Contact Information: Freehold Royalties Ltd. Karen Taylor Manager, Investor Relations and Corporate Secretary 403.221.0891 or tf. 1.888.257.1873 403.221.0888 (FAX) ktaylor@rife.com www.freeholdroyalties.com
Freehold Royalties Ltd. Announces 2010 Fourth Quarter Results and Year-end Reserves
| Source: Freehold Royalties Ltd
CALGARY, ALBERTA--(Marketwire - March 2, 2011) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced fourth quarter results and year-end reserves for the period ended December 31, 2010.
/T/
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RESULTS AT A GLANCE Three Months Ended Twelve Months Ended
December 31 December 31
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Financial ($000s, except as
noted) 2010 2009 Change 2010 2009 Change
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Gross revenue 36,525 35,167 4% 138,155 119,965 15%
Net income 10,419 14,721 -29% 36,273 31,741 14%
Per share, basic and diluted
($) (1) 0.18 0.29 -38% 0.62 0.63 -2%
Cash provided by operating
activities 28,015 25,937 8% 110,693 95,659 16%
Per share ($) (1) 0.48 0.50 -4% 1.90 1.91 -1%
Funds generated from
operations (2) 28,218 30,444 -7% 106,971 95,085 13%
Per share ($) (1) 0.48 0.59 -19% 1.83 1.90 -4%
Capital expenditures 4,664 4,435 5% 18,054 15,491 17%
Property and royalty
acquisitions (net) 283 9,539 -97% 38,600 9,539 305%
Distributions declared 24,797 23,937 4% 98,115 70,480 39%
Per share ($) (1) (3) 0.42 0.46 -9% 1.68 1.40 20%
Long-term debt, period end 65,000 45,000 44% 65,000 45,000 44%
Shareholders' equity, period
end 266,166 298,972 -11% 266,166 298,972 -11%
Shares outstanding, period
end (000s) 59,181 57,503 3% 59,181 57,503 3%
Average shares outstanding
(000s) (4) 58,972 51,483 15% 58,334 50,000 17%
Operating
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Average daily production
(boe/d) (5) 7,972 7,402 8% 7,615 7,302 4%
Average price realizations
($/boe) (5) 48.80 51.09 -4% 48.74 44.00 11%
Operating netback ($/boe) (2)
(5) 44.57 45.66 -2% 44.08 39.61 11%
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(1) Prior to conversion to a corporation on December 31, 2010, Freehold had
trust units outstanding instead of shares.
(2) See Non-GAAP Measures.
(3) Based on the number of shares issued and outstanding at each record
date.
(4) Weighted average number of shares outstanding during the period, basic.
(5) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).
/T/
Our results for the three and twelve months ended December 31 reflect higher revenues due to improved oil prices and higher royalty production volumes, partly offset by lower natural gas prices. Freehold's production, which remains unhedged, is oil weighted and shareholders continue to benefit from the relative strength of oil prices.
Corporate Conversion
The highlight of the quarter was our conversion to a corporation on December 31, 2010, after receiving unitholder approval on December 10. All outstanding trust units were exchanged for an equal number of common shares. We are now Freehold Royalties Ltd., and as a corporation, we pay monthly dividends instead of distributions. We dropped the ".UN" from our stock symbol and now trade on the Toronto Stock Exchange under the symbol FRU. Freehold's business activities and management did not change as a result of converting to a corporation. Our assets and strategies have delivered excellent returns over the past fourteen years, and true to our name, we intend to maintain our focus on oil and gas royalties.
Commodity Price Update
The global economy, emerging from the worst recession in decades, grew almost 5% in 2010. Rising demand for commodities led to a 29% increase in WTI crude oil prices. However, weakness in the U.S. dollar and wider price differentials for heavy oil in the last half of the year muted the effect of this increase as the benchmark Western Canada Select rose only 15% year-over-year. The pipeline issues that caused heavy oil differentials to soar should not have a permanent affect on pricing, and we believe markets for heavy oil remain positive due to continued strong refinery demand for this product type.
Natural gas prices have not fared so well, as supply continues to outstrip demand in North America. At the peak of the winter heating season, natural gas storage levels remain above the five-year average. Increasing production, due to enhanced drilling and completion techniques, is by far the largest contributor, and while natural gas is an environmentally-friendly, low cost source of fuel, abundant supply combined with modest demand growth continues to depress prices.
