Long Run Exploration Ltd. Announces Financial Results for the Fourth Quarter and Year Ended December 31, 2012 and 2012 Year End Reserve Results

March 7, 2013 9:48 PM

CALGARY, ALBERTA–(Marketwire – Mar 7, 2013) – LONG RUN EXPLORATION LTD. (LRE.TO) (“Long Run” or the “Corporation”) is pleased to announce its results for the fourth quarter and year ended December 31, 2012 and year end reserve results.

In the fourth quarter, WestFire Energy Ltd. (“WestFire”) and Guide Exploration Ltd. (“Guide”) completed an all share merger transaction. The management team of Guide is leading the renamed Long Run Exploration Ltd. Long Run is focusing on core properties in the Peace River and Edmonton areas of Alberta. Short to medium term development will focus on Montney oil projects at Peace River and Viking oil projects at Redwater. On a land base of more than 1.8 million net acres, Long Run is actively exploring new concepts while continuing to drive development and growing production in our core areas. Over the long term, it is our intention to build an exploration company with a balanced oil and gas portfolio that focuses on resource plays in western Canada.

Currently, Long Run is producing approximately 24,000 barrels of oil equivalent per day (12,500 barrels of crude oil and NGLs plus 69 Mmcf/d of natural gas), on target with our 2013 budget. Our winter drilling program is approaching completion and we are working to tie-in these wells prior to spring break-up.

All financial, operational, and reserve comparatives are based on historical WestFire information.

2012 HIGHLIGHTS

Long Run replaced 927 percent of 2012 production achieving all-in Finding, Development and Acquisition (“FD&A”) costs of $12.10 per boe on a Proved plus Probable (“P+P”) basis, including changes in Future Development Costs (“FDC”), and achieved Total Proved (“TP”) FD&A costs of $16.46 per boe, including FDC;

Fourth quarter funds from operations was $55.8 million or $0.48 per share (basic), (excluding transaction costs of $17.4 million or $0.15 per share (basic));

Using a fourth quarter funds flow netback of $28.34 per boe (excluding transaction costs) and 2012 P+P FD&A costs of $12.10 per boe, Long Run achieved a 2012 recycle ratio of 2.3x;

Exit production for 2012 of 23,032 boe per day was in-line with forecasted exit volumes of 23,000 boe per day and an increase of 148 percent (82 percent per share) compared to 2011 exit production of approximately 9,300 boe per day;

Long Run successfully divested non-core assets in west central Saskatchewan for cash proceeds of approximately $180 million, before closing adjustments. As a result of this transaction, Long Run”s 2012 year-end net debt was $293.1 million, which positions Long Run with a debt to annualized 2012 fourth quarter funds from operations ratio (excluding transaction costs) of 1.3x, among the lowest in the junior and intermediate oil and gas sector.

Long Run”s 2013 capital program of $265 million targets to increase production to average 25,000 boe per day for 2013, with an increase in liquids production from approximately 11,500 bbls per day at the end of 2012 to an average of approximately 13,400 bbls per day in 2013, an increase in average crude oil and liquids production in 2013 of approximately 17 percent.

FOURTH QUARTER FINANCIAL AND PRODUCTION RESULTS

Fourth quarter production averaged 21,405 boe per day, weighted approximately 56 percent to oil and liquids. Compared to the fourth quarter 2011, production increased approximately 149 percent with 2012 full year light oil volumes increasing 157 percent over 2011.

Higher production volumes in the fourth quarter increased funds from operations to approximately $55.8 million (excluding transaction costs) or $0.48 per share (basic), a 33 percent increase per share over the $29.9 million or $0.36 per share (basic) generated in the third quarter of 2012, (inclusive of Q4 2012 transaction costs funds from operations was $38.4 million or $0.33 per share (basic));

Operating costs improved for the fourth quarter of 2012, down 35 percent to $11.78 per boe, compared to $18.20 per boe in the third quarter of 2012, and down more than 30 percent from the fourth quarter of 2011 when operating costs were $16.83 per boe;

Capital spending of approximately $64.5 million in the fourth quarter of 2012 targeted oil development in the Montney at Girouxville and in the Viking at Redwater.

During the fourth quarter of 2012, Long Run recorded a net loss of $56.6 million ($0.49 per share (basic)) primarily due to a property, plant and equipment impairment charge of $144.1 million for the year ended December 31, 2012 resulting from a weakening of the future price forecasts and a reduction of the estimated reserve volumes at Kaybob, partially offset by a gain on disposal of assets, and income from operations.

2012 RESERVES

Total Proved plus Probable (“P+P”) gross reserves increased by approximately 92 percent (27 percent per share) to 83.2 mmboe compared with 43.3 mmboe at December 31, 2011;

Total Proved (“TP”) gross reserves increased by approximately 86 percent to 53.7 mmboe compared with 28.9 mmboe at December 31, 2011. TP reserves represent 65 percent of our P+P portfolio of 83.2 mmboe, a number which Long Run believes will increase further with 87 percent of development capital being directed into crude oil plays in the Montney in the Peace area and in the Viking at Redwater, two plays which continue to show improving results delivering low finding and development costs;

In Long Run”s emerging oil play in the Peace River area, P+P reserve bookings for the area increased 34 percent from year end 2011 from 21.2 mmboe to 28.5 mmboe (Guide, December 31, 2011), which is a trend likely to accelerate with Long Run”s plan to drill 50 wells into this emerging oil play in 2013;

Assuming 2013 average daily forecasted production volumes of 25,000 boe per day, Long Run”s P+P reserve life index is approximately 9.1 years.

