CALGARY, ALBERTA--(Marketwire - March 14, 2012) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced fourth quarter results and year-end reserves for the period ended December 31, 2011.
Results at a Glance
| FINANCIAL HIGHLIGHTS | |||||||||||||
| ($000s, except as noted) | Three Months Ended December 31 |
Twelve Months Ended December 31 |
|||||||||||
| 2011 | 2010 | Change | 2011 | 2010 | Change | ||||||||
| Gross revenue | 45,304 | 36,525 | 24 | % | 157,910 | 138,155 | 14 | % | |||||
| Net income | 16,033 | 11,387 | 41 | % | 55,259 | 49,349 | 12 | % | |||||
| Per share, basic and diluted ($) (1) | 0.26 | 0.19 | 37 | % | 0.92 | 0.85 | 8 | % | |||||
| Funds from operations (2) | 38,245 | 28,218 | 36 | % | 128,230 | 106,971 | 20 | % | |||||
| Per share ($) (1) | 0.63 | 0.48 | 31 | % | 2.14 | 1.83 | 17 | % | |||||
| Capital expenditures | 10,910 | 4,664 | 134 | % | 25,649 | 18,054 | 42 | % | |||||
| Property and royalty acquisitions (net) | (195 | ) | 283 | -169 | % | 7,467 | 38,600 | -81 | % | ||||
| Dividends declared | 25,585 | 24,797 | 3 | % | 100,968 | 98,115 | 3 | % | |||||
| Per share ($) (1) (3) | 0.42 | 0.42 | 0 | % | 1.68 | 1.68 | 0 | % | |||||
| Proceeds from the DRIP (4) | 10,232 | 6,845 | 49 | % | 33,490 | 25,695 | 30 | % | |||||
| Long-term debt, period end | 48,000 | 65,000 | -26 | % | 48,000 | 65,000 | -26 | % | |||||
| Shareholders' equity, period end | 272,973 | 281,395 | -3 | % | 272,973 | 281,395 | -3 | % | |||||
| Shares outstanding, period end (000s) | 61,141 | 59,181 | 3 | % | 61,141 | 59,181 | 3 | % | |||||
| Average shares outstanding (000s) (5) | 60,811 | 58,972 | 3 | % | 60,022 | 58,334 | 3 | % | |||||
| OPERATING HIGHLIGHTS | |||||||||||||
| Average daily production (boe/d) (6) | 7,773 | 7,972 | -2 | % | 7,476 | 7,615 | -2 | % | |||||
| Oil and NGL (bbls/d) | 5,081 | 4,810 | 6 | % | 4,697 | 4,704 | 0 | % | |||||
| Natural gas (Mcf/d) | 16,150 | 18,972 | -15 | % | 16,674 | 17,465 | -5 | % | |||||
| Average selling price ($/boe) (6) | 61.90 | 48.80 | 27 | % | 56.31 | 48.74 | 16 | % | |||||
| Oil and NGL ($/bbl) | 85.44 | 67.89 | 26 | % | 78.53 | 65.40 | 20 | % | |||||
| Natural gas ($/Mcf) | 2.91 | 3.29 | -12 | % | 3.13 | 3.64 | -14 | % | |||||
| Operating netback ($/boe) (2) (6) | 56.56 | 44.57 | 27 | % | 51.65 | 44.08 | 17 | % | |||||
(1) Prior to conversion to a corporation on December 31, 2010, Freehold had trust units outstanding instead of shares.
(2) See Non-GAAP Financial Measures.
(3) Based on the number of shares issued and outstanding at each record date.
(4) Dividends paid in shares pursuant to the dividend reinvestment plan (DRIP).
(5) Weighted average number of shares outstanding during the period, basic.
(6) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).
Availability on SEDAR
Freehold's 2011 audited financial statements and accompanying Management's Discussion and Analysis (MD&A) and Annual Information Form (including reserves disclosure required under National Instrument NI 51-101) are being filed today with Canadian securities regulators and will be available at www.sedar.com and on our website at www.freeholdroyalties.com.
March Dividend Announcement
The Board of Directors has declared the March dividend of $0.14 per share, which will be paid on April 16, 2012 to shareholders of record on March 31, 2012. Including the April 16 payment, our 12-month trailing cash dividends total $1.68 per share. This dividend is designated as an eligible dividend for Canadian income tax purposes. Over the past 15 years, we have paid out over $1 billion in dividends to our shareholders.
2011 Fourth Quarter Highlights
Freehold's assets delivered strong results in the fourth quarter. Our 65% oil-weighted production continued to benefit from robust oil prices, while our diversified portfolio served to mitigate the impact of lower natural gas prices. Revenue, operating netback, and funds from operations were all substantially higher than the fourth quarter of 2010. Per share amounts reflect increased participation in our dividend reinvestment plan (DRIP). Participation in the DRIP averaged 40% in the fourth quarter (Q4 2010 - 28%), allowing us to conserve $10.2 million in dividend payments by issuing shares from treasury.
Net income rose 41% in the fourth quarter, due to higher oil prices, despite an increase in deferred income tax as a result of converting from a trust structure to a corporation on December 31, 2010. Non-cash charges included in net income amounted to $22.3 million in the fourth quarter of 2011 (Q4 2010 - $16.9 million) and $75.7 million for the year (2010 - $59.6 million).
The ratio of net debt to annual funds from operations was 0.4 times and net debt was approximately 15% of total capitalization at the end of 2011. Subsequent to year-end, Freehold completed a $49.6 million royalty acquisition and closed a $67.6 million equity financing. As a result, net debt to annual funds from operations is currently approximately 0.2 times and net debt is approximately 8% of total capitalization.
Oil and natural gas liquids (NGL) production rose 6% in the fourth quarter, while natural gas production declined 15%. The fourth quarter benefitted from production additions of approximately 125 boe per day, mostly oil, from the royalty acquisition completed on September 30, 2011. Production in the fourth quarter of 2011 also included positive prior period adjustments of approximately 350 boe per day, mostly oil. The fourth quarter of 2010 included a number of prior period adjustments as well, that increased royalty interest natural gas volumes in the comparative period by approximately 2,700 Mcf (450 boe) per day. Due to the large number of wells in which we have royalty interests, the nature of royalty interests, the lag in receiving production receipts from the operators, and our audit program, our reported royalty volumes usually include adjustments (both positive and negative) for prior periods.
