04:04:58 EDT Mon 16 Sep 2019
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Freehold Royalties Ltd
Symbol C : FRU
Shares Issued 99,052,165
Close 2016-03-03 C$ 11.83
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Freehold loses $4.08-million in 2015

2016-03-03 17:57 ET - News Release

Mr. Matt Donohue reports

FREEHOLD ROYALTIES LTD. ANNOUNCES 2015 FOURTH QUARTER RESULTS AND YEAR-END RESERVES, ADJUSTS DIVIDEND

Freehold Royalties Ltd. has released its 2015 fourth-quarter results and reserves as at Dec. 31, 2015.

                            RESULTS AT A GLANCE

                        Three Months Ended       Twelve Months Ended
                               December 31               December 31
FINANCIAL ($000s, except
 as noted)                  2015     2014  Change     2015     2014  Change

Gross revenue             33,833   43,631     -22% 135,664  199,850     -32%
Net income (loss)         (7,423)  11,082    -167%  (4,080)  66,447    -106%
  Per share, basic and
   diluted ($)             (0.08)    0.15    -153%   (0.05)    0.94    -105%
Funds from operations(1)  25,509   30,774     -17% 103,820  138,447     -25%
  Per share, basic
   ($)(1)                   0.26     0.41     -37%    1.15     1.95     -41%
Operating income(1)       29,186   37,584     -22% 115,152  175,192     -34%
  Operating income from
   royalties (%)              89       80      11%      87       78      12%
Acquisitions                (143)  60,566    -100% 411,352  248,274      66%
Capital expenditures       5,607   13,500     -58%  22,295   33,701     -34%
Dividends declared        20,747   31,353     -34%  90,139  119,788     -25%
  Per share ($)(2)          0.21     0.42     -50%    1.00     1.68     -40%
Net debt obligations(1)  146,949  135,810       8% 146,949  135,810       8%
Shares outstanding,
 period end (000s)        98,940   74,919      32%  98,940   74,919      32%
Average shares
 outstanding (000s)(3)    98,731   74,545      32%  90,505   71,029      27%
OPERATING
Average daily production
 (boe/d)(4)               11,815    9,836      20%  10,945    9,180      19%
Average price
 realizations ($/boe)(4)   30.34    47.46     -36%   33.20    58.91     -44%
Operating netback
 ($/boe)(1) (4)            26.85    41.54     -35%   28.83    52.30     -45%

(1) See Additional GAAP Measures and Non-GAAP Financial Measures.
(2) Based on the number of shares issued and outstanding at each record
    date.
(3) Weighted average number of shares outstanding during the period, basic.
(4) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).


Dividend Announcement

Reflecting continued weakness in commodity prices, Freehold's Board of Directors has approved an adjustment to its monthly dividend to $0.04 per share from $0.07 per share. The Board of Directors has declared a dividend of Cdn. $0.04 per common share to be paid on April 15, 2016 to shareholders of record on March 31, 2016. Including the April 15 payment, our 12-month trailing cash dividends total $0.91 per share. This dividend is designated as an eligible dividend for Canadian income tax purposes.

The dividend reduction aligns with a lower for longer commodity outlook. Freehold's goal is not to pay dividends with debt, thus maintaining strength within our balance sheet and ensuring the long term success of our business model. Freehold will continue to evaluate dividend levels on a quarterly basis, with the expectation to increase dividend levels as funds from operations improve.

