Freehold Royalties Ltd. Announces 2012 Fourth Quarter Results and Year-end Reserves

CALGARY, ALBERTA--(Marketwire - March 7, 2013) - Freehold Royalties Ltd. (Freehold) (FRU.TO) today announced 2012 fourth quarter results and reserves as at December 31, 2012.

Results at a Glance

		Three Months Ended					Twelve Months Ended
FINANCIAL HIGHLIGHTS		December 31					December 31
($000s, except as noted)		2012	2011		Change		2012	2011	Change
Gross revenue		45,794	45,304		1	%	168,134	157,910	6	%
Net income		13,431	16,033		-16	%	46,328	55,259	-16	%
	Per share, basic and diluted ($)	0.20	0.26		-23	%	0.71	0.92	-23	%
Cash flow from operating activities		38,183	32,595		17	%	138,132	118,370	17	%
	Per share ($)	0.58	0.54		7	%	2.13	1.97	8	%
Capital expenditures		7,743	10,910		-29	%	36,746	25,649	43	%
Property and royalty acquisitions (net)		243	(195	)	-		60,852	7,467	-
Dividends paid in cash (1)		21,060	15,262		38	%	81,436	67,204	21	%
Dividends paid in shares (DRIP) (1)		6,672	10,232		-35	%	27,414	33,490	-18	%
	Average DRIP participation rate (%) (2)	24	40		-40	%	25	33	-24	%
Dividends declared (3)		27,787	25,585		9	%	109,568	100,968	9	%
	Per share ($) (4)	0.42	0.42		0	%	1.68	1.68	0	%
Long-term debt, period end		18,000	48,000		-63	%	18,000	48,000	-63	%
Shares outstanding, period end (000s)		66,270	61,141		8	%	66,270	61,141	8	%
Average shares outstanding (000s) (5)		66,091	60,811		9	%	64,880	60,022	8	%
OPERATING HIGHLIGHTS
Average daily production (boe/d) (6) (7)		9,510	7,773		22	%	8,850	7,476	18	%
Average realized price ($/boe) (6)		51.55	61.90		-17	%	51.00	56.31	-9	%
Operating netback ($/boe) (6) (8)		44.59	56.56		-21	%	45.09	51.65	-13	%

(1)	Excludes dividend declared in December and paid in January.
(2)	Participation in Freehold's dividend reinvestment plan (DRIP) ranged between 17% and 41% in 2012 and is subject to change monthly at the participants' discretion.
(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 2012 was approximately 36% natural gas and 64% liquids (34% light and medium oil, 25% heavy oil, and 5% NGL).
(8)	See Non-GAAP Financial Measures.

March Dividend Announcement

The Board of Directors has declared the March dividend of $0.14 per share, which will be paid on April 15, 2013 to shareholders of record on March 31, 2013. 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 16 years, we have paid out over $1.1 billion to our shareholders.

2012 Fourth Quarter Highlights

Freehold delivered strong operational results in the fourth quarter of 2012. Robust production volumes drove increases in revenue and cash flow from operating activities despite lower average realized prices.

• Average production for the fourth quarter was 22% higher than last year. Drilling activities, including flush production from newly completed horizontal wells, accounted for about two-thirds of the increase; prior period adjustments (650 boe per day versus 350 boe per day in fourth quarter last year) and acquisitions during 2012 accounted for the remainder.

• Dividends for the fourth quarter of 2012 totalled $0.42 per share, unchanged from last year.

• Average DRIP participation was 24% in the fourth quarter of 2012 (Q4 2011 - 40%), allowing us to retain $6.7 million (Q4 2011 - $10.2 million) in dividend payments by issuing shares from treasury.

• Net income of $13.4 million was 16% lower than last year, mainly as a result of increased depletion and depreciation expense, higher royalty expense, and higher operating expense due to a higher production base. Non-cash charges (excluding current income tax) included in net income amounted to $18.1 million (Q4 2011 - $22.3 million).

• Net capital expenditures on our working interest properties totalled $7.7 million in the fourth quarter (Q4 2011 - $10.9 million), the majority of which was incurred on horizontal drilling and multi-stage fracture well completions in southeast Saskatchewan.

• Long-term debt was $18.0 million at December 31, 2012, down $7.0 million from the third quarter as excess funds from operations were applied to debt repayment.

2012 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, 2012 totalled 24.4 MMboe, with reserves assigned to 22,589 wells. Net proved plus probable royalty interest reserves increased 10% year-over-year, and net proved plus probable working interest reserves increased 12%. Approximately 62% of our net reserves are in the proved category, and 93% of our net proved reserves are producing. On a boe basis, net reserves are 60% liquids (30% heavy oil, 24% light and medium oil, 6% natural gas liquids) and 40% natural gas.

• Net proved plus probable reserve additions totalled 5.3 MMboe (45% liquids). Drilling on our royalty lands added 1.0 MMboe (19%) of net proved plus probable reserves, development activities added 0.8 MMboe (15%), and acquisitions added 3.5 MMboe (66%). Based on this, we replaced approximately 167% of 2012 production.

