CALGARY, ALBERTA--(Marketwire - Aug. 10, 2011) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced second quarter results for the period ended June 30, 2011.

Results at a                                                                
                    Three Months Ended              Six Months Ended        
                               June 30                       June 30        
 ($000s, except                                                             
 as noted)             2011       2010 Change        2011       2010 Change 
Gross revenue        40,555     32,424     25%     76,787     68,993     11%
Net income           16,717     13,621     23%     27,936     24,963     12%
 Per share,                                                                 
  basic and                                                                 
  diluted ($)                                                               
  (1)                  0.28       0.23     22%       0.47       0.43      9%
Cash provided by                                                            
 activities          31,424     28,757      9%     55,520     55,974     -1%
 Per share ($)                                                              
  (1)                  0.53       0.49      8%       0.93       0.97     -4%
Funds generated                                                             
 from operations                                                            
 (2)                 33,891     25,197     35%     61,213     52,942     16%
 Per share ($)                                                              
  (1)                  0.57       0.43     33%       1.03       0.91     13%
 expenditures         4,537      4,735     -4%      9,202      7,387     25%
Property and                                                                
 (net)                   44         71    -38%        365     38,470    -99%
 declared            25,111     24,436      3%     50,061     48,701      3%
 Per share ($)                                                              
  (1) (3)              0.42       0.42      0%       0.84       0.84      0%
Long-term debt,                                                             
 period end          54,000     73,000    -26%     54,000     73,000    -26%
 equity, period                                                             
 end                275,874    291,233     -5%    275,874    291,233     -5%
 period end                                                                 
 (000s)              59,954     58,335      3%     59,954     58,335      3%
Average shares                                                              
 (000s) (4)          59,716     58,112      3%     59,531     57,907      3%
Average daily                                                               
 (boe/d) (5)          7,445      7,655     -3%      7,467      7,494      0%
Average price                                                               
 ($/boe) (5)          57.61      45.56     26%      55.07      49.89     10%
 netback ($/boe)                                                            
 (2) (5)              53.82      40.96     31%      51.39      45.08     14%

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
4.  Weighted average number of shares outstanding during the period, basic. 
5.  See Conversion of Natural Gas to Barrels of Oil Equivalent (boe). 

We delivered strong results for the second quarter of 2011, as our oil-weighted production continued to benefit from higher oil prices. Revenue, operating netback, and funds generated from operations were all substantially higher than last year's cash metrics; net income was 23% higher, mainly due to higher revenue.

In the second quarter of 2011, royalty interests comprised 77% of total volumes produced; prior period adjustments (mostly natural gas and natural gas liquids) increased production by 400 boe per day. Our production mix for the first half of 2011 was approximately 38% natural gas and 62% liquids (29% heavy oil, 29% light and medium oil, and 4% natural gas liquids).

Business Environment

In light of persistently low natural gas prices, industry activity has shifted from drilling for dry gas to drilling for oil and liquids-rich gas. Crown land sale bids are on the rise and well licensing activity was up nearly 30% in the first half of the year. In June, the Canadian Association of Oilwell Drilling Contractors released an updated forecast, projecting high activity levels through the remainder of the year. However, a prolonged spring breakup, forest fires in northern Alberta, and flooding in southeastern Saskatchewan have created a challenging operating environment, which will undoubtedly cause drilling and production delays in the last half of this year. As well, the weather-related delays will increase competition for goods and services, adding to growing industry inflationary pressures.

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, 53% of the wells drilled last year and 63% 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.

Royalty Interests

Because of the geographic diversity of our royalty holdings, our second quarter results were largely unaffected by the fires and flooding. On an equivalent net basis, drilling on our royalty lands improved significantly, despite wet spring conditions. Non-unitized drilling rose 157%.

As at June 30, 2011, there were 135 (5.1 equivalent net) licensed drilling locations on our royalty lands, up from 119 (4.1 equivalent net) at the same time last year. The 24% increase in well licences is a positive indicator of future activity on our royalty lands. We caution, however, that flooding is still an issue in southeastern Saskatchewan and the public database we rely on to obtain production information does not yet include data for May and June. Thus, we may see the impact of restricted access on reported drilling activity and production levels in the last half of the year. However, as a result of stronger than expected production performance for the first half of the year, we are increasing our production guidance for the year by 200 boe per day.

The ownership of coalbed methane (CBM) on freehold lands has been uncertain in Alberta due to ongoing disputes between coal owners and natural gas owners. In July, the Court of Queen's Bench of Alberta confirmed that CBM is natural gas and the right to exploit CBM is granted to natural gas leases under the terms of standard petroleum and natural gas leases. This ruling is positive for Freehold as it clarifies ownership of CBM rights in favour of the natural gas rights holder (for both Crown and freehold lands), which should provide more certainty to the industry and encourage development of CBM.