While natural gas production accounted for 35% of production in the fourth quarter, it comprised only 10% of revenue. Royalty interests comprised 75% (2010 - 73%) of total volumes produced in 2011.
| FOURTH QUARTER PRODUCTION SUMMARY | Royalty Interest | Working Interest | Total | ||||||||||
| Three months ended December 31 | 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||
| Average daily production | |||||||||||||
| Oil (bbls/d) | 3,262 | 2,938 | 1,461 | 1,539 | 4,723 | 4,477 | |||||||
| NGL (bbls/d) | 252 | 248 | 106 | 85 | 358 | 333 | |||||||
| Natural gas (Mcf/d) | 13,198 | 16,122 | 2,952 | 2,850 | 16,150 | 18,972 | |||||||
| Oil equivalent (boe/d) | 5,714 | 5,873 | 2,059 | 2,099 | 7,773 | 7,972 | |||||||
Industry Drilling
After drilling delays and production downtime in the second and third quarters due to forest fires and flooding, industry drilling activity ramped up in the fourth quarter, with producers directing capital investment towards higher value oil and liquids prospects while curtailing natural gas development. This, along with the increasing complexity of horizontal wells and longer associated drilling times resulted in fewer wells being drilled: 4,621 wells versus 5,352 wells in the fourth quarter of 2010. Nearly three-quarters of these were oil wells, and horizontal drilling techniques continue to be employed to access tight reservoirs and other resource plays. A single horizontal well, completed with multiple fractures, can access as much reservoir as several vertical wells, potentially yielding more production and reserves per well.
Royalty Interests
On an equivalent net basis, drilling on our royalty lands increased 15% from the fourth quarter last year, and non-unitized drilling rose 29%. We rely largely on public databases to monitor activity levels on our royalty lands. Due to a delay in updating the Alberta public database for 2010, the unitized well count for the fourth quarter of 2010 includes a 'catch-up' for the first nine months of 2010.
| ROYALTY WELLS DRILLED | Three Months Ended | Twelve Months Ended | |||||||
| December 31 | December 31 | ||||||||
| 2011 | 2010 | Change | 2011 | 2010 | Change | ||||
| Non-unitized wells | |||||||||
| Gross | 102 | 83 | 23 | % | 301 | 274 | 10 | % | |
| Equivalent net (1) | 4.9 | 3.8 | 29 | % | 14.4 | 12.2 | 18 | % | |
| Unitized wells (2) | |||||||||
| Gross | 60 | 337 | -82 | % | 322 | 505 | -36 | % | |
| Equivalent net (1) | 0.4 | 0.8 | -50 | % | 1.3 | 1.0 | 30 | % | |
| Total | |||||||||
| Gross | 162 | 420 | -61 | % | 623 | 779 | -20 | % | |
| Equivalent net (1) | 5.3 | 4.6 | 15 | % | 15.7 | 13.2 | 19 | % | |
(1) Equivalent net wells are the aggregate of the numbers obtained by multiplying each gross well by our royalty interest percentage.
(2) Unitized wells are in production units wherein we generally have small royalty interests in hundreds of wells.
The horizontal drilling trend continued, as nearly 60% of the wells drilled on our royalty lands in 2011 were horizontal compared to 37% in 2010. Continued success with horizontal drilling (for both oil and liquids-rich natural gas) on our royalty lands is positive and bodes well for improved well productivity.
In 2011, 76% of the royalty wells drilled on our lands were oil wells, versus 51% in 2010. On an equivalent net basis, drilling for oil was up 79% from 2010, while natural gas drilling declined 43%.
As at December 31, 2011, there were 106 (5.4 equivalent net) licensed drilling locations on our royalty lands, up on an equivalent net basis from 110 (3.2 equivalent net) at the same time last year. We view continued well licence activity as a positive indicator of the ongoing and future development potential on our royalty lands.
Working Interests
In the fourth quarter of 2011, capital expenditures related to development of working interest properties amounted to $10.9 million, bringing the total for the year to $25.6 million, or 20% of funds from operations. In the fourth quarter, we participated in the drilling of 10 (3.9 net) wells with a 100% success rate. The wells had little effect on production levels in the fourth quarter but will add to our production in 2012. In Saskatchewan, we drilled two (1.5 net) Bakken light oil wells, one (0.4 net) Frobisher light oil well, and one (0.03 net) Tilston oil well; all were horizontal wells. We also participated in one (0.1 net) vertical water injection well to support this activity. In Lloydminster, we participated in two (1.0 net) Lloydminster heavy oil wells and one (0.7 net) vertical Sparky heavy oil well. In Alberta, we participated in two (0.2 net) horizontal Cardium light oil wells.
On a per boe basis, operating expense on working interest production rose 35% in the fourth quarter of 2011 and was 19% higher for the year. The increase was attributable to several factors, including higher Alberta power costs, prior period adjustments, higher costs and a declining production base at Hayter, and wet weather in Southeast Saskatchewan earlier in the year, which impeded access to surface leases.
| WORKING INTEREST | Three Months Ended December 31 |
Twelve Months Ended December 31 |
||||||||||||||
| WELLS DRILLED | 2011 | 2010 | 2011 | 2010 | ||||||||||||
| Gross | Net (1 | ) | Gross | Net (1 | ) | Gross | Net (1 | ) | Gross | Net (1 | ) | |||||
| Oil | 9 | 3.8 | 9 | 2.9 | 29 | 11.1 | 30 | 9.1 | ||||||||
| Natural gas | - | - | - | - | 3 | 0.4 | 2 | 0.2 | ||||||||
| Other | 1 | 0.1 | - | - | 2 | 0.1 | - | - | ||||||||
| Total | 10 | 3.9 | 9 | 2.9 | 34 | 11.6 | 32 | 9.3 | ||||||||
(1) Excludes royalty interest portion on properties where Freehold has both a working interest and a royalty interest. The royalty interest portion is included in equivalent net wells in the Royalty Wells Drilled table above.
Guidance Update
Overall, the outlook for crude oil is more favourable than for natural gas.
West Texas Intermediate (WTI) crude oil prices averaged 10% higher than in the fourth quarter of 2010 and 20% higher for the year, but with continued volatility driven by global economic and political uncertainties. A transportation bottleneck out of North American inland markets (exacerbated by rising U.S. Bakken oil production and increasing oil sands volumes) has served to dislocate the WTI crude oil benchmark from other light oil benchmarks such as European Brent Crude, creating a significant price discount for WTI. In turn, this is serving to widen the discount for Canadian (Edmonton Par) light crude oil relative to WTI. However, it is anticipated that rail and pipeline projects will be commissioned within the next few years to link U.S. and Canadian oil production to U.S. Gulf Coast refining centres, where international prices prevail.