• Freehold's finding costs are calculated based on net reserves. In 2012, finding and development costs for net proved plus probable reserves were $21.37 per boe, while acquisition costs were $17.47 per boe and the all-in finding, development and acquisition (FD&A) cost was $18.80 per boe (including changes in future development capital). Based on an operating netback of $45.09 per boe in 2012, these activities resulted in a recycle ratio of 2.4 times the capital invested, and a three-year average recycle ratio of 2.1.

• Our land holdings as at December 31, 2012 encompassed 3.0 million gross acres, up 9% from last year mainly as a result of acquisitions. Royalty interests comprised 94% of our acreage. Our undeveloped land was independently valued by Seaton-Jordan & Associates Ltd., at $80.2 million.

Royalty Interest Activity

On an equivalent net basis, 85% of the royalty wells drilled on our lands during 2012 were oil wells (2011 - 78%) due to the oil-prone nature of our lands. As well, over 66% of the equivalent net wells drilled on our royalty lands in 2012 were horizontal wells, up from 59% 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. Over one quarter of the royalty wells drilled in the fourth quarter of 2012 had a Cardium target. Continued success with horizontal drilling (for both oil and liquids-rich natural gas) is positive and bodes well for improved well productivity.

As at December 31, 2012, there were 99 (5.9 equivalent net) licensed drilling locations on our royalty lands, compared with 106 (5.4 equivalent net) at the same time last year. We view continued well licence activity as a positive indicator of the ongoing and future development potential on our royalty lands.

ROYALTY INTEREST WELLS DRILLED	Three Months Ended December 31						Twelve Months Ended December 31
	2012			2011			2012			2011
	Gross		Equiv. Net (1)	Gross		Equiv. Net (1)	Gross		Equiv. Net (1)	Gross		Equiv. Net (1)
Non-unitized	57		2.6	102		4.9	231		11.6	301		14.4
Unitized (2)	30		0.1	60		0.4	200		1.2	322		1.3
Total	87		2.7	162		5.3	431		12.8	623		15.7

(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 2012, capital expenditures amounted to $7.7 million, the majority of which was spent to complete, equip, and tie-in wells drilled in southeast Saskatchewan during the third quarter. We participated in the drilling of seven (1.3 net) wells with a 100% success rate.

• In Saskatchewan, we participated in the drilling of two (0.3 net) vertical and one (0.1 net) horizontal Frobisher oil wells, as well as two (0.6 net) Bakken horizontal oil wells.

• In Alberta, we participated in one (0.1 net) horizontal Viking light oil well at Redwater and one (0.2 net) horizontal Cardium oil well at Minnehik Buck Lake.

This drilling activity had little effect on production levels in the fourth quarter but is expected to add to our production base in 2013.

WORKING INTEREST WELLS DRILLED (1)	Three Months Ended December 31						Twelve Months Ended December 31
	2012			2011			2012			2011
	Gross		Net	Gross		Net	Gross		Net	Gross		Net
Oil	7		1.3	9		3.8	36		13.5	29		11.1
Natural gas	-		-	-		-	-		-	3		0.4
Other	-		-	1		0.1	1		0.6	2		0.1
Total	7		1.3	10		3.9	37		14.1	34		11.6

(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 $4.8 million ($5.51 per boe) was 28% higher than the fourth quarter last year (4% higher on a per boe basis). The increase correlates to the increase in working interest production volumes, as we do not incur operating expense on our royalty interest production.

GROSS REVENUE BY PRODUCT		Three Months Ended					Twelve Months Ended
		December 31					December 31
($000s)		2012	2011		Change		2012	2011		Change
Royalty Interest
	Oil	20,503	25,419		-19	%	87,721	85,231		3	%
	NGL	1,512	2,014		-25	%	6,887	6,495		6	%
	Natural gas	3,831	3,402		13	%	10,501	15,581		-33	%
	Other (1)	556	808		-31	%	2,525	3,206		-21	%
	Total royalty interest revenue	26,402	31,643		-17	%	107,634	110,513		-3	%
Working Interest
	Oil	17,801	11,847		50	%	55,577	40,786		36	%
	NGL	476	655		-27	%	1,870	2,100		-11	%
	Natural gas	978	922		6	%	2,640	3,447		-23	%
	Other (1)	137	237		-42	%	413	1,064		-61	%
	Total working interest revenue	19,392	13,661		42	%	60,500	47,397		28	%
Total
	Oil	38,304	37,266		3	%	143,298	126,017		14	%
	NGL	1,988	2,669		-26	%	8,757	8,595		2	%
	Natural gas	4,809	4,324		11	%	13,141	19,028		-31	%
	Other (1)	693	1,045		-34	%	2,938	4,270		-31	%
	Total gross revenue	45,794	45,304		1	%	168,134	157,910		6	%

(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

Average production in the fourth quarter of 2012 was 1,737 boe per day higher than last year. Oil and natural gas liquids (NGL) production rose 22%, and natural gas production rose 26%.