2015 Fourth Quarter Highlights

Freehold delivered strong operational results in the fourth quarter of 2015. Some of the highlights included:

  • -- Production for Q4-2015 averaged 11,815 boe/d, a 20% increase over Q4- 2014 and a 5% increase over Q3-2015.
  • -- Royalties accounted for 89% of operating income and 78% of production, reinforcing our royalty focus.
  • -- Royalty production was up 26% compared to Q4-2014 averaging 9,249 boe/d. Growth in volumes was associated with a combination of production acquired through the year, new production from drilling on our royalty lands and a strong quarter from our audit function, including compensatory royalties on our mineral title lands, largely responsible for approximately 500 boe/d of prior period adjustments.
  • -- Working interest production averaged 2,566 boe/d for the quarter, up 2% when compared to the same period last year.
  • -- Funds from operations totalled $25.5 million ($0.26/share) in Q4-2015, down 17% from the same period last year owing to continued weakness in oil and natural gas prices.
  • -- Though average commodity price realizations decreased 36% reduced revenues were partly offset by the increase in production volumes, resulting in a 22% decrease in gross revenue compared to Q4-2014.
  • -- Q4-2015 net loss was $7.4 million (Q4-2014 net income $11.1 million) primarily due to a non-cash impairment charge of $8.0 million in our southeast Saskatchewan working interest area, as a result of the continued drop in expected future commodity prices. Lower revenues and higher depletion and depreciation also contributed to the difference.
  • -- Dividends declared for Q4-2015 totalled $0.21 per share, down from $0.42 per share one year ago due to the reduction in funds from operations resulting from lower commodity prices.
  • -- Average participation in our dividend reinvestment plan (DRIP) was 13% (Q4-2014 - 35%). DRIP proceeds for 2015 totalled $17.2 million.
  • -- Net capital expenditures on our working interest properties totalled $5.6 million over the quarter.
  • -- Basic payout ratio (dividends declared/funds from operations) for 2015 totalled 87% while the adjusted payout ratio (cash dividends plus capital expenditures/funds from operations) for the same period was 95%.
  • -- At December 31, 2015, net debt totalled $146.9 million, down $2.1 million from $149.0 million at September 30, 2015. This implies a net debt to 12-month trailing funds from operations ratio of 1.4 times (excluding the proforma effects of acquisitions).

Guidance Update

The table below summarizes our key operating assumptions for 2016.

  • -- Despite lower spending on our working interest and royalty lands, we have not revised our 2016 production forecast (9,800 boe/d). Volumes are expected to be weighted approximately 62% oil and natural gas liquids (NGLs) and 38% natural gas. We continue to maintain our royalty focus with royalty production accounting for 78% of forecasted 2016 production and 94% of operating income.
  • -- Continuing negative momentum in the commodity environment has resulted in a downward revision to our price assumptions. Through 2016, we are now forecasting WTI and WCS prices to average US$35.00/bbl and $31.00/bbl, respectively (previously US$50.00/bbl and $47.00/bbl). Our AECO natural gas price assumption has also been revised downwards to $2.00/mcf (previously $2.75/mcf).
  • -- The Canadian/U.S. exchange rate has been adjusted downwards to $0.72 (previously $0.76), reflecting the recent declining valuation of the Canadian dollar relative to the United States dollar.
  • -- Operating costs have been reduced to $4.75/boe from $5.00/boe representing an increasing portion of our production coming from royalties, which have no operating costs.
  • -- We have revised our general and administration expense to $2.65/boe from $2.85/boe, as a result of cost reduction initiatives.
  • -- Our capital spending budget has been reduced from $15 million to $7 million reflecting the weaker commodity outlook. A large percentage of our capital expenditures program is non-operated and the exact capital is difficult to predict. We expect to have additional information on the spending of our partners as we move through the year.

2016 Key Operating Assumptions

 Guidance Dated
2016 Annual Average                              Mar. 3, 2016  Nov. 12, 2015
----------------------------------------------------------------------------
Daily production                          boe/d         9,800          9,800
WTI oil price                           US$/bbl         35.00          50.00
Western Canadian Select (WCS)          Cdn$/bbl         31.00          47.00
AECO natural gas price                 Cdn$/Mcf          2.00           2.75
Exchange rate                          Cdn$/US$          0.72           0.76
Operating costs                           $/boe          4.75           5.00
General and administrative costs (1)      $/boe          2.65           2.85
Capital expenditures                 $ millions             7             15
Dividends paid in shares (DRIP) (2)  $ millions             8             13
Weighted average shares outstanding    millions           100            100
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes share based and other compensation.
(2) Assumes average 15% participation rate in Freehold's dividend
    reinvestment plan, which is subject to change at the participants'
    discretion.


