SYS-CON MEDIA Authors: Pat Romanski, Sean Houghton, Glenn Rossman, Ignacio M. Llorente, Xenia von Wedel

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Freehold Royalties Ltd. Announces 2013 Fourth Quarter Results and Year-end Reserves

CALGARY, ALBERTA -- (Marketwired) -- 03/06/14 -- Freehold Royalties Ltd. (Freehold) (TSX: FRU) today announced 2013 fourth quarter results and reserves as at December 31, 2013.


Results at a Glance
                                Three Months Ended      Twelve Months Ended
FINANCIAL HIGHLIGHTS                   December 31              December 31
                          --------------------------------------------------
($000s, except as noted)      2013     2012 Change     2013     2012 Change
----------------------------------------------------------------------------
Gross revenue               45,287   45,794     -1% 181,578  168,134      8%
Net income                  14,106   13,431      5%  57,852   46,328     25%
  Per share, basic and
   diluted ($)                0.21     0.20      5%    0.86     0.71     21%
Funds from operations (1)   29,092   31,475     -8% 119,431  103,882     15%
  Per share ($) (1)           0.43     0.48    -10%    1.79     1.60     12%
Capital expenditures         5,335    7,743    -31%  29,287   36,746    -20%
Property and royalty
 acquisitions (net)          6,891      243      -   10,091   60,852    -83%
Dividends paid in cash (3)
 (4)                        20,697   21,060     -2%  84,340   81,436      4%
Dividends paid in shares
 (DRIP) (2)                  7,617    6,672     14%  27,948   27,414      2%
  Average DRIP
   participation rate (%)       27       24     13%      25       25      0%
Dividends declared (3) (4)  28,373   27,787      2% 112,495  109,568      3%
  Per share ($) (4)           0.42     0.42      0%    1.68     1.68      0%
Long-term debt, period end  49,000   18,000    172%  49,000   18,000    172%
Shares outstanding, period
 end (000s)                 67,746   66,270      2%  67,746   66,270      2%
Average shares outstanding
 (000s) (5)                 67,483   66,091      2%  66,900   64,880      3%
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OPERATING HIGHLIGHTS
Average daily production
 (boe/d) (6) (7)             9,173    9,510     -4%   8,913    8,850      1%
Average realized price
 ($/boe) (6)                 52.99    51.55      3%   55.06    51.00      8%
Operating netback ($/boe)
 (1) (6)                     44.97    44.59      1%   47.91    45.09      6%
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(1) See Additional GAAP Measures and Non-GAAP Financial Measures.
(2) Excludes dividend declared in December and paid in January.
(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 2013 was approximately 36% natural gas and 64%
    liquids (34% light and medium oil, 25% heavy oil, and 5% NGL).

March Dividend Announcement

The Board of Directors has declared the March dividend of $0.14 per share, which will be paid on April 15, 2014 to shareholders of record on March 31, 2014. 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 17 years, we have paid out over $1.2 billion to our shareholders.

2013 Fourth Quarter Highlights

Freehold delivered strong operational results in the fourth quarter of 2013. Highlights included:


--  Production for the quarter averaged 9,173 boe per day representing a 4%
    decrease versus Q4/12. The key driver behind the reduction in volumes
    was lower prior period adjustments for the quarter (325 boe per day) as
    Freehold realized an above average total (650 boe per day) in Q4/12.
    Netting this out, production volumes were similar to the same period
    last year.
--  Gross revenue for the quarter totalled $45.3 million, compared to $45.8
    million in Q4/12.
--  Funds from operations totalled $29.1 million, compared to $31.5 million
    in Q4/12, with the decrease year-over-year associated with production
    declines, higher operating costs and higher current income taxes, offset
    by higher pricing.
--  Dividends for the fourth quarter of 2013 totalled $0.42 per share,
    unchanged from last year.
--  Net income of $14.1 million was 5% higher than last year. Variance in
    earnings versus Q4/12 was primarily driven by the above mentioned
    factors, lower depletion and depreciation, lower share based and other
    compensation and a larger deferred income tax recovery.
--  Acquired royalty interests in 4,480 acres in east central Alberta,
    producing approximately 40 boe per day for $5.1 million (net of
    adjustments). In addition, acquired a gross overriding royalty in two
    units and contractual gross overriding royalties in Alberta, producing
    approximately 22 boe per day for $0.9 million. We expect production from
    these acquired areas to grow in 2014.
--  Net capital expenditures on our working interest properties totalled
    $5.3 million in the fourth quarter (Q4 2012 - $7.7 million) with the
    majority of spending allocated to southeast Saskatchewan.
--  Freehold continues to maintain a strong balance sheet with long-term
    debt of $49 million as at December 31, 2013, flat when compared to Q3/13
    and up from $18 million at December 31, 2012. Debt levels increased when
    compared to 2012 primarily as a result of paying taxes in 2013 for both
    the 2012 and 2013 tax years.
--  Average DRIP participation was 27% in the fourth quarter of 2013 (Q4
    2012 - 24%), allowing us to retain $7.6 million (Q4 2012 - $6.7 million)
    in cash dividend payments by issuing shares from treasury.