• Royalty production volumes were 594 boe per day higher than last year, mainly as a result of royalty interests acquired during 2012 (which were 90% natural gas) and prior period adjustments due to the ongoing work of our audit team. Natural gas production was up 30%, while oil and NGL production declined 2%.

• Working interest production volumes were 1,143 boe per day higher than last year as a result of high activity levels in 2012 and flush production from newly completed wells in southeast Saskatchewan. Oil and NGL production was up 69% and natural gas production was up 12%.

AVERAGE DAILY PRODUCTION		Royalty Interest		Working Interest		Total
Three months ended December 31		2012	2011	2012	2011	2012	2011
	Oil (bbls/d)	3,190	3,262	2,561	1,461	5,751	4,723
	NGL (bbls/d)	267	252	88	106	355	358
	Total oil and NGL (bbls/d)	3,457	3,514	2,649	1,567	6,106	5,081
	Natural gas (Mcf/d)	17,105	13,198	3,315	2,952	20,420	16,150
	Oil equivalent (boe/d)	6,308	5,714	3,202	2,059	9,510	7,773

Commodity Prices

In the fourth quarter of 2012, the benchmark West Texas Intermediate (WTI) crude oil price averaged US$88.18 per barrel, 6% lower than the prior year. Prices deteriorated during the quarter, and WTI also continues to trade at a discount to Brent crude, the global benchmark. Historically, WTI has traded at a slight premium over Brent; however during the last two years, WTI has traded consistently at a discount to Brent as a result of market access constraints.

Crude oil supply in North America is growing, primarily from the Canadian oil sands and tight oil plays in western Canada, North Dakota, Montana, and Texas, and global demand remains strong. However, refinery outages and pipeline bottlenecks in the U.S. Midwest have severely reduced access to the Texas and Louisiana Gulf Coast where there is greater refinery demand.

Growing supplies of light crude oil from the United States and a lack of spare pipeline capacity has blends like Edmonton Par and Western Canadian Select (WCS) being steeply discounted against WTI. The widening differentials have been an ongoing issue for Canadian producers throughout 2012 and are expected to remain a concern in 2013.

Natural gas, because it is less readily transported abroad, is subject to supply and demand factors within North America. Although the low price environment of the past three years has served to curtail dry gas drilling, horizontal well technology in shale gas plays and liquids-rich gas development led to record North American production in 2012.

The average benchmark AECO natural gas price was 14% lower in the fourth quarter of 2012 versus Q4 2011. The pricing outlook is bearish in the near term due to the oversupply situation. Longer-term, we believe demand growth, driven by the phasing out of coal-fired power plants in favour of cleaner-burning natural gas, increasing transportation and industrial use, and developing offshore markets, will support stronger natural gas pricing.

Our average selling prices reflect product quality and transportation differences from benchmark prices. In the fourth quarter of 2012, our average realized oil price was $72.40 (Q4 2011 - $85.78) per barrel and our average realized natural gas price was $2.56 (Q4 2011 - $2.91) per Mcf.

Guidance Update

The following table compares changes in our key operating assumptions during 2012 to our actual results for the year. Compared to our November guidance:

• Average production for the fourth quarter was 856 boe per day higher than the third quarter of 2012 and annual production came in 3% above guidance, mainly due to prior period adjustments and flush production from successful drilling in Southeast Saskatchewan.

• Average oil prices were slightly lower than our assumptions, while natural gas prices were slightly higher.

• General and administrative costs per boe were lower than forecast as a result of higher a production base.

• Capital expenditures were $1.7 million higher than forecast, as we completed and equipped more oil wells than anticipated in the fourth quarter.

2012 Key Operating Assumptions

				Previous Guidance
Annual Average		2012 Actual Results		Nov. 8, 2012	Aug. 9, 2012	May 9, 2012	Mar. 14, 2012
Daily production	boe/d	8,850		8,600	8,300	8,100	7,600
WTI oil price	US$/bbl	94.20	(1)	95.00	93.00	100.00	100.00
Western Canada Select (WCS)	Cdn$/bbl	73.08	(1)	75.00	72.00	75.00	81.00
AECO natural gas price	Cdn$/Mcf	2.39	(1)	2.25	2.25	2.00	2.50
Exchange rate	Cdn$/US$	1.00		1.00	1.00	1.00	1.00
Operating costs	$/boe	4.82		4.80	4.80	4.80	4.60
General and administrative costs (2)	$/boe	2.39		2.65	3.00	3.00	3.00
Capital expenditures	$ millions	36.7		35	30	30	30
Dividends paid in shares (DRIP)	$ millions	27.4		27	27	27	27
Long-term debt at year end	$ millions	18		18	21	18	15
Cash taxes paid in 2012	$ millions	4.7		4.6	4.6	-	-
Weighted average shares outstanding	millions	64.9		65	65	65	65

(1)	As reported by the Canadian Association of Petroleum Producers (CAPP).
(2)	Excludes share based and other compensation.