Based on our current guidance and commodity price assumptions, and assuming no significant changes in the current business environment, we expect to maintain the current monthly dividend rate of $0.04/share through 2016, subject to the Board's quarterly review and approval.

Recognizing the cyclical nature of the oil and gas industry, we continue to closely monitor commodity prices and industry trends for signs of changing 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.

Fourth Quarter Production

Production volumes in Q4-2015 averaged 11,815 boe/d, an increase of 20% when compared with levels averaged in the comparative period in 2014.

  • -- Royalty production averaged 9,249 boe/d in Q4-2015, a 26% increase when compared to Q4-2014. Oil and natural gas liquids production was up 46%, largely associated with acquisitions and the strength of our audit function. On the natural gas side, volumes were up 4% from Q4-2014.
  • -- Working interest production volumes averaged 2,566 boe/d in Q4-2015, a 2% increase versus Q4-2014.


                            Three Months Ended       Twelve Months Ended
                               December 31               December 31
                        ----------------------------------------------------
                            2015     2014  Change     2015     2014  Change
----------------------------------------------------------------------------
Royalty interest (1)
Oil (bbls/d)               5,204    3,501      49%   4,456    3,384      32%
NGL (bbls/d)                 498      403      24%     422      435      -3%
Natural gas (Mcf/d)       21,280   20,494       4%  20,590   17,915      15%
Oil equivalent (boe/d)     9,249    7,320      26%   8,310    6,805      22%
----------------------------------------------------------------------------
Working interest (1)
Oil (bbls/d)               1,668    1,972     -15%   1,720    1,851      -7%
NGL (bbls/d)                 185      101      83%     159      102      56%
Natural gas (Mcf/d)        4,276    2,657      61%   4,533    2,531      79%
Oil equivalent (boe/d)     2,566    2,516       2%   2,635    2,375      11%
----------------------------------------------------------------------------
Total
Oil (bbls/d)               6,872    5,473      26%   6,176    5,235      18%
NGL (bbls/d)                 683      504      36%     581      537       8%
Natural gas (Mcf/d)       25,556   23,151      10%  25,123   20,446      23%
Oil equivalent (boe/d)    11,815    9,836      20%  10,945    9,180      19%
----------------------------------------------------------------------------
Number of days in period
 (days)                       92       92       0%     365      365       0%
Total volumes during
 period (Mboe)             1,087      905      20%   3,995    3,350      19%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) On certain properties where we have both a royalty interest and a
    working interest, production is allocated based on the applicable
    royalty and working interest percentages.


Royalty Interest Activity

In total, 377 (18.9 equivalent net) wells were drilled on our royalty lands through 2015 which was a 25% improvement versus 2014 on an equivalent net basis. Through Q4-2015, 85 gross (3.6 net) locations were drilled on our royalty lands; this compares to 138 gross (4.3 net) in Q4-2014.

Our royalty lands give us exposure to some of the most economic resource plays currently being pursued in the Western Canadian Sedimentary Basin. Through 2015, we have seen an increase in activity on our lands largely as a result of acquisitions made over the last two years. Some of the royalty drilling highlights are described below.

In the Viking Dodsland play horizontal drilling was very strong within the established royalty area. In 2015, the operator rig released 109 wells and has 64 gross wells licenced, representing a significant ready to drill inventory. The operator is currently focused on completing 21 wells from the Q4-2015 drill program.

In southeast Saskatchewan/Manitoba we have seen continued interest in our royalty lands situated in the heart of the Bakken and Mississippian subcrop play areas. In Q4-2015, seven gross Bakken horizontal wells were drilled on our royalty lands. In the Mississippian play areas, 10 gross horizontals wells were drilled for Midale and Frobisher targets. Operators achieved exceptional production results from these wells with 30-day average rates from each well exceeding 150 boe/d. Royalty drilling activity continued in Manitoba where several operators have drilled six gross wells targeting Reston and Bakken/Three Forks reservoirs.