The Canadian light/heavy oil price differential widened to an average of $17.93 per boe in 2011 from $10.27 per boe in 2010. The differential narrowed during the fourth quarter, but continues to rise and fall in response to domestic supply and demand factors. Historically, the benchmark Western Canada Select (WCS) heavy oil stream, with an average API gravity of 20.5 degrees, was considered a rough proxy for our average oil price. In 2011, our average oil price increased in relation to the benchmark WCS. Oil prices and differentials are expected to remain volatile in the short term, with both upside and downside risks.
Natural gas, because it is less readily transported, is subject to supply and demand factors within North America. The benchmark AECO natural gas price declined 11% in 2011, and has declined further in 2012. The outlook for natural gas prices remains grim in the near term as North American production continues to grow, while demand remains soft due to a warmer than expected winter. However, the low price environment has prompted some natural gas producers to shut in production until prices improve, and we believe the supply/demand balance will gradually improve, aided by projects aimed at exporting liquefied natural gas (LNG) to Asian markets as early as 2015.
The following table summarizes changes in our key operating assumptions during 2011 and our actual results for the year. Compared to our November guidance:
- Production came in 2% above guidance.
- Commodity prices surpassed our expectations, while the U.S. dollar was slightly stronger.
- Operating costs were slightly higher, while general and administrative costs were lower than expected.
- Capital expenditures were $4 million higher, as we were able to access surface leases and services in the fourth quarter more quickly than expected.
- Long-term debt at year end was $5 million higher as it included a $5 million deposit relating to the acquisition that closed on January 17, 2012.
| 2011 KEY OPERATING ASSUMPTIONS | Guidance Updated | ||||||||||||||
| 2011 Actual Results |
Nov. 9 2011 |
Aug. 10 2011 |
May 11 2011 |
Mar. 2 2011 |
|||||||||||
| Average daily production | boe/d | 7,476 | 7,300 | 7,300 | 7,100 | 7,100 | |||||||||
| Average WTI oil price | US$/bbl | 95.10 | 94.00 | 95.00 | 90.00 | 80.00 | |||||||||
| Average exchange rate | Cdn$/US$ | 1.01 | 1.03 | 1.03 | 1.00 | 0.95 | |||||||||
| Average heavy oil price differential (1) | Cdn$/bbl | (17.93 | ) | (19.50 | ) | (19.00 | ) | (15.00 | ) | (13.00 | ) | ||||
| Average AECO natural gas price | Cdn$/Mcf | 3.67 | 3.65 | 3.65 | 3.65 | 4.25 | |||||||||
| Average operating costs | $/boe | 4.68 | 4.50 | 4.50 | 4.50 | 4.50 | |||||||||
| Average general and administrative costs (2) | $/boe | 2.58 | 3.00 | 3.50 | 3.50 | 3.50 | |||||||||
| Capital expenditures | $ millions | 26 | 22 | 22 | 28 | 20 | |||||||||
| Proceeds from DRIP | $ millions | 33 | 33 | 28 | 28 | 27 | |||||||||
| Long-term debt at year end | $ millions | 48 | 43 | 41 | 50 | 50 | |||||||||
| Cash taxes payable | $ millions | - | - | - | - | - | |||||||||
| Weighted average shares outstanding | millions | 60 | 60 | 60 | 60 | 60 | |||||||||
(1) The difference between the Edmonton Par and Western Canada Select crude oil streams.
(2) Excludes share based and other compensation.
2012 Plans
On January 17, 2012, we acquired royalty interests in over 250,000 gross acres of land for $49.6 million before closing adjustments. The acquisition was funded through our existing bank line of credit. Royalty production from the acquisition for the remainder of 2012 is anticipated to be approximately 530 boe per day (90% natural gas) from over 400 producing wells. Net proved plus probable reserves were independently evaluated at 3.1 million boe, and have an estimated reserve life of 15.9 years. As this acquisition occurred subsequent to year end, these reserves were not included in our December 31, 2011 reserves evaluation. We anticipate further development on these lands when natural gas prices improve.
On February 29, 2012, we closed an equity offering, issuing 3.5 million shares (including the exercise in full of the underwriters' over-allotment option) at $20.50 per share. Net proceeds of $67.6 million were used to repay the bank indebtedness associated with the acquisitions completed on September 30, 2011 and January 17, 2012.
We currently have approximately $185 million of available capacity under our credit facilities, which gives us significant financial flexibility to take advantage of acquisition opportunities. We believe producers may look to sell non-core oil and gas assets, and particularly royalty interests, in order to reduce debt and fund their core exploration and development programs. In addition, cash preserved through our DRIP continues to enhance our capital resources.
We have maintained a steady monthly dividend rate of $0.14 ($1.68 annually) per share since January 2010. Based on our current guidance, we expect to maintain the current monthly dividend rate through 2012, subject to the Board's quarterly review.
For 2012, the Board has approved a capital budget of $30 million. Our plans include 60 (16.5 net) wells, of which 44% will be operated. About 80% of our capital will be deployed on our mineral title lands in Southeast Saskatchewan, where we continue to see opportunities. Spending may be adjusted as the year progresses, depending on the operating environment and well results. Based on this level of capital investment, anticipated drilling activity on our leased royalty lands, and normal production declines (and excluding any future acquisitions), we expect 2012 production to average approximately 7,600 boe per day. Our production remains unhedged, subject to quarterly review by our Board.
Up until December 31, 2010, our trust structure was such that both current income tax and deferred tax liabilities were passed on to our unitholders. With our conversion from a trust to a corporation, we became subject to normal corporate tax rates starting in 2011. The corporate income tax rate applicable to 2011 was 26.9%; however, we did not pay any corporate income tax in 2011 (2010 - $nil) due to the tax deductions available to us and the effect of the deferral of our partnership income.
In December 2011, legislation was passed implementing tax measures outlined in the 2011 budget (Bill C-13), which included the elimination of the ability of a corporation to defer income as a result of timing differences in the year-end of the corporation and of any partnership of which it is a member, subject to transitional relief over five years. Freehold's deferred income tax liability includes a partnership deferral that will be reduced over the transitional relief period.
