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

CALGARY, ALBERTA--(Marketwired - March 6, 2014) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced 2013 fourth quarter results and reserves as at December 31, 2013.

Results at a Glance

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

(1)	See Additional GAAP Measures and Non-GAAP Financial Measures.
(2)	Excludes dividend declared in December and paid in January.
(3)	Includes dividend declared in December and paid in January.
(4)	Based on the number of shares issued and outstanding at each record date.
(5)	Weighted average number of shares outstanding during the period, basic.
(6)	See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).
(7)	Our production mix in 2013 was approximately 36% natural gas and 64% liquids (34% light and medium oil, 25% heavy oil, and 5% NGL).

March Dividend Announcement

The Board of Directors has declared the March dividend of $0.14 per share, which will be paid on April 15, 2014 to shareholders of record on March 31, 2014. Including the April 15 payment, our 12-month trailing cash dividends total $1.68 per share. This dividend is designated as an eligible dividend for Canadian income tax purposes. Over the past 17 years, we have paid out over $1.2 billion to our shareholders.

2013 Fourth Quarter Highlights

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

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

2013 Year-end Reserves and Land Highlights

Freehold's reserves data is presented on a net basis (our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands). Freehold is unique in that the majority of our assets are royalty interests. However, under National Instrument 51-101, royalty interests cannot be included under gross reserves. This causes our gross reserves to be lower than our net reserves and makes it difficult for investors to compare our reserves to others in our industry. We believe the most appropriate measure of reserves for Freehold is net reserves. Reserve values do not include potential reserve additions that may occur as a result of future drilling on most of our royalty lands.

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

Royalty Interest Activity

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

Our royalty lands give us exposure to several of the attractive resource plays employing horizontal drilling, including Bakken and Mississippian light oil in southeast Saskatchewan, heavy oil in the Lloydminster area, and Cardium light oil in west-central Alberta.

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

ROYALTY INTEREST	Three Months Ended December 31								Twelve Months Ended December 31
WELLS DRILLED	2013				2012				2013				2012
	Gross		Equiv. Net (1	)	Gross		Equiv. Net (1	)	Gross		Equiv. Net (1	)	Gross		Equiv. Net (1	)
Non-unitized	68		4.3		57		2.6		197		11.3		231		11.6
Unitized (2)	38		0.2		30		0.1		141		0.6		200		1.2
Total	106		4.5		87		2.7		338		11.9		431		12.8

(1)	Equivalent net wells are the aggregate of the numbers obtained by multiplying each gross well by our royalty interest percentage.
(2)	Unitized wells are in production units wherein we generally have small royalty interests in hundreds of wells.

Working Interest Activity

Our development plans are primarily oil related, and are focused almost entirely on our own mineral title lands, where we have chosen to invest our own capital on attractive, low-risk opportunities.

In the fourth quarter of 2013, capital expenditures amounted to $5.3 million, the majority of which was spent to complete, equip, and tie-in wells drilled in southeast Saskatchewan. We participated in the drilling of six (1.2 net) wells with a 100% success rate.

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

WORKING INTEREST	Three Months Ended December 31								Twelve Months Ended December 31
WELLS DRILLED (1)	2013				2012				2013				2012
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Oil	6		1.2		7		1.3		41		12.9		36		13.5
Natural gas	-		-		-		-		-		-		-		-
Other	-		-		-		-		7		0.7		1		0.6
Total	6		1.2		7		1.3		48		13.6		37		14.1

(1)	Excludes royalty interest portion on properties where Freehold has both a working interest and a royalty interest. The royalty interest portion is included in equivalent net wells in the Royalty Interest Wells Drilled table above.

Operating Expense

Total operating expense of $5.5 million ($6.50 per boe) was 14% higher than the fourth quarter last year (18% higher on a per boe basis). The increase in costs was associated with a combination of higher than forecast electricity charges, well servicing and maintenance costs on our heavy oil properties.

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

(1)	Other includes potash, sulphur, lease rentals, and other revenue for royalty interest, and processing fees, interest, and other revenue for working interest.

