March 07, 2013 at 17:01 PM EST
Freehold Royalties Ltd. Announces 2012 Fourth Quarter Results and Year-end Reserves

CALGARY, ALBERTA -- (Marketwire) -- 03/07/13 -- Freehold Royalties Ltd. (Freehold) (TSX: FRU) today announced 2012 fourth quarter results and reserves as at December 31, 2012.

Results at a Glance


                         Three Months Ended         Twelve Months Ended
FINANCIAL HIGHLIGHTS        December 31                 December 31
                    --------------------------------------------------------
($000s, except as
 noted)                   2012     2011  Change       2012      2011 Change
----------------------------------------------------------------------------
Gross revenue           45,794   45,304       1%   168,134   157,910      6%
Net income              13,431   16,033     -16%    46,328    55,259    -16%
  Per share, basic
   and diluted ($)        0.20     0.26     -23%      0.71      0.92    -23%
Cash flow from
 operating
 activities             38,183   32,595      17%   138,132   118,370     17%
  Per share ($)           0.58     0.54       7%      2.13      1.97      8%
Capital expenditures     7,743   10,910     -29%    36,746    25,649     43%
Property and royalty
 acquisitions (net)        243     (195)      -     60,852     7,467      -
Dividends paid in
 cash (1)               21,060   15,262      38%    81,436    67,204     21%
Dividends paid in
 shares (DRIP) (1)       6,672   10,232     -35%    27,414    33,490    -18%
  Average DRIP
   participation
   rate (%) (2)             24       40     -40%        25        33    -24%
Dividends declared
 (3)                    27,787   25,585       9%   109,568   100,968      9%
  Per share ($) (4)       0.42     0.42       0%      1.68      1.68      0%
Long-term debt,
 period end             18,000   48,000     -63%    18,000    48,000    -63%
Shares outstanding,
 period end (000s)      66,270   61,141       8%    66,270    61,141      8%
Average shares
 outstanding (000s)
 (5)                    66,091   60,811       9%    64,880    60,022      8%
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OPERATING HIGHLIGHTS
Average daily
 production (boe/d)
 (6) (7)                 9,510    7,773      22%     8,850     7,476     18%
Average realized
 price ($/boe) (6)       51.55    61.90     -17%     51.00     56.31     -9%
Operating netback
 ($/boe) (6) (8)         44.59    56.56     -21%     45.09     51.65    -13%
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(1) Excludes dividend declared in December and paid in January.
(2) Participation in Freehold's dividend reinvestment plan (DRIP) ranged
    between 17% and 41% in 2012 and is subject to change monthly at the
    participants' discretion.
(3) Includes dividend declared in December and paid in January.
(4) Based on the number of shares issued and outstanding at each record
    date.
(5) Weighted average number of shares outstanding during the period, basic.
(6) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).
(7) Our production mix in 2012 was approximately 36% natural gas and 64%
    liquids (34% light and medium oil, 25% heavy oil, and 5% NGL).
(8) See Non-GAAP Financial Measures.

March Dividend Announcement

The Board of Directors has declared the March dividend of $0.14 per share, which will be paid on April 15, 2013 to shareholders of record on March 31, 2013. Including the April 15 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 16 years, we have paid out over $1.1 billion to our shareholders.

2012 Fourth Quarter Highlights

Freehold delivered strong operational results in the fourth quarter of 2012. Robust production volumes drove increases in revenue and cash flow from operating activities despite lower average realized prices.


--  Average production for the fourth quarter was 22% higher than last year.
    Drilling activities, including flush production from newly completed
    horizontal wells, accounted for about two-thirds of the increase; prior
    period adjustments (650 boe per day versus 350 boe per day in fourth
    quarter last year) and acquisitions during 2012 accounted for the
    remainder.
--  Dividends for the fourth quarter of 2012 totalled $0.42 per share,
    unchanged from last year.
--  Average DRIP participation was 24% in the fourth quarter of 2012 (Q4
    2011 - 40%), allowing us to retain $6.7 million (Q4 2011 - $10.2
    million) in dividend payments by issuing shares from treasury.
--  Net income of $13.4 million was 16% lower than last year, mainly as a
    result of increased depletion and depreciation expense, higher royalty
    expense, and higher operating expense due to a higher production base.
    Non-cash charges (excluding current income tax) included in net income
    amounted to $18.1 million (Q4 2011 - $22.3 million).
--  Net capital expenditures on our working interest properties totalled
    $7.7 million in the fourth quarter (Q4 2011 - $10.9 million), the
    majority of which was incurred on horizontal drilling and multi-stage
    fracture well completions in southeast Saskatchewan.
--  Long-term debt was $18.0 million at December 31, 2012, down $7.0 million
    from the third quarter as excess funds from operations were applied to
    debt repayment.

2012 Year-end Reserves and Land Highlights

Freehold's reserves data 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. Reserve values do not include potential reserve additions that may occur as a result of future drilling on most of our royalty lands.


--  Net proved plus probable reserves at December 31, 2012 totalled 24.4
    MMboe, with reserves assigned to 22,589 wells. Net proved plus probable
    royalty interest reserves increased 10% year-over-year, and net proved
    plus probable working interest reserves increased 12%. Approximately 62%
    of our net reserves are in the proved category, and 93% of our net
    proved reserves are producing. On a boe basis, net reserves are 60%
    liquids (30% heavy oil, 24% light and medium oil, 6% natural gas
    liquids) and 40% natural gas.
--  Net proved plus probable reserve additions totalled 5.3 MMboe (45%
    liquids). Drilling on our royalty lands added 1.0 MMboe (19%) of net
    proved plus probable reserves, development activities added 0.8 MMboe
    (15%), and acquisitions added 3.5 MMboe (66%). Based on this, we
    replaced approximately 167% of 2012 production.
--  Freehold's finding costs are calculated based on net reserves. In 2012,
    finding and development costs for net proved plus probable reserves were
    $21.37 per boe, while acquisition costs were $17.47 per boe and the all-
    in finding, development and acquisition (FD&A) cost was $18.80 per boe
    (including changes in future development capital). Based on an operating
    netback of $45.09 per boe in 2012, these activities resulted in a
    recycle ratio of 2.4 times the capital invested, and a three-year
    average recycle ratio of 2.1.
--  Our land holdings as at December 31, 2012 encompassed 3.0 million gross
    acres, up 9% from last year mainly as a result of acquisitions. Royalty
    interests comprised 94% of our acreage. Our undeveloped land was
    independently valued by Seaton-Jordan & Associates Ltd., at $80.2
    million.