2013 Key Operating Assumptions (1)

			Guidance Updated
Annual Average			March 7, 2013		November 8, 2012
Daily production	boe/d		8,500		8,400
WTI oil price	US$/bbl		95.00		95.00
Western Canada Select (WCS)	Cdn$/bbl		71.00		76.00
AECO natural gas price	Cdn$/Mcf		3.10		3.25
Exchange rate	Cdn$/US$		1.00		1.00
Operating costs	$/boe		5.00		5.00
General and administrative costs (2)	$/boe		2.60		2.60
Capital expenditures	$ millions		30		33
Dividends paid in shares (DRIP) (3)	$ millions		28		28
Long-term debt at year end	$ millions		48		48
Cash taxes payable in 2013 for 2012 tax year (4)	$ millions		23		25
Cash taxes payable for 2013 tax year (instalments) (4)	$ millions		25		25
Weighted average shares outstanding	millions		67		67

(1)	A sensitivity analysis of the potential impact of key variables on funds from operations per share is provided in our 2012 Annual MD&A.
(2)	Excludes share based and other compensation.
(3)	Assumes average 25% participation rate in Freehold's dividend reinvestment plan, which is subject to change at the participants' discretion.
(4)	Corporate tax estimates will vary depending on commodity prices and other factors.

As 2012 capital was ahead of guidance, we have revised our 2013 capital budget to $30 million. Our development plans are primarily oil related, focused almost entirely on our mineral title lands, and include approximately 40 gross (13 net) wells. Roughly half of our capital will be deployed in southeast Saskatchewan (light oil), with the balance allocated to our expanding mineral title opportunity base in both the Lloydminster area (heavy oil) and western Alberta (Cardium oil). Almost half of our total capital for the year will be spent in the first quarter of 2013, with area allocations similar to our annual budget. Spending may be adjusted as the year progresses, depending on the operating environment and well results.

Based on this level of capital investment, anticipated drilling activity by lessees on our royalty lands, and normal production declines (and excluding any potential acquisitions), we expect 2013 production to average approximately 8,500 boe per day. On a boe basis, production volumes for 2013 are expected to be approximately 64% oil and NGL and 36% natural gas. We continue to maintain our royalty focus with royalty production accounting for 67% of forecasted 2013 production.

In February 2013, we remitted $23 million for estimated 2012 corporate taxes. We expect to pay approximately $25 million for the 2013 tax year by way of monthly instalments. The large cash outlay for income taxes in 2013 is an anomaly that we have prepared for and have the financial capacity to handle. We expect our tax bill will normalize in 2014, at approximately 20% of pre-tax cash flow.

As our results demonstrate, we continue to benefit from activity on our oil-weighted asset base, and from relatively strong, if somewhat volatile, crude oil pricing. Of significance, natural gas accounted for 36% of production volumes in the fourth quarter (Q4 2011 - 35%), but only 11% of gross revenue (Q4 2011 - 10%). Clearly, we would benefit from any improvement in natural gas prices. However, despite a significant decline in revenue from natural gas, we have been able to maintain a steady monthly dividend rate of $0.14 ($1.68 annually) per share since January 2010.

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 2013 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 2013, subject to the Board's quarterly review and approval.

Succession Planning

After more than 16 years with Freehold and 29 years with Rife Resources Ltd. (the Manager of Freehold), Mr. William O. Ingram has announced that he plans to retire as President and CEO in May 2013. Mr. Ingram will step down as a director of Freehold but will continue to serve on the boards of Rife and Canpar Holdings Ltd. As well, Dr. P. Michael Maher, who has been a director of Freehold since 1996, will be retiring from the Board in May. The directors of Freehold thank Dr. Maher and Mr. Ingram for their many years of service to Freehold, and wish them both well in their retirement.

Following the retirement of Mr. Ingram in May, the Board plans to appoint Mr. Thomas J. Mullane as President and CEO, and he will stand for election as a director of Freehold at the annual meeting of shareholders to be held on May 15, 2013. Mr. Mullane joined Freehold in 2012 as Executive Vice-President and Chief Operating Officer, and brings a solid background of industry experience and knowledge at a senior level that will be an asset to Freehold in the years to come.

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 2012, our undeveloped land was independently valued at $80.2 million by Seaton-Jordan & Associates Ltd. Our total land holdings encompass approximately three million gross acres, 94% of which are royalties. Of this, our mineral title lands (including royalty assumption lands), which we own in perpetuity, cover more than 630,000 acres; all but approximately 107,000 gross acres of which are currently leased to third parties. In addition, we have gross overriding royalty interests in nearly 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 do not include potential reserve additions that may occur as a result of future drilling on most of 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 $20.7 million before tax (discounted at 10%).