Fourth Quarter Production

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

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

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

Commodity Prices

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

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

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

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

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

2013 Performance Compared to Guidance

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

Compared to our November guidance:

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

2013 Key Operating Assumptions

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

(1)	Excludes share based and other compensation.

2014 Outlook

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

Based on this level of capital investment, anticipated drilling activity by lessees on our royalty lands, and normal production declines (and excluding any potential acquisitions), we expect 2014 production to average approximately 8,700 boe/d. Volumes will be comprised of approximately 62% oil and NGL's and 38% natural gas. We continue to maintain our royalty focus with royalty production expected to account for approximately 68% of forecasted 2014 production.

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

2014 Key Operating Assumptions

			Guidance Updated
Annual Average			March 6, 2014		November 14, 2013
Daily production	boe/d		8,700		8,600
WTI oil price	US$/bbl		97.00		95.00
Western Canada Select (WCS)	Cdn$/bbl		83.00		75.00
AECO natural gas price	Cdn$/Mcf		4.50		3.50
Exchange rate	Cdn$/US$		0.90		0.95
Operating costs	$/boe		6.00		5.60
General and administrative costs (1)	$/boe		2.60		2.60
Capital expenditures	$ millions		35		30
Dividends paid in shares (DRIP) (2)	$ millions		29		29
Long-term debt at year end	$ millions		38		57
Current income tax expense (3) (4)	$ millions		32		28
Weighted average shares outstanding	millions		68		68

(1)	Excludes share based and other compensation.
(2)	Assumes average 25% participation rate in Freehold's dividend reinvestment plan, which is subject to change at the participants' discretion.
(3)	Corporate tax estimates will vary depending on all other assumptions.
(4)	November 14, 2013 Guidance was adjusted to be comparable to the current presentation.

Recognizing the cyclical nature of the oil and gas industry, we continue to closely monitor commodity prices and industry trends for signs of deteriorating market conditions. We caution that it is inherently difficult to predict activity levels on our royalty lands since we have no operational control. As well, significant changes (positive or negative) in commodity prices (including Canadian oil price differentials), foreign exchange rates, or production rates may result in adjustments to the dividend rate. In particular, our 2014 forecast for Western Canada Select pricing assumes an improvement in the second half of the year, but it is possible that the North American infrastructure constraints will become a longer-term issue for western Canadian production.

Based on our current guidance and commodity price assumptions, and assuming there are no significant changes in the current business environment, we expect to maintain the current monthly dividend rate through 2014, subject to the Board's quarterly review and approval.

Executive Retirement and Appointments

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

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

Land and Reserves

Freehold is unique in that the majority of our assets are royalty interests. However, under National Instrument 51-101, royalty interests cannot be included under gross reserves. This causes our gross reserves to be lower than our net reserves and makes it difficult for investors to compare our reserves and finding and development costs to others in our industry. We believe the most appropriate measure of reserves and finding and development costs for Freehold is on a net basis.

As at year-end 2013, our undeveloped land was independently valued at $89.1 million by Seaton-Jordan & Associates Ltd. Our total land holdings encompass approximately 3.1 million gross acres, 93% of which are royalties. Of this, our mineral title lands (including royalty assumption lands), which we own in perpetuity, cover nearly 630,000 acres; all but approximately 100,000 gross acres of which are currently leased to third parties. In addition, we have gross overriding royalty interests in over 2.2 million acres.

These royalty interest lands are significant to Freehold. The majority of these lands are leased to third party operators. As a royalty owner, we have no operational control over the operator's future development activities. As such, the extent of drilling and development activity in future years can be difficult to predict. However, these operators have historically invested significant amounts to generate future reserve additions, and production from which Freehold receives certain royalties. Reserve values include minimal reserve additions that may occur as a result of future drilling on our royalty lands. In addition, based on an internal estimate, we have estimated the net present value of the future royalty revenue from our potash reserves at $17.7 million before tax (discounted at 10%).

Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2013. The evaluation was conducted in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in National Instrument 51-101. Our Reserves Committee met with Trimble to review the findings and procedures, and the reserves report has been accepted by our Board.

