Freehold Royalty Trust

Freehold Royalty Trust

November 10, 2009 18:02 ET

Freehold Royalty Trust Announces 2009 Third Quarter Results, 17% Increase in Monthly Distributions, and Extra Distribution for 2009

CALGARY, ALBERTA--(Marketwire - Nov. 10, 2009) - Freehold Royalty Trust (Freehold or the Trust) (TSX:FRU.UN) today announced third quarter results for the period ended September 30, 2009.

RESULTS AT A GLANCE Three Months Ended Nine Months Ended
September 30 September 30
Financial ($000s, ------------------------------------------------------
except as noted) 2009 2008 Change 2009 2008 Change
Gross revenue 29,016 59,780 -51% 84,798 169,655 -50%
Net income 7,853 36,772 -79% 17,020 96,582 -82%
Per Trust Unit,
basic and diluted ($) 0.16 0.74 -79% 0.34 1.96 -83%
Cash provided by
operating activities 26,215 57,380 -54% 69,722 137,580 -49%
Per Trust Unit ($) 0.53 1.16 -54% 1.41 2.79 -49%
Funds generated from
operations (1) 24,189 51,977 -53% 64,641 144,342 -55%
Per Trust Unit ($) 0.49 1.05 -53% 1.31 2.92 -55%
Capital expenditures 7,368 4,885 51% 11,056 9,222 20%
Property and royalty
acquisitions (net) - 8,475 0% - 8,475 0%
declared 16,850 37,050 -55% 46,543 89,362 -48%
Per Trust Unit ($)
(2) 0.34 0.75 -55% 0.94 1.81 -48%
Long-term debt,
period end 147,000 141,000 4% 147,000 141,000 4%
Unitholders' equity,
period end 192,103 260,612 -26% 192,103 260,612 -26%
Trust Units (000s)
(3) 49,543 49,389 0% 49,500 49,353 0%
Operating (per boe)
Average daily
production (boe/d) 6,994 7,613 -8% 7,268 7,812 -7%
Average price
realizations ($) 44.01 83.47 -47% 41.57 77.75 -47%
Operating netback ($)
(1) 42.16 79.14 -47% 37.55 72.90 -48%

(1) See non-GAAP measures.
(2) Based on the number of Trust Units issued and outstanding at each record
(3) Weighted average number of Trust Units outstanding during the period,
(4) See "Conversion of Natural Gas to Barrels of Oil Equivalent (boe)".

Our results for the third quarter and nine months ended September 30, 2009 reflect sharply lower commodity prices compared with last year. Production volumes were also lower than last year, reflecting the reduction in industry drilling activity and our decision to defer major capital projects to the second half of 2009.


While WTI crude oil prices remain volatile, the improving global economic outlook has fuelled a gradual oil price improvement since the first quarter of this year - with the benefit being partly offset by the corresponding rise of the Canadian dollar. As anticipated, light/heavy oil differentials widened in the third quarter, marking the end of the summer asphalt paving season. The differential remains at historical lows, however, due to continued strong demand for heavier crude by North American refiners. We believe this trend will continue, which is positive for Freehold given our product mix.

The short-term outlook for natural gas remains clouded. Marginal production continues to be shut-in and natural gas directed drilling curtailed. With stockpiles high and demand low, prices continued to fall in the third quarter. Leading into the winter heating season, natural gas in storage is at record levels. Over the coming months, natural gas prices will depend largely on weather-related demand. We believe that lower reinvestment will reduce natural gas supply and lead to an eventual price recovery as economic conditions improve, but the timing of such a recovery remains uncertain. In this environment, we are fortunate to have an oil-weighted portfolio and oil-weighted development opportunities.


As expected, drilling on our royalty lands continues to reflect the overall decline in industry drilling, which was down 64% from last year. The Alberta Government's short-term stimulus plan to encourage conventional oil and natural gas activity in the province is expected to have a positive impact on industry activity levels in the coming months, although producers may delay initial production (particularly for natural gas wells) until prices improve. While operators may focus on opportunities on Crown lands to take advantage of the incentives, we anticipate that increased activity will be eventually reflected on our royalty lands.

As at September 30, 2009, there were 61 (Q3 2008 - 79) licensed drilling locations on our royalty lands, up from only 43 at the end of June, perhaps signalling an improvement in industry activity. That outlook is shared by the Canadian Association of Oilwell Drilling Contractors, which expects a 4% increase in activity next year. The CAODC's forecast suggests that most of the improvement in 2010 will come in the last half of the year and assumes some improvement in natural gas prices. The Canadian Association of Petroleum Producers also predicts a modest increase in capital spending in 2010 versus 2009.

Improving access to equity markets is another sign that we might be nearing the bottom of the cycle. In recent months, a number of financings for oil and gas companies have been completed. Although access to capital has moderately improved, producers' capital investment programs continue to be funded primarily from cash flows.


Third quarter drilling on working interest properties was significantly higher than last year on a net basis, as we drilled our first two 100% working interest wells on our Bakken oil-prone title lands in Southeast Saskatchewan. Both wells were recently fracture stimulated using multi-stage packer technology along the horizontal leg. Initial production tests are underway. In addition, we participated as to our title interest in one (0.5 net) Bakken well at Taylorton, near the Saskatchewan/North Dakota border. The economics of our participation are extremely attractive, as we own the mineral rights. The production is light oil (which we intend to take in kind) and yields very high netbacks. Since 2005, we have participated in the drilling of 25 (6.5 net) Bakken wells on our title lands.

