Freehold Royalties Ltd. Announces 2012 Third Quarter Results

Freehold Royalties Ltd. Announces 2012 Third Quarter Results and
November Dividend 
CALGARY, ALBERTA -- (Marketwire) -- 11/08/12 -- Freehold Royalties
Ltd. (Freehold) (TSX:FRU) today announced third quarter results for
the period ended September 30, 2012. 

RESULTS AT A GLANCE                                                         
                            Three Months Ended  Nine Months Ended September 
                                  September 30                           30 
FINANCIAL ($000s,                                                           
 except as noted)       2012     2011   Change       2012     2011   Change 
Gross revenue         41,811   35,819       17%   122,340  112,606        9%
Net income            11,975   11,290        6%    32,897   39,226      -16%
 Per share, basic                                                           
  and diluted ($)       0.18     0.19       -5%      0.51     0.66      -23%
Cash flow from                                                              
 activities           36,212   30,255       20%    99,949   85,775       17%
 Per share ($)          0.55     0.50       10%      1.55     1.44        8%
 expenditures          9,160    5,537       65%    29,003   14,739       97%
Property and                                                                
 acquisitions (net)   10,789    7,297       48%    60,609    7,662      691%
Dividends paid in                                                           
 cash                 20,542   16,482       25%    60,376   51,942       16%
Dividends paid in                                                           
 shares (DRIP)         7,013    8,765      -20%    20,742   23,258      -11%
Dividends declared                                                          
 (2)                  27,616   25,322       
 9%    81,781   75,383        8%
 Per share ($) (3)      0.42     0.42        0%      1.26     1.26        0%
Long-term debt,                                                             
 period end           25,000   51,000      -51%    25,000   51,000      -51%
Shares outstanding,                                                         
 period end (000s)    65,879   60,492        9%    65,879   60,492        9%
Average shares                                                              
 outstanding (000s)                                                         
 (4)                  65,677   60,198        9%    64,473   59,756        8%
Average daily                                                               
 production (boe/d)                                                         
 (5)                   8,654    7,195       20%     8,628    7,376       17%
Average price                                                               
 ($/boe) (5)           51.71    52.80       -2%     50.80    54.32       -6%
(1) Includes dividend declared in September and paid in October.            
(2) Based on the number of shares issued and outstanding at each record     
(3) Weighted average number of shares outstanding during the period, basic. 
(4) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).       

November Dividend Announcement  
The Board of Directors has declared the November dividend of $0.14
per share, which will be paid on December 17, 2012 to shareholders of
record on November 30, 2012. This dividend is designated as an
eligible dividend for Canadian income tax purposes. Including the
December 17, 2012 payment, the twelve-month trailing cash dividends
total $1.68 per share.  
2012 Third Quarter Highlights 

--  Average production for the third quarter rose 20%, while average price
    realizations fell 2%, resulting in a 17% increase in gross revenue
    compared to the third quarter of 2011. Production increases were mainly
    attributed to drilling activities (70%) and acquisitions (30%). 
--  Oil and natural gas liquids (NGL) production increased 32% in the third
    quarter, and natural gas production rose 2%. While natural gas
    production accounted for 33% of boe production in the third quarter, it
    comprised only 7% of revenue as a result of weak prices. 
--  Royalty production rose 13%, mainly due to successful royalty drilling
    in southeast Saskatchewan and east central Alberta, as well as the
    addition of over 500 boe per day stemming from various royalty interests
    acquired since September 2011. Working interest production was 40%
    higher than the third quarter last year as a result of higher activity
    levels, flush production from newly completed wells, and prior period
    adjustments of approximately 190 boe per day. 
--  Cash flow from operating activities rose 20%, and on a per share basis
    rose 10%, as a result of the factors outlined above. 
--  Net income of $12 million was 6% higher than last year, mainly as a
    result of higher revenue, partly offset by higher depletion and
    depreciation expense. Non-cash charges (excluding current income tax)
    included in net income amounted to $14.5 million (2011 - $17.7 million).
--  Dividends for the third quarter of 2012 totalled $0.42 per share,
    unchanged from last year. 
--  Average participation in our DRIP was 25%. Cash retained through the
    DRIP ($20.7 million in the first nine months of 2012) continued to help
    fund our capital program. 
--  Net capital expenditures on our working interest properties totalled
    $9.2 million ($29.0 million for the year to date), the majority of which
    was incurred on horizontal drilling and multi-stage fracture well
    completions in southeast Saskatchewan. 
--  On August 31, 2012, we acquired approximately 6,100 net acres of leased
    mineral title lands in Alberta and Saskatchewan. The lands and 90 boe
    per day (21% royalty production) were purchased for $10.8 million and
    funded through our existing credit facilities. 