Summary oil and gas reserves information is provided below. Complete reserves disclosure as required under National Instrument 51-101 will be included in our Annual Information Form.

Summary of Oil and Gas Reserves

As of December 31, 2013

Forecast Prices and Costs (1)		Light and Medium Oil				Heavy Oil				Total Crude Oil
		Gross (2)		Net (3)		Gross (2)		Net (3)		Gross (2)		Net (3)
Reserves Category		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)
Proved
	Developed producing	1,722		3,415		748		4,167		2,471		7,582
	Developed non-producing	104		91		16		14		120		105
	Undeveloped	-		-		-		-		-		-
Total proved		1,827		3,506		764		4,181		2,591		7,687
Probable		1,456		2,322		851		2,730		2,307		5,052
Total proved plus probable		3,283		5,828		1,615		6,911		4,898		12,739
		Natural Gas				Natural Gas Liquids				Oil Equivalent
		Gross (2)		Net (3)		Gross (2)		Net (3)		Gross (2)		Net (3)
Reserves Category		(MMcf)		(MMcf)		(Mbbls)		(Mbbls)		(Mboe)		(Mboe)
Proved
	Developed producing	3,400		30,887		131		846		3,168		13,576
	Developed non-producing	586		622		44		35		262		244
	Undeveloped	-		3,734		-		42		-		664
Total proved		3,986		35,243		175		923		3,430		14,483
Probable		4,363		18,385		237		513		3,271		8,629
Total proved plus probable		8,349		53,627		412		1,436		6,702		23,113

(1)	Numbers may not add due to rounding.
(2)	Gross reserves are our share of working interest properties before deduction of royalties payable to others. Gross reserves exclude royalty interests.
(3)	Net reserves are defined as our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands.

The reserves data below is presented on a net basis (our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands).

Summary of Net Present Values of Future Net Revenue

As of December 31, 2013

Forecast Prices and Costs ($000s) (1)		Before Income Taxes, Discounted at (% per year)
		0%		5%		10%		15%		20%
Proved
	Developed producing	756,691		558,106		448,309		379,056		331,345
	Developed non-producing	6,640		4,908		3,989		3,423		3,036
	Undeveloped	20,139		13,417		9,422		6,882		5,184
Total proved		783,470		576,431		461,721		389,361		339,566
Probable		532,947		280,416		184,316		136,501		108,128
Total proved plus probable		1,316,417		856,847		646,037		525,862		447,693
		After Income Taxes, Discounted at (% per year) (2)
Reserves Category		0%		5%		10%		15%		20%
Proved
	Developed producing	634,088		467,455		375,628		317,755		277,886
	Developed non-producing	4,938		3,595		2,879		2,438		2,137
	Undeveloped	15,042		10,021		7,036		5,139		3,870
Total proved		654,068		481,071		385,544		325,331		283,893
Probable		396,944		208,014		136,175		100,447		79,257
Total proved plus probable		1,051,012		689,085		521,719		425,778		363,150

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

Total Future Net Revenue (Undiscounted)

As of December 31, 2013

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

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

Future Development Costs (Undiscounted) ($000s)

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

(1)	The source of funding for future development costs includes internally generated cash flow, debt or a combination of both. Disclosed reserves and future net revenue will not be materially affected by the costs of funding the future development expenditures. Columns may not add due to rounding.

Reserve Life Index

As of December 31, 2013 (1)

	Proved Producing		Total Proved		Proved Plus Probable
Net reserves (Mboe)	13,576		14,483		23,113
Net production (Mboe)	2,357		2,409		2,707
Reserve life index (years)	5.8		6.0		8.5

(1)	Reflects the theoretical production life of a property if the remaining reserves were produced out at current rates. The index is calculated by dividing the reserves in the selected reserve category at a certain date by the estimated production for the first year's production period (calculated by dividing the Trimble forecast of 2014 net production into the remaining net reserves).