Our oil and gas reserves were independently evaluated by Trimble Engineering Associates Ltd. (Trimble) as at December 31, 2012. 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, 2012

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	1,754		3,490			827		4,150			2,581		7,640
	Developed non-producing	73		64			-		6			73		70
	Undeveloped	-		-			28		23			28		23
Total proved		1,826		3,554			856		4,178			2,682		7,733
Probable		1,346		2,301			916		3,197			2,262		5,498
Total proved plus probable		3,173		5,855			1,771		7,376			4,944		13,231
		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	4,024		33,628			146		841			3,398		14,085
	Developed non-producing	59		794			7		7			90		209
	Undeveloped	-		4,314			-		46			28		788
Total proved		4,083		38,736			154		893			3,516		15,082
Probable		3,042		20,212			124		476			2,893		9,343
Total proved plus probable		7,125		58,949			277		1,369			6,409		24,425

(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, 2012

Forecast Prices and Costs ($000s) (1)			Before Income Taxes, Discounted at (% per year)
			0%		5%		10%		15%		20%
Proved
	Developed producing		730,246		537,722		431,272		364,055		317,704
	Developed non-producing		4,259		2,773		1,986		1,517		1,211
	Undeveloped		23,328		16,185		11,818		8,958		6,987
Total proved			757,833		556,679		445,076		374,529		325,902
Probable			564,863		295,635		193,236		142,680		112,973
Total proved plus probable			1,322,696		852,314		638,312		517,209		438,875
			After Income Taxes, Discounted at (% per year) (2)
Reserves Category			0%		5%		10%		15%		20%
Proved
	Developed producing		616,012		453,317		363,687		307,156		268,186
	Developed non-producing		3,194		2,060		1,458		1,099		865
	Undeveloped		17,434		12,070		8,789		6,639		5,158
Total proved			636,639		467,447		373,934		314,894		274,210
Probable			420,690		219,454		142,981		105,240		83,075
Total proved plus probable			1,057,329		686,902		516,915		420,134		357,284

(1)	Based on the December 31, 2012 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, 2012

Forecast Prices and Costs ($000s) (1)	Reserves Category
	Proved Reserves		Proved Plus Probable Reserves
Royalty income	660,266		1,136,234
Revenue from working interest properties	269,358		506,074
Royalty expense on working interest properties	(40,759	)	(83,190	)
Operating costs	(121,380	)	(214,202	)
Development costs	(1,441	)	(12,560	)
Well abandonment and reclamation costs	(8,212	)	(9,661	)
Future net revenue before income taxes	757,833		1,322,696
Future income taxes (2)	(121,194	)	(265,367	)
Future net revenue after income taxes (2)	636,639		1,057,329

(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.

Future Development Costs (Undiscounted) ($000s)

Forecast Prices and Costs (1)	Proved Reserves	Proved Plus Probable Reserves
2013	773	5,538
2014	519	6,525
2015	29	131
2016	29	117
2017	30	119
Remainder	61	130
Total	1,441	12,560

(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, 2012 (1)

	Proved Producing	Total Proved	Proved Plus Probable
Net reserves (Mboe)	14,085	15,082	24,425
Net production (Mboe)	2,518	2,546	2,878
Reserve life index (years)	5.6	5.9	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 2013 net production into the remaining net reserves).

Reconciliation of Net Reserves (1)

By Principal Product Type

Forecast Prices and Costs (1)		Light and Medium Oil						Heavy Oil
						Proved Plus						Proved Plus
		Proved		Probable		Probable		Proved		Probable		Probable
		(Mbbls	)	(Mbbls	)	(Mbbls	)	(Mbbls	)	(Mbbls	)	(Mbbls	)
December 31, 2011		3,445		1,885		5,330		4,533		2,841		7,373
	Extensions	569		426		995		324		199		523
	Improved recovery	-		-		-		-		-		-
	Technical revisions	319		(178	)	142		167		(74	)	93
	Discoveries	-		-		-		-		-		-
	Acquisitions	87		165		253		46		232		278
	Dispositions	-		-		-		-		-		-
	Economic factors	16		3		19		5		-		5
	Production	(883	)	-		(883	)	(897	)	-		(897	)
December 31, 2012		3,554		2,301		5,855		4,178		3,197		7,376
		Natural Gas						Natural Gas Liquids
						Proved Plus						Proved Plus
		Proved		Probable		Probable		Proved		Probable		Probable
		(MMcf	)	(MMcf	)	(MMcf	)	(Mbbls	)	(Mbbls	)	(Mbbls	)
December 31, 2011		32,560		17,113		49,673		802		405		1,206
	Extensions	810		523		1,333		42		27		69
	Improved recovery	-		-		-		-		-		-
	Technical revisions	771		(1,677	)	(906	)	42		(31	)	11
	Discoveries	-		-		-		-		-		-
	Acquisitions	11,765		4,263		16,028		206		75		281
	Dispositions	-		-		-		-		-		-
	Economic factors	(21	)	(10	)	(31	)	-		-		-
	Production	(7,149	)	-		(7,149	)	(198	)	-		(198	)
December 31, 2012		38,736		20,212		58,949		893		476		1,369
								Oil Equivalent
												Proved Plus
								Proved		Probable		Probable
								(Mboe	)	(Mboe	)	(Mboe	)
December 31, 2011								14,206		7,982		22,189
	Extensions							1,071		738		1,809
	Improved recovery							-		-		-
	Technical revisions							657		(562	)	95
	Discoveries							-		-		-
	Acquisitions							2,300		1,183		3,483
	Dispositions							-		-		-
	Economic factors							17		1		19
	Production							(3,169	)	-		(3,169	)
December 31, 2012								15,082		9,343		24,425

