CALGARY, ALBERTA -- (Marketwired) -- 03/03/16 -- Freehold Royalties Ltd. (Freehold) (TSX: FRU) today announced 2015 fourth quarter results and reserves as at December 31, 2015.
Results at a Glance
Three Months Ended Twelve Months Ended
December 31 December 31
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FINANCIAL ($000s, except
as noted) 2015 2014 Change 2015 2014 Change
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Gross revenue 33,833 43,631 -22% 135,664 199,850 -32%
Net income (loss) (7,423) 11,082 -167% (4,080) 66,447 -106%
Per share, basic and
diluted ($) (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
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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%
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(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
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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.
Three Months Ended December 31
2015 2014
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Equivalent Equivalent
Gross Net(2) Gross Net (2)
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Non-unitized wells 65 3.5 73 4.0
Unitized wells (3) 20 0.1 65 0.3
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Total 85 3.6 138 4.3
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Royalty joint venture (4) - 9
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Twelve Months Ended December 31
2015 (1) 2014
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Equivalent Equivalent
Gross Net(2) Gross Net (2)
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Non-unitized wells 259 18.2 258 14.0
Unitized wells (3) 118 0.7 185 1.1
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Total 377 18.9 443 15.1
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Royalty joint venture (4) 4 13
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(1) 2015 counts for the twelve months ended December 31 include wells
drilled on all 2015 acquisition lands from January 1, 2015.
(2) Equivalent net wells are the aggregate of the numbers obtained by
multiplying each gross well by our royalty interest percentage.
(3) Unitized wells are in production units wherein we generally have small
royalty interests in hundreds of wells.
(4) Wells drilled on various royalty joint venture lands, where equivalent
net wells cannot be calculated.
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
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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
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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)
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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)
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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
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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)
By Principal Product Type
Light and Medium Crude
Oil(2) Heavy Crude Oil
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Proved Proved
Plus Plus
Proved Probable Probable Proved Probable Probable
(Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls)
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December 31, 2014 4,014 3,106 7,120 4,010 2,592 6,602
Extensions 399 237 636 267 134 401
Improved recovery - - - - - -
Technical revisions 312 (642) (330) 317 (349) (32)
Discoveries - - - - - -
Acquisitions 4,167 2,036 6,202 498 58 556
Dispositions (38) (19) (56) - - -
Economic factors 3 (6) (3) (2) 8 6
Production (1,222) - (1,222) (864) - (864)
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December 31, 2015 7,635 4,711 12,346 4,227 2,443 6,670
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Conventional Natural
Gas(3) Natural Gas Liquids
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Proved Proved
Plus Plus
Proved Probable Probable Proved Probable Probable
(MMcf) (MMcf) (MMcf) (Mbbls) (Mbbls) (Mbbls)
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December 31, 2014 60,369 22,525 82,894 1,536 639 2,175
Extensions 800 856 1,656 22 11 33
Improved recovery - - - - - -
Technical revisions (1,541) 3,193 1,652 (155) (25) (180)
Discoveries - - - - - -
Acquisitions 9,177 5,738 14,915 238 182 421
Dispositions (387) (1,266) (1,653) (21) (70) (92)
Economic factors (97) 249 152 (4) 10 7
Production (10,018) - (10,018) (259) - (259)
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December 31, 2015 58,303 31,296 89,599 1,357 748 2,105
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Total Oil Equivalent
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Proved
Plus
Proved Probable Probable
(Mboe) (Mboe) (Mboe)
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December 31, 2014 19,622 10,091 29,713
Extensions 820 525 1,346
Improved recovery - - -
Technical revisions 218 (485) (267)
Discoveries - - -
Acquisitions 6,432 3,232 9,664
Dispositions (123) (300) (423)
Economic factors (20) 54 35
Production (4,014) - (4,014)
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December 31, 2015 22,936 13,118 36,054
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(1) Net reserves are our share of working interest properties minus
royalties payable to others, plus royalties receivable on our royalty
lands. Numbers may not add due to rounding.
(2) Light and medium crude oil includes an immaterial amount of tight oil
reserves.
(3) Conventional natural gas includes an immaterial amount of shale gas and
coal bed methane reserves.
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Total revenue, less operating costs and royalty expenses.
(2) Development expenditures, plus change in future capital, plus
acquisition costs; divided by net reserves added through development and
acquisition activities.