Reconciliation of Net Reserves (1)

By Principal Product Type

Forecast Prices and Costs		Light and Medium Oil						Heavy Oil
						Proved Plus						Proved Plus
		Proved		Probable		Probable		Proved		Probable		Probable
		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)		(Mbbls)
December 31, 2012		3,554		2,301		5,855		4,178		3,197		7,376
	Extensions	495		382		878		155		81		236
	Improved recovery	-		-		-		-		-		-
	Technical revisions	374		(356	)	18		636		(677	)	(41	)
	Discoveries	-		-		-		-		-		-
	Acquisitions	-		-		-		82		128		210
	Dispositions	-		-		-		-		-		-
	Economic factors	(4	)	(5	)	(9	)	(1	)	-		-
	Production	(914	)	-		(914	)	(870	)	-		(870	)
December 31, 2013		3,506		2,322		5,828		4,181		2,730		6,911
		Natural Gas						Natural Gas Liquids
						Proved Plus						Proved Plus
		Proved		Probable		Probable		Proved		Probable		Probable
		(MMcf)		(MMcf)		(MMcf)		(Mbbls)		(Mbbls)		(Mbbls)
December 31, 2012		38,736		20,212		58,949		893		476		1,369
	Extensions	814		1,494		2,309		48		102		150
	Improved recovery	-		-		-		-		-		-
	Technical revisions	1,831		(3,433	)	(1,602	)	181		(64	)	117
	Discoveries	-		-		-		-		-		-
	Acquisitions	361		140		501		-		-		-
	Dispositions	-		-		-		-		-		-
	Economic factors	(55	)	(29	)	(84	)	(0	)	(1	)	(1	)
	Production	(6,445	)	-		(6,445	)	(199	)	-		(199	)
December 31, 2013		35,243		18,385		53,627		923		513		1,436
								Oil Equivalent
												Proved Plus
								Proved		Probable		Probable
								(Mboe)		(Mboe)		(Mboe)
December 31, 2012								15,082		9,343		24,425
	Extensions							835		814		1,649
	Improved recovery							-		-		-
	Technical revisions							1,496		(1,669	)	(174	)
	Discoveries							-		-		-
	Acquisitions							142		152		293
	Dispositions							-		-		-
	Economic factors							(14	)	(11	)	(25	)
	Production							(3,057	)	-		(3,057	)
December 31, 2013								14,483		8,629		23,113

(1)	Net reserves are our share of working interest properties minus royalties payable to others, plus royalties receivable on our royalty lands. Numbers may not add due to rounding.

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

Net Proved Reserves		2013		2012		2011		Three-Year Results
Finding and development expenditures ($000s)		29,287		36,746		25,649		91,682
	Change in future development capital estimates ($000s)	1,142		(934	)	1,556		1,764
	Net reserve additions by development (Mboe)	834		1,071		581		2,486
Finding and development costs ($/boe)		36.47		33.45		46.81		37.59
Acquisition expenditures ($000s)		10,091		60,852		7,467		78,410
Net reserve additions by acquisition (Mboe)		142		2,300		103		2,545
Acquisition costs ($/boe)		71.21		26.46		72.42		30.81
Total expenditures ($000s)		39,378		97,598		33,116		170,092
	Change in future development capital estimates ($000s)	1,142		(934	)	1,556		1,764
	Net reserve additions (Mboe)	976		3,371		684		5,031
Finding, development and acquisition costs ($/boe)		41.52		28.68		50.67		34.16
Net Proved Plus Probable Reserves		2013		2012		2011		Three-Year Results
Finding and development expenditures ($000s)		29,287		36,746		25,649		91,682
	Change in future development capital estimates ($000s)	3,448		1,916		4,959		10,323
	Net reserve additions by development (Mboe)	1,649		1,809		1,085		4,543
Finding and development costs ($/boe)		19.85		21.37		28.20		22.45
Acquisition expenditures ($000s)		10,091		60,852		7,467		78,410
	Net reserve additions by acquisition (Mboe)	294		3,483		207		3,983
Acquisition costs ($/boe)		34.38		17.47		36.12		19.68
Total expenditures ($000s)		39,378		97,598		33,116		170,092
	Change in future development capital estimates ($000s)	3,447		1,916		4,959		10,322
	Net reserve additions (Mboe)	1,943		5,292		1,292		8,527
Finding, development and acquisition costs ($/boe)		22.04		18.80		29.47		21.16