Land and Reserves Update
Our land holdings, 2.8 million gross acres at year-end, grew 17% from the prior year as a result of a royalty acquisition in 2010. The value of our undeveloped land also grew to $96.8 million, due to higher average land sale prices during 2010. Most of the increase was attributed to our exposure to the Bakken trend in Southeast Saskatchewan, where we own significant mineral title lands.
Virtually all our original royalty lands were leased to third parties. Over the years, our unleased mineral title acreage has grown - through lease expiries, surrenders, defaults, and acquisitions. We now have about 100,000 unleased acres, two-thirds of which are in Southeast Saskatchewan. We are proactively working to crystallize the value of this undeveloped acreage through selective lease-outs to industry partners and by investing our own capital in the development of these lands.
Our net proved plus probable reserves at year-end totalled 23.6 million barrels of oil equivalent (MMboe), with royalty interests accounting for 79%. We added 2.3 MMboe before 2010 production of 2.8 MMboe, replacing 84% of 2010 production at an all-in finding, development and acquisition (FD&A) cost of $24.63 per boe (including changes in future development capital), contributing to a three-year average FD&A cost of $21.45 per boe. These activities resulted in a recycle ratio of 1.8 times the capital invested, and a three-year average recycle ratio of 2.3 times.
Acquisitions contributed 59% of the net reserve additions for 2010, "free drilling" on our royalty lands accounted for 17%, and development activities on our working interest properties provided 24%.
Drilling Activity
The Canadian Association of Oilwell Drilling Contractors (CAODC) reported a total of 13,566 wells drilled in western Canada (on a "wells completed" basis) in 2010, with a significant shift towards oil-focused investment. The CAODC's 2011 forecast (issued in October 2010) projects similar activity levels for 2011, and assumes little improvement in natural gas prices. Industry activity in 2010 was more active than the prior year and this was reflected on our lands as well.
Horizontal drilling technology is increasingly being used to access tight reservoirs and other resource plays. Across our land base, more than half of the wells drilled in 2010 were horizontal wells (38% on our royalty lands). Given our extensive land holdings, almost 2.8 million gross acres spanning much of the Western Canada Sedimentary Basin, we are well positioned to participate in many of the emerging resource plays. The most promising opportunities for us are in areas south of the North Saskatchewan River in Alberta, and in Southeast Saskatchewan where we own significant mineral title lands.
On Freehold's royalty lands, non-unitized drilling was up 12% in the quarter and up 63% for the year largely due to development activity at Hayter and in Southeast Saskatchewan, where we also have working interests. As at December 31, 2010, there were 110 (3.2 equivalent net) licensed drilling locations on our royalty lands compared with 86 (2.6 equivalent net) at the end of 2009. Continued well licence activity is a positive indicator of future activity on our lands.
In the fourth quarter, our working interest activities were directed entirely to oil development. We drilled seven (3.1 net) wells in Southeast Saskatchewan and two (0.5 net) wells in Provost, Alberta. The Saskatchewan wells were all horizontal wells with multi stage fracture completions and included two (1.0 net) Bakken wells, which were completed in the first quarter of 2011. This activity had little impact on production volumes in the fourth quarter but will add to our production going forward.
2011 Plans
Our Board has approved a capital budget for 2011 of $20 million for the continued development of our working interest properties. About two-thirds of our budget will be spent in Southeast Saskatchewan, including our Bakken-prone title lands where we continue to see opportunities. In the current environment, we are also seeing some interesting acquisition opportunities. While we have not budgeted funds for acquisitions, we have $145 million of available capacity under our credit facilities to take advantage of accretive opportunities.
In 2010, our production averaged just over 7,600 boe per day. Based on our $20 million capital program, conservative estimates of drilling activity on our leased royalty lands, and normal production declines (and excluding any potential acquisitions), we expect production to decline 7% in 2011, to average approximately 7,100 boe per day for the year.
/T/
Our key operating assumptions for 2011 are outlined below.
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2011 KEY OPERATING ASSUMPTIONS Mar. 2 Nov. 10
2011 2010
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Average daily production (boe/d) 7,100 7,100
Average WTI oil price (US$/bbl) 80.00 80.00
Average exchange rate (Cdn$/US$) 0.95 0.95
Average heavy oil price differential (Cdn$/bbl) (1) (13.00) (13.00)
Average AECO natural gas price (Cdn$/Mcf) 4.25 4.25
Average operating costs ($/boe) 4.50 4.50
Average general and administrative costs ($/boe) (2) 3.50 3.40
Capital expenditures ($ millions) 20 20
Proceeds from DRIP ($ millions) (3) 27 27
Long-term debt at year end ($ millions) 50 52
Weighted average shares outstanding (millions) 60 60
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(1) The difference between the Edmonton Par and Western Canada Select crude
oil streams.