Royalty Interest Activity

On an equivalent net basis, 85% of the royalty wells drilled on our lands during 2012 were oil wells (2011 - 78%) due to the oil-prone nature of our lands. As well, over 66% of the equivalent net wells drilled on our royalty lands in 2012 were horizontal wells, up from 59% last year.

Our royalty lands give us exposure to several of the attractive resource plays employing horizontal drilling, including Bakken and Mississippian light oil in southeast Saskatchewan, heavy oil in the Lloydminster area, and Cardium light oil in west-central Alberta. Over one quarter of the royalty wells drilled in the fourth quarter of 2012 had a Cardium target. Continued success with horizontal drilling (for both oil and liquids-rich natural gas) is positive and bodes well for improved well productivity.

As at December 31, 2012, there were 99 (5.9 equivalent net) licensed drilling locations on our royalty lands, compared with 106 (5.4 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.


ROYALTY INTEREST      Three Months Ended            Twelve Months Ended
 WELLS DRILLED            December 31                   December 31
                      2012           2011           2012           2011
                ------------------------------------------------------------
                         Equiv.         Equiv.         Equiv.         Equiv.
                  Gross Net (1)  Gross Net (1)  Gross Net (1)  Gross Net (1)
----------------------------------------------------------------------------
Non-unitized         57     2.6    102     4.9    231    11.6    301    14.4
Unitized (2)         30     0.1     60     0.4    200     1.2    322     1.3
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Total                87     2.7    162     5.3    431    12.8    623    15.7
----------------------------------------------------------------------------
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(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.

Working Interest Activity

Our development plans are primarily oil related, and are focused almost entirely on our own mineral title lands, where we have chosen to invest our own capital on attractive, low-risk opportunities.

In the fourth quarter of 2012, capital expenditures amounted to $7.7 million, the majority of which was spent to complete, equip, and tie-in wells drilled in southeast Saskatchewan during the third quarter. We participated in the drilling of seven (1.3 net) wells with a 100% success rate.


--  In Saskatchewan, we participated in the drilling of two (0.3 net)
    vertical and one (0.1 net) horizontal Frobisher oil wells, as well as
    two (0.6 net) Bakken horizontal oil wells.
--  In Alberta, we participated in one (0.1 net) horizontal Viking light oil
    well at Redwater and one (0.2 net) horizontal Cardium oil well at
    Minnehik Buck Lake.

This drilling activity had little effect on production levels in the fourth quarter but is expected to add to our production base in 2013.


WORKING INTEREST
 WELLS DRILLED        Three Months Ended           Twelve Months Ended
 (1)                      December 31                   December 31
                      2012           2011           2012           2011
                ------------------------------------------------------------
                  Gross     Net  Gross     Net  Gross     Net  Gross     Net
----------------------------------------------------------------------------
Oil                   7     1.3      9     3.8     36    13.5     29    11.1
Natural gas           -       -      -       -      -       -      3     0.4
Other                 -       -      1     0.1      1     0.6      2     0.1
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Total                 7     1.3     10     3.9     37    14.1     34    11.6
----------------------------------------------------------------------------
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(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 Interest Wells
    Drilled table above.

Operating Expense

Total operating expense of $4.8 million ($5.51 per boe) was 28% higher than the fourth quarter last year (4% higher on a per boe basis). The increase correlates to the increase in working interest production volumes, as we do not incur operating expense on our royalty interest production.


GROSS REVENUE BY PRODUCT    Three Months Ended       Twelve Months Ended
                               December 31               December 31
                        ----------------------------------------------------
($000s)                      2012     2011 Change      2012     2011 Change
----------------------------------------------------------------------------
Royalty Interest
  Oil                      20,503   25,419    -19%   87,721   85,231      3%
  NGL                       1,512    2,014    -25%    6,887    6,495      6%
  Natural gas               3,831    3,402     13%   10,501   15,581    -33%
  Other (1)                   556      808    -31%    2,525    3,206    -21%
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  Total royalty interest
   revenue                 26,402   31,643    -17%  107,634  110,513     -3%
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Working Interest
  Oil                      17,801   11,847     50%   55,577   40,786     36%
  NGL                         476      655    -27%    1,870    2,100    -11%
  Natural gas                 978      922      6%    2,640    3,447    -23%
  Other (1)                   137      237    -42%      413    1,064    -61%
----------------------------------------------------------------------------
  Total working interest
   revenue                 19,392   13,661     42%   60,500   47,397     28%
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Total
  Oil                      38,304   37,266      3%  143,298  126,017     14%
  NGL                       1,988    2,669    -26%    8,757    8,595      2%
  Natural gas               4,809    4,324     11%   13,141   19,028    -31%
  Other (1)                   693    1,045    -34%    2,938    4,270    -31%
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  Total gross revenue      45,794   45,304      1%  168,134  157,910      6%
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(1) Other includes potash, sulphur, lease rentals, and other revenue for
    royalty interest, and processing fees, interest, and other revenue for
    working interest.

Fourth Quarter Production

Average production in the fourth quarter of 2012 was 1,737 boe per day higher than last year. Oil and natural gas liquids (NGL) production rose 22%, and natural gas production rose 26%.


--  Royalty production volumes were 594 boe per day higher than last year,
    mainly as a result of royalty interests acquired during 2012 (which were
    90% natural gas) and prior period adjustments due to the ongoing work of
    our audit team. Natural gas production was up 30%, while oil and NGL
    production declined 2%.
--  Working interest production volumes were 1,143 boe per day higher than
    last year as a result of high activity levels in 2012 and flush
    production from newly completed wells in southeast Saskatchewan. Oil and
    NGL production was up 69% and natural gas production was up 12%.