(1)

Freehold did not incur any exploration expenditures in any of the applicable years. In calculating finding and development costs, NI 51-101 requires that the exploration and development costs incurred in the year and the change in estimated future development costs be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions on both reserves and costs. We believe that by excluding the effects of acquisitions, the provisions of NI 51-101 do not fully reflect Freehold's ongoing reserve replacement costs. Because acquisitions can have a significant impact on annual reserve replacement costs, excluding these amounts could result in an inaccurate portrayal of Freehold's cost structure. Accordingly, we also provide costs that incorporate all acquisitions during the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Recycle Statistics, Net Proved Plus Probable Reserves

($ per boe, except as noted)	2013		2012		2011		Three-Year Results
Operating netback (1) (4)	47.91		45.09		51.65		48.03
Finding, development and acquisition costs (2) (4)	22.04		18.80		29.47		21.16
Recycle ratio (times) (3)	2.2		2.4		1.8		2.3

(1)	Total revenue, less operating costs and royalty expenses.
(2)	Development expenditures, plus change in future capital, plus acquisition costs; divided by net reserves added through development and acquisition activities.
(3)	Operating netback divided by the average cost of acquiring and developing new reserves.
(4)	Operating netback is based on gross production, while development and acquisition costs are based on net reserves.

Land Holdings

As of December 31, 2013

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

Land Holdings by Province

	Royalty Interest				Working Interest									Total Acreage
	Developed		Undeveloped		Developed				Undeveloped					Developed		Undeveloped
	Gross (1)		Gross (1)		Gross (1)		Net		Gross (1)		Net			Gross (1)		Gross (1)
Alberta	1,601,021		390,976		132,927		19,692		28,188		5,743			1,733,948		419,164
British Columbia	85,152		24,523		19,247		1,265		6,131		101			104,399		30,654
Saskatchewan	285,488		188,881		17,097		5,787		7,293		4,000			302,585		196,174
Manitoba	6,258		1,422		158		37		79		18			6,416		1,501
Ontario	88,799		174,580		-		-		-		-			88,799		174,580
Total	2,066,718		780,382		169,429		26,781		41,691		9,862			2,236,147		822,073

(1)	Gross acres are the total number of acres in which we have an interest.
(2)	The royalties received from the sale of oil, natural gas and potash produced from the leased mineral title lands are determined by the individual lease agreements. All but approximately 107,000 gross acres of our mineral title lands are currently leased to third parties.
(3)	Mineral title properties owned by a number of third party oil and gas companies in respect of which gross overriding royalties, varying from 4.7% to 6.5%, have been reserved to Freehold.
(4)	Title lands are held in perpetuity.
(5)	Gross overriding royalty lands consist of properties leased by a number of third party oil and gas companies in respect of which contractual royalties or net profits interests have been reserved to Freehold.