(3) Operating netback divided by the average cost of acquiring and
developing new reserves.
(4) Operating netback is based on gross production, while development and
acquisition costs are based on net reserves.
Land Holdings
As of December 31, 2015
Developed Undeveloped Total
----------------------------------------------------------------------------
Mineral Title Lands 386,145 276,338 662,483
Royalty Assumption Lands 73,218 19,839 93,057
----------------------------------------------------------------------------
Total Title Lands 459,363 296,177 755,540
Gross Overriding Royalty 1,791,522 591,768 2,383,290
----------------------------------------------------------------------------
Total Royalty Lands 2,250,885 887,945 3,138,830
Working Interest Properties 205,803 49,961 255,764
----------------------------------------------------------------------------
Total 2,456,688 937,906 3,394,594
----------------------------------------------------------------------------
Additional Lands(1) 280,000
----------------------------------------------------------------------------
Total Land Holdings 3,674,594
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Approximately 280,000 gross acres of additional title and royalty lands
acquired from Penn West Petroleum Ltd. in 2015, which has not been
categorized as of yet.
Land Holdings by Province
----------------------------------------------------------------------------
Royalty Interest Working Interest
------------------------------------------
Developed Undeveloped Developed
------------------------------------------
Gross Gross Gross Net
----------------------------------------------------------------------------
Alberta 1,688,012 567,188 162,912 35,169
Saskatchewan 368,837 261,636 23,365 8,394
Ontario 86,913 21,732 0 0
British Columbia 98,085 26,231 19,247 1,265
Manitoba 9,038 11,158 279 13
----------------------------------------------------------------------------
TOTAL(1) 2,250,885 887,945 205,803 44,841
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Working Interest Total
------------------------------------------
Undeveloped Developed Undeveloped
------------------------------------------
Gross Net Gross Gross
----------------------------------------------------------------------------
Alberta 33,590 7,287 1,850,924 600,778
Saskatchewan 10,034 5,322 392,202 271,670
Ontario 0 0 86,913 21,732
British Columbia 6,131 101 117,332 32,362
Manitoba 206 9 9,317 11,364
----------------------------------------------------------------------------
TOTAL(1) 49,961 12,719 2,456,688 937,906
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Approximately 280,000 gross acres of lands acquired from Penn West
Petroleum Ltd. in 2015 have not been included in these totals as they
have not been released from our integration process and therefore have
not been broken down by province as of yet.
Quarterly Review
2015
----------------------------------------
Q4 Q3 Q2 Q1
----------------------------------------
Financial ($000s, except as noted)
Revenue, net of royalty expense 33,728 35,391 37,222 27,026
Dividends declared 20,747 24,604 24,459 20,329
Per share ($) (1) 0.21 0.25 0.27 0.27
Net income (loss) (7,423) (22,193) 3,919 21,617
Per share, basic and diluted ($) (0.08) (0.23) 0.04 0.29
Funds from operations (2) 25,509 27,643 28,730 21,938
Per share, basic ($) (2) 0.26 0.28 0.32 0.29
Operating Income (2) 29,186 30,601 32,733 22,632
Operating income from royalties
(%) 89 90 85 83
Dividends paid in shares (DRIP) 2,758 3,708 2,398 8,361
Average DRIP participation rate (%)
(3) 13 14 11 35
Acquisitions (143) 815 342,310 68,370
Capital expenditures 5,607 7,969 2,750 5,969
Net debt obligations (2) 146,949 148,994 146,992 198,834
----------------------------------------------------------------------------