(2) Excludes share based and other compensation.
(3) Average 27% participation rate, which is subject to change.
/T/
A sensitivity analysis of the potential impact of key variables on funds generated from operations is provided below. For the purposes of the sensitivity analysis, the effect of a variation in a particular variable is calculated independently of any change in another variable. In reality, changes in one factor will contribute to changes in another, which can magnify or counteract the sensitivities. For instance, trends have shown a correlation between the movement in the foreign exchange rate of the Canadian dollar relative to the U.S. dollar and the benchmark WTI crude oil price.
/T/
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SENSITIVITY ANALYSIS
Estimated Change in
Funds Generated From Operations
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Variables Change (+/-) ($000s) ($ per share)
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WTI crude oil price US$1.00/bbl 1,700 0.03
Cdn$/US$ exchange rate US$0.01 1,400 0.02
Light/heavy oil price differential
(1) Cdn$1.00/bbl 1,600 0.03
AECO natural gas price Cdn$0.25/Mcf 1,400 0.02
Interest rate 1% 600 0.01
Oil and NGL production 100 bbls/d 2,500 0.04
Natural gas production 1,000 Mcf/d 1,500 0.02
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(1) The difference between the Edmonton Par and Western Canada Select crude
oil streams.
/T/
Recognizing the cyclical nature of our industry, we caution that significant changes (positive or negative) in commodity prices (including light/heavy oil price differentials), foreign exchange rates, or production rates will result in adjustments to the dividend rate. It is also inherently difficult to predict activity levels on our royalty lands since we do not know the future plans of the various operators. Freehold is particularly vulnerable to swings in the light/heavy oil price differential, as roughly one third of our total boe production is heavy oil.
Dividend Policy
As a corporation, our dividend policy will be similar to our distribution policy as a trust, subject to the satisfaction of liquidity and solvency tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends. Dividends will continue to be paid monthly, with the Board reviewing the dividend policy quarterly.
Under our current production, commodity price, and operating assumptions, we expect to pay a monthly dividend of $0.14 ($1.68 annually) per share in 2011. Future dividend levels will depend on the cash flow generated by Freehold's assets, which can vary depending on a number of factors, including commodity prices, production volumes, foreign exchange rates, capital expenditures, participation levels in the dividend reinvestment plan, debt service requirements, costs and taxes.
As a corporation, Freehold is subject to corporate taxation. We currently have $235 million in tax pools available to shelter income from cash taxes. As an owner of primarily royalty interests, our ability to generate additional tax pools to shelter taxable income is limited. We do not expect to pay corporate income tax on income earned in 2011; however, starting in 2012, we expect to be cash taxable at a rate of 15% to 20%, which may reduce the amount available for dividends.
The majority of our oil and natural gas production comes from mineral title lands and gross overriding royalties, which have no associated capital or operating costs; thus we have relatively low capital expenditure requirements. The strength of our royalties has allowed us to preserve a high payout ratio historically and should allow us to maintain a high dividend payout going forward.
March Dividend Announcement
The Board of Directors has declared the March dividend of $0.14 per share, which will be paid on April 15, 2011 to shareholders of record on March 31, 2011 (ex-dividend date March 29, 2011). Including the April 15 payment, our 12-month trailing cash dividends total $1.68 per share (including the distributions paid on trust units of Freehold Royalty Trust prior to conversion). The monthly dividend is fixed at $0.14 per share until further notice.
Land Update
- Our land holdings at year-end encompassed 2.8 million gross acres, up 17% from the prior year as a result of a royalty acquisition during 2010.
- Royalty interests (freehold mineral titles and gross overriding royalties) comprised 92% of our acreage.
- Our undeveloped land, totalling 0.8 million gross acres, was independently valued at $96.8 million, up from $79.4 million at year-end 2009, due to higher average land sale prices during 2010. Most of the increase was attributed to our exposure to the Bakken trend in Southeast Saskatchewan.