Quarterly Review

		2013								2012
		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
FINANCIAL ($000s, except as noted)
Revenue, net of royalty expense		43,436		49,728		42,704		39,332		43,832		40,294		34,498		43,036
Dividends declared		28,373		28,206		28,019		27,897		27,787		27,616		27,399		26,766
	Per share ($) (1)	0.42		0.42		0.42		0.42		0.42		0.42		0.42		0.42
Net income		14,106		18,961		14,292		10,493		13,431		11,975		7,862		13,060
	Per share, basic and diluted ($)	0.21		0.28		0.21		0.16		0.20		0.18		0.12		0.21
Funds from operations (2)		29,092		36,407		30,115		23,817		31,475		26,272		20,522		25,613
	Per share ($) (2)	0.43		0.54		0.45		0.36		0.48		0.40		0.31		0.41
Dividends paid in shares (DRIP)		7,617		9,076		6,874		4,381		6,672		7,013		6,940		6,789
	Average DRIP participation rate (%)	27		32		25		16		24		25		25		26
Property and royalty acquisitions (net)		6,891		2,542		658		-		243		10,789		(99	)	49,919
Capital expenditures		5,335		5,725		3,313		14,914		7,743		9,160		6,598		13,245
Long-term debt		49,000		49,000		55,000		47,000		18,000		25,000		23,000		18,000
SHARES OUTSTANDING
	Weighted average, basic (000s)	67,483		67,078		66,649		66,375		66,091		65,677		65,159		62,571
	At quarter end (000s)	67,746		67,326		66,874		66,522		66,270		65,879		65,440		64,993
OPERATING ($/boe, except as noted)
Daily production (boe/d) (3)		9,173		8,699		8,714		9,067		9,510		8,654		8,501		8,733
	Royalty interest production (%)	68		67		71		71		66		68		76		74
Average selling price		52.99		63.74		54.66		49.09		51.55		51.71		45.74		54.80
Operating netback (2)		44.97		55.79		47.80		43.32		44.59		45.59		40.64		49.48
Operating expenses		6.50		6.36		6.06		4.88		5.51		5.02		3.96		4.68
	Working interest properties	20.53		19.50		21.00		16.91		16.36		15.47		16.47		17.86
Net general and administrative expenses (4)		2.13		1.74		2.04		3.47		2.25		1.88		2.13		3.31
BENCHMARK PRICES
WTI crude oil (US$/bbl)		97.46		105.83		94.22		94.37		88.18		92.22		93.49		102.93
Exchange rate (Cdn$/US$)		0.95		0.96		0.98		0.99		1.01		1.01		0.99		1.00
Edmonton Par crude oil (Cdn$)		86.28		104.69		92.55		88.16		83.99		84.33		83.95		92.23
Western Canada Select (WCS) (Cdn$/bbl)		68.44		91.71		76.78		62.96		69.43		69.99		71.29		81.61
WTI/Edmonton Par differential ($/bbl)		(11.18	)	(1.14	)	(1.67	)	(6.21	)	(4.19	)	(7.89	)	(9.54	)	(10.70	)
Edmonton Par/WCS differential (Cdn$/bbl)		(17.84	)	(12.98	)	(15.77	)	(25.20	)	(14.56	)	(14.34	)	(12.66	)	(10.62	)
AECO natural gas (Cdn$/Mcf)		3.15		2.82		3.59		3.08		3.06		2.19		1.83		2.52
SHARE TRADING PERFORMANCE
High ($)		24.63		24.88		24.58		24.48		22.45		20.34		19.67		21.59
Low ($)		21.54		22.50		22.46		21.00		19.62		17.83		17.25		19.16
Close ($)		22.11		23.78		23.57		23.38		22.40		19.76		18.44		19.59
Volume (000s)		6,077		4,374		8,108		7,203		7,435		5,656		7,483		8,076

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

Consolidated Balance Sheets

		December 31		December 31
($000s) (unaudited)		2013		2012
Assets
Current assets:
	Cash	$ 158		$ 102
	Accounts receivable	25,587		23,225
		25,745		23,327
Exploration and evaluation assets		24,858		25,905
Petroleum and natural gas interests		377,262		399,005
		$ 427,865		$ 448,237
Liabilities and Shareholders' Equity
Current liabilities:
	Dividends payable	$ 9,485		$ 9,278
	Accounts payable and accrued liabilities	10,813		12,743
	Current taxes payable	730		23,095
	Current portion of share based and other compensation payable	1,102		2,108
		22,130		47,224
Decommissioning liability		15,781		16,714
Share based and other compensation payable		1,240		1,290
Long-term debt		49,000		18,000
Deferred income tax liability		45,642		49,194
Shareholders' equity:
	Shareholders' capital	455,497		422,728
	Contributed surplus	2,167		2,036
	Deficit	(163,592	)	(108,949	)
		294,072		315,815
		$ 427,865		$ 448,237