2013 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, 2013 totalled 23.1
    MMboe, with reserves assigned to 22,885 wells. Net proved plus probable
    royalty interest reserves declined 8% year-over-year, and net proved
    plus probable working interest reserves were up 4%. Approximately 63% of
    our net reserves are in the proved category, and 94% of our net proved
    reserves are producing. On a boe basis, net reserves are 61% liquids
    (30% heavy oil, 25% light and medium oil, 6% natural gas liquids) and
    39% natural gas.
--  Net proved plus probable reserve additions totalled 1.9 MMboe (76%
    liquids). Drilling on our royalty lands added 0.5 MMboe (26%) of net
    proved plus probable reserves, development activities added 1.1 MMboe
    (58%), and acquisitions added 0.3 MMboe (16%). Based on this, we
    replaced approximately 64% of 2013 production.
--  Freehold's finding costs are calculated based on net reserves. In 2013,
    finding and development costs for net proved plus probable reserves were
    $19.85 per boe, while acquisition costs were $34.38 per boe and the all-
    in finding, development and acquisition (FD&A) cost was $22.04 per boe
    (including changes in future development capital). Based on an operating
    netback of $47.91 per boe in 2013, these activities resulted in a
    recycle ratio of 2.2 times the capital invested, and a three-year
    average recycle ratio of 2.3.
--  Our land holdings as at December 31, 2013 encompassed 3.1 million gross
    acres, up 2% from last year mainly as a result of some small
    acquisitions. Royalty interests comprised 93% of our acreage. Our
    undeveloped land was independently valued by Seaton-Jordan & Associates
    Ltd., at $89.1 million.

Royalty Interest Activity

On an equivalent net basis, 76% of the royalty wells drilled on our lands during 2013 were oil wells (2012 - 85%) due to the oil-prone nature of our lands. As well, over 70% of the equivalent net wells drilled on our royalty lands in 2013 were horizontal wells, up from 66% 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.

As at December 31, 2013, there were 51 (3.6 equivalent net) licensed drilling locations on our royalty lands.


                             Three Months Ended         Twelve Months Ended
ROYALTY INTEREST                    December 31                 December 31
WELLS DRILLED                2013          2012          2013          2012
                     -------------------------------------------------------
                           Equiv.        Equiv.        Equiv.        Equiv.
                     Gross Net (1) Gross Net (1) Gross Net (1) Gross Net (1)
----------------------------------------------------------------------------
Non-unitized            68    4.3     57    2.6    197   11.3    231   11.6
Unitized (2)            38    0.2     30    0.1    141    0.6    200    1.2
----------------------------------------------------------------------------
Total                  106    4.5     87    2.7    338   11.9    431   12.8
----------------------------------------------------------------------------
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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 2013, capital expenditures amounted to $5.3 million, the majority of which was spent to complete, equip, and tie-in wells drilled in southeast Saskatchewan. We participated in the drilling of six (1.2 net) wells with a 100% success rate.


--  In southeast Saskatchewan, we participated in the drilling of one (0.1
    net) horizontal Tilston oil well, two (0.8 net) horizontal Frobisher oil
    wells and one (0.1 net) horizontal Bakken oil well.
--  In Alberta, we participated in the drilling of one (0.2 net) horizontal
    Cardium oil well at Ferrier and one small interest horizontal Glauconite
    oil well in the Thorsby Unit.

                              Three Months Ended         Twelve Months Ended
WORKING INTEREST                     December 31                 December 31
WELLS DRILLED (1)             2013          2012          2013          2012
                      ------------------------------------------------------
                      Gross    Net  Gross    Net  Gross    Net  Gross    Net
----------------------------------------------------------------------------
Oil                       6    1.2      7    1.3     41   12.9     36   13.5
Natural gas               -      -      -      -      -      -      -      -
Other                     -      -      -      -      7    0.7      1    0.6
----------------------------------------------------------------------------
Total                     6    1.2      7    1.3     48   13.6     37   14.1
----------------------------------------------------------------------------
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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 $5.5 million ($6.50 per boe) was 14% higher than the fourth quarter last year (18% higher on a per boe basis). The increase in costs was associated with a combination of higher than forecast electricity charges, well servicing and maintenance costs on our heavy oil properties.


GROSS REVENUE BY
 PRODUCT                    Three Months Ended          Twelve Months Ended
                                   December 31                  December 31
                      ------------------------------------------------------
($000s)                   2013     2012 Change       2013       2012 Change
----------------------------------------------------------------------------
Royalty Interest
  Oil                   22,147   20,503      8%    89,511     87,721      2%
  NGL                    1,849    1,512     22%     7,273      6,887      6%
  Natural gas            3,775    3,831     -1%    14,343     10,501     37%
  Other (1)                470      556    -15%     2,193      2,525    -13%
----------------------------------------------------------------------------
  Total royalty
   interest revenue     28,241   26,402      7%   113,320    107,634      5%
----------------------------------------------------------------------------
Working Interest
  Oil                   15,300   17,801    -14%    62,451     55,577     12%
  NGL                      574      476     21%     2,088      1,870     12%
  Natural gas            1,069      978      9%     3,454      2,640     31%
  Other (1)                103      137    -25%       265        413    -36%
----------------------------------------------------------------------------
  Total working
   interest revenue     17,046   19,392    -12%    68,258     60,500     13%
----------------------------------------------------------------------------
Total
  Oil                   37,447   38,304     -2%   151,962    143,298      6%
  NGL                    2,423    1,988     22%     9,361      8,757      7%
  Natural gas            4,844    4,809      1%    17,797     13,141     35%
  Other (1)                573      693    -17%     2,458      2,938    -16%
----------------------------------------------------------------------------
  Total gross revenue   45,287   45,794     -1%   181,578    168,134      8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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

Production volumes through the fourth quarter were down slightly when compared with levels averaged one-year ago, but up versus Q3/13.