Shares outstanding
Weighted average, basic (000s) 98,731 98,357 89,388 75,199
At quarter end (000s) 98,940 98,599 98,203 75,457
----------------------------------------------------------------------------
Operating ($/boe, except as noted)
Daily production (boe/d) (4) 11,815 11,266 10,617 10,058
Royalty interest (%) 78 78 76 71
Average selling price 30.34 34.11 38.63 29.80
Operating netback (2) 26.85 29.52 33.88 25.01
Operating expenses 4.18 4.62 4.65 4.85
Working interest properties 19.24 20.78 19.14 16.87
Net general and administrative
expenses (5) 2.23 2.33 2.34 3.92
----------------------------------------------------------------------------
Benchmark Prices
WTI crude oil (US$/bbl) 42.18 46.43 57.94 48.64
Exchange rate (US$/Cdn$) 0.75 0.76 0.81 0.81
Edmonton Par crude oil (Cdn$/bbl) 52.89 56.23 67.75 51.95
Western Canadian Select (WCS)
(Cdn$/bbl) 36.86 43.29 56.97 42.14
AECO natural gas (Cdn$/Mcf) 2.65 2.80 2.67 2.95
----------------------------------------------------------------------------
Share Trading Performance
High ($) 13.52 16.07 19.04 20.62
Low ($) 9.00 8.73 15.86 16.14
Close ($) 10.86 10.82 16.14 17.94
Volume (000s) 19,312 22,753 18,912 14,297
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2014
----------------------------------------
Q4 Q3 Q2 Q1
----------------------------------------
Financial ($000s, except as noted)
Revenue, net of royalty expense 42,597 50,625 52,793 48,169
Dividends declared 31,353 31,148 28,711 28,576
Per share ($) (1) 0.42 0.42 0.42 0.42
Net income (loss) 11,082 17,913 19,598 17,854
Per share, basic and diluted ($) 0.15 0.24 0.29 0.26
Funds from operations (2) 30,774 39,561 37,319 30,793
Per share, basic ($) (2) 0.41 0.54 0.55 0.45
Operating Income (2) 37,584 46,012 47,801 43,795
Operating income from royalties
(%) 80 78 77 77
Dividends paid in shares (DRIP) 10,915 6,170 7,588 7,591
Average DRIP participation rate (%)
(3) 35 20 26 27
Acquisitions 60,566 76,780 109,044 1,884
Capital expenditures 13,500 2,811 6,284 11,106
Net debt obligations (2) 135,810 122,091 160,061 48,600
----------------------------------------------------------------------------
Shares outstanding
Weighted average, basic (000s) 74,545 73,214 68,296 67,965
At quarter end (000s) 74,919 74,286 68,520 68,157
----------------------------------------------------------------------------
Operating ($/boe, except as noted)
Daily production (boe/d) (4) 9,836 9,430 8,810 8,623
Royalty interest (%) 74 75 74 74
Average selling price 47.46 59.54 67.45 62.72
Operating netback (2) 41.54 53.03 59.62 56.43
Operating expenses 5.54 5.32 6.23 5.64
Working interest properties 21.66 21.05 23.61 21.40
Net general and administrative
expenses (5) 2.32 2.16 2.36 3.62
----------------------------------------------------------------------------
Benchmark Prices
WTI crude oil (US$/bbl) 73.15 97.15 102.99 98.68
Exchange rate (US$/Cdn$) 0.88 0.92 0.92 0.91
Edmonton Par crude oil (Cdn$/bbl) 75.79 97.10 105.70 99.73
Western Canadian Select (WCS)
(Cdn$/bbl) 66.74 83.82 90.44 83.40
AECO natural gas (Cdn$/Mcf) 4.01 4.22 4.68 4.75
----------------------------------------------------------------------------
Share Trading Performance
High ($) 23.27 26.92 28.15 23.47
Low ($) 17.02 22.64 23.01 21.41
Close ($) 19.12 23.16 26.78 23.28
Volume (000s) 18,607 10,412 7,232 7,322
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on the number of shares issued and outstanding at each record
date.
(2) See Additional GAAP Measures and Non-GAAP Financial Measures.
(3) Participation in Freehold's DRIP is subject to change at the
participants discretion.
(4) Reported production for a period may include minor adjustments from
previous production periods.
(5) Excludes share based and other compensation.