Consolidated Statements of Income and Comprehensive Income

		Three Months Ended				Year ended
(unaudited)		December 31				December 31
($000s, except per share and weighted average data)		2013		2012		2013		2012
Revenue:
	Royalty income and working interest sales	$ 45,287		$ 45,794		$ 181,578		$ 168,134
	Royalty expense	(1,851	)	(1,962	)	(6,378	)	(6,474	)
		43,436		43,832		175,200		161,660
Expenses:
	Operating	5,482		4,820		19,356		15,598
	General and administrative	1,795		1,972		7,634		7,746
	Share based and other compensation	(158	)	999		1,531		2,371
	Interest and financing	613		421		2,554		2,235
	Depletion and depreciation	15,283		16,372		61,320		64,576
	Accretion of decommissioning liability	127		107		452		381
	Management fee	1,080		1,072		4,495		3,808
		24,222		25,763		97,342		96,715
Income before taxes		19,214		18,069		77,858		64,945
Income tax:
	Current expense	6,214		5,063		23,558		27,792
	Deferred recovery	(1,106	)	(425	)	(3,552	)	(9,175	)
		5,108		4,638		20,006		18,617
Net income and comprehensive income		$ 14,106		$ 13,431		$ 57,852		$ 46,328
Net income per share, basic and diluted		$ 0.21		$ 0.20		$ 0.86		$ 0.71
Weighted average number of shares:
	Basic	67,483,469		66,090,969		66,899,776		64,880,038
	Diluted	67,598,380		66,194,503		67,021,372		64,979,074

Consolidated Statements of Cash Flows

			Three Months Ended				Year ended
			December 31				December 31
($000s) (unaudited)			2013		2012		2013		2012
Operating:
	Net income		$ 14,106		$ 13,431		$ 57,852		$ 46,328
	Items not involving cash:
		Depletion and depreciation	15,283		16,372		61,320		64,576
		Share based and other compensation	(158	)	999		1,531		2,371
		Deferred income tax recovery	(1,106	)	(425	)	(3,552	)	(9,175	)
		Accretion of decommissioning liability	127		107		452		381
		Management fee	1,080		1,072		4,495		3,808
	Expenditures on share based and other compensation		(189	)	-		(2,299	)	(3,883	)
	Decommissioning expenditures		(51	)	(81	)	(368	)	(524	)
	Funds from operations		29,092		31,475		119,431		103,882
	Changes in non-cash working capital		1,336		6,708		(26,196	)	34,250
			30,428		38,183		93,235		138,132
Financing:
	Issuance of shares, net of issue costs		-		-		-		67,597
	Long-term debt		-		(7,000	)	31,000		(30,000	)
	Dividends paid		(20,697	)	(21,060	)	(84,340	)	(81,436	)
			(20,697	)	(28,060	)	(53,340	)	(43,839	)
Investing:
	Deposit on acquisition		-		-		-		5,000
	Property and royalty acquisitions		(6,891	)	(243	)	(10,091	)	(60,852	)
	Capital expenditures		(5,335	)	(7,743	)	(29,287	)	(36,746	)
	Changes in non-cash working capital		1,965		(2,149	)	(461	)	(1,757	)
			(10,261	)	(10,135	)	(39,839	)	(94,355	)
Increase (decrease) in cash			(530	)	(12	)	56		(62	)
Cash, beginning of period			688		114		102		164
Cash, end of period			$ 158		$ 102		$ 158		$ 102

Consolidated Statements of Changes in Shareholders' Equity

		Year ended
		December 31
($000s) (unaudited)		2013		2012
Shareholders' capital:
	Balance, beginning of year	$ 422,728		$ 323,115
	Shares issued for dividend reinvestment plan	27,948		27,414
	Shares issued in lieu of management fee	4,495		3,808
	Shares issued for deferred share and plan redemption	326		-
	Shares issued for equity offering	-		70,725
	Issue costs, net of tax effect	-		(2,334	)
	Balance, end of year	455,497		422,728
Contributed surplus:
	Balance, beginning of year	2,036		1,480
	Share based compensation expense	597		556
	Deferred share unit plan redemption	(466	)	-
	Balance, end of year	2,167		2,036
Deficit:
	Balance, beginning of year	(108,949	)	(45,709	)
	Net income and comprehensive income	57,852		46,328
	Dividends declared	(112,495	)	(109,568	)
	Balance, end of year	(163,592	)	(108,949	)
Total shareholders' equity		$ 294,072		$ 315,815