In Central Alberta, three Nisku horizontals were drilled on our royalty lands located on the prolific Leduc Woodbend reef complex. The operator in this area is targeting the light oil trapped in Nisku reefs draped over the Leduc reef complex. Horizontal drilling and staged fracture treatments are leading to impressive 3-month average production rates of 160 boe/d per well. With modern drilling and completion technology there is abundant incremental light oil remaining to be recovered from these heritage Devonian reef production areas.

In the Deep Basin, we had five deep horizontal wells drilled on our royalty lands. Montney and Wilrich targets are being pursued by several operators in the overpressured liquids rich areas of the basin. Two of these horizontal tests targeting the Wilrich had first month average production exceeding 14 MMcf/d of gas plus associated liquids, which demonstrates the material nature of these play types.

Working Interest Activity

Freehold's working interest drilling program was relatively limited for Q4-2015. Five wells were drilled in our southeast Saskatchewan operating area for Midale and Bakken horizontal targets. Production results are very encouraging with current average production greater than 150 boe/d per well.

In addition, a number of Freehold operated wells drilled in the third quarter were brought on stream in Q4-2015. Two Mississippian Frobisher horizontals (100% interest) were placed on production in December with each well averaging 45 boe/d. Also our vertical heavy oil well drilled in the Greenstreet area (90% interest) was placed on production in November and is currently averaging approximately 40 boe/d.

Freehold is also encouraged by the strong production performance from its Pembina Cardium horizontal well drilled early in 2015 (42.5% working interest, 15% royalty interest). The well continues to produce strongly averaging greater than 250 boe/d for the quarter. Additional downspace locations offsetting this location are ready to be drilled when prices recover.

 Three Months Ended December 31 Twelve Months Ended December 31
                   2015            2014            2015            2014
             ---------------------------------------------------------------
               Gross  Net(1)   Gross Net (1)   Gross  Net(1)   Gross Net (1)
----------------------------------------------------------------------------
Oil                5     0.7      22     4.9      39     7.3      47    11.3
Natural gas        -       -       3     0.8       4     0.2       7     0.9
Other              -       -       -       -       -       -       -       -
----------------------------------------------------------------------------
Total              5     0.7      25     5.7      43     7.5      54    12.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.


2015 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), as under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (NI 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 exploration and development companies. 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 present value of future net reserves before tax totalled $860 million (NPV 10), up from $786 million in 2014. The increase versus 2014 was associated with acquisitions completed through 2015, offset by the reduction in prices.
  • -- Net proved plus probable reserves at December 31, 2015 totalled 36.1 MMboe, with reserves assigned to 26,948 wells. Net proved plus probable royalty interest reserves increased 26% year-over-year, and net proved plus probable working interest reserves were flat. Approximately 64% of our net reserves are in the proved category, and 73% of our net proved reserves are producing. On a boe basis, net reserves are 58% liquids (18% heavy oil, 34% light and medium oil, 6% natural gas liquids) and 42% natural gas.
  • -- On our royalty lands, net proved plus probable reserve additions totalled 9.5 MMboe (81% liquids). Drilling added 0.9 MMboe of net proved plus probable reserves, and acquisitions added 8.6 MMboe of net proved plus probable reserves. Based on this, we replaced approximately 303% of 2015 production.
  • -- Freehold's finding costs are calculated based on net reserves. In 2015, finding and development costs for net proved plus probable reserves were $12.98 per boe (including changes in future development capital), while acquisition costs were $37.87 per boe and the all-in finding, development and acquisition (FD&A) cost was $34.83 per boe (including changes in future development capital). Based on an operating netback of $28.83 per boe in 2015, these activities resulted in a recycle ratio of 0.8, and a three-year average recycle ratio of 1.4.
  • -- Our land holdings as at December 31, 2015 encompassed approximately 3.7 million gross acres, up 16% from last year mainly as a result of acquisitions completed throughout the year. Royalty interests comprised over 90% of our acreage.
  • -- As at year-end 2015, our undeveloped land was independently valued at $111.7 million by Seaton-Jordan & Associates Ltd.

Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2015. The evaluation was conducted in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101. Our Reserves Committee met with Trimble to review the findings and procedures, and the reserves report has been accepted by our Board of Directors.

Summary of Oil and Gas Reserves

As of December 31, 2015

Forecast Prices and Costs(1)

 Light and Medium
                          Crude Oil(2)    Heavy Crude Oil   Total Crude Oil
                       -----------------------------------------------------
                       Gross(4)   Net(5) Gross(4)   Net(5) Gross(4)   Net(5)
Reserves Category       (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)  (Mbbls)
----------------------------------------------------------------------------
Proved
  Developed producing     1,470    5,640      651    3,981    2,121    9,621
  Developed non-
   producing                 90       78        -        3       90       81
  Undeveloped                20    1,917        -      242       20    2,159
----------------------------------------------------------------------------
Total proved              1,580    7,635      651    4,227    2,231   11,861
Probable                  1,519    4,711      722    2,443    2,241    7,154
----------------------------------------------------------------------------
Total proved plus
 probable                 3,099   12,346    1,373    6,670    4,472   19,016
----------------------------------------------------------------------------
----------------------------------------------------------------------------


                          Conventional       Natural Gas         Total
                         Natural Gas(3)       Liquids        Oil Equivalent
                       -----------------------------------------------------
                       Gross(4)   Net(5) Gross(4)   Net(5) Gross(4)   Net(5)
Reserves Category        (MMcf)   (MMcf)  (Mbbls)  (Mbbls)   (Mboe)   (Mboe)
----------------------------------------------------------------------------
Proved
  Developed producing     6,441   36,997      148      888    3,342   16,675
  Developed non-
   producing              1,645    1,349       59       42      424      348
  Undeveloped                 -   19,958        -      427       20    5,913
----------------------------------------------------------------------------
Total proved              8,087   58,303      207    1,357    3,786   22,936
Probable                  5,817   31,296      157      748    3,368   13,118
----------------------------------------------------------------------------
Total proved plus
 probable                13,903   89,599      364    2,105    7,154   36,054
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Numbers may not add due to rounding.
(2) Includes an immaterial amount of tight oil reserves.
(3) Includes an immaterial amount of shale gas and coal bed methane
    reserves.
(4) Gross reserves are our share of working interest properties before
    deduction of royalties payable to others. Gross reserves exclude royalty
    interests.
(5) Net reserves are defined as 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, 2015

Forecast Prices and Costs (000's)(1)(2)

 Before Income Taxes, Discounted at (% per year)
                           -------------------------------------------------
Reserves Category                 0%        5%       10%       15%       20%
----------------------------------------------------------------------------
Proved
  Developed producing        767,278   564,204   446,998   371,727   319,597
  Developed non-producing      4,276     3,089     2,354     1,863     1,515
  Undeveloped                302,280   216,824   162,572   126,054   100,381
----------------------------------------------------------------------------
Total proved               1,073,834   784,116   611,925   499,644   421,493
Probable                     730,355   390,233   248,229   175,678   133,226
----------------------------------------------------------------------------
Total proved plus probable 1,804,189 1,174,349   860,154   675,322   554,719
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                             After Income Taxes, Discounted at (% per year)
                           -------------------------------------------------
Reserves Category                 0%        5%       10%       15%       20%
----------------------------------------------------------------------------
Proved
  Developed producing        767,278   564,204   446,998   371,727   319,597
  Developed non-producing      4,276     3,089     2,354     1,863     1,515
  Undeveloped                262,811   192,394   146,898   115,687    93,343
----------------------------------------------------------------------------
Total proved               1,034,366   759,686   596,251   489,277   414,455
Probable                     542,795   290,023   186,727   134,569   104,166
----------------------------------------------------------------------------
Total proved plus probable 1,577,161 1,049,709   782,978   623,847   518,621
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on the December 31, 2015 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, 2015