Royalty Interest Drilling  
On an equivalent net basis, royalty drilling declined 33% from the
third quarter last year, while drilling for the year to date declined
3%. The decline can be attributed to a reduction in natural gas
drilling due to the low price environment.  
To date in 2012, royalty drilling has focused primarily on recognized
oil trends within the Alberta and Williston basins, including the
Lloydminster heavy oil area, the Mississippian subcrop play of
southeast Saskatchewan, and the Cardium light oil play in west
central Alberta. Almost 80% of the equivalent net wells drilled in 
the first nine months of 2012 were oil, up from 76% oil in the first
nine months of last year. Both vertical and horizontal wells were
drilled on our royalty lands, with horizontal drilling accounting for
64% of the activity this year as compared to 58% during the same
period last year.  
As at September 30, 2012, there were 107 (4.8 equivalent net)
licensed drilling locations on our royalty lands. On a net basis,
this is similar to last year, when there were 118 (4.9 equivalent
net) locations. We view continued well licence activity as a positive
indicator of the ongoing and future development potential on our
royalty lands.  
Acquisition of Mineral Title Lands  
On August 31, 2012, we acquired approximately 6,100 net acres of
leased mineral title lands in Alberta and Saskatchewan. The lands and
90 boe per day (21% royalty production) were purchased for $10.8
million and funded through our existing credit facilities. The vendor
had participated to its title interest in a major portion of the
development of the lands. The producing assets have a reserve life of
9.5 years based on estimated proved plus probable reserves of 0.3
MMboe. Along with current production (75% liquids), the lands offer
future development potential, with exposure to Pekisko light oil in
the Twining area of Alberta, and Bakken and Mannville heavy oil in
the Plover Lake area of Saskatchewan. Attractive future development
drilling on these mineral title lands will help us maintain our
overall working interest and royalty production, similar to our
approach on other Freehold mineral title lands.  
Working Interest Drilling  
In the third quarter of 2012, we invested $9.2 million on working
interest properties, bringing our capital for the year to date to
$29.0 million. In the quarter, we participated in the drilling of 14
(5.9 net) wells with a 93% success rate. In southeast Saskatchewan,
we participated in the drilling of one (0.1 net) vertical and three
(1.1 net) horizontal Frobisher oil wells, one (0.5 net) horizontal
Tilston oil well, one (0.2 net) horizontal Midale oil well, and one
(1.0 net) Bakken horizontal oil well. In Lloydminster, we
participated in two (1.0 net) horizontal Cummings heavy oil wells,
one (0.2 net) horizontal and four (1.8 net) vertical Sparky heavy oil
wells. One (0.5 net) of the wells in Lloydminster encountered
mechanical problems after drilling into a very good Cummings sand and
will be redrilled in 2013.  
Capital investment in the fourth quarter of 2012 is expected to be $6
million. Approximately $3 million will be on drilling in southeast
Saskatchewan where we plan to drill five (1.0 net) horizontal oil
wells, of which two (0.5 net) will be in the Bakken. The balance of
the capital ($3 million) is primarily associated with installing
equipment and facilities for the 14 (5.9 net) wells drilled in the
third quarter.  
Our production mix for the first nine months of 2012 was
approximately 36% natural gas and 64% liquids (24% heavy oil, 35%
light and medium oil, and 5% NGL). Over the past two years, the
composition of our oil production has become lighter, largely as a
result of our exposure to the Bakken and Cardium light oil plays.  
Oil and NGL production was 32% higher than the third quarter last
year and 22% higher for the year to date, largely due to drilling and
completion activity in southeast Saskatchewan. Natural gas production
was up 2% in the third quarter and up 9% for the year to date. The
increase related primarily to the royalty acquisition completed in
January 2012.  
Royalty interests comprised 68% (2011 - 72%) of total volumes
produced in the third quarter 2012, and 72% (2011 - 75%) for the year
to date. Royalty production rose 13%, mainly due to successful
royalty drilling in southeast Saskatchewan and east central Alberta,
as well as the addition of over 500 boe per day stemming from various