Working Interests

In the second quarter of 2011, we participated in the drilling of eight (1.6 net) wells for a 100% success rate. Seven wells were drilled in Saskatchewan, of which three (0.6 net) were horizontal Bakken oil wells, one (0.2 net) was a Tilston oil well, and three (0.6 net) were Waseca heavy oil wells. In Alberta, one (0.2 net) horizontal Glauconite natural gas well was drilled at Willesden Green. This drilling activity had little impact on production volumes for the quarter.

Flooding in Southeast Saskatchewan has delayed our capital program, and we now expect to defer the drilling of three (2.0 net) horizontal wells until 2012. This will result in a $6 million reduction in our 2011 capital program. Capital spending in the second half of the year is expected to total $12.8 million. The majority of our activity will be in the fourth quarter, and subject to partner approval, availability of equipment and services, and access to the leases (drying and freeze up). In Saskatchewan, we plan to complete and tie-in wells drilled in the second quarter, and participate in the drilling of six (3.0 net wells).

Our plans also include four (0.9 net) infill wells at Hayter, Alberta. This is a reduction from our historical infill program of 10 wells per year for the last 10 years as we are approaching the limits of well density. An enhanced oil recovery study is underway to evaluate the feasibility of pattern flooding to change sweep patterns and recover incremental oil.

Guidance Update

Under our updated assumptions, the additional cash flow generated will be used to reduce long-term debt or for acquisitions. We also have $156 million of available capacity under our credit facilities to take advantage of acquisition opportunities. In addition, cash preserved through our dividend reinvestment plan continues to enhance our ability to fund our capital program, strengthen our balance sheet, and pursue acquisition opportunities, while allowing us to maintain an attractive dividend payout ratio.

Freehold is subject to corporate taxation; however we do not expect to pay corporate income tax on income earned in 2011. Starting in 2012, we expect to be cash taxable at a rate of approximately 20% of funds generated from operations, which may reduce the amount available for dividends. In addition, the March federal budget introduced a new regime for the taxation of partnership income that will accelerate tax on our partnership income, subject to transitional relief over five years.

Our goal is to hold the monthly dividend steady at $0.14 ($1.68 annually) per share, subject to the satisfaction of statutory liquidity and solvency tests. Future dividends may vary, however, depending on fluctuations in commodity prices, production volumes, foreign exchange rates, capital expenditures, participation levels in the dividend reinvestment plan (DRIP), debt service requirements, costs, and taxes.

The following table summarizes our key operating assumptions, updated to reflect actual results for the first half of 2011 and our current expectations for the remainder of the year. WTI oil prices were very strong in the first half of the year, averaging US$98.30 per barrel, but are expected to be somewhat lower in the second half.

2011 Key Operating                                                          
                                             Aug. 10      May 11      Mar. 2
                                                2011        2011        2011
Average daily production           boe/d       7,300       7,100       7,100
Average WTI oil price            US$/bbl       95.00       90.00       80.00
Average exchange rate           Cdn$/US$        1.03        1.00        0.95
Average heavy oil price                                                     
 differential (1)               Cdn$/bbl       19.00       15.00       13.00
Average AECO natural gas                                                    
 price                          Cdn$/Mcf        3.65        3.65        4.25
Average operating costs            $/boe        4.50        4.50        4.50
Average general and                                                         
 administrative costs (2)          $/boe        3.50        3.50        3.50
Capital expenditures          $ millions          22          28          20
Proceeds from DRIP (3)        $ millions          28          28          27
Long-term debt at year end    $ millions          41          50          50
Weighted average shares                                                     
 outstanding                    millions          60          60          60

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. 

August Dividend Announcement

The Board of Directors has declared the August dividend of $0.14 per share, which will be paid on September 15, 2011 to shareholders of record on August 31, 2011 (ex-dividend date August 29, 2011). Including the September 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.

Availability on SEDAR

Freehold's 2011 second 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.

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at August 10, 2011, 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; 
--  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
--  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; 
--  deferred income tax and our expected taxability; 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 Annual Information Form.

With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future oil and natural gas prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future participation rates in the DRIP and use of cash preserved through the DRIP, future legislation, the cost of developing and producing our assets, our ability and the ability of our lessees to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers, our expectation for the consumption of crude oil and natural gas, our expectation for industry drilling levels, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through development and acquisition activities. The key operating assumptions with respect to the forward-looking statements referred to above are detailed in our discussion of the Business Environment.

You are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is to update our key operating assumptions quarterly and, except as required by law, we do not undertake to update any other forward-looking statements.

Conversion of Natural Gas To Barrels of Oil Equivalent (BOE)

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation.

Non-GAAP Financial Measures

Within this news release, references are made to terms commonly used as key performance indicators in the oil and natural gas industry. We believe that operating netback 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 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 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 throughout this report are based on cash provided by operating activities before changes in non-cash working capital as per the Statements of Cash Flows. Funds generated from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.

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:

Freehold Royalties Ltd.
Karen Taylor
Manager, Investor Relations and Corporate Secretary
403.221.0891 or Toll Free: 1.888.257.1873
403.221.0888 (FAX)