Forecast Prices and Costs (000's)(1)

 Reserves Category
                                              ------------------------------
                                                                Proved Plus
                                                      Proved       Probable
----------------------------------------------------------------------------
Royalty Income                                     1,019,441      1,675,142
Revenue from working interest properties             208,429        433,902
Royalty expense on working interest properties       (26,009)       (64,298)
Operating costs                                     (109,083)      (207,946)
Development costs                                     (3,216)       (13,875)
Well abandonment and reclamation costs(3)            (15,728)       (18,736)
----------------------------------------------------------------------------
Future net revenue before income taxes             1,073,834      1,804,189
Future income taxes(2)                               (39,468)      (227,027)
----------------------------------------------------------------------------
Future net revenue after income taxes              1,034,366      1,577,161
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
(3) Reflects estimated abandonment and reclamation for all wells (both
    existing and undrilled wells) that have been attributed reserves. Does
    not reflect abandonment and reclamation costs for wells with no
    attributed reserves or for facilities or pipelines.


Future Development Costs (Undiscounted) ($000s)(1)

 Forecast Prices and Costs
                                               -----------------------------
                                                                 Proved Plus
                                                       Proved       Probable
                                                     Reserves       Reserves
Year                                           (undiscounted) (undiscounted)
----------------------------------------------------------------------------
2016                                                      188          4,882
2017                                                    1,477          4,233
2018                                                      564            928
2019                                                       73          2,117
2020                                                      839          1,353
Remainder                                                  76            362
----------------------------------------------------------------------------
Total                                                   3,217         13,875
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2015(1)

 Proved          Total    Proved Plus
                                     Producing         Proved       Probable
----------------------------------------------------------------------------
Net Reserves (Mboe)                     16,675         22,936         36,054
Net Production (Mboe)                    3,198          3,276          3,649
----------------------------------------------------------------------------
Reserves Life Index (years)                5.2            7.0            9.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2016 net production into
    the remaining net reserves).


Reconciliation of Net Reserves(1)

Finding, Development and Acquisition (FD&A) Costs(1)