/T/
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Total Land Holdings Undeveloped Land
SUMMARY OF LAND HOLDINGS -----------------------------------------
(gross acres) (1) 2010 2009 2010 2009
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Mineral title lands (2) 545,147 548,198 163,117 160,232
Royalty assumption lands (3) 95,111 95,111 20,042 18,925
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Total title lands (4) 640,258 643,309 183,159 179,157
Gross overriding royalty (GORR)
lands (5) 1,930,089 1,530,160 567,769 425,760
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Total royalty lands 2,570,347 2,173,469 750,928 604,917
Working interest properties 211,232 212,413 43,186 43,445
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Total land holdings 2,781,579 2,385,882 794,114 648,362
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Total Land Holdings Undeveloped Land
LAND HOLDINGS BY PROVINCE -----------------------------------------
(gross acres) (1) 2010 2009 2010 2009
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Alberta 1,850,473 1,493,335 372,872 238,980
Saskatchewan 511,333 507,707 194,861 191,616
Ontario 288,120 295,769 193,818 199,555
British Columbia 123,493 80,788 30,639 16,164
Manitoba 8,160 8,283 1,924 2,047
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Total 2,781,579 2,385,882 794,114 648,362
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(1) Gross acres represents the total number of acres in which we have an
interest.
(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. All but approximately 100,000 gross acres
of our mineral title lands are currently leased to third parties.
(3) 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.
(4) Title lands are held in perpetuity.
(5) 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.
/T/
Reserves Update
Our oil and natural gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2010. The evaluation was conducted in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in National Instrument 51-101 (NI 51-101). 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 net 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, are included in our annual information form (AIF), which will be filed on SEDAR later this month.
The reserves data below is presented on a net basis (our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands). Freehold is unique in that the majority of our assets are royalty interests. However, under NI 51-101, royalty interests cannot be included under gross reserves. This causes our gross reserves to be lower than our net reserves and makes it difficult for investors to compare our reserves to others in our industry. We believe the most appropriate measure of reserves for Freehold is net reserves.
- Net proved plus probable reserves declined 2.1% to 23.6 million barrels of oil equivalent (MMboe), with reserves assigned to 23,969 wells. Royalty interest reserves remained level year-over-year, while working interest reserves decreased 8.3%.
- Approximately 63% of our reserves are in the proved category, and 99% of our proved reserves are producing.
- On a boe basis, our reserves profile was 39% natural gas, 34% heavy oil, 22% light and medium oil, and 5% natural gas liquids (NGL).
- Free drilling on our royalty lands added 0.4 MMboe of net proved plus probable reserve additions, development activities on our working interest properties added 0.5 MMboe, and acquisitions added 1.4 MMboe, bringing the total additions to 2.3 MMboe before 2010 production of 2.8 MMboe.
- On a proved plus probable basis, we replaced approximately 84% of 2010 production at an all-in finding, development and acquisition (FD&A) cost of $24.63 per boe (including changes in future development capital), contributing to a three-year average FD&A cost of $21.45 per boe.
- These activities resulted in a recycle ratio of 1.8 times the capital invested, and a three-year average recycle ratio of 2.3 times.
- The net asset value decreased 9.5% from the prior year. This decline was primarily related to a reduction in the long-term natural gas price outlook, and by the increased debt to acquire royalty properties in 2010.
/T/
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OIL AND GAS RESERVES
as at December 31, Light and Medium
2010 (1) Crude Oil Heavy Crude Oil Total Crude Oil
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Gross (2) Net (3) Gross (2) Net (3) Gross (2) Net (3)
Reserves Category (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
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Proved developed
producing 1,597 3,330 855 4,563 2,452 7,893
Proved developed
non-producing 71 63 - - 71 63
Proved undeveloped - - - 77 - 77
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Total proved 1,669 3,393 855 4,640 2,523 8,032
Probable 973 1,835 689 3,240 1,662 5,075
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Total proved plus
probable 2,642 5,228 1,544 7,880 4,185 13,107
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Natural
Natural Gas Gas Liquids Oil Equivalent
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Gross (2) Net (3) Gross (2) Net (3) Gross (2) Net (3)
Reserves Category (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
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Proved developed
producing 4,763 35,379 190 847 3,436 14,636
Proved developed
non-producing 58 51 7 5 88 76
Proved undeveloped - 66 - - - 88
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Total proved 4,822 35,496 197 851 3,524 14,800
Probable 2,963 19,860 118 445 2,274 8,830
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Total proved plus
probable 7,785 55,356 315 1,296 5,797 23,629
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(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
interests.