--  Royalty production averaged 6,271 boe per day through the fourth
    quarter, representing a 1% decrease when compared to Q4/12. Oil and
    natural gas liquids production was up 5% due to drilling activity and
    prior period adjustments. On the natural gas side, volumes were down 7%
    from Q4/12, largely as the result of a higher number of prior period
    adjustments in Q4/12.
--  Working interest production volumes averaged 2,902 boe per day in Q4/13.
    This represented a 300 boe per day decrease versus Q4/12 with reduced
    volumes primarily associated with greater flush production one-year ago.

AVERAGE DAILY PRODUCTION             Royalty         Working
                                    Interest        Interest           Total
                             -----------------------------------------------
Three months ended December
 31                             2013    2012    2013    2012    2013    2012
----------------------------------------------------------------------------
Oil (bbls/d)                   3,336   3,190   2,225   2,561   5,561   5,751
NGL (bbls/d)                     293     267      91      88     384     355
----------------------------------------------------------------------------
Total oil and NGL (bbls/d)     3,629   3,457   2,316   2,649   5,945   6,106
Natural gas (Mcf/d)           15,853  17,105   3,515   3,315  19,368  20,420
Oil equivalent (boe/d)         6,271   6,308   2,902   3,202   9,173   9,510
----------------------------------------------------------------------------
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Commodity Prices

In the fourth quarter, the benchmark West Texas Intermediate (WTI) crude oil price averaged US$97.46 per barrel, 11% higher than the previous year. While prices were up compared to 2012 levels, the short-term outlook was somewhat bearish with prices retreating versus Q3/13. We saw weakness into year-end driven by a combination of increased supply associated with U.S. shale and Canadian oil sands growth, indications that the U.S. federal reserve would look to implement tapering initiatives early in 2014 and weakening economic fundamentals out of China.

In the near-term, crude oil supply out of North America is expected to grow at not seen before levels, driven primarily by tight oil plays in North Dakota, Montana, and Texas, along with smaller gains from unconventional resource plays and oil sands within Canada. While growth in supply remains strong, getting volumes through pipeline bottlenecks to premium pricing points in the U.S. Gulf Coast remains a near-term concern for Canadian producers, reflecting some of the discount realized within Edmonton Par and Western Canadian Select pricing in the fourth quarter. Looking forward, while the macro environment is expected to improve marginally for heavy oil producers, we expect Canadian light oil prices to remain discounted through the remainder of 2014.

While remaining depressed for much of the trailing five years, natural gas prices within North America appear to be building momentum, exhibited by strong recent price appreciation. In the fourth quarter, the average benchmark AECO natural gas price was C$3.15 per mcf, representing a 3% improvement versus prices realized in 2012. A key driver behind price appreciation included below average temperatures within consuming regions of the eastern U.S. which has spurred incremental U.S. residential and commercial consumption.

At year-end, North American natural gas inventories stood at approximately 16% below levels seen one year ago and 9% below the five year average. In the near-term, we expect weather within key demand centres, along with the supply response from growing U.S. shale plays to be the primary drivers behind further movement in price levels. In the longer-term, LNG initiatives both within the U.S. and Canada will present some optionality within the North American price environment.

Our average selling prices reflect product quality and transportation differences from benchmark prices. In the fourth quarter of 2013, our average realized oil price was $73.20 (Q4 2012 - $72.40) per barrel and our average realized natural gas price was $2.72 (Q4 2012 - $2.56) per Mcf.

2013 Performance Compared to Guidance

The following table compares our key operating assumptions during 2013 to our actual results for the year.

Compared to our November guidance:


--  Average production for the year was 113 boe per day higher than November
    production guidance, mainly due to prior period adjustments.
--  Average oil prices, both for WTI and WCS were in-line with our
    forecasts.
--  General and administrative costs per boe were lower than November
    guidance, as a result of a higher production base.
--  Operating costs per boe were higher than forecast as electricity prices
    and maintenance charges increased costs.
--  Capital expenditures were $3 million lower than forecast, primarily
    associated with timing delays in getting a scheduled well drilled before
    year-end. This location will be part of the Company's 2014 drilling
    program.

2013 Key Operating Assumptions

                                                    Previous Guidance
                                       2013
                                     Actual Nov. 14, Aug. 8, May 15, Mar. 7,
Annual Average                      Results     2013    2013    2013    2013
----------------------------------------------------------------------------
Daily production            boe/d     8,913    8,800   8,800   8,700   8,500
WTI oil price             US$/bbl     97.97    98.00   96.00   93.00   95.00
Western Canada Select
 (WCS)                   Cdn$/bbl     74.99    75.00   75.00   69.00   71.00
AECO natural gas price   Cdn$/Mcf      3.16     3.25    3.00    3.50    3.10
Exchange rate            Cdn$/US$      0.97     0.97    0.98    0.98    1.00
Operating costs             $/boe      5.95     5.60    5.30    5.00    5.00
General and
 administrative costs
 (1)                        $/boe      2.35     2.60    2.60    2.60    2.60
Capital expenditures   $ millions        29       32      32      30      30
Dividends paid in
 shares (DRIP)         $ millions        28       28      28      28      28
Long-term debt at year
 end                   $ millions        49       53      44      44      48
Cash taxes paid in
 2013 for 2012 tax
 year                  $ millions        22       22      22      23      23
Cash taxes paid for
 2013 tax year         $ millions        24       24      24      25      25
Weighted average
 shares outstanding      millions        67       67      67      67      67
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Excludes share based and other compensation.

