,788 1,788 1,788
Working capital 11,219 11,219 11,219 11,219
Bank debt (178,000) (178,000) (178,000) (178,000)
Net asset value 1,562,830 864,129 591,200 448,155
Trust Units outstanding 49,316,813 49,316,813 49,316,813 49,316,813
Net asset value per
Trust Unit 31.69 17.52 11.99 9.09

(1) Columns may not add due to rounding.

(2) Based on net proved plus probable reserves evaluated by Trimble.

(3) Potash reserves, evaluated by Rife Resources Ltd., are not subject to NI

(4) Evaluated by Seaton-Jordan & Associates Ltd., effective December 31,


Freehold's fourth quarter report, including unaudited financial statements and Management's Discussion & Analysis, is being filed today with Canadian securities regulators and will be available on SEDAR at or on our website.


This news release offers our assessment of Freehold's future plans and operations as at February 27, 2008, 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, taxation, royalties, regulation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, and our ability to access sufficient capital from internal and external sources. Risks are described in more detail in our Annual Information Form, which is available on our website. 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. Except as required by law, we do not undertake to update these forward-looking statements.


To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the international standard 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 the boe ratio is useful for comparative measures and observing trends, it may not accurately reflect individual product values and may be misleading if used in isolation.


Within this news release, references are made to terms commonly used as key performance indicators in the oil and gas industry. We believe that operating netback and funds generated from operations are useful supplemental measures to analyze operating performance, leverage, and liquidity. However, these terms do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

Operating netback, which is calculated as average unit sales price less royalties and operating expenses, represents the cash margin for product sold, calculated on a per boe basis. Funds generated from operations is a key measure of our ability to generate cash, finance operations, and pay monthly distributions. Funds generated from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash provided by operating activities, net income or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds generated from operations throughout this report are based on cash provided by operating activities before changes in non-cash working capital as per the Statement of Cash Flows. Funds generated from operations per Trust Unit is calculated based on the weighted average number of Trust Units outstanding consistent with the calculation of net income per Trust Unit.

In addition, we refer to various per boe figures, such as revenues and costs, which are also considered non-GAAP measures but provide meaningful information on our operational performance. We derive per boe figures by dividing the relevant revenue or cost figure by the total volume of oil and gas production during the period, with natural gas converted to equivalent barrels of oil as described above.

Contact Information

  • Freehold Royalty Trust
    David Sandmeyer
    President and CEO
    (403) 221-0848
    Freehold Royalty Trust
    Joe Holowisky
    Vice-President, Finance and CFO
    (403) 221-0855
    Freehold Royalty Trust
    Karen Taylor
    Manager, Investor Relations
    (403) 221-0891
    Freehold Royalty Trust
    (403) 221-0802
    Toll free in Canada/U.S. 1-888-257-1873
    (403) 221-0888 (FAX)