(3) Net reserves are our share of working interest properties minus
royalties payable to others, plus royalties receivable on our royalty
lands.
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RECONCILIATION Light and Associated
OF NET OIL AND Medium Heavy Total Natural and Non-
GAS BY RESERVES Crude Crude Crude Gas Associated Oil
PRINCIPAL PRODUCT Oil Oil Oil Liquids Gas Equivalent
TYPE (1) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (Mboe)
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Proved Producing
December 31, 2009 3,520 4,806 8,326 824 35,428 15,055
Extensions 188 141 329 23 682 465
Improved recovery - - - - - -
Technical revisions 93 378 471 105 2,506 993
Discoveries - - - - - -
Acquisitions 85 181 266 54 3,223 857
Dispositions - - - - (1) -
Economic factors 12 3 15 - 25 19
Production (2) (568) (946) (1,514) (159) (6,483) (2,753)
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December 31, 2010 3,330 4,563 7,893 847 35,379 14,636
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Total Proved
December 31, 2009 3,596 4,889 8,486 824 35,555 15,236
Extensions 188 141 329 23 682 465
Improved recovery - - - - - -
Technical revisions 89 372 460 110 2,497 986
Discoveries - - - - - -
Acquisitions 85 181 266 54 3,223 857
Dispositions (8) - (8) - (1) (8)
Economic factors 10 3 13 - 24 17
Production (2) (568) (946) (1,514) (159) (6,483) (2,753)
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December 31, 2010 3,393 4,640 8,032 851 35,496 14,800
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Proved Plus Probable
December 31, 2009 5,571 8,159 13,730 1,222 54,615 24,054
Extensions 366 255 621 63 1,600 950
Improved recovery - - - - - -
Technical revisions (261) 125 (136) 80 468 22
Discoveries - - - - - -
Acquisitions 128 280 408 91 5,118 1,352
Dispositions (19) - (19) - (1) (19)
Economic factors 11 7 18 - 38 24
Production (2) (568) (946) (1,514) (159) (6,483) (2,753)
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December 31, 2010 5,228 7,880 13,107 1,296 55,356 23,629
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(1) Net reserves are our share of working interest properties minus
royalties payable to others, plus royalties receivable on our royalty
lands. Numbers may not add due to rounding.
(2) Production estimated by Trimble.
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RESERVE LIFE INDEX (1) Proved Total Proved Plus
Producing Proved Probable
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Net reserves (Mboe) 14,636 14,800 23,629
Net production (Mboe) 2,232 2,234 2,497
Reserve life index (years) 6.6 6.6 9.5
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(1) Reserve Life Index is an index reflecting the theoretical production
life of a property if the remaining reserves were to be produced out at
current rates. The index is calculated by dividing the reserves in the
selected reserve category at a certain date by the estimated production
for the following 12 month period (calculated by dividing the Trimble
forecast of 2011 net production into the remaining net reserves).
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TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
AS AT DECEMBER 31, 2010 - FORECAST PRICES AND
COSTS (1) Proved Plus
($000s) Proved Probable
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Royalty income 734,806 1,248,260
Revenue from working interests 291,505 504,881
Royalty expense on working interests (42,210) (77,332)
Operating costs on working interests (117,476) (199,793)
Development costs on working interests (819) (5,685)
Well abandonment and reclamation costs on working
interests (7,053) (8,107)
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Future net revenue before income taxes 858,754 1,462,224
Future income taxes (160,431) (314,336)
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Future net revenue after income taxes 698,323 1,147,887
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(1) Future net revenue calculation includes future capital expenditures
required to bring booked non-producing and undeveloped reserves on
production. Future net revenue values do not represent fair market
value. Columns may not add due to rounding.
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FUTURE DEVELOPMENT COSTS (1)
Proved Plus
Probable
($000s) Proved Reserves Reserves
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2011 70 71
2012 71 2,478
2013 527 2,868
2014 29 29
2015 30 30
Remainder 92 209
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Total 819 5,685
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(1) Based on forecast prices and costs. The source of funding for future
development costs includes internally generated cash flow, debt or a
combination of both. Disclosed reserves and future net revenue will not
be materially affected by the costs of funding the future development
expenditures.
