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 $7
million reflecting the weaker commodity outlook. A large percentage of
our capital expenditures program is non-operated and the exact capital
is difficult to predict. We expect to have additional information on the
spending of our partners as we move through the year.
2016 Key Operating Assumptions
Guidance Dated
2016 Annual Average Mar. 3, 2016 Nov. 12, 2015
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Daily production boe/d 9,800 9,800
WTI oil price US$/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
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(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
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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%
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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%
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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%
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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%
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(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
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Gross Net(1) Gross Net (1) Gross Net(1) Gross Net (1)
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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 - - - - - - - -
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Total 5 0.7 25 5.7 43 7.5 54 12.2
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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.
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)
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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
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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
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Total proved plus
probable 3,099 12,346 1,373 6,670 4,472 19,016
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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)
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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
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Total proved 8,087 58,303 207 1,357 3,786 22,936
Probable 5,817 31,296 157 748 3,368 13,118
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Total proved plus
probable 13,903 89,599 364 2,105 7,154 36,054
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(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%
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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
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Total proved 1,073,834 784,116 611,925 499,644 421,493
Probable 730,355 390,233 248,229 175,678 133,226
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Total proved plus probable 1,804,189 1,174,349 860,154 675,322 554,719
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After Income Taxes, Discounted at (% per year)
-------------------------------------------------
Reserves Category 0% 5% 10% 15% 20%
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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
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Total proved 1,034,366 759,686 596,251 489,277 414,455
Probable 542,795 290,023 186,727 134,569 104,166
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Total proved plus probable 1,577,161 1,049,709 782,978 623,847 518,621
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(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
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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)
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Future net revenue before income taxes 1,073,834 1,804,189
Future income taxes(2) (39,468) (227,027)
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Future net revenue after income taxes 1,034,366 1,577,161
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(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)
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2016 188 4,882
2017 1,477 4,233
2018 564 928
2019 73 2,117
2020 839 1,353
Remainder 76 362
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Total 3,217 13,875
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(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
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Net Reserves (Mboe) 16,675 22,936 36,054
Net Production (Mboe) 3,198 3,276 3,649
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Reserves Life Index (years) 5.2 7.0 9.9
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(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
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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
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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
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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
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Three-year
Net Proved Plus Probable Reserves 2015 2014 2013 results
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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
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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
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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
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(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 $15.0 million of costs for undeveloped land
acquired during the year. The aggregate of the exploration and
development costs incurred in the most recent financial year and the
change during that year in estimated future development costs generally
will not reflect total finding and development costs related to reserves
additions for that year.
Recycle Statistics, Net Proved Plus Probable Reserves
Three-year
2015 2014 2013 results
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Operating netback ($/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
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Revenue:
Royalty income and working
interest sales $ 33,833 $ 43,631 $ 135,664 $ 199,850
Royalty expense (105) (1,034) (2,297) (5,666)
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33,728 42,597 133,367 194,184
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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
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43,583 27,541 174,082 104,900
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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
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(2,432) 3,974 (11,539) 22,837
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Net income (loss) and
comprehensive income (loss) $ (7,423) $ 11,082 $ (4,080) $ 66,447
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Net income (loss) per share,
basic and diluted $ (0.08) $ 0.15 $ (0.05) $ 0.94
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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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