The corporate income tax rate applicable to 2012 is approximately 25%. Taxable income as a corporation is based on total income and expenses (which will vary depending on commodity prices, production volumes, and costs), reduced by claims for both accumulated tax pools and tax pools associated with current year expenditures. As our partnership has a March 31 year-end, we expect to pay no cash income taxes in 2012. However, we expect to have current income tax expense of approximately $21 million, which will be payable in the first quarter of 2013.
| 2012 KEY OPERATING ASSUMPTIONS | March 14, 2012 | November 9, 2011 | |||
| Average daily production | boe/d | 7,600 | 7,100 | ||
| Average WTI oil price | US$/bbl | 100.00 | 92.00 | ||
| Average exchange rate | Cdn$/US$ | 1.00 | 0.98 | ||
| Average heavy oil price differential (1) | Cdn$/bbl | (18.00 | ) | (20.00 | ) |
| Average AECO natural gas price | Cdn$/Mcf | 2.50 | 3.75 | ||
| Average operating costs | $/boe | 4.60 | 4.60 | ||
| Average general and administrative costs (2) | $/boe | 3.00 | 3.00 | ||
| Capital expenditures | $ millions | 30 | 30 | ||
| Proceeds from DRIP (3) | $ millions | 27 | 27 | ||
| Long-term debt at year end | $ millions | 15 | 37 | ||
| Cash taxes payable in 2012 (4) | $ millions | - | 2 | ||
| Current income tax expense (payable in 2013) (4) | $ millions | 21 | - | ||
| Weighted average shares outstanding | millions | 65 | 62 |
(1) The difference between the Edmonton Par and Western Canada Select crude oil streams.
(2) Excludes share based and other compensation.
(3) Average 25% participation rate, which is subject to change.
(4) Corporate tax estimates will vary depending on commodity prices and other factors.
A sensitivity analysis of the potential impact of key variables on funds from operations per share is provided on page 7 of our 2011 Annual MD&A. Recognizing the cyclical nature of the oil and gas 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 have no operational control and do not know the future plans of the various operators.
Director Succession
Mr. Tullio Cedraschi, who has been a director of Freehold since 1998, plans to retire from the Board in 2012 and will not stand for re-election in May. In 1996, as head of the CN Pension Trust Funds, Tullio was instrumental in the formation of Freehold as a publicly-traded energy trust, with assets contributed from Rife Resources Ltd. and Canpar Holdings Ltd. His knowledge and experience with respect to capital markets as well as with Freehold's original assets, has been invaluable to the Board over the past 14 years. We will miss the broad perspective he has brought to the Board's strategic decision making.
We are pleased to announce that Mr. Arthur N. Korpach, Vice Chairman Investment Banking at CIBC World Markets Inc., has agreed to stand for election as a director at the annual meeting of shareholders on May 9, 2012. Art is a Fellow Chartered Accountant and a Chartered Business Valuator with 27 years of investment banking experience.
Land Holdings
Our land holdings as at December 31, 2011 encompassed 2.7 million gross acres, down 1% from the prior year as a result of lease expires on our contracted royalty land base. Royalty interests comprised 93% of our acreage. Our undeveloped land, totalling 0.8 million gross acres, was independently valued at $91.3 million, down from $96.8 million at year-end 2010, due to a reclassification of certain acreage from undeveloped to developed and changes in value (increases as well as decreases) based on prices paid during 2011 at Crown land sales directly offsetting Freehold's lands.
Oil and Gas Reserves
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 National Instrument 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.
Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2011. The evaluation was conducted in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in National Instrument 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.
Net proved plus probable reserves at December 31, 2011 totalled 22.2 MMboe, with reserves assigned to 25,044 wells. Net proved plus probable royalty interest reserves declined 7% year-over-year, and net proved plus probable working interest reserves declined 3%. Approximately 64% of our net reserves are in the proved category, and 98% of our net proved reserves are producing. On a boe basis, net reserves are approximately 37% natural gas, 34% heavy oil, 24% light and medium oil, and 5% natural gas liquids (NGL).
Drilling by others on our royalty lands added 0.4 MMboe (31%) of net proved plus probable reserves, development activities on our working interest properties added 0.7 MMboe (54%), and acquisitions added 0.2 MMboe (15%), bringing the total additions to 1.3 MMboe before 2011 production of 2.6 MMboe. Over 80% of the 2011 reserve additions were oil and NGL.
Finding and development costs in 2011 were $46.81 per boe for net proved reserves, and $28.20 per boe for net proved plus probable reserves. Based on net proved plus probable reserves, we replaced approximately half of 2011 production at an all-in finding, development and acquisition (FD&A) cost of $29.47 per boe (including changes in future development capital), contributing to a three-year average FD&A cost of $24.23 per boe. The increase in development expenditures over the past three years relates to our capital program in Southeast Saskatchewan. The relatively high cost of acquisitions is justified by the addition of high netback royalty production with no future capital requirements. These activities resulted in a recycle ratio of 1.8 times the capital invested, and a three-year average recycle ratio of 1.9 times.
| SUMMARY OF OIL AND GAS RESERVES | |||||||||||||
| AS OF DECEMBER 31, 2011 | Light and Medium Oil | Heavy Oil | Total Crude Oil | ||||||||||
| FORECAST PRICES AND COSTS (1) | Gross (2 | ) | Net (3 | ) | Gross (2 | ) | Net (3 | ) | Gross (2 | ) | Net (3 | ) | |
| Reserves Category | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | |
| Proved | |||||||||||||
| Developed producing | 1,554.5 | 3,334.3 | 710.1 | 4,385.0 | 2,264.5 | 7,719.2 | |||||||
| Developed non-producing | 135.6 | 111.1 | 128.6 | 147.7 | 264.2 | 258.7 | |||||||
| Undeveloped | - | - | - | - | - | - | |||||||
| Total proved | 1,690.1 | 3,445.4 | 838.7 | 4,532.6 | 2,528.8 | 7,978.0 | |||||||
| Probable | 1,009.1 | 1,884.6 | 665.9 | 2,840.8 | 1,675.0 | 4,725.4 | |||||||
| Total proved plus probable | 2,699.1 | 5,330.0 | 1,504.6 | 7,373.5 | 4,203.7 | 12,703.4 | |||||||
| Natural Gas | Natural Gas Liquids | Oil Equivalent | |||||||||||
| Gross (2 | ) | Net (3 | ) | Gross (2 | ) | Net (3 | ) | Gross (2 | ) | Net (3 | ) | ||
| Reserves Category | (MMcf | ) | (MMcf | ) | (Mbbls | ) | (Mbbls | ) | (Mboe | ) | (Mboe | ) | |
| Proved | |||||||||||||
| Developed producing | 4,274.1 | 32,502.1 | 174.0 | 796.4 | 3,150.9 | 13,932.7 | |||||||
| Developed non-producing | 64.9 | 57.8 | 7.9 | 5.3 | 282.9 | 273.7 | |||||||
| Undeveloped | - | - | - | - | - | - | |||||||
| Total proved | 4,339.0 | 32,559.9 | 181.9 | 801.7 | 3,433.8 | 14,206.3 | |||||||
| Probable | 3,003.3 | 17,113.4 | 127.0 | 404.7 | 2,302.6 | 7,982.4 | |||||||
| Total proved plus probable | 7,342.3 | 49,673.3 | 308.9 | 1,206.4 | 5,736.4 | 22,188.7 | |||||||
(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 interests.