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at March 6, 2014, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. These forward-looking statements include our expectations for the following:

• our outlook for commodity prices including supply and demand factors relating to crude oil, heavy oil, and natural gas;
• light/heavy oil price differentials;
• changing economic conditions;
• foreign exchange rates;
• industry drilling, development activity on our royalty lands, our exposure in emerging resource plays, and the potential impact of horizontal drilling on production and reserves;
• development of working interest properties;
• participation in the DRIP and our use of cash preserved through the DRIP;
• estimated capital budget and expenditures and the timing thereof;
• long-term debt at year end;
• average production and contribution from royalty lands;
• key operating assumptions;
• acquisition opportunities;
• amounts and rates of income taxes and timing of payment thereof;
• maintaining our monthly dividend rate through 2014 and our dividend policy; and
• production rates on properties acquired in 2013.

In addition, statements relating to "reserves" and the future net revenue associated with such reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe", and similar expressions (including the negatives thereof). By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, lack of pipeline capacity, currency fluctuations, imprecision of reserve estimates, royalties, environmental risks, taxation, regulation, changes in tax or other legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, and our ability to access sufficient capital from internal and external sources. Risks are described in more detail in our AIF.

In this news release, we make references to "flush" production rates, which is the first yield from a flowing oil well during its most productive period. Such "flush" production rates are not determinative of future production rates. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in estimating future production rates for Freehold.

With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future commodity prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future participation rates in the DRIP and use of cash preserved through the DRIP, future legislation, the cost of developing and producing our assets, our ability and the ability of our lessees to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, our expectation for the consumption of crude oil and natural gas, our expectation for industry drilling levels, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through development and acquisition activities. The key operating assumptions with respect to the forward-looking statements referred to above are detailed in the body of this news release.

You are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is to update our key operating assumptions quarterly and, except as required by law, we do not undertake to update any other forward-looking statements.

You are further cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. These estimates may change, having either a positive or negative effect on net income, as further information becomes available and as the economic environment changes.

Conversion of Natural Gas To Barrels of Oil Equivalent (BOE)

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

Additional GAAP Measures

This news release contains the term "funds from operations", which does not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities. Funds from operations, as presented, is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to net income or other measures of financial performance calculated in accordance with GAAP. We consider funds from operations to be a key measure of operating performance as it demonstrates Freehold's ability to generate the necessary funds to fund capital expenditures, sustain dividends, and repay debt. We believe that such a measure provides a useful assessment of Freehold's operations on a continuing basis by eliminating certain non-cash charges. It is also used by research analysts to value and compare oil and gas companies, and it is frequently included in their published research when providing investment recommendations. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.

Non-GAAP Financial Measures

Within this news release, references are made to terms commonly used as key performance indicators in the oil and gas industry, such as operating income, operating netback, finding, development and acquisition (FD&A) costs, and recycle ratio. We believe that these measures are useful supplemental measures for management and investors to analyze operating performance, and we use these terms to facilitate the understanding and comparability of our results of operations. However, these terms do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

Operating income, which is calculated as gross revenue less royalties and operating expenses, represents the cash margin for product sold. Operating netback, which is calculated as average unit sales price less royalties and operating expenses, represents the cash margin for product sold, calculated on a per boe basis.

Availability on SEDAR

Freehold's 2013 audited financial statements and accompanying Management's Discussion and Analysis (MD&A) are being filed today with Canadian securities regulators and will be available at www.sedar.com and on our website at www.freeholdroyalties.com. Our Annual Information Form (including reserves disclosure required under National Instrument NI 51-101) is expected to be filed on or about March 10, 2014.