royalty interests acquired since September 2011. We have no
operational control over our royalty lands and, as we hold small
royalty interests in over 26,000 wells, obtaining timely production
data from the well operators is extremely difficult. Thus, we use
government reporting databases and past production receipts to
estimate revenue accruals. Due to the large number of wells in which
we have royalty interests, the nature of royalty interests, the lag
in receiving production receipts from the operators, and our audit
program, our reported royalty volumes usually include adjustments
(both positive and negative) for prior periods.  
Working interest production was 40% higher for the quarter and 29%
higher for the year to date compared to the same periods last year.
For the year to date, the increase primarily reflects the results of
our development activities in southeast Saskatchewan and
significantly higher activity levels compared to last year. The
higher activity level resulted in part from the wet weather access
problem in southeast Saskatchewan in 2011 and increased activity by
other partners in southeast Saskatchewan where we have participated
to our title interest. In the first nine months of this year, we
participated in 17 (7.9 net) wells in this area, up from 11 (4.7 net)
wells drilled in the same period a year ago. Last year, access was
limited through the second and third quarters as a result of wet
ground conditions, causing a delay in drilling and completion
activities. Production in southeast Saskatchewan accounted for
approximately 44% (2011 - 33%) of our working interest volumes for
the year to date. The third quarter of 2012 also includes flush
production from newly completed wells and prior period adjustments
amounting to approximately 190 boe per day.  
2012 Guidance Update  
With strong production performance to date in 2012, we now expect
average oil production to be 300 barrels per day higher than our
previous estimate, bringing our total production for 2012 to 8,600
boe per day. Our revised guidance takes into consideration the high
rate of success to date and the momentum from the very wet 2011
conditions in southeast Saskatchewan; our capital program for the
balance of the year; anticipated drilling activity on our leased
royalty lands, and historical rates of production decline. On a boe
basis, production volumes for 2012 are expected to be approximately
64% oil and NGL, with 72% of production attributable to royalty
interest wells. Our success in southeast Saskatchewan has increased
both our working interest and our royalty production.  
We are increasing our total capital for 2012 to approximately $35
million, mainly due to the high activity levels of our operating
partners in southeast Saskatchewan. Capital investment in the fourth
quarter is expected to be $6 million.  
Long-term debt at year-end is expected to be $18 million, down from
our prior estimate of $21 million, despite our increased capital.  
2013 Outlook  
For 2013, the Board has approved a capital budget of $33 million. Our
development plans are primarily oil related on our mineral title
lands and include approximately 40 gross (13 net risked) wells.
Roughly half of our capital will be deployed in southeast
Saskatchewan (light oil), with the balance allocated to our expanding
mineral title opportunity base in both the Lloydminster area (heavy
oil), including our recent mineral title land acquisition, and
western Alberta (Cardium 
oil). Spending may be adjusted as the year
progresses, depending on the operating environment and well results.  
Based on this level of capital investment, anticipated drilling
activity by lessees on our royalty lands, and normal production
declines (and excluding any potential acquisitions), we expect 2013
production to average approximately 8,400 boe per day. On a boe
basis, production volumes for 2013 are expected to be approximately
64% oil and NGL and 36% natural gas. We continue to maintain our
royalty focus with royalty production accounting for 70% of
forecasted 2013 production.  
In 2013, we expect to pay $25 million for 2012 taxes, in addition to
the $2.3 million of instalments already made. Also in 2013, we expect
to remit higher monthly instalments for the 2013 tax year, totalling
approximately $25 million. The large cash outlay for income taxes in
2013 is an anomaly that we have prepared for and have the financial
capacity to handle. We expect our tax bill will normalize in 2014, at
approximately 20% of pre-tax cash flow. 