2014 Outlook

Through 2014, we are forecasting a capital spending program of $35 million. Our focus will continue to centre on oil development within our mineral title lands and includes approximately 58 gross (14 net risked) wells. Our spending will be comprised of approximately 40% in southeast Saskatchewan (light oil), with the remaining balance allocated to our opportunity base in both the Lloydminster area (heavy oil), and Western Alberta (Cardium oil) plays. The increase in costs per well are related to the shift from vertical to horizontal drilling within our program, along with two well completions that were scheduled for 2013 and were delayed into 2014. We maintain that capital may be adjusted as the year progresses, depending on the operating environment and individual well results. Approximately forty percent of our total capital for the year will be spent in the first quarter of 2014, with area allocations similar to our annual budget.

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 2014 production to average approximately 8,700 boe/d. Volumes will be comprised of approximately 62% oil and NGL's and 38% natural gas. We continue to maintain our royalty focus with royalty production expected to account for approximately 68% of forecasted 2014 production.

After paying a large lump sum ($46 million) associated with two years tax burden in 2013, we expect our tax liability to normalize through 2014, at approximately 20% of pre-tax cash flow.

2014 Key Operating Assumptions


                                                      Guidance Updated
                                               -----------------------------
Annual Average                                                  November 14,
                                                March 6, 2014           2013
----------------------------------------------------------------------------
Daily production                         boe/d          8,700          8,600
WTI oil price                          US$/bbl          97.00          95.00
Western Canada Select (WCS)           Cdn$/bbl          83.00          75.00
AECO natural gas price                Cdn$/Mcf           4.50           3.50
Exchange rate                         Cdn$/US$           0.90           0.95
Operating costs                          $/boe           6.00           5.60
General and administrative costs
 (1)                                     $/boe           2.60           2.60
Capital expenditures                $ millions             35             30
Dividends paid in shares (DRIP)
 (2)                                $ millions             29             29
Long-term debt at year end          $ millions             38             57
Current income tax expense (3) (4)  $ millions             32             28
Weighted average shares
 outstanding                          millions             68             68
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(1) Excludes share based and other compensation.
(2) Assumes average 25% participation rate in Freehold's dividend
    reinvestment plan, which is subject to change at the participants'
    discretion.
(3) Corporate tax estimates will vary depending on all other assumptions.
(4) November 14, 2013 Guidance was adjusted to be comparable to the current
    presentation.

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 2014 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 2014, subject to the Board's quarterly review and approval.

Executive Retirement and Appointments

On December 31, 2013, Mr. Frank George, Vice-President, Special Projects (previously Vice-President, Exploration) retired from Rife Resources Ltd. (the Manager of Freehold) after 30 years with Rife. Mr. Garry Bieber, appointed Vice-President, Special Projects effective January 1, 2014 (previously Vice-President, Production) will be retiring effective April 1, 2014 after 28 years with Rife. The directors of Freehold thank Mr. George and Mr. Bieber for their many years of service, and wish them well in their retirement.

We are pleased to announce that Mr. Daniel Moore was appointed Vice-President, Production on January 1, 2014. Mr. Moore is a Professional Engineer with 22 years of experience. He joined Rife in December 2011 as Manager, Engineering, and most recently was Chief Engineer.

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 2013, our undeveloped land was independently valued at $89.1 million by Seaton-Jordan & Associates Ltd. Our total land holdings encompass approximately 3.1 million gross acres, 93% of which are royalties. Of this, our mineral title lands (including royalty assumption lands), which we own in perpetuity, cover nearly 630,000 acres; all but approximately 100,000 gross acres of which are currently leased to third parties. In addition, we have gross overriding royalty interests in over 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 include minimal reserve additions that may occur as a result of future drilling on 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 $17.7 million before tax (discounted at 10%).

Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2013. 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, 2013
Forecast Prices    Light and Medium
 and 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         1,722     3,415       748     4,167     2,471     7,582
  Developed non-
   producing           104        91        16        14       120       105
  Undeveloped            -         -         -         -         -         -
----------------------------------------------------------------------------
Total proved         1,827     3,506       764     4,181     2,591     7,687
Probable             1,456     2,322       851     2,730     2,307     5,052
----------------------------------------------------------------------------
Total proved plus
 probable            3,283     5,828     1,615     6,911     4,898    12,739
----------------------------------------------------------------------------

                     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         3,400    30,887       131       846     3,168    13,576
  Developed non-
   producing           586       622        44        35       262       244
  Undeveloped            -     3,734         -        42         -       664
----------------------------------------------------------------------------
Total proved         3,986    35,243       175       923     3,430    14,483
Probable             4,363    18,385       237       513     3,271     8,629
----------------------------------------------------------------------------
Total proved plus
 probable            8,349    53,627       412     1,436     6,702    23,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------



(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, 2013
Forecast Prices and Costs
 ($000s) (1)                Before Income Taxes, Discounted at (% per year)
                           -------------------------------------------------
                                  0%        5%       10%       15%       20%
----------------------------------------------------------------------------
Proved
  Developed producing        756,691   558,106   448,309   379,056   331,345
  Developed non-producing      6,640     4,908     3,989     3,423     3,036
  Undeveloped                 20,139    13,417     9,422     6,882     5,184
----------------------------------------------------------------------------
Total proved                 783,470   576,431   461,721   389,361   339,566
Probable                     532,947   280,416   184,316   136,501   108,128
----------------------------------------------------------------------------
Total proved plus probable 1,316,417   856,847   646,037   525,862   447,693
----------------------------------------------------------------------------