AVERAGE DAILY PRODUCTION Royalty Interest  Working Interest       Total
                        ----------------------------------------------------
Three months ended
 December 31                2012      2011    2012      2011    2012    2011
----------------------------------------------------------------------------
  Oil (bbls/d)             3,190     3,262   2,561     1,461   5,751   4,723
  NGL (bbls/d)               267       252      88       106     355     358
----------------------------------------------------------------------------
  Total oil and NGL
   (bbls/d)                3,457     3,514   2,649     1,567   6,106   5,081
  Natural gas (Mcf/d)     17,105    13,198   3,315     2,952  20,420  16,150
  Oil equivalent (boe/d)   6,308     5,714   3,202     2,059   9,510   7,773
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Commodity Prices

In the fourth quarter of 2012, the benchmark West Texas Intermediate (WTI) crude oil price averaged US$88.18 per barrel, 6% lower than the prior year. Prices deteriorated during the quarter, and WTI also continues to trade at a discount to Brent crude, the global benchmark. Historically, WTI has traded at a slight premium over Brent; however during the last two years, WTI has traded consistently at a discount to Brent as a result of market access constraints.

Crude oil supply in North America is growing, primarily from the Canadian oil sands and tight oil plays in western Canada, North Dakota, Montana, and Texas, and global demand remains strong. However, refinery outages and pipeline bottlenecks in the U.S. Midwest have severely reduced access to the Texas and Louisiana Gulf Coast where there is greater refinery demand.

Growing supplies of light crude oil from the United States and a lack of spare pipeline capacity has blends like Edmonton Par and Western Canadian Select (WCS) being steeply discounted against WTI. The widening differentials have been an ongoing issue for Canadian producers throughout 2012 and are expected to remain a concern in 2013.

Natural gas, because it is less readily transported abroad, is subject to supply and demand factors within North America. Although the low price environment of the past three years has served to curtail dry gas drilling, horizontal well technology in shale gas plays and liquids-rich gas development led to record North American production in 2012.

The average benchmark AECO natural gas price was 14% lower in the fourth quarter of 2012 versus Q4 2011. The pricing outlook is bearish in the near term due to the oversupply situation. Longer-term, we believe demand growth, driven by the phasing out of coal-fired power plants in favour of cleaner-burning natural gas, increasing transportation and industrial use, and developing offshore markets, will support stronger natural gas pricing.

Our average selling prices reflect product quality and transportation differences from benchmark prices. In the fourth quarter of 2012, our average realized oil price was $72.40 (Q4 2011 - $85.78) per barrel and our average realized natural gas price was $2.56 (Q4 2011 - $2.91) per Mcf.

Guidance Update

The following table compares changes in our key operating assumptions during 2012 to our actual results for the year. Compared to our November guidance:


--  Average production for the fourth quarter was 856 boe per day higher
    than the third quarter of 2012 and annual production came in 3% above
    guidance, mainly due to prior period adjustments and flush production
    from successful drilling in Southeast Saskatchewan.
--  Average oil prices were slightly lower than our assumptions, while
    natural gas prices were slightly higher.
--  General and administrative costs per boe were lower than forecast as a
    result of higher a production base.
--  Capital expenditures were $1.7 million higher than forecast, as we
    completed and equipped more oil wells than anticipated in the fourth
    quarter.

2012 Key Operating Assumptions


                                                    Previous Guidance
                                            --------------------------------
                                   2012
Annual Average                     Actual    Nov. 8, Aug. 9,  May 9,Mar. 14,
                                   Results      2012    2012    2012    2012
----------------------------------------------------------------------------
Daily production              boe/d 8,850      8,600   8,300   8,100   7,600
WTI oil price               US$/bbl 94.20(1)   95.00   93.00  100.00  100.00
Western Canada Select
 (WCS)                     Cdn$/bbl 73.08(1)   75.00   72.00   75.00   81.00
AECO natural gas price     Cdn$/Mcf  2.39(1)    2.25    2.25    2.00    2.50
Exchange rate              Cdn$/US$  1.00       1.00    1.00    1.00    1.00
Operating costs               $/boe  4.82       4.80    4.80    4.80    4.60
General and
 administrative costs
 (2)                          $/boe  2.39       2.65    3.00    3.00    3.00
Capital expenditures     $ millions  36.7         35      30      30      30
Dividends paid in
 shares (DRIP)           $ millions  27.4         27      27      27      27
Long-term debt at year
 end                     $ millions    18         18      21      18      15
Cash taxes paid in 2012  $ millions   4.7        4.6     4.6       -       -
Weighted average shares
 outstanding               millions  64.9         65      65      65      65
(1) As reported by the Canadian Association of Petroleum Producers (CAPP).
(2) Excludes share based and other compensation.

2013 Key Operating Assumptions (1)


                                                     Guidance Updated
                                              ------------------------------
Annual Average                                March 7, 2013 November 8, 2012
----------------------------------------------------------------------------
Daily production                        boe/d         8,500            8,400
WTI oil price                         US$/bbl         95.00            95.00
Western Canada Select (WCS)          Cdn$/bbl         71.00            76.00
AECO natural gas price               Cdn$/Mcf          3.10             3.25
Exchange rate                        Cdn$/US$          1.00             1.00
Operating costs                         $/boe          5.00             5.00
General and administrative costs
 (2)                                    $/boe          2.60             2.60
Capital expenditures               $ millions            30               33
Dividends paid in shares (DRIP)
 (3)                               $ millions            28               28
Long-term debt at year end         $ millions            48               48
Cash taxes payable in 2013 for
 2012 tax year (4)                 $ millions            23               25
Cash taxes payable for 2013 tax
 year (instalments) (4)            $ millions            25               25
Weighted average shares
 outstanding                         millions            67               67
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(1) A sensitivity analysis of the potential impact of key variables on funds
    from operations per share is provided in our 2012 Annual MD&A.
(2) Excludes share based and other compensation.
(3) Assumes average 25% participation rate in Freehold's dividend
    reinvestment plan, which is subject to change at the participants'
    discretion.
(4) Corporate tax estimates will vary depending on commodity prices and
    other factors.

As 2012 capital was ahead of guidance, we have revised our 2013 capital budget to $30 million. Our development plans are primarily oil related, focused almost entirely on our mineral title lands, and include approximately 40 gross (13 net) wells. Roughly half of our capital will be deployed in southeast Saskatchewan (light oil), with the balance allocated to our expanding mineral title opportunity base in both the Lloydminster area (heavy oil) and western Alberta (Cardium oil). Almost half of our total capital for the year will be spent in the first quarter of 2013, with area allocations similar to our annual budget. 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 by lessees on our royalty lands, and normal production declines (and excluding any potential acquisitions), we expect 2013 production to average approximately 8,500 boe per day. On a boe basis, production volumes for 2013 are expected to be approximately 64% oil and NGL and 36% natural gas. We continue to maintain our royalty focus with royalty production accounting for 67% of forecasted 2013 production.