(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		2012		2011	2010		Three-Year Results
Finding and development expenditures ($000s)		36,746		25,649	18,054		80,449
	Change in future development capital estimates ($000s)	(934	)	1,556	(59	)	563
	Net reserve additions by development (Mboe)	1,071		581	465		2,117
Finding and development costs ($/boe)		33.45		46.81	38.67		38.27
Acquisition expenditures ($000s)		60,852		7,467	38,600		106,919
	Net reserve additions by acquisition (Mboe)	2,300		103	857		3,260
Acquisition costs ($/boe)		26.46		72.42	45.05		32.80
Total expenditures ($000s)		97,598		33,116	56,654		187,368
	Change in future development capital estimates ($000s)	(934	)	1,556	(59	)	563
	Net reserve additions (Mboe)	3,371		684	1,322		5,377
Finding, development and acquisition costs ($/boe)		28.68		50.67	42.81		34.95
Net Proved Plus Probable Reserves		2012		2011	2010		Three-Year Results
Finding and development expenditures ($000s)		36,746		25,649	18,054		80,449
	Change in future development capital estimates ($000s)	1,916		4,959	35		6,910
	Net reserve additions by development (Mboe)	1,809		1,085	950		3,845
Finding and development costs ($/boe)		21.37		28.20	19.04		22.72
Acquisition expenditures ($000s)		60,852		7,467	38,600		106,919
	Net reserve additions by acquisition (Mboe)	3,483		207	1,352		5,042
Acquisition costs ($/boe)		17.47		36.12	28.56		21.21
Total expenditures ($000s)		97,598		33,116	56,654		187,368
	Change in future development capital estimates ($000s)	1,916		4,959	35		6,910
	Net reserve additions (Mboe)	5,292		1,292	2,302		8,886
Finding, development and acquisition costs ($/boe)		18.80		29.47	24.63		21.86

(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)	2012	2011	2010	Three-Year Results
Operating netback (1) (4)	45.09	51.65	44.08	46.81
Finding, development and acquisition costs (2) (4)	18.80	29.47	24.63	21.86
Recycle ratio (times) (3)	2.4	1.8	1.8	2.1

(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, 2012

(gross acres) (1)	Developed	Undeveloped	Total
Mineral title lands (2)	367,071	168,364	535,435
Royalty assumption lands (3)	73,940	20,882	94,822
Total title lands (4)	441,011	189,246	630,257
Gross overriding royalty (GORR) lands (5)	1,571,533	603,548	2,175,081
Total royalty lands	2,012,544	792,794	2,805,338
Working interest properties	147,781	40,253	188,034
Total land holdings	2,160,325	833,047	2,993,372

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	1,537,959		380,780			111,672		16,793		26,695		5,480		1,649,631		407,475
Saskatchewan	294,474		199,025			16,703		5,062		7,427		4,417		311,177		206,452
Ontario	88,858		184,834			-		-		-		-		88,858		184,834
British Columbia	84,996		26,571			19,247		1,265		6,131		101		104,243		32,702
Manitoba	6,257		1,584			159		37		-		-		6,416		1,584
Total	2,012,544		792,794			147,781		23,157		40,253		9,998		2,160,325		833,047