                             After Income Taxes, Discounted at (% per year)
                                                  (2)
                           -------------------------------------------------
Reserves Category                 0%        5%       10%       15%       20%
----------------------------------------------------------------------------
Proved
  Developed producing        634,088   467,455   375,628   317,755   277,886
  Developed non-producing      4,938     3,595     2,879     2,438     2,137
  Undeveloped                 15,042    10,021     7,036     5,139     3,870
----------------------------------------------------------------------------
Total proved                 654,068   481,071   385,544   325,331   283,893
Probable                     396,944   208,014   136,175   100,447    79,257
----------------------------------------------------------------------------
Total proved plus probable 1,051,012   689,085   521,719   425,778   363,150
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Based on the December 31, 2013 escalated oil and gas price forecasts by
    an independent qualified reserves evaluator. Future net revenue values
    do not represent fair market value. Columns may not add due to rounding.
(2) The after-tax net present value calculation reflects the tax burden on
    the properties on a standalone basis, utilizing our tax pools to the
    maximum depreciation rate as currently permitted. It does not consider
    the corporate-level tax situation, or tax planning. It does not provide
    an estimate of the value at the corporate level, which may be
    significantly different. See our financial statements and accompanying
    MD&A for additional tax information.

Total Future Net Revenue (Undiscounted)
As of December 31, 2013
Forecast Prices and Costs ($000s) (1)                     Reserves Category
                                              ------------------------------
                                                                Proved Plus
                                                      Proved       Probable
                                                    Reserves       Reserves
----------------------------------------------------------------------------
Royalty income                                       684,094      1,113,378
Revenue from working interest properties             286,536        565,905
Royalty expense on working interest                  (44,686)       (95,158)
Operating costs                                     (130,578)      (240,560)
Development costs                                     (2,583)       (16,007)
Well abandonment and reclamation costs                (9,312)       (11,141)
----------------------------------------------------------------------------
Future net revenue before income taxes               783,470      1,316,417
Future income taxes (2)                             (129,402)      (265,404)
----------------------------------------------------------------------------
Future net revenue after income taxes (2)            654,068      1,051,012
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Future net revenue calculation includes future capital expenditures
    required to bring booked non-producing and undeveloped reserves on
    production. Future net revenue values do not represent fair market
    value. Columns may not add due to rounding.
(2) The after-tax net present value calculation reflects the tax burden on
    the properties on a standalone basis, utilizing our tax pools to the
    maximum depreciation rate as currently permitted. It does not consider
    the corporate-level tax situation, or tax planning. It does not provide
    an estimate of the value at the corporate level, which may be
    significantly different. See our financial statements and accompanying
    MD&A for additional tax information.

Future Development Costs (Undiscounted) ($000s)
                                                                Proved Plus
                                                      Proved       Probable
Forecast Prices and Costs (1)                       Reserves       Reserves
----------------------------------------------------------------------------
2014                                                   1,388          8,228
2015                                                     237          5,290
2016                                                     180          1,509
2017                                                     628            664
2018                                                      74            127
Remainder                                                 76            189
----------------------------------------------------------------------------
Total                                                  2,583         16,007
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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, 2013 (1)
                                        Proved                   Proved Plus
                                     Producing   Total Proved       Probable
----------------------------------------------------------------------------
Net reserves (Mboe)                     13,576         14,483         23,113
Net production (Mboe)                    2,357          2,409          2,707
----------------------------------------------------------------------------
Reserve life index (years)                 5.8            6.0            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 2014 net production into
    the remaining net reserves).

Reconciliation of Net Reserves (1)
By Principal Product Type
Forecast Prices and
 Costs                   Light and Medium Oil             Heavy Oil
                      ------------------------------------------------------
                                          Proved                     Proved
                                            Plus                       Plus
                        Proved Probable Probable   Proved Probable Probable
                       (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)
----------------------------------------------------------------------------
December 31, 2012        3,554    2,301    5,855    4,178    3,197    7,376
  Extensions               495      382      878      155       81      236
  Improved recovery          -        -        -        -        -        -
  Technical revisions      374     (356)      18      636     (677)     (41)
  Discoveries                -        -        -        -        -        -
  Acquisitions               -        -        -       82      128      210
  Dispositions               -        -        -        -        -        -
  Economic factors          (4)      (5)      (9)      (1)       -        -
  Production              (914)       -     (914)    (870)       -     (870)
----------------------------------------------------------------------------
December 31, 2013        3,506    2,322    5,828    4,181    2,730    6,911
----------------------------------------------------------------------------

                              Natural Gas            Natural Gas Liquids
                      ------------------------------------------------------
                                          Proved                     Proved
                                            Plus                       Plus
                        Proved Probable Probable   Proved Probable Probable
                        (MMcf)   (MMcf)   (MMcf)  (Mbbls)  (Mbbls)  (Mbbls)
----------------------------------------------------------------------------
December 31, 2012       38,736   20,212   58,949      893      476    1,369
  Extensions               814    1,494    2,309       48      102      150
  Improved recovery          -        -        -        -        -        -
  Technical revisions    1,831   (3,433)  (1,602)     181      (64)     117
  Discoveries                -        -        -        -        -        -
  Acquisitions             361      140      501        -        -        -
  Dispositions               -        -        -        -        -        -
  Economic factors         (55)     (29)     (84)      (0)      (1)      (1)
  Production            (6,445)       -   (6,445)    (199)       -     (199)
----------------------------------------------------------------------------
December 31, 2013       35,243   18,385   53,627      923      513    1,436
----------------------------------------------------------------------------