(3) Net reserves are our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands.
| SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE | |||||||||||
| AS OF DECEMBER 31, 2011 | |||||||||||
| FORECAST PRICES AND COSTS (1) | Before Income Taxes, Discounted at (% per year) | ||||||||||
| Reserves Category | 0 | % | 5 | % | 10 | % | 15 | % | 20 | % | |
| ($000s | ) | ($000s | ) | ($000s | ) | ($000s | ) | ($000s | ) | ||
| Proved | |||||||||||
| Developed producing | 826,953 | 579,313 | 451,824 | 375,036 | 323,705 | ||||||
| Developed non-producing | 11,181 | 9,568 | 8,494 | 7,699 | 7,071 | ||||||
| Undeveloped | - | - | - | - | - | ||||||
| Total proved | 838,134 | 588,880 | 460,319 | 382,735 | 330,776 | ||||||
| Probable | 583,373 | 264,999 | 161,150 | 114,742 | 89,047 | ||||||
| Total proved plus probable | 1,421,508 | 853,879 | 621,469 | 497,477 | 419,823 | ||||||
| After Income Taxes, Discounted at (% per year) (2) | |||||||||||
| Reserves Category | 0 | % | 5 | % | 10 | % | 15 | % | 20 | % | |
| ($000s | ) | ($000s | ) | ($000s | ) | ($000s | ) | ($000s | ) | ||
| Proved | |||||||||||
| Developed producing | 677,267 | 476,367 | 372,669 | 310,023 | 268,044 | ||||||
| Developed non-producing | 8,265 | 6,987 | 6,140 | 5,516 | 5,027 | ||||||
| Undeveloped | - | - | - | - | - | ||||||
| Total proved | 685,533 | 483,354 | 378,809 | 315,539 | 273,070 | ||||||
| Probable | 434,266 | 196,645 | 119,082 | 84,418 | 65,233 | ||||||
| Total proved plus probable | 1,119,799 | 679,999 | 497,891 | 399,957 | 338,304 | ||||||
(1) Based on the December 31, 2011 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.
(2) The after-tax net present value calculation reflects the tax burden on the properties on a standalone basis, utilizing our tax pools to the maximum depreciation rate as currently permitted. It does not consider the corporate-level tax situation, or tax planning. It does not provide an estimate of the value at the corporate level, which may be significantly different. See our financial statements and accompanying MD&A for additional tax information.
| TOTAL FUTURE NET REVENUE (UNDISCOUNTED) | ||||
| AS OF DECEMBER 31, 2011 | ||||
| FORECAST PRICES AND COSTS (1) | Reserves Category | |||
| ($000s) | Proved Reserves | Proved Plus Probable Reserves | ||
| Royalty income | 722,927 | 1,220,554 | ||
| Revenue from working interest properties | 296,643 | 525,604 | ||
| Royalty expense on working interest properties | (44,429 | ) | (81,842 | ) |
| Operating costs | (126,985 | ) | (222,909 | ) |
| Development costs | (2,375 | ) | (10,644 | ) |
| Well abandonment and reclamation costs | (7,647 | ) | (9,255 | ) |
| Future net revenue before income taxes | 838,134 | 1,421,508 | ||
| Future income taxes (2) | (152,602 | ) | (301,709 | ) |
| Future net revenue after income taxes (2) | 685,533 | 1,119,799 | ||
(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.
(2) The after-tax net present value calculation reflects the tax burden on the properties on a standalone basis, utilizing our tax pools to the maximum depreciation rate as currently permitted. It does not consider the corporate-level tax situation, or tax planning. It does not provide an estimate of the value at the corporate level, which may be significantly different. See our financial statements and accompanying MD&A for additional tax information.
| FUTURE DEVELOPMENT COSTS (UNDISCOUNTED) (1) | Forecast Prices and Costs | |||
| Proved Reserves | Proved Plus Probable Reserves | |||
| (undiscounted | ) | (undiscounted | ) | |
| Year | ($000s | ) | ($000s | ) |
| 2012 | 1,671 | 7,281 | ||
| 2013 | 552 | 2,896 | ||
| 2014 | 29 | 82 | ||
| 2015 | 30 | 46 | ||
| 2016 | 30 | 213 | ||
| Remainder | 63 | 128 | ||
| Total | 2,375 | 10,644 | ||
(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. Columns may not add due to rounding.
| RESERVE LIFE INDEX (1) | Proved Producing | Total Proved | Proved Plus Probable |
| Net reserves (Mboe) | 13,933 | 14,206 | 22,189 |
| Net production (Mboe) | 2,103 | 2,173 | 2,431 |
| Reserve life index (years) | 6.6 | 6.5 | 9.1 |
(1) Reflects the theoretical production life of a property if the remaining reserves were 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 2012 net production into the remaining net reserves).
| RECONCILIATION OF NET RESERVES (1) | |||||||||||||
| BY PRINCIPAL PRODUCT TYPE | Light and Medium Oil | Heavy Oil | |||||||||||
| FORECASTS PRICES AND COSTS | Proved Plus | Proved Plus | |||||||||||
| Proved | Probable | Probable | Proved | Probable | Probable | ||||||||
| (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | ||
| December 31, 2010 | 3,393 | 1,835 | 5,228 | 4,640 | 3,240 | 7,880 | |||||||
| Extensions | 337 | 295 | 632 | 116 | 111 | 227 | |||||||
| Improved recovery | - | - | - | - | - | - | |||||||
| Technical revisions | 250 | (330 | ) | (81 | ) | 609 | (509 | ) | 99 | ||||
| Discoveries | - | - | - | - | - | - | |||||||
| Acquisitions | 86 | 87 | 173 | - | - | - | |||||||
| Dispositions | - | - | - | - | - | - | |||||||
| Economic factors | (7 | ) | (2 | ) | (9 | ) | (1 | ) | (1 | ) | (2 | ) | |
| Production | (614 | ) | - | (614 | ) | (830 | ) | - | (830 | ) | |||
| December 31, 2011 | 3,445 | 1,885 | 5,330 | 4,533 | 2,841 | 7,373 | |||||||
| Natural Gas | Natural Gas Liquids | ||||||||||||
| Proved Plus | Proved Plus | ||||||||||||
| Proved | Probable | Probable | Proved | Probable | Probable | ||||||||
| (MMcf | ) | (MMcf | ) | (MMcf | ) | (Mbbls | ) | (Mbbls | ) | (Mbbls | ) | ||
| December 31, 2010 | 35,496 | 19,860 | 55,356 | 851 | 445 | 1,296 | |||||||
| Extensions | 697 | 505 | 1,202 | 12 | 14 | 26 | |||||||
| Improved recovery | - | - | - | - | - | - | |||||||
| Technical revisions | 2,371 | (3,361 | ) | (990 | ) | 92 | (54 | ) | 38 | ||||
| Discoveries | - | - | - | - | - | - | |||||||
| Acquisitions | 98 | 98 | 197 | - | - | 1 | |||||||
| Dispositions | - | - | - | - | - | - | |||||||
| Economic factors | (11 | ) | 12 | 1 | - | - | - | ||||||
| Production | (6,092 | ) | - | (6,092 | ) | (154 | ) | - | (154 | ) | |||
| December 31, 2011 | 32,560 | 17,113 | 49,673 | 802 | 405 | 1,206 | |||||||
| Oil Equivalent | |||||||||||||
| Proved Plus | |||||||||||||
| Proved | Probable | Probable | |||||||||||
| (Mboe | ) | (Mboe | ) | (Mboe | ) | ||||||||
| December 31, 2010 | 14,800 | 8,830 | 23,629 | ||||||||||
| Extensions | 581 | 504 | 1,085 | ||||||||||
| Improved recovery | - | - | - | ||||||||||
| Technical revisions | 1,346 | (1,454 | ) | (108 | ) | ||||||||
| Discoveries | - | - | - | ||||||||||
| Acquisitions | 103 | 104 | 207 | ||||||||||
| Dispositions | - | - | - | ||||||||||
| Economic factors | (10 | ) | (1 | ) | (11 | ) | |||||||
| Production | (2,613 | ) | - | (2,613 | ) | ||||||||
| December 31, 2011 | 14,206 | 7,982 | 22,189 | ||||||||||
(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.