(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

		2012								2011
		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
FINANCIAL ($000s, except as noted)
Revenue, net of royalty expense		43,832		40,294		34,498		43,036		44,217		34,614		39,560		35,322
Dividends declared		27,787		27,616		27,399		26,766		25,585		25,322		25,111		24,950
	Per share ($) (1)	0.42		0.42		0.42		0.42		0.42		0.42		0.42		0.42
Net income (2)		13,431		11,975		7,862		13,060		16,033		11,290		16,717		11,219
	Per share, basic and diluted ($) (2)	0.20		0.18		0.12		0.21		0.26		0.19		0.28		0.19
Cash flow from operating activities		38,183		36,212		27,402		36,335		32,595		30,255		31,424		24,096
	Per share ($)	0.58		0.55		0.42		0.58		0.54		0.50		0.53		0.41
Funds from operations (3)		31,475		26,272		20,522		25,613		38,245		28,772		33,891		27,322
	Per share ($) (3)	0.48		0.40		0.31		0.41		0.63		0.48		0.57		0.46
Dividends paid in shares (DRIP)		6,672		7,013		6,940		6,789		10,232		8,765		7,798		6,695
	Average DRIP participation rate (%) (4)	24		25		25		26		40		35		31		27
Property and royalty acquisitions (net)		243		10,789		(99	)	49,919		(195	)	7,297		44		321
Capital expenditures		7,743		9,160		6,598		13,245		10,910		5,537		4,537		4,665
Long-term debt		18,000		25,000		23,000		18,000		48,000		51,000		54,000		61,000
Shares outstanding
	Weighted average, basic (000s)	66,091		65,677		65,159		62,571		60,811		60,198		59,716		59,343
	At quarter end (000s)	66,270		65,879		65,440		64,993		61,141		60,492		59,954		59,536
OPERATING ($/boe, except as noted)
Daily production (boe/d) (5)		9,510		8,654		8,501		8,733		7,773		7,195		7,445		7,490
	Royalty interest production (%)	66		68		76		74		74		72		77		76
Average selling price		51.55		51.71		45.74		54.80		61.90		52.80		57.61		52.51
Operating netback (3)		44.59		45.59		40.64		49.48		56.56		46.86		53.82		48.96
Operating expenses		5.51		5.02		3.96		4.68		5.28		5.43		4.57		3.44
	Working interest properties	16.36		15.47		16.47		17.86		19.91		19.47		19.73		14.32
Net general and administrative expenses (6)		2.25		1.88		2.13		3.31		2.05		2.16		2.36		3.75
BENCHMARK PRICES
WTI crude oil (US$/bbl)		88.18		92.22		93.49		102.93		94.06		89.75		102.56		94.02
Exchange rate (Cdn$/US$)		1.01		1.01		0.99		1.00		0.98		1.02		1.03		1.01
Edmonton Par crude oil (Cdn$)		83.99		84.33		83.95		92.18		97.35		91.74		103.07		87.97
Western Canada Select (WCS) (Cdn$/bbl)		69.43		69.99		71.29		81.61		85.48		70.63		82.09		70.19
WTI/Edmonton Par differential ($/bbl)		(4.19	)	(7.89	)	(9.54	)	(10.75	)	3.29		1.99		0.51		(6.05	)
Edmonton Par/WCS differential (Cdn$/bbl)		(14.56	)	(14.34	)	(12.66	)	(10.57	)	(11.87	)	(21.11	)	(20.98	)	(17.78	)
AECO natural gas (Cdn$/Mcf)		3.00		2.19		1.83		2.52		3.47		3.72		3.74		3.77
SHARE TRADING PERFORMANCE
High ($)		22.45		20.34		19.67		21.59		19.75		21.58		23.28		22.93
Low ($)		19.62		17.83		17.25		19.16		14.51		16.04		19.37		19.86
Close ($)		22.40		19.76		18.44		19.59		19.41		16.36		19.64		22.75
Volume (000s)		7,435		5,656		7,483		8,076		7,114		7,780		5,317		7,921

(1)	Based on the number of shares issued and outstanding at each record date.
(2)	Net income and net income per share for the three months ended March 31, 2011 have been restated for revisions made to deferred tax.
(3)	See Non-GAAP Financial Measures.
(4)	Average participation in Freehold's DRIP ranged between 24% and 40% over the past eight quarters and is subject to change at the participants' discretion.
(5)	Reported production for a period may include minor adjustments from previous production periods.
(6)	Excludes share based and other compensation.

Consolidated Balance Sheets

		December 31		December 31
($000s) (unaudited)		2012		2011
Assets
Current assets:
	Cash	$ 102		$ 164
	Accounts receivable	23,225		34,763
		23,327		34,927
Deposit on acquisition		-		5,000
Exploration and evaluation assets		25,905		25,045
Petroleum and natural gas interests		399,005		363,967
		$ 448,237		$ 428,939
Liabilities and Shareholders' Equity
Current liabilities:
	Dividends payable	$ 9,278		$ 8,560
	Accounts payable and accrued liabilities	12,743		14,883
	Current taxes payable	23,095		-
	Current portion of share based and other compensation payable	2,108		3,876
		47,224		27,319
Asset retirement obligation		16,714		14,282
Share based and other compensation payable		1,290		1,289
Long-term debt		18,000		48,000
Deferred income tax liability		49,194		59,163
Shareholders' equity:
	Shareholders' capital	422,728		323,115
	Contributed surplus	2,036		1,480
	Deficit	(108,949	)	(45,709	)
		315,815		278,886
		$ 448,237		$ 428,939

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)		2012		2011		2012		2011
Revenue:
	Royalty income and working interest sales	$ 45,794		$ 45,304		$ 168,134		$ 157,910
	Royalty expense	(1,962	)	(1,087	)	(6,474	)	(4,197	)
		43,832		44,217		161,660		153,713
Expenses:
	Operating	4,820		3,772		15,598		12,782
	General and administrative	1,972		1,468		7,746		7,029
	Share based and other compensation	999		1,268		2,371		2,190
	Interest and financing	421		610		2,235		2,907
	Depletion and depreciation	16,372		13,603		64,576		49,251
	Accretion of asset retirement obligation	107		83		381		344
	Management fee	1,072		857		3,808		3,401
		25,763		21,661		96,715		77,904
Income before taxes		18,069		22,556		64,945		75,809
Income tax:
	Current expense	5,063		80		27,792		80
	Deferred expense (recovery)	(425	)	6,443		(9,175	)	20,470
		4,638		6,523		18,617		20,550
Net income and comprehensive income		$ 13,431		$ 16,033		$ 46,328		$ 55,259
Net income per share, basic and diluted		$ 0.20		$ 0.26		$ 0.71		$ 0.92
Weighted average number of shares:
	Basic	66,090,969		60,811,300		64,880,038		60,021,736
	Diluted	66,194,503		60,886,218		64,979,074		60,093,840