                                                       Oil Equivalent
                                                 ---------------------------
                                                                     Proved
                                                                       Plus
                                                   Proved Probable Probable
                                                   (Mboe)   (Mboe)   (Mboe)
----------------------------------------------------------------------------
December 31, 2012                                  15,082    9,343   24,425
  Extensions                                          835      814    1,649
  Improved recovery                                     -        -        -
  Technical revisions                               1,496   (1,669)    (174)
  Discoveries                                           -        -        -
  Acquisitions                                        142      152      293
  Dispositions                                          -        -        -
  Economic factors                                    (14)     (11)     (25)
  Production                                       (3,057)       -   (3,057)
----------------------------------------------------------------------------
December 31, 2013                                  14,483    8,629   23,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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                      2013      2012      2011    Results
----------------------------------------------------------------------------
Finding and development expenditures
 ($000s)                               29,287    36,746    25,649     91,682
  Change in future development
   capital estimates ($000s)            1,142      (934)    1,556      1,764
  Net reserve additions by
   development (Mboe)                     834     1,071       581      2,486
Finding and development costs
 ($/boe)                                36.47     33.45     46.81      37.59
----------------------------------------------------------------------------
Acquisition expenditures ($000s)       10,091    60,852     7,467     78,410
Net reserve additions by acquisition
 (Mboe)                                   142     2,300       103      2,545
Acquisition costs ($/boe)               71.21     26.46     72.42      30.81
----------------------------------------------------------------------------
Total expenditures ($000s)             39,378    97,598    33,116    170,092
  Change in future development
   capital estimates ($000s)            1,142      (934)    1,556      1,764
  Net reserve additions (Mboe)            976     3,371       684      5,031
Finding, development and acquisition
 costs ($/boe)                          41.52     28.68     50.67      34.16
----------------------------------------------------------------------------

                                                                  Three-Year
Net Proved Plus Probable Reserves        2013      2012      2011    Results
----------------------------------------------------------------------------
Finding and development expenditures
 ($000s)                               29,287    36,746    25,649     91,682
  Change in future development
   capital estimates ($000s)            3,448     1,916     4,959     10,323
  Net reserve additions by
   development (Mboe)                   1,649     1,809     1,085      4,543
Finding and development costs
 ($/boe)                                19.85     21.37     28.20      22.45
----------------------------------------------------------------------------
Acquisition expenditures ($000s)       10,091    60,852     7,467     78,410
  Net reserve additions by
   acquisition (Mboe)                     294     3,483       207      3,983
Acquisition costs ($/boe)               34.38     17.47     36.12      19.68
----------------------------------------------------------------------------
Total expenditures ($000s)             39,378    97,598    33,116    170,092
  Change in future development
   capital estimates ($000s)            3,447     1,916     4,959     10,322
  Net reserve additions (Mboe)          1,943     5,292     1,292      8,527
Finding, development and acquisition
 costs ($/boe)                          22.04     18.80     29.47      21.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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)             2013      2012      2011    Results
----------------------------------------------------------------------------
Operating netback (1) (4)               47.91     45.09     51.65      48.03
Finding, development and acquisition
 costs (2) (4)                          22.04     18.80     29.47      21.16
Recycle ratio (times) (3)                 2.2       2.4       1.8        2.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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, 2013
(gross acres) (1)                    Developed    Undeveloped          Total
----------------------------------------------------------------------------
Mineral title lands (2)                361,246        170,821        532,067
Royalty assumption lands (3)            73,624         21,198         94,822
----------------------------------------------------------------------------
Total title lands (4)                  434,870        192,019        626,889
Gross overriding royalty (GORR)
 lands (5)                           1,631,848        588,363      2,220,211
----------------------------------------------------------------------------
Total royalty lands                  2,066,718        780,382      2,847,100
Working interest properties            169,429         41,691        211,120
----------------------------------------------------------------------------
Total land holdings                  2,236,147        822,073      3,058,220
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Land Holdings by Province
                        Royalty Interest           Working Interest
                     -------------------------------------------------------
                     Developed Undeveloped     Developed      Undeveloped
                     -------------------------------------------------------
                     Gross (1)   Gross (1) Gross (1)    Net Gross (1)   Net
----------------------------------------------------------------------------
Alberta              1,601,021     390,976   132,927 19,692    28,188 5,743
British Columbia        85,152      24,523    19,247  1,265     6,131   101
Saskatchewan           285,488     188,881    17,097  5,787     7,293 4,000
Manitoba                 6,258       1,422       158     37        79    18
Ontario                 88,799     174,580         -      -         -     -
----------------------------------------------------------------------------
Total                2,066,718     780,382   169,429 26,781    41,691 9,862
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                           Total Acreage
                     -------------------------------------------------------
                                                       Developed Undeveloped
                     -------------------------------------------------------
                                                       Gross (1)   Gross (1)
----------------------------------------------------------------------------
Alberta                                                1,733,948     419,164
British Columbia                                         104,399      30,654
Saskatchewan                                             302,585     196,174
Manitoba                                                   6,416       1,501
Ontario                                                   88,799     174,580
----------------------------------------------------------------------------
Total                                                  2,236,147     822,073
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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
                                                      2013
                                    ----------------------------------------
                                           Q4        Q3        Q2        Q1
                                    ----------------------------------------
FINANCIAL ($000s, except as noted)
Revenue, net of royalty expense        43,436    49,728    42,704    39,332
Dividends declared                     28,373    28,206    28,019    27,897
  Per share ($) (1)                      0.42      0.42      0.42      0.42
Net income                             14,106    18,961    14,292    10,493
  Per share, basic and diluted ($)       0.21      0.28      0.21      0.16
Funds from operations (2)              29,092    36,407    30,115    23,817
  Per share ($) (2)                      0.43      0.54      0.45      0.36
Dividends paid in shares (DRIP)         7,617     9,076     6,874     4,381
  Average DRIP participation rate
   (%)                                     27        32        25        16
Property and royalty acquisitions
 (net)                                  6,891     2,542       658         -
Capital expenditures                    5,335     5,725     3,313    14,914
Long-term debt                         49,000    49,000    55,000    47,000
----------------------------------------------------------------------------
SHARES OUTSTANDING
  Weighted average, basic (000s)       67,483    67,078    66,649    66,375
  At quarter end (000s)                67,746    67,326    66,874    66,522
----------------------------------------------------------------------------
OPERATING ($/boe, except as noted)
Daily production (boe/d) (3)            9,173     8,699     8,714     9,067
  Royalty interest production (%)          68        67        71        71
Average selling price                   52.99     63.74     54.66     49.09
Operating netback (2)                   44.97     55.79     47.80     43.32
Operating expenses                       6.50      6.36      6.06      4.88
  Working interest properties           20.53     19.50     21.00     16.91
Net general and administrative
 expenses (4)                            2.13      1.74      2.04      3.47
----------------------------------------------------------------------------
BENCHMARK PRICES
WTI crude oil (US$/bbl)                 97.46    105.83     94.22     94.37
Exchange rate (Cdn$/US$)                 0.95      0.96      0.98      0.99
Edmonton Par crude oil (Cdn$)           86.28    104.69     92.55     88.16
Western Canada Select (WCS)
 (Cdn$/bbl)                             68.44     91.71     76.78     62.96
WTI/Edmonton Par differential
 ($/bbl)                               (11.18)    (1.14)    (1.67)    (6.21)
Edmonton Par/WCS differential
 (Cdn$/bbl)                            (17.84)   (12.98)   (15.77)   (25.20)
AECO natural gas (Cdn$/Mcf)              3.15      2.82      3.59      3.08
----------------------------------------------------------------------------
SHARE TRADING PERFORMANCE
High ($)                                24.63     24.88     24.58     24.48
Low ($)                                 21.54     22.50     22.46     21.00
Close ($)                               22.11     23.78     23.57     23.38
Volume (000s)                           6,077     4,374     8,108     7,203
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                      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                             13,431    11,975     7,862    13,060
  Per share, basic and diluted ($)       0.20      0.18      0.12      0.21
Funds from operations (2)              31,475    26,272    20,522    25,613
  Per share ($) (2)                      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
   (%)                                     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 ($/boe, except as noted)
Daily production (boe/d) (3)            9,510     8,654     8,501     8,733
  Royalty interest production (%)          66        68        76        74
Average selling price                   51.55     51.71     45.74     54.80
Operating netback (2)                   44.59     45.59     40.64     49.48
Operating expenses                       5.51      5.02      3.96      4.68
  Working interest properties           16.36     15.47     16.47     17.86
Net general and administrative
 expenses (4)                            2.25      1.88      2.13      3.31
----------------------------------------------------------------------------
BENCHMARK PRICES
WTI crude oil (US$/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$)           83.99     84.33     83.95     92.23
Western Canada Select (WCS)
 (Cdn$/bbl)                             69.43     69.99     71.29     81.61
WTI/Edmonton Par differential
 ($/bbl)                                (4.19)    (7.89)    (9.54)   (10.70)
Edmonton Par/WCS differential
 (Cdn$/bbl)                            (14.56)   (14.34)   (12.66)   (10.62)
AECO natural gas (Cdn$/Mcf)              3.06      2.19      1.83      2.52
----------------------------------------------------------------------------
SHARE TRADING PERFORMANCE
High ($)                                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
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Based on the number of shares issued and outstanding at each record
    date.
(2) See Additional GAAP Measures and Non-GAAP Financial Measures.
(3) Reported production for a period may include minor adjustments from
    previous production periods.
(4) Excludes share based and other compensation.