 Three-year
Net Proved Reserves                      2015      2014      2013    results
----------------------------------------------------------------------------
Finding and development expenditures
 ($000s)                               22,295    33,701    29,287     85,283
  Change in future development
   capital estimates ($000s)           (1,005)    1,638     1,142      1,776
  Net reserve additions by
   development (Mboe)                     820       956       834      2,610
Finding and development cost ($/boe)    25.95     36.98     36.47      33.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Acquisition expenditures ($000s)      366,009   233,274    10,091    609,374
  Net reserve additions by
   acquisition (Mboe)                   6,432     5,903       142     12,477
Acquisition cost ($/Boe)                56.90     39.52     71.21      48.84
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total expenditures ($000s)            388,304   266,975    39,378    694,657
  Change in future development
   capital estimates ($000s)           (1,005)    1,638     1,142      1,776
  Net reserve additions (Mboe)          7,253     6,858       976     15,087
Finding, development and acquisition
 cost ($/boe)                           53.40     39.17     41.52      46.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                                  Three-year
Net Proved Plus Probable Reserves        2015      2014      2013    results
----------------------------------------------------------------------------
Finding and development expenditures
 ($000s)                               22,295    33,701    29,287     85,283
  Change in future development
   capital estimates ($000s)           (4,834)    2,702     3,448      1,315
  Net reserve additions by
   development (Mboe)                   1,346     1,665     1,649      4,660
Finding and development cost ($/boe)    12.98     21.87     19.85      18.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Acquisition expenditures ($000s)      366,009   233,274    10,091    609,374
  Net reserve additions by
   acquisition (Mboe)                   9,664     7,765       294     17,723
Acquisition cost ($/Boe)                37.87     30.04     34.38      34.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total expenditures ($000s)            388,304   266,975    39,378    694,657
  Change in future development
   capital estimates ($000s)           (4,834)    2,702     3,448      1,315
  Net reserve additions (Mboe)         11,010     9,430     1,943     22,383
Finding, development and acquisition
 cost ($/boe)                           34.83     28.60     22.04      31.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Finding, development and acquisition costs are used as a measure of
    capital efficiency. The calculation for finding and development costs
    includes all exploration and development capital for that period plus
    the change in future development capital for that period. This total
    capital including the change in the future development capital is then
    divided by the change in reserves for that period excluding revisions
    for that same period. The calculation for finding, development and
    acquisition costs is calculated in the same manner except it also
    accounts for any acquisition costs (except as otherwise noted) incurred
    during the period. Excluded from 2015 acquisition expenditures are $45.3
    million for undeveloped land acquired and other costs unrelated to
    reserve additions. Included in 2014 acquisition costs are $15.2 million
    of exploration costs from four wells drilled on the East Edson joint
    venture lands and included in 2014 finding and development costs are
    $0.1 million of miscellaneous exploration costs. Excluded from 2014
    acquisition costs are $15.0 million of costs for undeveloped land
    acquired 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
                                         2015      2014      2013    results
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating netback ($/boe)(1)(4)         28.83     52.30     47.90      42.10
Finding, development and acquisition
 costs ($/boe)(2)(4)                    34.83     28.60     22.04      31.09
Recycle Ratio (times)(3)                  0.8       1.8       2.2        1.4
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----------------------------------------------------------------------------
(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.


Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)

 Three Months Ended   Twelve Months Ended
(unaudited)                          December 31           December 31
                                --------------------------------------------
($000s, except per share and
 weighted average data)               2015       2014       2015       2014
----------------------------------------------------------------------------

Revenue:
  Royalty income and working
   interest sales                 $ 33,833   $ 43,631  $ 135,664  $ 199,850
  Royalty expense                     (105)    (1,034)    (2,297)    (5,666)
----------------------------------------------------------------------------
                                    33,728     42,597    133,367    194,184
----------------------------------------------------------------------------

Gain on corporate acquisition            -          -     24,340          -
Other income                             -          -        756          -

Expenses:
  Operating                          4,542      5,013     18,215     18,992
  General and administrative         2,420      2,102     10,643      8,679
  Share based and other
   compensation                         70     (1,164)       766        438
  Interest and financing             1,221      1,196      5,696      4,405
  Depletion and depreciation        26,397     19,237     95,703     67,145
  Impairment                         8,000          -     38,800          -
  Accretion of decommissioning
   liability                           152        123        566        498
  Management fee                       781      1,034      3,693      4,743
----------------------------------------------------------------------------
                                    43,583     27,541    174,082    104,900
----------------------------------------------------------------------------

Income (loss) before taxes          (9,855)    15,056    (15,619)    89,284

Income taxes:
  Current expense (recovery)             -      3,273     (5,097)    22,178
  Deferred expense (recovery)       (2,432)       701     (6,442)       659
----------------------------------------------------------------------------
                                    (2,432)     3,974    (11,539)    22,837
----------------------------------------------------------------------------

Net income (loss) and
 comprehensive income (loss)      $ (7,423)  $ 11,082   $ (4,080)  $ 66,447
----------------------------------------------------------------------------
Net income (loss) per share,
 basic and diluted                 $ (0.08)    $ 0.15    $ (0.05)    $ 0.94
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average number of
 shares:
  Basic                         98,730,518 74,544,796 90,504,786 71,029,156
  Diluted                       98,730,518 74,681,308 90,504,786 71,170,896
----------------------------------------------------------------------------
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Freehold's 2015 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 by on or about March 7, 2016.

We seek Safe Harbor.

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