In February 2013, we remitted $23 million for estimated 2012 corporate taxes. We expect to pay approximately $25 million for the 2013 tax year by way of monthly instalments. The large cash outlay for income taxes in 2013 is an anomaly that we have prepared for and have the financial capacity to handle. We expect our tax bill will normalize in 2014, at approximately 20% of pre-tax cash flow.

As our results demonstrate, we continue to benefit from activity on our oil-weighted asset base, and from relatively strong, if somewhat volatile, crude oil pricing. Of significance, natural gas accounted for 36% of production volumes in the fourth quarter (Q4 2011 - 35%), but only 11% of gross revenue (Q4 2011 - 10%). Clearly, we would benefit from any improvement in natural gas prices. However, despite a significant decline in revenue from natural gas, we have been able to maintain a steady monthly dividend rate of $0.14 ($1.68 annually) per share since January 2010.

Recognizing the cyclical nature of the oil and gas industry, we continue to closely monitor commodity prices and industry trends for signs of deteriorating market conditions. We caution that it is inherently difficult to predict activity levels on our royalty lands since we have no operational control. As well, significant changes (positive or negative) in commodity prices (including Canadian oil price differentials), foreign exchange rates, or production rates may result in adjustments to the dividend rate. In particular, our 2013 forecast for Western Canada Select pricing assumes an improvement in the second half of the year, but it is possible that the North American infrastructure constraints will become a longer-term issue for western Canadian production.

Based on our current guidance and commodity price assumptions, and assuming there are no significant changes in the current business environment, we expect to maintain the current monthly dividend rate through 2013, subject to the Board's quarterly review and approval.

Succession Planning

After more than 16 years with Freehold and 29 years with Rife Resources Ltd. (the Manager of Freehold), Mr. William O. Ingram has announced that he plans to retire as President and CEO in May 2013. Mr. Ingram will step down as a director of Freehold but will continue to serve on the boards of Rife and Canpar Holdings Ltd. As well, Dr. P. Michael Maher, who has been a director of Freehold since 1996, will be retiring from the Board in May. The directors of Freehold thank Dr. Maher and Mr. Ingram for their many years of service to Freehold, and wish them both well in their retirement.

Following the retirement of Mr. Ingram in May, the Board plans to appoint Mr. Thomas J. Mullane as President and CEO, and he will stand for election as a director of Freehold at the annual meeting of shareholders to be held on May 15, 2013. Mr. Mullane joined Freehold in 2012 as Executive Vice-President and Chief Operating Officer, and brings a solid background of industry experience and knowledge at a senior level that will be an asset to Freehold in the years to come.

Land and Reserves

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 and finding and development costs to others in our industry. We believe the most appropriate measure of reserves and finding and development costs for Freehold is on a net basis.

As at year-end 2012, our undeveloped land was independently valued at $80.2 million by Seaton-Jordan & Associates Ltd. Our total land holdings encompass approximately three million gross acres, 94% of which are royalties. Of this, our mineral title lands (including royalty assumption lands), which we own in perpetuity, cover more than 630,000 acres; all but approximately 107,000 gross acres of which are currently leased to third parties. In addition, we have gross overriding royalty interests in nearly 2.2 million acres.

These royalty interest lands are significant to Freehold. The majority of these lands are leased to third party operators. As a royalty owner, we have no operational control over the operator's future development activities. As such, the extent of drilling and development activity in future years can be difficult to predict. However, these operators have historically invested significant amounts to generate future reserve additions, and production from which Freehold receives certain royalties. Reserve values do not include potential reserve additions that may occur as a result of future drilling on most of our royalty lands. In addition, based on an internal estimate, we have estimated the net present value of the future royalty revenue from our potash reserves at $20.7 million before tax (discounted at 10%).

Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2012. 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.

Summary oil and gas reserves information is provided below. Complete reserves disclosure as required under National Instrument 51-101 will be included in our Annual Information Form.


Summary of Oil and Gas Reserves
As of December 31, 2012
Forecast Prices and  Light and Medium
 Costs (1)                 Oil             Heavy Oil       Total Crude Oil
                    --------------------------------------------------------
                    Gross (2)  Net (3) Gross (2)  Net (3) Gross (2)  Net (3)
Reserves Category     (Mbbls)  (Mbbls)   (Mbbls)  (Mbbls)   (Mbbls)  (Mbbls)
----------------------------------------------------------------------------
Proved
  Developed
   producing           1,754    3,490       827    4,150     2,581    7,640
  Developed non-
   producing              73       64         -        6        73       70
  Undeveloped              -        -        28       23        28       23
----------------------------------------------------------------------------
Total proved           1,826    3,554       856    4,178     2,682    7,733
Probable               1,346    2,301       916    3,197     2,262    5,498
----------------------------------------------------------------------------
Total proved plus
 probable              3,173    5,855     1,771    7,376     4,944   13,231
----------------------------------------------------------------------------

                                          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           4,024   33,628       146      841     3,398   14,085
  Developed non-
   producing              59      794         7        7        90      209
  Undeveloped              -    4,314         -       46        28      788
----------------------------------------------------------------------------
Total proved           4,083   38,736       154      893     3,516   15,082
Probable               3,042   20,212       124      476     2,893    9,343
----------------------------------------------------------------------------
Total proved plus
 probable              7,125   58,949       277    1,369     6,409   24,425
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Numbers may not add due to rounding.
(2) Gross reserves are our share of working interest properties before
    deduction of royalties payable to others. Gross reserves exclude royalty
    interests.
(3) Net reserves are defined as our share of working interest properties
    minus royalties payable to others, plus royalties receivable on our
    royalty lands.

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).