Consolidated Balance Sheets
                                                 December 31    December 31
($000s) (unaudited)                                     2013           2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Assets
Current assets:
  Cash                                                 $ 158          $ 102
  Accounts receivable                                 25,587         23,225
----------------------------------------------------------------------------
                                                      25,745         23,327
Exploration and evaluation assets                     24,858         25,905
Petroleum and natural gas interests                  377,262        399,005
----------------------------------------------------------------------------
                                                   $ 427,865      $ 448,237
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities:
  Dividends payable                                  $ 9,485        $ 9,278
  Accounts payable and accrued liabilities            10,813         12,743
  Current taxes payable                                  730         23,095
  Current portion of share based and other
   compensation payable                                1,102          2,108
----------------------------------------------------------------------------
                                                      22,130         47,224
Decommissioning liability                             15,781         16,714
Share based and other compensation payable             1,240          1,290
Long-term debt                                        49,000         18,000
Deferred income tax liability                         45,642         49,194

Shareholders' equity:
  Shareholders' capital                              455,497        422,728
  Contributed surplus                                  2,167          2,036
  Deficit                                           (163,592)      (108,949)
----------------------------------------------------------------------------
                                                     294,072        315,815
----------------------------------------------------------------------------
                                                   $ 427,865      $ 448,237
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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)               2013       2012       2013       2012
----------------------------------------------------------------------------

Revenue:
  Royalty income and working
   interest sales                 $ 45,287   $ 45,794  $ 181,578  $ 168,134
  Royalty expense                   (1,851)    (1,962)    (6,378)    (6,474)
----------------------------------------------------------------------------
                                    43,436     43,832    175,200    161,660
----------------------------------------------------------------------------