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NET PRESENT VALUES Before tax, discounted at
OF FUTURE NET REVENUE (1) -------------------------------------------
0% per year 5% per 10% per 15% per
($000s) year year year
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Proved developed producing 851,792 604,051 475,253 396,874
Proved developed non-producing 923 387 140 16
Proved undeveloped 6,039 4,624 3,683 3,026
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Total proved 858,754 609,062 479,076 399,916
Total probable 603,470 284,029 177,156 128,172
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Proved plus probable 1,462,223 893,091 656,232 528,088
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(1) Based on forecast prices and costs, before tax, based on the December
31, 2010 escalated oil and gas price forecasts by an independent
qualified reserves evaluator. Future net revenue values do not represent
fair market value. Columns may not add due to rounding.
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ANALYSIS OF FINDING, DEVELOPMENT AND Three-Year
ACQUISITIONS (FD&A) COSTS (1) 2010 2009 2008 Results
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Net Proved Reserves:
Development expenditures ($000s) 18,054 15,491 12,992 46,537
Change in future development capital
estimates ($000s) (59) (295) 597 243
Net reserve additions by development
(Mboe) 465 615 409 1,490
Development costs ($/boe) 38.67 24.70 33.22 31.40
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Acquisition expenditures ($000s) 38,600 9,539 7,693 55,832
Net reserve additions by acquisition
(Mboe) 857 211 192 1,260
Acquisition costs ($/boe) 45.05 45.14 40.07 44.30
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Total expenditures ($000s) 56,654 25,030 20,685 102,369
Change in future development capital
estimates ($000s) (59) (295) 597 243
Net reserve additions (Mboe) 1,322 827 601 2,750
Development and acquisition costs
($/boe) 42.81 29.92 35.41 37.31
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Net Proved Plus Probable Reserves:
Development expenditures ($000s) 18,054 15,491 12,992 46,537
Change in future development capital
estimates ($000s) 35 1,944 (564) 1,415
Net reserve additions by development
(Mboe) 950 1,106 833 2,889
Development costs ($/boe) 19.04 15.77 14.92 16.60
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Acquisition expenditures ($000s) 38,600 9,539 7,693 55,832
Net reserve additions by acquisition
(Mboe) 1,352 325 272 1,949
Acquisition costs ($/boe) 28.56 29.38 28.25 28.65
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Total expenditures ($000s) 56,654 25,030 20,685 102,369
Change in future development capital
estimates ($000s) 35 1,944 (564) 1,415
Net reserve additions (Mboe) 2,302 1,430 1,105 4,838
Development and acquisition costs
($/boe) 24.63 18.86 18.20 21.45
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(1) Freehold did not incur any exploration costs in any of the applicable
years. In calculating finding and development costs, NI 51-101 requires
that the exploration and development costs incurred in the year and the
change in estimated future development costs be aggregated and then
divided by the applicable reserve additions. The calculation
specifically excludes the effects of acquisitions on both reserves and
costs. We believe that by excluding the effects of acquisitions the
provisions of NI 51-101 do not fully reflect Freehold's ongoing reserve
replacement costs. Because acquisitions can have a significant impact on
annual reserve replacement costs, excluding these amounts could result
in an inaccurate portrayal of Freehold's cost structure. Accordingly,
we also provide costs that incorporate all acquisitions during the year.
The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated
future development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
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RECYCLE STATISTICS
NET PROVED PLUS PROBABLE RESERVES Three-Year
($ per boe, except as noted) 2010 2009 2008 Results
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Operating netback (1) (4) 44.08 39.61 65.18 49.91
Development and acquisition costs
(2)(4) 24.63 18.86 18.20 21.45
Recycle ratio (times) (3) 1.8 2.1 3.6 2.3
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(1) Total revenue, less operating costs and royalty expenses.
(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.
Net Asset Value
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NET ASSET VALUE AS AT DECEMBER 31, 2010 (1) (2) (3)
($000s, except share data) 2010 2009 2008
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Present value of oil and gas reserves (4) (8) 656,232 707,583 730,659
Present value of potash reserves (5) (8) 20,194 17,809 27,807
Undeveloped land (6) 96,785 79,408 93,975
Reclamation fund (7) 2,725 2,261 1,827
Working capital (7) (6,479) (3,082) (20,055)
Bank debt (7) (65,000) (45,000) (140,000)
Asset retirement obligations (7) (7,067) (7,160) (5,663)
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Net asset value 697,390 751,818 688,550
Shares outstanding (000s) 59,181 57,503 49,459
Net asset value per share ($) 11.78 13.06 13.92
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(1) Prior to conversion to a corporation on December 31, 2010, Freehold had
trust units outstanding instead of shares.