In Alberta, we completed our 2009 infill drilling program at Hayter with 11 (2.6 net) horizontal wells, and participated in the drilling of three (0.3 net) wells at Pembina Cardium Unit #9. The Pembina unit wells were part of a pilot program initiated in the first quarter, using horizontal drilling, staged fracture stimulation, and micro-seismic technology. Production from this successful third quarter development activity will be reflected in our volumes over the next two quarters.

Successful drilling, particularly in Southeast Saskatchewan, has led to additional oil development opportunities on our working interest properties. As a result, we have increased our 2009 capital program by $2 million to $14 million. Fourth quarter capital expenditures will be approximately $3 million.

Our Board has approved a capital budget for 2010 of $24 million. This is a substantial increase over 2009, as we plan to accelerate development of our Bakken-prone title lands in Southeast Saskatchewan. In addition, we anticipate an active program at Pembina Cardium Unit #9 as the operator continues with field redevelopment using horizontal infill drilling and multistage fracture technology. Based on this activity, and excluding any potential acquisitions, our 2010 production is forecast to average 7,000 boe per day. Our key operating assumptions are outlined below.

(as at November 10, 2009) 2010 2009
Average daily production (boe/d) 7,000 7,300
Average WTI oil price (US$/bbl) 75.00 60.00
Average AECO natural gas price (Cdn$/Mcf) 5.00 3.70
Average exchange rate (Cdn$/US$) 0.90 0.88
Average operating costs ($/boe) 4.75 4.10
Average G&A costs (1) 3.00 2.90
Capital expenditures ($ millions) 24.0 14.0
Long-term debt at year end ($ millions) 125.0 146.0
Weighted average Trust Units outstanding (thousands) 50,734 49,563
Estimated portion of distributions taxable as income (%) 90-100% 90-100%

(1) Excludes unit based compensation.


Due to the continued strength of oil prices, we are increasing monthly distributions by 17% and declaring an additional payment for 2009 as we expect to have excess cash from operating activities this year. The regular monthly distribution will be $0.14 per Trust Unit until further notice. The Board of Directors has declared the November distribution of $0.14 per Trust Unit and an extra distribution of $0.06 per Trust Unit (for a total of $0.20 per Trust Unit) to be paid concurrently on December 15, 2009 to Unitholders of record on November 30, 2009 (ex-distribution date November 26, 2009). Including the December 15 payment, our 12-month trailing cash distributions total $1.86 per Trust Unit.


In the third quarter of 2009, Peter Harrison joined CN Investment Division. Because the Manager of Freehold is a wholly-owned subsidiary of the CN Pension Trust Funds, Mr. Harrison is no longer considered an independent director of Freehold. To maintain the number of Manager-appointed directors at two, Russell Hiscock of CN Investment Division has stepped down from the Board. We thank Mr. Hiscock for his valuable wisdom, advice, and support as a member of our Board. The Manager-appointed directors are now Peter Harrison and Bill Ingram.

We are pleased to announce the appointment of a new independent director, Rodger Tourigny, to Freehold's Board effective November 10, 2009. A Chartered Accountant, Mr. Tourigny is President of Tourigny Management Ltd., a private consulting company providing services to the oil and gas, financial services, and real estate sectors since 1979. Mr. Tourigny was appointed to the Audit, Compensation, and Corporate SIFT Tax Strategy committees, and will serve as Chair of the Audit Committee.

Michael Okrusko, Vice-President, Land, has indicated his intention to retire during 2010 after serving for more than 28 years with Rife Resources, the Manager of the Trust. We appreciate Mike's significant contributions toward the success of Freehold since 1996. The Board is working with the Manager on the succession planning process to provide for a smooth transition.


Freehold's 2009 third 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 or on our website.


This news release offers our assessment of Freehold's future plans and operations as at November 10, 2009, and contains forward-looking statements including our expectations for improving economic conditions, access to capital markets, industry drilling and activity on our royalty lands, capital expenditures, average production, commodity prices, demand for heavier crude, reduced natural gas supply, and acquisition opportunities. These forward-looking statements are provided to allow readers to better understand our business and prospects.

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, environmental risks, taxation, royalties, regulation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, and our ability to access sufficient capital from internal and external sources. Risks are described in more detail in our 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, 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 third quarter report.

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 news release 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.


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.


Within this news release, references are made to terms commonly used as key performance indicators in the oil and gas industry. We believe that operating netback and funds generated from operations are useful supplemental measures 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 generated from operations is a financial term commonly used in the oil and 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 Trust Unit is calculated based on the weighted average number of Trust Units outstanding consistent with the calculation of net income per Trust Unit.

In addition, we refer to various per boe figures, such as revenues and costs, 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.

CUSIP: 355904103

Contact Information

  • Freehold Royalty Trust
    Bill Ingram
    President and CEO
    (403) 221-0822
    Freehold Royalty Trust
    Darren Gunderson
    Vice-President Finance and CFO
    (403) 221-0811
    Freehold Royalty Trust
    Karen Taylor
    Manager, Investor Relations & Corporate Secretary
    (403) 221-0891
    Freehold Royalty Trust
    (403) 221-0802 or Toll free in Canada/U.S. 1-888-257-1873
    (403) 221-0888 (FAX)