Summary of Net Present Values of Future Net Revenue
As of December 31, 2012
Forecast Prices and Costs
 ($000s) (1)                Before Income Taxes, Discounted at (% per year)
                           -------------------------------------------------
                                  0%        5%       10%       15%       20%
----------------------------------------------------------------------------
Proved
  Developed producing        730,246   537,722   431,272   364,055   317,704
  Developed non-producing      4,259     2,773     1,986     1,517     1,211
  Undeveloped                 23,328    16,185    11,818     8,958     6,987
----------------------------------------------------------------------------
Total proved                 757,833   556,679   445,076   374,529   325,902
Probable                     564,863   295,635   193,236   142,680   112,973
----------------------------------------------------------------------------
Total proved plus probable 1,322,696   852,314   638,312   517,209   438,875
----------------------------------------------------------------------------

                             After Income Taxes, Discounted at (% per year)
                                                  (2)
                           -------------------------------------------------
Reserves Category                 0%        5%       10%       15%       20%
----------------------------------------------------------------------------
Proved
  Developed producing        616,012   453,317   363,687   307,156   268,186
  Developed non-producing      3,194     2,060     1,458     1,099       865
  Undeveloped                 17,434    12,070     8,789     6,639     5,158
----------------------------------------------------------------------------
Total proved                 636,639   467,447   373,934   314,894   274,210
Probable                     420,690   219,454   142,981   105,240    83,075
----------------------------------------------------------------------------
Total proved plus probable 1,057,329   686,902   516,915   420,134   357,284
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on the December 31, 2012 escalated oil and gas price forecasts by
    an independent qualified reserves evaluator. Future net revenue values
    do not represent fair market value. Reserve values do not include
    potential reserve additions that may occur as a result of future
    drilling on our royalty lands. 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, 2012
Forecast Prices and Costs ($000s) (1)               Reserves Category
                                              ------------------------------
                                                                Proved Plus
                                                      Proved       Probable
                                                    Reserves       Reserves
----------------------------------------------------------------------------
Royalty income                                       660,266      1,136,234
Revenue from working interest properties             269,358        506,074
Royalty expense on working interest properties       (40,759)       (83,190)
Operating costs                                     (121,380)      (214,202)
Development costs                                     (1,441)       (12,560)
Well abandonment and reclamation costs                (8,212)        (9,661)
----------------------------------------------------------------------------
Future net revenue before income taxes               757,833      1,322,696
Future income taxes (2)                             (121,194)      (265,367)
----------------------------------------------------------------------------
Future net revenue after income taxes (2)            636,639      1,057,329
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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. Reserve values do not include potential reserve additions that
    may occur as a result of future drilling on our royalty lands. 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) ($000s)
                                                                 Proved Plus
                                                                    Probable
Forecast Prices and Costs (1)                 Proved Reserves       Reserves
----------------------------------------------------------------------------
2013                                                      773          5,538
2014                                                      519          6,525
2015                                                       29            131
2016                                                       29            117
2017                                                       30            119
Remainder                                                  61            130
----------------------------------------------------------------------------
Total                                                   1,441         12,560
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 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
As of December 31, 2012 (1)

                                        Proved                   Proved Plus
                                     Producing   Total Proved       Probable
----------------------------------------------------------------------------
Net reserves (Mboe)                     14,085         15,082         24,425
Net production (Mboe)                    2,518          2,546          2,878
----------------------------------------------------------------------------
Reserve life index (years)                 5.6            5.9            8.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 first year's production period
    (calculated by dividing the Trimble forecast of 2013 net production into
    the remaining net reserves).

Reconciliation of Net Reserves (1)
By Principal Product Type

Forecast Prices and
 Costs (1)               Light and Medium Oil             Heavy Oil
                      ------------------------------------------------------
                                          Proved                     Proved
                                            Plus                       Plus
                        Proved Probable Probable   Proved Probable Probable
                        (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)
----------------------------------------------------------------------------
December 31, 2011        3,445    1,885    5,330    4,533    2,841    7,373
  Extensions               569      426      995      324      199      523
  Improved recovery          -        -        -        -        -        -
  Technical revisions      319     (178)     142      167      (74)      93
  Discoveries                -        -        -        -        -        -
  Acquisitions              87      165      253       46      232      278
  Dispositions               -        -        -        -        -        -
  Economic factors          16        3       19        5        -        5
  Production              (883)       -     (883)    (897)       -     (897)
----------------------------------------------------------------------------
December 31, 2012        3,554    2,301    5,855    4,178    3,197    7,376
----------------------------------------------------------------------------

                              Natural Gas            Natural Gas Liquids
                      ------------------------------------------------------
                                          Proved                     Proved
                                            Plus                       Plus
                        Proved Probable Probable   Proved Probable Probable
                         (MMcf)   (MMcf)   (MMcf)  (Mbbls)  (Mbbls)  (Mbbls)
----------------------------------------------------------------------------
December 31, 2011       32,560   17,113   49,673      802      405    1,206
  Extensions               810      523    1,333       42       27       69
  Improved recovery          -        -        -        -        -        -
  Technical revisions      771   (1,677)    (906)      42      (31)      11
  Discoveries                -        -        -        -        -        -
  Acquisitions          11,765    4,263   16,028      206       75      281
  Dispositions               -        -        -        -        -        -
  Economic factors         (21)     (10)     (31)       -        -        -
  Production            (7,149)       -   (7,149)    (198)       -     (198)
----------------------------------------------------------------------------
December 31, 2012       38,736   20,212   58,949      893      476    1,369
----------------------------------------------------------------------------

                                                       Oil Equivalent
                                                 ---------------------------
                                                                     Proved
                                                                       Plus
                                                   Proved Probable Probable
                                                    (Mboe)   (Mboe)   (Mboe)
----------------------------------------------------------------------------
December 31, 2011                                  14,206    7,982   22,189
  Extensions                                        1,071      738    1,809
  Improved recovery                                     -        -        -
  Technical revisions                                 657     (562)      95
  Discoveries                                           -        -        -
  Acquisitions                                      2,300    1,183    3,483
  Dispositions                                          -        -        -
  Economic factors                                     17        1       19
  Production                                       (3,169)       -   (3,169)
----------------------------------------------------------------------------
December 31, 2012                                  15,082    9,343   24,425
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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)

                                                                  Three-Year
Net Proved Reserves                      2012       2011     2010    Results
----------------------------------------------------------------------------
Finding and development expenditures
 ($000s)                               36,746     25,649   18,054     80,449
  Change in future development
   capital estimates ($000s)             (934)     1,556      (59)       563
  Net reserve additions by
   development (Mboe)                   1,071        581      465      2,117
Finding and development costs
 ($/boe)                                33.45      46.81    38.67      38.27
----------------------------------------------------------------------------
Acquisition expenditures ($000s)       60,852      7,467   38,600    106,919
  Net reserve additions by
   acquisition (Mboe)                   2,300        103      857      3,260
Acquisition costs ($/boe)               26.46      72.42    45.05      32.80
----------------------------------------------------------------------------
Total expenditures ($000s)             97,598     33,116   56,654    187,368
  Change in future development
   capital estimates ($000s)             (934)     1,556      (59)       563
  Net reserve additions (Mboe)          3,371        684    1,322      5,377
Finding, development and acquisition
 costs ($/boe)                          28.68      50.67    42.81      34.95
----------------------------------------------------------------------------