(2) Non-GAAP measure. Net asset value (NAV) is a measure used widely within
the investment community and in the oil and natural gas industry. It
shows what is normally referred to as a 'produce-out' NAV calculation
under which our reserves would be produced at forecast future prices
and costs. The value is a snapshot in time and is based on various
assumptions including commodity prices and foreign exchange rates that
vary over time. It does not represent a 'going concern' value and it
should not be assumed that the present value of oil and gas reserves
represent the fair market value of the reserves. Net asset value does
not have any standardized meaning prescribed by GAAP and therefore may
not be comparable with the calculations of similar measures for other
entities.
(3) Columns may not add due to rounding.
(4) Based on net proved plus probable reserves evaluated by Trimble, before
tax, discounted at 10%, and includes future capital expenditure
expectations required to bring undeveloped reserves on production.
(5) Based on net proved plus probable reserves evaluated internally, before
tax, discounted at 10%. Potash reserves are not subject to NI 51-101.
(6) Evaluated by Seaton-Jordan & Associates Ltd.
(7) Financial information per Freehold's consolidated financial statements.
(8) Future net revenue values do not represent fair market value.
/T/
Availability on SEDAR
Freehold's 2010 fourth quarter report, including unaudited financial statements and Management's Discussion and Analysis, is being filed today with Canadian securities regulators and will be available on SEDAR at www.sedar.com or on our website.
Forward-Looking Statements
This news release offers our assessment of Freehold's future plans and operations as at March 2, 2011, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. Forward-looking statements contained herein include our expectations for the following:
- our outlook for commodity prices including supply and demand factors relating to crude oil, heavy oil, and natural gas;
- light/heavy oil price differentials;
- changing economic conditions;
- foreign exchange rates;
- industry drilling and development activity on our royalty lands;
- participation in the DRIP and our use of cash preserved through the DRIP;
- estimated capital expenditures and the timing thereof;
- long-term debt at year end;
- average production and contribution from royalty lands;
- key operating assumptions;
- acquisition opportunities;
- future income tax;
- the expected impact of international financial reporting standards on our reported results;
- our dividend policy; and
- our tax pools and the expected tax horizon.
Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe", and similar expressions (including the negatives thereof). 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, royalties, environmental risks, taxation, regulation, changes in tax or other legislation, 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 AIF.
With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future oil and natural gas prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future participation rates in the DRIP and use of cash preserved through the DRIP, future legislation, the cost of developing and producing our assets, our ability and the ability of our lessees to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers, our expectation for the consumption of crude oil and natural gas, our expectation for industry drilling levels, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through development and acquisition activities. The key operating assumptions with respect to the forward-looking statements referred to above are detailed in our discussion of the Business Environment.
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. The forward-looking information contained in this document is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is to update our key operating assumptions quarterly and, except as required by law, we do not undertake to update any other forward-looking statements.
Conversion of Natural Gas To Barrels of Oil Equivalent (BOE)
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 industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation.
Non-GAAP Measures
Within this news release, references are made to terms commonly used as key performance indicators in the oil and natural gas industry. We believe that operating netback, funds generated from operations, and net debt to funds generated from operations are useful supplemental measures for management and investors to analyze operating performance, financial leverage, and liquidity, and we use these terms to facilitate the understanding and comparability of our results of operations and financial position. 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 (see Operating Netback).
Funds generated from operations is a financial term commonly used in the oil and natural gas industry. It represents cash provided by operating activities before changes in non-cash working capital and 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 GAAP. The key difference between cash provided by operating activities and funds generated from operations is changes in non-cash working capital, which is affected by accounts receivable, accounts payable, and accrued liabilities. Accounts receivable, and therefore working capital, can fluctuate greatly between reporting periods due to timing of receipt of payments. In the event that commodity prices and/or volumes have changed significantly from the previous reporting period, a significant difference could occur between cash provided by operating activities and funds generated from operations. 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 Statements of Cash Flows. Funds generated from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share (see Funds Generated From Operations and Net Income).
In addition, we refer to various per boe figures, such as revenues and costs, also considered non-GAAP measures, which 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 natural gas production during the period, with natural gas converted to equivalent barrels of oil as described above.