CALGARY, ALBERTA--(Marketwire - May 11, 2011) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced first quarter results for the period ended March 31, 2011.
Results at a Glance
Three Months Ended March 31
FINANCIAL ($000s, except as ------------------------------ Percentage
noted) 2011 2010 Change
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Gross revenue 36,232 36,569 -1%
Net income 15,313 11,342 35%
Per share, basic and
diluted($)(1) 0.26 0.20 30%
Cash provided by operating
activities 24,096 27,217 -11%
Per share ($) (1) 0.41 0.47 -13%
Funds generated from
operations(2) 27,322 27,745 -2%
Per share ($) (1) 0.46 0.48 -4%
Capital expenditures 4,665 2,652 76%
Property and royalty
acquisitions (net) 321 38,399 -99%
Dividends declared 24,950 24,265 3%
Per share ($) (1) (3) 0.42 0.42 0%
Long-term debt, period end 61,000 78,000 -22%
Shareholders' equity, period
end 279,676 295,172 -5%
Shares outstanding, period end
(000s) 59,536 57,926 3%
Average shares outstanding
(000s) (4) 59,343 57,700 3%
OPERATING
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Average daily production
(boe/d) (5) 7,490 7,331 2%
Average price realizations
($/boe) (5) 52.51 54.45 -4%
Operating netback ($/boe)(2)(5) 48.96 49.44 -1%
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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 Financial 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).
Freehold's results reflect, for the first time, the adoption of International Financial Reporting Standards effective January 1, 2011. Adoption required restatement, for comparative purposes, of amounts reported for the year ended December 31, 2010, including our opening balance sheet as at January 1, 2010. Our conversion to IFRS had no material impact on our operating cash flows and increased 2010 net income by 36%.
Overall, our results for the three months ended March 31 were similar to last year. WTI crude oil prices remain robust, having risen nearly 20% since the first quarter of last year. The global economic recovery has increased demand for oil, and fears of supply disruptions stemming from political chaos in the Middle East are driving oil futures contracts. Weakness in the U.S. dollar has also contributed to the rise in WTI. Conversely, a stronger Canadian dollar and wider price differentials for heavy oil have nullified the effect of this increase. The benchmark Western Canada Select fell 3% from the first quarter last year.
Natural gas prices remain depressed, as supply continues to outstrip demand in North America. The continuing low price environment for natural gas translates into marginal economics for low-productivity natural gas wells. At the same time, inventories remain high, augmented by new shale gas production. Concerns about the safety of hydraulic fracturing have led to a temporary moratorium in some shale gas jurisdictions and, in the U.S., President Obama has called for a broad-based panel to study the potential risks.
Royalty interest drilling was down 29% in the first quarter of 2011 as compared to Q1 2010 largely due to the drop in activity in the shallow gas area of southern Alberta. As at March 31, 2011, there were 82 (3.8 equivalent net) licensed drilling locations on our royalty lands compared with 58 (2.0 equivalent net) at the same time last year. Continued well licence activity is a positive indicator of future activity on our royalty lands.
Horizontal drilling techniques are increasingly being employed to access tight reservoirs and other resource plays, as are new technologies for more complex completions. Across our land base, more than half of the wells drilled last year and two thirds of the wells drilled to date this year were horizontal wells. 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.
When we began operations in 1996, virtually all our mineral title lands were leased to third parties. Over the years, our unleased mineral title acreage has grown - through acquisitions, lease expiries, surrenders, and defaults. We now have about 100,000 unleased acres and are actively working to crystallize the value of this undeveloped acreage through selective farm-outs and lease-outs to industry partners and by investing our own capital in the development of these lands. These efforts are starting to show results. Partnering with top tier industry operators, we have recently farmed-out the drilling of four wells in Alberta. The first two wells were drilled in the first quarter - both into the Cardium oil trend.
In the first quarter of 2011, we drilled five (2.6 net) oil wells in Southeast Saskatchewan, all of which were placed on production subsequent to quarter end. These wells were all drilled using horizontal, multi stage fracture techniques. Four (2.2 net) wells were in the Bakken and two (1.6 net) of these wells were operated by Freehold. In addition, two (1.0 net) Bakken oil wells drilled in the fourth quarter of 2010 were placed on production late in the first quarter and consequently had little impact on production volumes for the quarter.
Our Board has approved an $8 million increase in our capital budget for 2011 to $28 million. About 75% of our 2011 capital expenditures will be 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 $149 million of available capacity under our credit facilities to take advantage of accretive opportunities.
Heavy snowfall this past winter and extremely wet spring conditions throughout western Canada could mean an extended spring break-up and restricted access to leases. Resulting delays in drilling activity could have a negative impact on production levels over the next two quarters. Based on our $28 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 average approximately 7,100 boe per day in 2011.
Cash preserved through our dividend reinvestment plan enhances our ability to fund our capital program, strengthen our balance sheet, and pursue acquisition opportunities, while maintaining an attractive dividend payout ratio. 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 approximately 20% of pre-tax cash flow, which may reduce the amount available for dividends. In addition, the March federal budget proposed a new regime for the taxation of partnership income. When enacted, the new regime will accelerate tax on our partnership income, subject to transitional relief over five years.
The following table summarizes our key operating assumptions for 2011, updated to reflect actual results for the first quarter and our current expectations for the remainder of the year. We have adjusted our commodity price and foreign exchange assumptions based on current market conditions. Based on our increased capital spending and updated pricing assumptions (and excluding any potential acquisitions) we anticipate reducing long-term debt to $50 million by year end.
2011 Key Operating Assumptions
May 11, 2011 March 2, 2011
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Average daily production boe/d 7,100 7,100
Average WTI oil price US$/bbl 90.00 80.00
Average exchange rate Cdn$/US$ 1.00 0.95
Average heavy oil price
differential (1) Cdn$/bbl 15.00 13.00
Average AECO natural gas price Cdn$/Mcf 3.65 4.25
Average operating costs $/boe 4.50 4.50
Average general and
administrative costs (2) $/boe 3.50 3.50
Capital expenditures $ millions 28 20
Proceeds from DRIP (3) $ millions 28 27
Long-term debt at year end $ millions 50 50
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.
May Dividend Announcement
The Board of Directors has declared the May dividend of $0.14 per share, which will be paid on June 15, 2011 to shareholders of record on May 31, 2011 (ex-dividend date May 27, 2011). Including the June 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. These dividends are designated as "eligible dividends" for Canadian income tax purposes. As previously announced, Freehold's dividend reinvestment plan (DRIP) has been amended to allow for the issuance of shares from treasury at a 5% discount to market. The amended DRIP document is available on our website.
Availability on SEDAR
Freehold's 2011 first 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 May 11, 2011, and contains forward-looking statements that we believe allow readers to better understand our business and prospects, including the following expectations:
-- 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 and our
participation in emerging resource plays;
-- 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;
-- our dividend policy; and
-- our 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 herein, 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.
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 Financial Measures
In 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 and funds generated from operations are useful supplemental measures for management and investors to analyze operating performance and liquidity, and we use these terms to facilitate the understanding and comparability of our results of operations. However, these terms do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.
Operating netback, which is calculated as average unit sales price less royalties and operating expenses, represents the cash margin for product sold, calculated on a per boe basis.
Funds generated from operations is a 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 dividends. 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 in this news release 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.
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.
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