                                                                  Three-Year
Net Proved Plus Probable Reserves        2012       2011     2010    Results
----------------------------------------------------------------------------
Finding and development expenditures
 ($000s)                               36,746     25,649   18,054     80,449
  Change in future development
   capital estimates ($000s)            1,916      4,959       35      6,910
  Net reserve additions by
   development (Mboe)                   1,809      1,085      950      3,845
Finding and development costs
 ($/boe)                                21.37      28.20    19.04      22.72
----------------------------------------------------------------------------
Acquisition expenditures ($000s)       60,852      7,467   38,600    106,919
  Net reserve additions by
   acquisition (Mboe)                   3,483        207    1,352      5,042
Acquisition costs ($/boe)               17.47      36.12    28.56      21.21
----------------------------------------------------------------------------
Total expenditures ($000s)             97,598     33,116   56,654    187,368
  Change in future development
   capital estimates ($000s)            1,916      4,959       35      6,910
  Net reserve additions (Mboe)          5,292      1,292    2,302      8,886
Finding, development and acquisition
 costs ($/boe)                          18.80      29.47    24.63      21.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
                                                                  Three-Year
($ per boe, except as noted)        2012        2011        2010     Results
----------------------------------------------------------------------------
Operating netback (1) (4)          45.09       51.65       44.08       46.81
Finding, development and
 acquisition costs (2) (4)         18.80       29.47       24.63       21.86
Recycle ratio (times) (3)            2.4         1.8         1.8         2.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2012
(gross acres) (1)                    Developed    Undeveloped          Total
----------------------------------------------------------------------------
Mineral title lands (2)                367,071        168,364        535,435
Royalty assumption lands (3)            73,940         20,882         94,822
----------------------------------------------------------------------------
Total title lands (4)                  441,011        189,246        630,257
Gross overriding royalty (GORR)
 lands (5)                           1,571,533        603,548      2,175,081
----------------------------------------------------------------------------
Total royalty lands                  2,012,544        792,794      2,805,338
Working interest properties            147,781         40,253        188,034
----------------------------------------------------------------------------
Total land holdings                  2,160,325        833,047      2,993,372
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Land Holdings by Province


                    Royalty Interest               Working Interest
                 -----------------------------------------------------------
                  Developed Undeveloped      Developed        Undeveloped
                 -----------------------------------------------------------
                   Gross (1)   Gross (1) Gross (1)     Net Gross (1)     Net
----------------------------------------------------------------------------
Alberta           1,537,959     380,780   111,672   16,793   26,695    5,480
Saskatchewan        294,474     199,025    16,703    5,062    7,427    4,417
Ontario              88,858     184,834         -        -        -        -
British Columbia     84,996      26,571    19,247    1,265    6,131      101
Manitoba              6,257       1,584       159       37        -        -
----------------------------------------------------------------------------
Total             2,012,544     792,794   147,781   23,157   40,253    9,998
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                      Total Acreage
                 -----------------------------------------------------------
                                                   Developed    Undeveloped
                 -----------------------------------------------------------
                                                    Gross (1)      Gross (1)
----------------------------------------------------------------------------
Alberta                                            1,649,631        407,475
Saskatchewan                                         311,177        206,452
Ontario                                               88,858        184,834
British Columbia                                     104,243         32,702
Manitoba                                               6,416          1,584
----------------------------------------------------------------------------
Total                                              2,160,325        833,047
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 107,000 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 leased by a number
    of third party oil and gas companies in respect of which contractual
    royalties or net profits interests have been reserved to Freehold.