Expenses:
  Operating                          5,482      4,820     19,356     15,598
  General and administrative         1,795      1,972      7,634      7,746
  Share based and other
   compensation                       (158)       999      1,531      2,371
  Interest and financing               613        421      2,554      2,235
  Depletion and depreciation        15,283     16,372     61,320     64,576
  Accretion of decommissioning
   liability                           127        107        452        381
  Management fee                     1,080      1,072      4,495      3,808
----------------------------------------------------------------------------
                                    24,222     25,763     97,342     96,715
----------------------------------------------------------------------------

Income before taxes                 19,214     18,069     77,858     64,945

Income tax:
  Current expense                    6,214      5,063     23,558     27,792
  Deferred recovery                 (1,106)      (425)    (3,552)    (9,175)
----------------------------------------------------------------------------
                                     5,108      4,638     20,006     18,617
----------------------------------------------------------------------------

Net income and comprehensive
 income                           $ 14,106   $ 13,431   $ 57,852   $ 46,328
----------------------------------------------------------------------------
Net income per share, basic and
 diluted                            $ 0.21     $ 0.20     $ 0.86     $ 0.71
----------------------------------------------------------------------------

Weighted average number of
 shares:
  Basic                         67,483,469 66,090,969 66,899,776 64,880,038
  Diluted                       67,598,380 66,194,503 67,021,372 64,979,074
----------------------------------------------------------------------------

Consolidated Statements of Cash Flows
                                     Three Months Ended          Year ended
                                            December 31         December 31
($000s) (unaudited)                      2013      2012      2013      2012
----------------------------------------------------------------------------

Operating:
  Net income                         $ 14,106  $ 13,431  $ 57,852  $ 46,328
  Items not involving cash:
    Depletion and depreciation         15,283    16,372    61,320    64,576
    Share based and other
     compensation                        (158)      999     1,531     2,371
    Deferred income tax recovery       (1,106)     (425)   (3,552)   (9,175)
    Accretion of decommissioning
     liability                            127       107       452       381
    Management fee                      1,080     1,072     4,495     3,808
  Expenditures on share based and
   other compensation                    (189)        -    (2,299)   (3,883)
  Decommissioning expenditures            (51)      (81)     (368)     (524)
----------------------------------------------------------------------------
  Funds from operations                29,092    31,475   119,431   103,882
  Changes in non-cash working
   capital                              1,336     6,708   (26,196)   34,250
----------------------------------------------------------------------------
                                       30,428    38,183    93,235   138,132
Financing:
  Issuance of shares, net of issue
   costs                                    -         -         -    67,597
  Long-term debt                            -    (7,000)   31,000   (30,000)
  Dividends paid                      (20,697)  (21,060)  (84,340)  (81,436)
----------------------------------------------------------------------------
                                      (20,697)  (28,060)  (53,340)  (43,839)
Investing:
  Deposit on acquisition                    -         -         -     5,000
  Property and royalty acquisitions    (6,891)     (243)  (10,091)  (60,852)
  Capital expenditures                 (5,335)   (7,743)  (29,287)  (36,746)
  Changes in non-cash working
   capital                              1,965    (2,149)     (461)   (1,757)
----------------------------------------------------------------------------
                                      (10,261)  (10,135)  (39,839)  (94,355)
----------------------------------------------------------------------------
Increase (decrease) in cash              (530)      (12)       56       (62)
Cash, beginning of period                 688       114       102       164
----------------------------------------------------------------------------
Cash, end of period                     $ 158     $ 102     $ 158     $ 102
----------------------------------------------------------------------------

Consolidated Statements of Changes in Shareholders' Equity
                                                                 Year ended
                                                                December 31
($000s) (unaudited)                                     2013           2012
----------------------------------------------------------------------------

Shareholders' capital:
  Balance, beginning of year                       $ 422,728      $ 323,115
  Shares issued for dividend reinvestment plan        27,948         27,414
  Shares issued in lieu of management fee              4,495          3,808
  Shares issued for deferred share and plan
   redemption                                            326              -
  Shares issued for equity offering                        -         70,725
  Issue costs, net of tax effect                           -         (2,334)
----------------------------------------------------------------------------
  Balance, end of year                               455,497        422,728
----------------------------------------------------------------------------

Contributed surplus:
  Balance, beginning of year                           2,036          1,480
  Share based compensation expense                       597            556
  Deferred share unit plan redemption                   (466)             -
----------------------------------------------------------------------------
  Balance, end of year                                 2,167          2,036
----------------------------------------------------------------------------

Deficit:
  Balance, beginning of year                        (108,949)       (45,709)
  Net income and comprehensive income                 57,852         46,328
  Dividends declared                                (112,495)      (109,568)
----------------------------------------------------------------------------
  Balance, end of year                              (163,592)      (108,949)
----------------------------------------------------------------------------
Total shareholders' equity                         $ 294,072      $ 315,815
----------------------------------------------------------------------------

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at March 6, 2014, 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, 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 2014 and our dividend
    policy; and
--  production rates on properties acquired in 2013.

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.

Additional GAAP Measures

This news release contains the term "funds from operations", which does not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities. 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 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, sustain dividends, and repay debt. We believe that such a measure provides a useful assessment of Freehold's operations on a continuing basis by eliminating certain non-cash charges. It is also used by research analysts to value and compare oil and gas companies, and it is frequently included in their published research when providing investment recommendations. 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.

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, operating netback, finding, development and acquisition (FD&A) costs, and recycle ratio. We believe that these measures are useful supplemental measures for management and investors to analyze operating performance, and we use these terms to facilitate the understanding and comparability of our results of operations. However, these terms do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

Operating 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.

Availability on SEDAR

Freehold's 2013 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 on or about March 10, 2014.

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