| FINDING, DEVELOPMENT AND ACQUISITION (FD&A) COSTS (1) | |||||||
| Net Proved Reserves | 2011 | 2010 | 2009 | Three-Year Results |
|||
| Finding and development expenditures ($000s) | 25,649 | 18,054 | 15,491 | 59,194 | |||
| Change in future development capital estimates ($000s) | 1,556 | (59 | ) | (295 | ) | 1,202 | |
| Net reserve additions by development (Mboe) | 581 | 465 | 615 | 1,662 | |||
| Finding and development costs ($/boe) | 46.81 | 38.67 | 24.70 | 36.34 | |||
| Acquisition expenditures ($000s) | 7,467 | 38,600 | 9,539 | 55,606 | |||
| Net reserve additions by acquisition (Mboe) | 103 | 857 | 211 | 1,171 | |||
| Acquisition costs ($/boe) | 72.42 | 45.05 | 45.14 | 47.48 | |||
| Total expenditures ($000s) | 33,116 | 56,654 | 25,030 | 114,800 | |||
| Change in future development capital estimates ($000s) | 1,556 | (59 | ) | (295 | ) | 1,202 | |
| Net reserve additions (Mboe) | 684 | 1,322 | 827 | 2,833 | |||
| Finding, development and acquisition costs ($/boe) | 50.67 | 42.81 | 29.92 | 40.95 | |||
| Net Proved Plus Probable Reserves | 2011 | 2010 | 2009 | Three-Year Results |
|||
| Finding and development expenditures ($000s) | 25,649 | 18,054 | 15,491 | 59,194 | |||
| Change in future development capital estimates ($000s) | 4,959 | 35 | 1,944 | 6,938 | |||
| Net reserve additions by development (Mboe) | 1,085 | 950 | 1,106 | 3,141 | |||
| Finding and development costs ($/boe) | 28.20 | 19.04 | 15.77 | 21.05 | |||
| Acquisition expenditures ($000s) | 7,467 | 38,600 | 9,539 | 55,606 | |||
| Net reserve additions by acquisition (Mboe) | 207 | 1,352 | 325 | 1,883 | |||
| Acquisition costs ($/boe) | 36.12 | 28.56 | 29.38 | 29.53 | |||
| Total expenditures ($000s) | 33,116 | 56,654 | 25,030 | 114,800 | |||
| Change in future development capital estimates ($000s) | 4,959 | 35 | 1,944 | 6,938 | |||
| Net reserve additions (Mboe) | 1,292 | 2,302 | 1,430 | 5,024 | |||
| Finding, development and acquisition costs ($/boe) | 29.47 | 24.63 | 18.86 | 24.23 | |||
(1) Freehold did not incur any exploration expenditures 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.
| RECYCLE STATISTICS | ||||
| NET PROVED PLUS PROBABLE RESERVES | ||||
| ($ per boe, except as noted) | 2011 | 2010 | 2009 | Three-Year Results |
| Operating netback (1) (4) | 51.65 | 44.08 | 39.61 | 45.15 |
| Finding, development and acquisition costs (2) (4) | 29.47 | 24.63 | 18.86 | 24.23 |
| Recycle ratio (times) (3) | 1.8 | 1.8 | 2.1 | 1.9 |
(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.
| LAND HOLDINGS AS OF DECEMBER 31, 2011 | |||
| (gross acres) (1) | Developed | Undeveloped | Total |
| Mineral title lands (2) | 370,590 | 168,348 | 538,938 |
| Royalty assumption lands (3) | 74,740 | 20,082 | 94,822 |
| Total title lands (4) | 445,330 | 188,430 | 633,760 |
| Gross overriding royalty (GORR) lands (5) | 1,368,303 | 565,855 | 1,934,158 |
| Total royalty lands | 1,813,633 | 754,285 | 2,567,918 |
| Working interest properties | 141,247 | 38,042 | 179,289 |
| Total land holdings | 1,954,880 | 792,327 | 2,747,207 |
| LAND HOLDINGS | Royalty Interest | Working Interest | Total | ||||||||||||
| BY PROVINCE | Developed | Undeveloped | Developed | Undeveloped | Developed | Undeveloped | |||||||||
| Gross (1 | ) | Gross (1 | ) | Gross (1 | ) | Net | Gross (1 | ) | Net | Gross (1 | ) | Gross (1 | ) | ||
| Alberta | 1,342,895 | 345,174 | 107,362 | 16,358 | 28,005 | 4,277 | 1,450,257 | 373,179 | |||||||
| Saskatchewan | 298,075 | 192,778 | 13,085 | 4,069 | 5,300 | 1,857 | 311,160 | 198,078 | |||||||
| Ontario | 94,297 | 190,149 | - | - | - | - | 94,297 | 190,149 | |||||||
| British Columbia | 72,230 | 24,479 | 20,641 | 1,285 | 4,737 | 79 | 92,871 | 29,216 | |||||||
| Manitoba | 6,136 | 1,705 | 159 | 37 | - | - | 6,295 | 1,705 | |||||||
| Total | 1,813,633 | 754,285 | 141,247 | 21,749 | 38,042 | 6,213 | 1,954,880 | 792,327 | |||||||
(1) Gross acres are 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 108,000 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.