Condensed Consolidated Balance Sheets
December 31 December 31
($000s) (unaudited) 2015 2014
----------------------------------------------------------------------------
Assets
Current assets:
Cash $ 876 $ 1,126
Accounts receivable 21,046 26,430
Current taxes receivable 73 2,597
----------------------------------------------------------------------------
21,995 30,153
Acquistion advance - 949
Exploration and evaluation assets 49,479 37,852
Petroleum and natural gas interests 846,825 584,323
Deferred income tax asset 21,095 -
----------------------------------------------------------------------------
$ 939,394 $ 653,277
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities:
Dividends payable $ 6,924 $ 10,488
Accounts payable and accrued liabilities 9,826 15,864
Current portion of share based and other
compensation payable 194 611
----------------------------------------------------------------------------
16,944 26,963
Decommissioning liability 27,635 21,279
Share based and other compensation payable 191 321
Long-term debt 152,000 139,000
Deferred income tax liability - 44,847
Shareholders' equity:
Shareholders' capital 1,050,494 635,223
Contributed surplus 3,282 2,577
Deficit (311,152) (216,933)
----------------------------------------------------------------------------
742,624 420,867
----------------------------------------------------------------------------
$ 939,394 $ 653,277
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Condensed Consolidated Statements of Cash Flows
Three Months Ended Twelve Months Ended
December 31 December 31
----------------------------------------
($000s) (unaudited) 2015 2014 2015 2014
----------------------------------------------------------------------------
Operating:
Net income (loss) $ (7,423) $ 11,082 $ (4,080) $ 66,447
Items not involving cash:
Depletion and depreciation 26,397 19,237 95,703 67,145
Impairment 8,000 - 38,800 -
Share based and other
compensation 70 (1,164) 766 438
Deferred income tax expense
(recovery) (2,432) 701 (6,442) 659
Accretion of decommissioning
liability 152 123 566 498
Management fee 781 1,034 3,693 4,743
Gain on corporate acquisition - - (24,340) -
Expenditures on share based and
other compensation - (91) (619) (1,195)
Decommissioning expenditures (36) (148) (227) (288)
----------------------------------------------------------------------------
Funds from operations 25,509 30,774 103,820 138,447
Changes in non-cash working
capital 2,063 3,741 6,693 (4,060)
----------------------------------------------------------------------------
27,572 34,515 110,513 134,387
Financing:
Issuance of shares, net of issue
costs - - 390,236 141,085
Long-term debt (3,000) 6,000 13,000 90,000
Dividends paid (17,965) (20,350) (76,478) (86,521)
----------------------------------------------------------------------------
(20,965) (14,350) 326,758 144,564
Investing:
Acquisition advance - 49,211 949 (949)
Acquisitions 143 (60,566) (411,352) (248,274)
Capital expenditures (5,607) (13,500) (22,295) (33,701)
Changes in non-cash working
capital (530) 5,014 (4,823) 4,941
----------------------------------------------------------------------------
(5,994) (19,841) (437,521) (277,983)
----------------------------------------------------------------------------
Increase (decrease) in cash 613 324 (250) 968
Cash, beginning of period 263 802 1,126 158
----------------------------------------------------------------------------
Cash, end of period $ 876 $ 1,126 $ 876 $ 1,126
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Condensed Consolidated Statements of Changes in Shareholders' Equity
Twelve Months Ended
December 31
------------------------------
($000s) (unaudited) 2015 2014
----------------------------------------------------------------------------
Shareholders' capital:
Balance, beginning of period $ 635,223 $ 455,497
Shares issued for dividend reinvestment plan 17,225 32,264
Shares issued in lieu of management fee 3,693 4,743
Deferred share unit plan redemption - 180
Shares issued for equity offering 405,600 146,810
Issue costs, net of tax effect (11,247) (4,271)
----------------------------------------------------------------------------
Balance, end of period 1,050,494 635,223
----------------------------------------------------------------------------
Contributed surplus:
Balance, beginning of period 2,577 2,167
Share based compensation expense 705 666
Deferred share unit plan redemption - (256)
----------------------------------------------------------------------------
Balance, end of period 3,282 2,577
----------------------------------------------------------------------------
Deficit:
Balance, beginning of period (216,933) (163,592)
Net income (loss) and comprehensive income
(loss) (4,080) 66,447
Dividends declared (90,139) (119,788)
----------------------------------------------------------------------------
Balance, end of period (311,152) (216,933)
----------------------------------------------------------------------------
Total shareholders' equity $ 742,624 $ 420,867
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Forward-Looking Statements
This news release offers our assessment of Freehold's future plans and operations as at March 3, 2016, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. These forward-looking statements include our expectations for the following:
-- our outlook for commodity prices including supply and demand factors
relating to crude oil, heavy oil, and natural gas;
-- light/heavy oil price differentials;
-- changing economic conditions;
-- foreign exchange rates;
-- drilling activity during 2016 and the impact on our production base;
-- industry drilling, development activity on our royalty lands, our
exposure in emerging resource plays, and the potential impact of
horizontal drilling on production and reserves;
-- development of working interest properties;
-- participation in the DRIP and our use of cash preserved through the
DRIP;
-- estimated capital budget and expenditures and the timing thereof;
-- average production and contribution from royalty lands;
-- key operating assumptions;
-- amounts and rates of income taxes and timing of payment thereof;
-- maintaining our revised monthly dividend rate through 2016 and our
dividend policy.