Quarterly Review
                                                  2012
                            ------------------------------------------------
                                     Q4          Q3          Q2          Q1
                            ------------------------------------------------
FINANCIAL ($000s, except as
 noted)
Revenue, net of royalty
 expense                         43,832      40,294      34,498      43,036
Dividends declared               27,787      27,616      27,399      26,766
  Per share ($) (1)                0.42        0.42        0.42        0.42
Net income (2)                   13,431      11,975       7,862      13,060
  Per share, basic and
   diluted ($) (2)                 0.20        0.18        0.12        0.21
Cash flow from operating
 activities                      38,183      36,212      27,402      36,335
  Per share ($)                    0.58        0.55        0.42        0.58
Funds from operations (3)        31,475      26,272      20,522      25,613
  Per share ($) (3)                0.48        0.40        0.31        0.41
Dividends paid in shares
 (DRIP)                           6,672       7,013       6,940       6,789
  Average DRIP participation
   rate (%) (4)                      24          25          25          26
Property and royalty
 acquisitions (net)                 243      10,789         (99)     49,919
Capital expenditures              7,743       9,160       6,598      13,245
Long-term debt                   18,000      25,000      23,000      18,000
Shares outstanding
  Weighted average, basic
   (000s)                        66,091      65,677      65,159      62,571
  At quarter end (000s)          66,270      65,879      65,440      64,993
----------------------------------------------------------------------------
OPERATING ($/boe, except as
 noted)
Daily production (boe/d) (5)      9,510       8,654       8,501       8,733
  Royalty interest
   production (%)                    66          68          76          74
Average selling price             51.55       51.71       45.74       54.80
Operating netback (3)             44.59       45.59       40.64       49.48
Operating expenses                 5.51        5.02        3.96        4.68
  Working interest
   properties                     16.36       15.47       16.47       17.86
Net general and
 administrative expenses (6)       2.25        1.88        2.13        3.31
----------------------------------------------------------------------------
BENCHMARK PRICES
WTI crude oil (US$/bbl)           88.18       92.22       93.49      102.93
Exchange rate (Cdn$/US$)           1.01        1.01        0.99        1.00
Edmonton Par crude oil
 (Cdn$)                           83.99       84.33       83.95       92.18
Western Canada Select (WCS)
 (Cdn$/bbl)                       69.43       69.99       71.29       81.61
WTI/Edmonton Par
 differential ($/bbl)             (4.19)      (7.89)      (9.54)     (10.75)
Edmonton Par/WCS
 differential (Cdn$/bbl)         (14.56)     (14.34)     (12.66)     (10.57)
AECO natural gas (Cdn$/Mcf)        3.00        2.19        1.83        2.52
----------------------------------------------------------------------------
SHARE TRADING PERFORMANCE
High ($)                          22.45       20.34       19.67       21.59
Low ($)                           19.62       17.83       17.25       19.16
Close ($)                         22.40       19.76       18.44       19.59
Volume (000s)                     7,435       5,656       7,483       8,076
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                  2011
                            ------------------------------------------------
                                     Q4          Q3          Q2          Q1
                            ------------------------------------------------
FINANCIAL ($000s, except as
 noted)
Revenue, net of royalty
 expense                         44,217      34,614      39,560      35,322
Dividends declared               25,585      25,322      25,111      24,950
  Per share ($) (1)                0.42        0.42        0.42        0.42
Net income (2)                   16,033      11,290      16,717      11,219
  Per share, basic and
   diluted ($) (2)                 0.26        0.19        0.28        0.19
Cash flow from operating
 activities                      32,595      30,255      31,424      24,096
  Per share ($)                    0.54        0.50        0.53        0.41
Funds from operations (3)        38,245      28,772      33,891      27,322
  Per share ($) (3)                0.63        0.48        0.57        0.46
Dividends paid in shares
 (DRIP)                          10,232       8,765       7,798       6,695
  Average DRIP participation
   rate (%) (4)                      40          35          31          27
Property and royalty
 acquisitions (net)                (195)      7,297          44         321
Capital expenditures             10,910       5,537       4,537       4,665
Long-term debt                   48,000      51,000      54,000      61,000
Shares outstanding
  Weighted average, basic
   (000s)                        60,811      60,198      59,716      59,343
  At quarter end (000s)          61,141      60,492      59,954      59,536
----------------------------------------------------------------------------
OPERATING ($/boe, except as
 noted)
Daily production (boe/d) (5)      7,773       7,195       7,445       7,490
  Royalty interest
   production (%)                    74          72          77          76
Average selling price             61.90       52.80       57.61       52.51
Operating netback (3)             56.56       46.86       53.82       48.96
Operating expenses                 5.28        5.43        4.57        3.44
  Working interest
   properties                     19.91       19.47       19.73       14.32
Net general and
 administrative expenses (6)       2.05        2.16        2.36        3.75
----------------------------------------------------------------------------
BENCHMARK PRICES
WTI crude oil (US$/bbl)           94.06       89.75      102.56       94.02
Exchange rate (Cdn$/US$)           0.98        1.02        1.03        1.01
Edmonton Par crude oil
 (Cdn$)                           97.35       91.74      103.07       87.97
Western Canada Select (WCS)
 (Cdn$/bbl)                       85.48       70.63       82.09       70.19
WTI/Edmonton Par
 differential ($/bbl)              3.29        1.99        0.51       (6.05)
Edmonton Par/WCS
 differential (Cdn$/bbl)         (11.87)     (21.11)     (20.98)     (17.78)
AECO natural gas (Cdn$/Mcf)        3.47        3.72        3.74        3.77
----------------------------------------------------------------------------
SHARE TRADING PERFORMANCE
High ($)                          19.75       21.58       23.28       22.93
Low ($)                           14.51       16.04       19.37       19.86
Close ($)                         19.41       16.36       19.64       22.75
Volume (000s)                     7,114       7,780       5,317       7,921
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on the number of shares issued and outstanding at each record
    date.
(2) Net income and net income per share for the three months ended March 31,
    2011 have been restated for revisions made to deferred tax.
(3) See Non-GAAP Financial Measures.
(4) Average participation in Freehold's DRIP ranged between 24% and 40% over
    the past eight quarters and is subject to change at the participants'
    discretion.
(5) Reported production for a period may include minor adjustments from
    previous production periods.
(6) Excludes share based and other compensation.

Consolidated Balance Sheets
                                                 December 31    December 31
($000s) (unaudited)                                     2012           2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Assets
Current assets:
 Cash                                                  $ 102          $ 164
 Accounts receivable                                  23,225         34,763
----------------------------------------------------------------------------
                                                      23,327         34,927
Deposit on acquisition                                     -          5,000
Exploration and evaluation assets                     25,905         25,045
Petroleum and natural gas interests                  399,005        363,967
----------------------------------------------------------------------------
                                                   $ 448,237      $ 428,939
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities:
 Dividends payable                                   $ 9,278        $ 8,560
 Accounts payable and accrued liabilities             12,743         14,883
 Current taxes payable                                23,095              -
 Current portion of share based and other
  compensation payable                                 2,108          3,876
----------------------------------------------------------------------------
                                                      47,224         27,319
Asset retirement obligation                           16,714         14,282
Share based and other compensation payable             1,290          1,289
Long-term debt                                        18,000         48,000
Deferred income tax liability                         49,194         59,163

Shareholders' equity:
 Shareholders' capital                               422,728        323,115
 Contributed surplus                                   2,036          1,480
 Deficit                                            (108,949)       (45,709)
----------------------------------------------------------------------------
                                                     315,815        278,886
----------------------------------------------------------------------------
                                                   $ 448,237      $ 428,939
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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)            2012        2011        2012        2011
----------------------------------------------------------------------------

Revenue:
  Royalty income and working
   interest sales              $ 45,794    $ 45,304   $ 168,134   $ 157,910
  Royalty expense                (1,962)     (1,087)     (6,474)     (4,197)
----------------------------------------------------------------------------
                                 43,832      44,217     161,660     153,713
----------------------------------------------------------------------------

Expenses:
  Operating                       4,820       3,772      15,598      12,782
  General and administrative      1,972       1,468       7,746       7,029
  Share based and other
   compensation                     999       1,268       2,371       2,190
  Interest and financing            421         610       2,235       2,907
  Depletion and depreciation     16,372      13,603      64,576      49,251
  Accretion of asset
   retirement obligation            107          83         381         344
  Management fee                  1,072         857       3,808       3,401
----------------------------------------------------------------------------
                                 25,763      21,661      96,715      77,904
----------------------------------------------------------------------------

Income before taxes              18,069      22,556      64,945      75,809

Income tax:
  Current expense                 5,063          80      27,792          80
  Deferred expense
   (recovery)                      (425)      6,443      (9,175)     20,470
----------------------------------------------------------------------------
                                  4,638       6,523      18,617      20,550
----------------------------------------------------------------------------