| NET ASSET VALUE AS OF DECEMBER 31, 2011 (1) (2) | December 31 | |||||
| ($000s, except share data) | 2011 | 2010 | Change | |||
| Present value of oil and gas reserves (3) (7) | 621,469 | 656,232 | -5 | % | ||
| Present value of potash reserves (4) (7) | 31,656 | 20,194 | 57 | % | ||
| Undeveloped land (5) | 91,256 | 96,785 | -6 | % | ||
| Reclamation fund (6) | - | 2,725 | -100 | % | ||
| Working capital (6) | 479 | (6,479 | ) | -107 | % | |
| Bank debt (6) | (48,000 | ) | (65,000 | ) | -26 | % |
| Asset retirement obligation (8) | (1,511 | ) | (1,229 | ) | 23 | % |
| Net asset value | 695,349 | 703,228 | -1 | % | ||
| Shares outstanding (000s) | 61,141 | 59,181 | 3 | % | ||
| Net asset value per share ($) | 11.37 | 11.88 | -4 | % | ||
(1) Non-GAAP measure. Net asset value (NAV) is a measure used widely within the investment community and in the oil and 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.
(2) Columns may not add due to rounding.
(3) Based on net proved plus probable reserves evaluated by Trimble, before tax, discounted at 10%, and includes future capital expenditure expectations required to bring booked undeveloped reserves on production.
(4) Based on net proved plus probable reserves evaluated internally, before tax, discounted at 10%. Potash reserves are not subject to NI 51-101.
(5) Evaluated by Seaton-Jordan & Associates Ltd.
(6) Financial information per Freehold's consolidated financial statements.
(7) Future net revenue values do not represent fair market value.
(8) Asset retirement obligation (ARO) calculated based on the same methodology used to calculate ARO on Freehold's consolidated statements with two exceptions: future expected ARO costs are discounted at 10% and a deduction is made for abandonment costs incorporated in the present value of oil and gas reserves.
| CONSOLIDATED BALANCE SHEETS | December 31 | December 31 | ||||
| ($000s) (unaudited) | 2011 | 2010 | ||||
| Assets | ||||||
| Current assets: | ||||||
| Cash | $ | 164 | $ | 409 | ||
| Accounts receivable | 27,634 | 22,631 | ||||
| 27,798 | 23,040 | |||||
| Reclamation fund | - | 2,725 | ||||
| Deposit on acquisition | 5,000 | - | ||||
| Exploration and evaluation assets | 25,045 | 26,251 | ||||
| Petroleum and natural gas interests | 365,597 | 375,486 | ||||
| $ | 423,440 | $ | 427,502 | |||
| Liabilities and Shareholders' Equity | ||||||
| Current liabilities: | ||||||
| Dividends payable | $ | 8,560 | $ | 8,286 | ||
| Accounts payable and accrued liabilities | 14,883 | 18,760 | ||||
| Current portion of share based and other compensation payable | 3,876 | 2,473 | ||||
| 27,319 | 29,519 | |||||
| Asset retirement obligation | 14,282 | 9,451 | ||||
| Share based and other compensation payable | 1,289 | 3,030 | ||||
| Long-term debt | 48,000 | 65,000 | ||||
| Deferred income tax liability | 59,577 | 39,107 | ||||
| Shareholders' equity: | ||||||
| Shareholders' capital | 317,202 | 280,311 | ||||
| Contributed surplus | 1,480 | 1,084 | ||||
| Deficit | (45,709 | ) | - | |||
| 272,973 | 281,395 | |||||
| $ | 423,440 | $ | 427,502 | |||
| CONSOLIDATED STATEMENTS OF INCOME | |||||||||||||
| AND COMPREHENSIVE INCOME | Three Months Ended | Year ended | |||||||||||
| (unaudited) | December 31 | December 31 | |||||||||||
| ($000s, except per share and weighted average data) | 2011 | 2010 | 2011 | 2010 | |||||||||
| Revenue: | |||||||||||||
| Royalty income and working interest sales | $ | 45,304 | $ | 36,525 | $ | 157,910 | $ | 138,155 | |||||
| Royalty expense and mineral tax | (1,087 | ) | (1,000 | ) | (4,197 | ) | (4,092 | ) | |||||
| 44,217 | 35,525 | 153,713 | 134,063 | ||||||||||
| Other expense | - | (1,850 | ) | - | (1,850 | ) | |||||||
| Expenses: | |||||||||||||
| Operating | 3,772 | 2,842 | 12,782 | 11,569 | |||||||||
| General and administrative | 1,468 | 1,664 | 7,029 | 7,803 | |||||||||
| Share based and other compensation | 1,268 | 1,329 | 2,190 | 3,771 | |||||||||
| Interest and financing | 610 | 811 | 2,907 | 3,601 | |||||||||
| Depletion and depreciation | 13,603 | 12,769 | 49,251 | 46,132 | |||||||||
| Accretion of asset retirement obligation | 83 | 90 | 344 | 352 | |||||||||
| Management fee | 857 | 877 | 3,401 | 3,016 | |||||||||
| 21,661 | 20,382 | 77,904 | 76,244 | ||||||||||
| Income before taxes | 22,556 | 13,293 | 75,809 | 55,969 | |||||||||
| Income and capital taxes: | |||||||||||||
| Income and capital taxes | 80 | 85 | 80 | 276 | |||||||||
| Deferred income tax expense | 6,443 | 1,821 | 20,470 | 6,344 | |||||||||
| 6,523 | 1,906 | 20,550 | 6,620 | ||||||||||
| Net income and comprehensive income | 16,033 | 11,387 | 55,259 | 49,349 | |||||||||
| Net income per share, basic and diluted | $ | 0.26 | $ | 0.19 | $ | 0.92 | $ | 0.85 | |||||
| Weighted average number of shares: | |||||||||||||
| Basic | 60,811,300 | 58,972,227 | 60,021,736 | 58,334,117 | |||||||||
| Diluted | 60,886,218 | 59,029,782 | 60,093,840 | 58,389,088 | |||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | Three Months Ended | Year ended | ||||||||||||
| December 31 | December 31 | |||||||||||||
| ($000s) (unaudited) | 2011 | 2010 | 2011 | 2010 | ||||||||||
| Cash provided by (used in): | ||||||||||||||
| Operating: | ||||||||||||||
| Net income | $ | 16,033 | $ | 11,387 | $ | 55,259 | $ | 49,349 | ||||||
| Items not involving cash: | ||||||||||||||
| Depletion and depreciation | 13,603 | 12,769 | 49,251 | 46,132 | ||||||||||
| Share based and other compensation | 1,268 | 1,329 | 2,190 | 3,771 | ||||||||||
| Deferred income tax expense | 6,443 | 1,821 | 20,470 | 6,344 | ||||||||||
| Accretion of asset retirement obligation | 83 | 90 | 344 | 352 | ||||||||||
| Shares issued in lieu of management fee | 857 | 877 | 3,401 | 3,016 | ||||||||||
| Expenditures on share based and other compensation | - | - | (2,440 | ) | (1,647 | ) | ||||||||
| Expenditures on reclamation | (42 | ) | (55 | ) | (245 | ) | (346 | ) | ||||||
| Changes in non-cash working capital | (5,650 | ) | (203 | ) | (9,860 | ) | 3,722 | |||||||
| 32,595 | 28,015 | 118,370 | 110,693 | |||||||||||
| Financing: | ||||||||||||||
| Long-term debt | (3,000 | ) | (5,000 | ) | (17,000 | ) | 20,000 | |||||||