In addition, statements relating to "reserves" and the future net revenue associated with such reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.
Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe", and similar expressions (including the negatives thereof). By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including the impact of general economic conditions, industry conditions, continued weakness in the oil and gas industry, reliance on third party royalty payors and operators of our working interest properties, volatility of commodity prices, lack of pipeline capacity; currency fluctuations, imprecision of reserve estimates, royalties, environmental risks, taxation, regulation, changes in tax or other legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, and our ability to access sufficient capital from internal and external sources. Risks are described in more detail in our AIF.
With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future commodity prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future participation rates in the DRIP and use of cash preserved through the DRIP, future legislation, the cost of developing and producing our assets, our ability and the ability of our lessees to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, our expectation for the consumption of crude oil and natural gas, our expectation for industry drilling levels, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through development and acquisition activities. The key operating assumptions with respect to the forward-looking statements referred to above are detailed in the body of this news release.
You are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. To the extent any guidance or forward looking statements herein constitute a financial outlook, they are included herein to provide readers with an understanding of management's plans and assumptions for budgeting purposes and readers are cautioned that the information may not be appropriate for other purposes. Our policy for updating forward-looking statements is to update our key operating assumptions quarterly and, except as required by law, we do not undertake to update any other forward-looking statements.
You are further cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. These estimates may change, having either a positive or negative effect on net income, as further information becomes available and as the economic environment changes.
Conversion of Natural Gas To Barrels of Oil Equivalent (BOE)
To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.
Additional GAAP Measures
This news release contains the term "funds from operations", which does not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities. Funds from operations, as presented, is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to net income or other measures of financial performance calculated in accordance with GAAP. We consider funds from operations to be a key measure of operating performance as it demonstrates Freehold's ability to generate the necessary funds to fund capital expenditures, sustain dividends, and repay debt. We believe that such a measure provides a useful assessment of Freehold's operations on a continuing basis by eliminating certain non-cash charges. It is also used by research analysts to value and compare oil and gas companies, and it is frequently included in their published research when providing investment recommendations. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.
Non-GAAP Financial Measures
Within this news release, references are made to terms commonly used as key performance indicators in the oil and natural gas industry. We believe that, operating income, operating netback, net debt obligations, net debt to funds from operations, basic payout ratio and adjusted payout ratio are useful supplemental measures for management and investors to analyze operating performance, financial leverage, and liquidity, and we use these terms to facilitate the understanding and comparability of our results of operations and financial position. However, these terms do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.
Operating income, which is calculated as gross revenue less royalties and operating expenses, represents the cash margin for product sold. Operating netback, which is calculated as average unit sales price less royalties and operating expenses, represents the cash margin for product sold, calculated on a per boe basis. Net debt obligations is long-term debt less working capital (current assets less current liabilities). Net debt to funds from operations is calculated as net debt as a proportion of funds from operations for the previous twelve months. In addition, we refer to various per boe figures, such as revenues and costs, also considered non-GAAP measures, which provide meaningful information on our operational performance. We derive per boe figures by dividing the relevant revenue or cost figure by the total volume of oil and natural gas production during the period, with natural gas converted to equivalent barrels of oil as described above.
Payout ratios are often used for dividend paying companies in the oil and gas industry to identify its dividend levels in relation to the funds it receives and uses in its capital and operational activities. Basic payout ratio is calculated as dividends declared as a percentage of funds from operations. Adjusted payout ratio is calculated as dividends paid in cash plus capital expenditures as a percentage of funds from operations.
Oil and Gas Metrics
This news release contains a number of oil and gas metrics, including finding and development costs, finding, development and acquisition costs, recycle ratio and reserves life index, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate Freehold's performance; however, such measures are not reliable indicators of the future performance of Freehold and future performance may not compare to the performance in previous periods.
Availability on SEDAR
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.
Contacts:
Freehold Royalties Ltd.
Matt Donohue
Manager, Investor Relations
403.221.0833 or tf. 1.888.257.1873
403.221.0888 (FAX)
mdonohue@rife.com
www.freeholdroyalties.com