2013 KEY OPERATING ASSUMPTIONS                                              
                                                          Annual Average for
Daily production                                   boe/d               8,400
WTI crude oil                                    US$/bbl               95.00
Western Canada Select (WCS)                     Cdn$/bbl               76.00
AECO natural gas price                          Cdn$/Mcf                3.25
Exchange rate                                   Cdn$/US$                1.00
Operating costs                                    $/boe                5.00
General and administrative costs (1)               $/boe                2.60
Capital expenditures                          $ millions                  33
Dividends paid in shares (DRIP) (2)           $ millions                  28
Long-term debt at year end                    $ millions                  48
Cash taxes payable for 2012 tax year          $ millions                  25
Cash taxes payable for 2013 tax year          $ millions                  25
 (instalments) (3)                                                          
Weighted average shares outstanding             millions                  67
(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'          
(3) Corporate tax estimates will vary depending on commodity prices and     
other factors.                                                              

As our results demonstrate, we continue to benefit from activity on
our oil-weighted asset base, and from relatively strong, if somewhat
volatile, crude oil pricing. Of significance, for the year to date,
natural gas (on a boe basis) accounted for 36% of production volumes
(2011 - 38%), but it comprised only 7% of revenue (2011 - 13%).
Clearly, we would benefit from any improvement in natural gas prices.
However, despite a significant decline in revenue from natural gas,
we have been able to maintain a steady monthly dividend rate of $0.14
($1.68 annually) per share since January 2010.  
We continue to closely monitor commodity prices and industry trends
for signs of deteriorating market conditions. Based on our current
guidance and commodity price assumptions, and assuming no change in
the current business environment, we expect to maintain the current
monthly dividend rate through 2013, subject to the Board's quarterly
review and approval.  
Recognizing the cyclical nature of the oil and gas industry, we
caution that systemic negative changes in the outlook for commodity
prices (including light/heavy oil price differentials), foreign
exchange rates, or production rates could result in adjustments to
the dividend rate. It is also inherently difficult to predict
activity levels on our royalty lands since we have no operational
control and do not know the future plans of the various operators.  
Forward-Looking Statements  
This news release offers our assessment of Freehold's future plans
and operations as at November 8, 2012, and contains forward-looking
statements that we believe allow readers to better understand our
business and prospects. Forward-looking statements include our
expectations for the following: 

--  our outlook for commodity prices including supply and demand factors
    relating to crude oil, heavy oil, and natural gas; 
--  light/heavy oil price differentials; 
--  changing economic conditions; 
--  foreign exchange rates; 
--  industry drilling and development activity on our royalty lands; 
--  reduction in natural gas drilling and potential production shut-ins due
    to weak prices; 
--  development of working interest properties; 
--  participation in the DRIP and our use of cash retained through the DRIP;
--  estimated capital budget and expenditures and the timing thereof; 
--  long-term debt at year end; 
--  average production, rate of production declines, and contribution from
    royalty lands; 
--  key operating assumptions; 
--  acquisition opportunities; 
--  current and deferred income tax and our expected taxability and the
    timing thereof; and 
--  our dividend policy. 

Such statements are generally identified by the use of words such as
"anticipate", "continue", "estimate", "expect", "forecast", "may",
"will", "project", "should", "plan", "intend", "believe", and similar
expressions (including the negatives thereof). By their nature,
forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond our control, including the
impact of general economic conditions, industry conditions,
volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, royalties, environmental risks, taxation,
regulation, changes in tax or other legislation, competition from
other industry participants, the lack of availability of qualified
personnel or management, stock market volatility, and our ability to
access sufficient capital from internal and external sources. Risks
are described in more detail in our AIF.  
With respect to forward-looking statements contained in this news
release, we have made assumptions regarding, among other things,
future oil and natural gas prices, future capital expenditure levels,
future production levels, future exchange rates, future tax rates,
future participation rates in the DRIP and use of cash retained
through the DRIP, future legislation, the cost of developing and
producing our assets, our ability and the ability of our lessees to
obtain equipment in a timely manner to carry out development
activities, our ability to market our oil and natural gas
successfully to current and new customers, our expectation for the
consumption of crude oil and natural gas, our expectation for
industry drilling levels, our ability to obtain financing on
acceptable terms, and our ability to add production and reserves
through development and acquisition activities.  
You are cautioned that the assumptions used in the preparation of
such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance
should not be
 placed on forward-looking statements. Our actual
results, performance, or achievement could differ materially from
those expressed in, or implied by, these forward-looking statements.
We can give no assurance that any of the events anticipated will
transpire or occur, or if any of them do, what benefits we will
derive from them. The forward-looking information contained in this
news release is expressly qualified by this cautionary statement. Our
policy for updating forward-looking statements is to update our key
operating assumptions quarterly and, except as required by law, we do
not undertake to update any other forward-looking statements. 
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. 
Availability on SEDAR  
Freehold's 2012 Third Quarter Report, including unaudited financial
statements and accompanying Management's Discussion and Analysis
(MD&A), is being filed today with Canadian securities regulators and
will be available at and at 
Freehold Royalties Ltd.
Karen Taylor
Manager, Investor Relations and Corporate Secretary
403.221.0891 or Toll Free: 1.888.257.1873
403.221.0888 (FAX)
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