| Dividends paid | (15,262 | ) | (17,895 | ) | (67,204 | ) | (72,184 | ) | ||||||
| (18,262 | ) | (22,895 | ) | (84,204 | ) | (52,184 | ) | |||||||
| Investing: | ||||||||||||||
| Deposit on acquisition | (5,000 | ) | - | (5,000 | ) | - | ||||||||
| Property and royalty acquisitions | 195 | (283 | ) | (7,467 | ) | (38,600 | ) | |||||||
| Capital expenditures | (10,910 | ) | (4,664 | ) | (25,649 | ) | (18,054 | ) | ||||||
| Change in reclamation fund | - | (150 | ) | 2,725 | (464 | ) | ||||||||
| Changes in non-cash working capital | 1,358 | (52 | ) | 980 | (1,414 | ) | ||||||||
| (14,357 | ) | (5,149 | ) | (34,411 | ) | (58,532 | ) | |||||||
| Decrease in cash | (24 | ) | (29 | ) | (245 | ) | (23 | ) | ||||||
| Cash, beginning of period | 188 | 438 | 409 | 432 | ||||||||||
| Cash, end of period | $ | 164 | $ | 409 | $ | 164 | $ | 409 | ||||||
| CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY | Year ended | ||||||
| December 31 | |||||||
| ($000s) (unaudited) | 2011 | 2010 | |||||
| Shareholders' capital: | |||||||
| Balance, beginning of year | $ | 280,311 | $ | 684,979 | |||
| Shares issued for dividend reinvestment plan | 33,490 | 25,695 | |||||
| Shares issued in lieu of management fee | 3,401 | 3,016 | |||||
| Elimination of deficit | - | (433,379 | ) | ||||
| Balance, end of year | 317,202 | 280,311 | |||||
| Contributed surplus: | |||||||
| Balance, beginning of year | 1,084 | 759 | |||||
| Share based compensation expense | 396 | 325 | |||||
| Balance, end of year | 1,480 | 1,084 | |||||
| Deficit: | |||||||
| Balance, beginning of year | - | (384,613 | ) | ||||
| Net income and comprehensive income | 55,259 | 49,349 | |||||
| Dividends declared | (100,968 | ) | (98,115 | ) | |||
| Elimination of deficit | - | 433,379 | |||||
| Balance, end of year | (45,709 | ) | - | ||||
| Total shareholders' equity | $ | 272,973 | $ | 281,395 | |||
Forward-Looking Statements
This news release offers our assessment of Freehold's future plans and operations as at March 14, 2012, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. These forward-looking statements 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;
- completion of pipeline projects and the timing thereof;
- foreign exchange rates;
- industry drilling, development activity on our royalty lands, our participation in emerging resource plays, and the potential impact of horizontal drilling on production and reserves;
- development of working interest properties;
- participation in the DRIP and our use of cash preserved through the DRIP;
- estimated capital budget and expenditures and the timing thereof;
- long-term debt at year end;
- average production and contribution from royalty lands;
- key operating assumptions;
- acquisition opportunities;
- deferred income tax and our expected taxability and the timing thereof; and
- our dividend policy.
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 crude 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 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 the body of this news release.
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.
You are further cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. These estimates may change, having either a positive or negative effect on net income, as further information becomes available and as the economic environment changes.
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. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.
Non-GAAP Financial Measures
Within this news release, references are made to terms commonly used as key performance indicators in the oil and gas industry, such as operating netback, funds from operations, funds from operations per share, finding, development and acquisition costs, recycle ratio, and net asset value. We believe that these measures 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.
Funds from operations is a financial term commonly used in the oil and gas industry. It is a key measure of our ability to generate cash, finance operations, and pay monthly dividends. Funds 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 net income or other measures of financial performance calculated in accordance with GAAP. We define funds from operations as net income adjusted for non-cash depletion and depreciation, share based and other compensation, deferred tax expense, accretion of asset retirement obligation, and management fee, and further adjusted for expenditures on reclamation. We consider funds from operations to be a key measure of operating performance as it demonstrates Freehold's ability to generate the necessary funds to fund capital expenditures and repay debt. We believe that such a measure provides a better assessment of Freehold's operations on a continuing basis by eliminating certain non-cash charges. From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share. A reconciliation of funds from operations to net income is provided below.
| RECONCILIATION OF NET INCOME | Three Months Ended | Twelve Months Ended | |||||||
| TO FUNDS FROM OPERATIONS | December 31 | December 31 | |||||||
| 2011 | 2010 | 2011 | 2010 | ||||||
| Net income | 16,033 | 11,387 | 55,259 | 49,349 | |||||
| Adjust for non-cash items: | |||||||||
| Depletion and depreciation | 13,603 | 12,769 | 49,251 | 46,132 | |||||
| Share based and other compensation | 1,268 | 1,329 | (250 | ) | 2,124 | ||||
| Deferred income tax | 6,443 | 1,821 | 20,470 | 6,344 | |||||
| Accretion of asset retirement obligation | 83 | 90 | 344 | 352 | |||||
| Management fee | 857 | 877 | 3,401 | 3,016 | |||||
| Adjust for cash item: | |||||||||
| Expenditures on reclamation | (42 | ) | (55 | ) | (245 | ) | (346 | ) | |
| Funds from operations | 38,245 | 28,218 | 128,230 | 106,971 | |||||
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 gas production during the period, with natural gas converted to equivalent barrels of oil as described above.
Contact Information:
Karen Taylor
Manager, Investor Relations and Corporate Secretary
403.221.0891 or Toll Free: 1.888.257.1873
403.221.0888 (FAX)
ktaylor@rife.com
www.freeholdroyalties.com