Net income and comprehensive
 income                        $ 13,431    $ 16,033    $ 46,328    $ 55,259
----------------------------------------------------------------------------
Net income per share, basic
 and diluted                     $ 0.20      $ 0.26      $ 0.71      $ 0.92
----------------------------------------------------------------------------

Weighted average number of
 shares:
  Basic                      66,090,969  60,811,300  64,880,038  60,021,736
  Diluted                    66,194,503  60,886,218  64,979,074  60,093,840
----------------------------------------------------------------------------

Consolidated Statements of Cash Flows
                                 Three Months Ended              Year ended
                                        December 31             December 31
($000s) (unaudited)                2012        2011        2012        2011
----------------------------------------------------------------------------

Operating:
  Net income                   $ 13,431    $ 16,033    $ 46,328    $ 55,259
  Items not involving cash:
    Depletion and
     depreciation                16,372      13,603      64,576      49,251
    Share based and other
     compensation                   999       1,268       2,371       2,190
    Deferred income tax
     expense (recovery)            (425)      6,443      (9,175)     20,470
    Accretion of asset
     retirement obligation          107          83         381         344
    Shares issued in lieu of
     management fee               1,072         857       3,808       3,401
  Expenditures on share
   based and other
   compensation                       -           -      (3,883)     (2,440)
  Expenditures on
   reclamation                      (81)        (42)       (524)       (245)
  Changes in non-cash
   working capital                6,708      (5,650)     34,250      (9,860)
----------------------------------------------------------------------------
                                 38,183      32,595     138,132     118,370
Financing:
  Issuance of shares, net of
   issue costs                        -           -      67,597           -
  Long-term debt                 (7,000)     (3,000)    (30,000)    (17,000)
  Dividends paid                (21,060)    (15,262)    (81,436)    (67,204)
----------------------------------------------------------------------------
                                (28,060)    (18,262)    (43,839)    (84,204)
Investing:
  Deposit on acquisition              -      (5,000)      5,000      (5,000)
  Property and royalty
   acquisitions                    (243)        195     (60,852)     (7,467)
  Capital expenditures           (7,743)    (10,910)    (36,746)    (25,649)
  Change in reclamation fund          -           -           -       2,725
  Changes in non-cash
   working capital               (2,149)      1,358      (1,757)        980
----------------------------------------------------------------------------
                                (10,135)    (14,357)    (94,355)    (34,411)
----------------------------------------------------------------------------
Decrease in cash                    (12)        (24)        (62)       (245)
Cash, beginning of period           114         188         164         409
----------------------------------------------------------------------------
Cash, end of period               $ 102       $ 164       $ 102       $ 164
----------------------------------------------------------------------------

Consolidated Statements of Changes in Shareholders' Equity
                                                          Year ended
                                                         December 31
($000s) (unaudited)                                       2012         2011
----------------------------------------------------------------------------

Shareholders' capital:
  Balance, beginning of year                         $ 323,115    $ 286,224
  Shares issued for dividend reinvestment plan          27,414       33,490
  Shares issued in lieu of management fee                3,808        3,401
  Shares issued for equity offering                     70,725            -
  Issue costs, net of tax effect                        (2,334)           -
----------------------------------------------------------------------------
  Balance, end of year                                 422,728      323,115
----------------------------------------------------------------------------

Contributed surplus:
  Balance, beginning of year                             1,480        1,084
  Share based compensation expense                         556          396
----------------------------------------------------------------------------
  Balance, end of year                                   2,036        1,480
----------------------------------------------------------------------------

Deficit:
  Balance, beginning of year                           (45,709)           -
  Net income and comprehensive income                   46,328       55,259
  Dividends declared                                  (109,568)    (100,968)
----------------------------------------------------------------------------
  Balance, end of year                                (108,949)     (45,709)
----------------------------------------------------------------------------
Total shareholders' equity                           $ 315,815    $ 278,886
----------------------------------------------------------------------------

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at March 7, 2013, 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;
--  drilling activity during the fourth quarter of 2012 adding to our
    production base in 2013;
--  industry drilling, development activity on our royalty lands, our
    exposure 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;
--  amounts and rates of income taxes and timing of payment thereof;
--  maintaining our monthly dividend rate through 2013 and our dividend
    policy; and
--  the appointment of Thomas J. Mullane as President and CEO and his
    standing for election as a director of Freehold.

In addition, statements relating to "reserves" and the future net revenue associated with such reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

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, lack of pipeline capacity; 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.

In this news release, we make references to "flush" production rates, which is the first yield from a flowing oil well during its most productive period. Such "flush" production rates are not determinative of future production rates. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in estimating future production rates for Freehold.

With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future commodity 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 income, netback, funds from operations, funds from operations per share, finding, development and acquisition (FD&A) 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 income, which is calculated as gross revenue less royalties and operating expenses, represents the cash margin for product sold. 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/recovery, 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 to Funds from Operations
                                 Three Months Ended     Twelve Months Ended
                                        December 31             December 31
                            ------------------------------------------------
                                   2012        2011        2012        2011
----------------------------------------------------------------------------
Net income                       13,431      16,033      46,328      55,259
Adjust for non-cash items:
  Depletion and depreciation     16,372      13,603      64,576      49,251
  Share based and other
   compensation                     999       1,268      (1,512)       (250)
  Deferred income tax
   (recovery)                      (425)      6,443      (9,175)     20,470
  Accretion of asset
   retirement obligation            107          83         381         344
  Management fee                  1,072         857       3,808       3,401
Adjust for cash item:
  Expenditures on
   reclamation                      (81)        (42)       (524)       (245)
----------------------------------------------------------------------------
Funds from operations            31,475      38,245     103,882     128,230
  Per share                        0.48        0.63        1.60        2.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------

In addition, we refer to various per boe figures, such as revenues and costs, operating netback, FD&A costs, and NAV, also considered non-GAAP financial 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.

Availability on SEDAR

Freehold's 2012 audited financial statements and accompanying Management's Discussion and Analysis (MD&A) are being filed today with Canadian securities regulators and will be available at www.sedar.com and on our website at www.freeholdroyalties.com. Our Annual Information Form (including reserves disclosure required under National Instrument NI 51-101) is expected to be filed next week.

Contacts:
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)
ktaylor@rife.com
www.freeholdroyalties.com

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