Consolidated Statements of Cash Flows

			Three Months Ended				Year ended
			December 31				December 31
($000s) (unaudited)			2012		2011		2012		2011
Operating:
	Net income		$ 13,431		$ 16,033		$ 46,328		$ 55,259
	Items not involving cash:
		Depletion and depreciation	16,372		13,603		64,576		49,251
		Share based and other compensation	999		1,268		2,371		2,190
		Deferred income tax expense (recovery)	(425	)	6,443		(9,175	)	20,470
		Accretion of asset retirement obligation	107		83		381		344
		Shares issued in lieu of management fee	1,072		857		3,808		3,401
	Expenditures on share based and other compensation		-		-		(3,883	)	(2,440	)
	Expenditures on reclamation		(81	)	(42	)	(524	)	(245	)
	Changes in non-cash working capital		6,708		(5,650	)	34,250		(9,860	)
			38,183		32,595		138,132		118,370
Financing:
	Issuance of shares, net of issue costs		-		-		67,597		-
	Long-term debt		(7,000	)	(3,000	)	(30,000	)	(17,000	)
	Dividends paid		(21,060	)	(15,262	)	(81,436	)	(67,204	)
			(28,060	)	(18,262	)	(43,839	)	(84,204	)
Investing:
	Deposit on acquisition		-		(5,000	)	5,000		(5,000	)
	Property and royalty acquisitions		(243	)	195		(60,852	)	(7,467	)
	Capital expenditures		(7,743	)	(10,910	)	(36,746	)	(25,649	)
	Change in reclamation fund		-		-		-		2,725
	Changes in non-cash working capital		(2,149	)	1,358		(1,757	)	980
			(10,135	)	(14,357	)	(94,355	)	(34,411	)
Decrease in cash			(12	)	(24	)	(62	)	(245	)
Cash, beginning of period			114		188		164		409
Cash, end of period			$ 102		$ 164		$ 102		$ 164

Consolidated Statements of Changes in Shareholders' Equity

		Year ended
		December 31
($000s) (unaudited)		2012		2011
Shareholders' capital:
	Balance, beginning of year	$ 323,115		$ 286,224
	Shares issued for dividend reinvestment plan	27,414		33,490
	Shares issued in lieu of management fee	3,808		3,401
	Shares issued for equity offering	70,725		-
	Issue costs, net of tax effect	(2,334	)	-
	Balance, end of year	422,728		323,115
Contributed surplus:
	Balance, beginning of year	1,480		1,084
	Share based compensation expense	556		396
	Balance, end of year	2,036		1,480
Deficit:
	Balance, beginning of year	(45,709	)	-
	Net income and comprehensive income	46,328		55,259
	Dividends declared	(109,568	)	(100,968	)
	Balance, end of year	(108,949	)	(45,709	)
Total shareholders' equity		$ 315,815		$ 278,886

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at March 7, 2013, 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 the fourth quarter of 2012 adding to our production base in 2013;

• 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 2013 and our dividend policy; and

• the appointment of Thomas J. Mullane as President and CEO and his standing for election as a director of Freehold.

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.

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, netback, funds from operations, funds from operations per share, finding, development and acquisition (FD&A) costs, recycle ratio, and net asset value. We believe that these measures 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

Funds from operations is a financial term commonly used in the oil and gas industry. It is a key measure of our ability to generate cash, finance operations, and pay monthly dividends. 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 define funds from operations as net income adjusted for non-cash depletion and depreciation, share based and other compensation, deferred tax expense/recovery, accretion of asset retirement obligation, and management fee, and further adjusted for expenditures on reclamation. 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 and repay debt. We believe that such a measure provides a better assessment of Freehold's operations on a continuing basis by eliminating certain non-cash charges. From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income. 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. A reconciliation of funds from operations to net income is provided below.

Reconciliation of Net Income to Funds from Operations

		Three Months Ended				Twelve Months Ended
		December 31				December 31
		2012		2011		2012		2011
Net income		13,431		16,033		46,328		55,259
Adjust for non-cash items:
	Depletion and depreciation	16,372		13,603		64,576		49,251
	Share based and other compensation	999		1,268		(1,512	)	(250	)
	Deferred income tax (recovery)	(425	)	6,443		(9,175	)	20,470
	Accretion of asset retirement obligation	107		83		381		344
	Management fee	1,072		857		3,808		3,401
Adjust for cash item:
	Expenditures on reclamation	(81	)	(42	)	(524	)	(245	)
Funds from operations		31,475		38,245		103,882		128,230
	Per share	0.48		0.63		1.60		2.14

In addition, we refer to various per boe figures, such as revenues and costs, operating netback, FD&A costs, and NAV, also considered non-GAAP financial 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 gas production during the period, with natural gas converted to equivalent barrels of oil as described above.

Availability on SEDAR

Freehold's 2012 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 next week.