2012 FINDING, DEVLEOPMENT and ACQUISITION COSTS

On a P+P basis, Long Run replaced 927 percent of 2012 production achieving total Finding, Development and Acquisition (“FD&A”) costs, including Future Development Capital (“FDC”), of $12.10 per boe. On a TP basis, FD&A costs were $16.46 per boe, including FDC.

COMMODITY ENVIRONMENT

WTI crude oil prices averaged US$94.19 per barrel in 2012, compared to US$95.00 per barrel in 2011. Edmonton light sweet traded at an average discount of $7.97 per barrel in 2012 compared to WTI (2011 – premium of $1.22 per barrel).

WTI crude oil prices averaged US$88.20 per barrel in the fourth quarter of 2012, compared to US$92.19 per barrel in the third quarter of 2012 and US$94.02 per barrel for the fourth quarter of 2011. Edmonton light sweet oil traded at a discount of $3.46 per barrel compared to WTI during the fourth quarter of 2012 (2011 – premium of $1.44 per barrel) compared to a discount of $7.40 per barrel during the third quarter of 2012.

In 2012, the AECO Monthly Index averaged $2.40 per mcf compared to $3.67 per mcf in 2011.

In the fourth quarter of 2012, the AECO Monthly Index averaged $3.06 per mcf compared to $2.19 per mcf in the third quarter of 2012 and $3.47 per mcf for the fourth quarter of 2011.

OPERATIONS UPDATE

In the fourth quarter of 2012, Long Run spent $64.5 million in capital which included drilling 29 (26.5 net) wells. This included 9 (net) Viking oil wells at Redwater, 5 (net) Montney oil wells in the Peace River area, 12 (9.5 net) on subsequently divested west central Saskatchewan assets, and 3 (net) exploration wells in the Peace River area. Long Run continues to achieve results above management”s expectations while keeping on-stream costs in-line with historical averages.

In the near term, Long Run will focus development primarily on oil opportunities at Redwater and in the Peace River area, both in Alberta. Up to 53 (50.4 net) wells are planned, including 18 (net) Montney oil wells in the Peace Area, and 30 (27.4 net) Viking oil wells at Redwater.

Total first quarter capital spending is expected to be approximately $100 million.

Peace Area Montney

Results from this project have started to exceed management”s expectations with wells completed with 20 or more frac stages exhibiting initial month average rates in excess of 200 boe per day.

During the second half of 2012, Long Run expanded the Girouxville portion of this play and brought the 5,000 bbl per day capacity Girouxville crude oil processing facility on stream. This increases our oil processing capacity in the Peace Area to 10,000 bbl per day complemented by 50 Mmcf per day of gas processing.

Enhanced oil recovery (“EOR”) will be a key component in maximizing the value from this project. Long Run anticipates receiving regulatory approval for its EOR pilot project in the Peace Area during the first half of 2013, and is working towards a second EOR pilot with expected approval in late 2013.

Redwater Viking

During the fourth quarter of 2012, Long Run tested cemented liner completion systems which was a departure from the previously applied burst-port completion system. Long Run expects to see improved reservoir stimulation, resulting in better well performance from this change and other changes to the Redwater frac design.

Currently, the average rate of the initial 12 wells completed since these changes is approximately 86 boe per day per well.

Financial and Operating Highlights

		Three months ended December 31						Year ended December 31
		2012		2011		% change		2012		2011		% change
Financial
(thousands, except per share amounts)
Gross revenue ⁽¹⁾		106,320		54,810		94	%	284,754		141,970		101	%
Funds from operations ⁽²⁾		38,407		29,896		28	%	128,719		74,666		72	%
	Basic per share	0.33		0.36		-8	%	1.41		1.18		19	%
	Diluted per share	0.33		0.36		-8	%	1.41		1.17		21	%
Net income (loss)		(56,590	)	(66,612	)	15	%	(42,652	)	(52,667	)	19	%
	Basic per share	(0.49	)	(0.80	)	39	%	(0.47	)	(0.83	)	43	%
	Diluted per share	(0.49	)	(0.80	)	39	%	(0.47	)	(0.83	)	43	%
Capital expenditures, net		(111,392	)	72,552		n/a		32,169		178,178		-82	%
Ending net debt		293,123		124,753		135	%	293,123		124,753		135	%
Operations
Daily production
	Light oil and NGL (Bbls/d)	10,457		5,342		96	%	7,561		3,308		129	%
	Heavy oil (Bbls/d)	1,538		530		190	%	1,015		531		91	%
	Natural gas (Mcf/d)	56,453		16,376		245	%	27,679		11,822		134	%
Total production (BOE/d)		21,405		8,601		149	%	13,189		5,809		127	%
Average sales price
	Light oil and NGL (per bbl)	75.07		93.18		-19	%	79.97		91.32		-12	%
	Heavy oil (per bbl)	57.89		77.17		-25	%	61.37		67.68		-9	%
	Natural gas (per mcf)	3.35		3.32		1	%	2.80		3.76		-26	%
Netback per boe
	Sales price	50.27		71.01		-29	%	57.30		67.36		-15	%
	Risk management gain (loss)	3.72		(1.75	)	n/a		1.69		(0.40	)	n/a
	Net sales price	53.99		69.26		-22	%	58.99		66.96		-12	%
	Royalties	(6.36	)	(7.49	)	-15	%	(6.03	)	(7.94	)	-24	%
	Operating expenses	(11.78	)	(16.83	)	-30	%	(14.57	)	(16.39	)	-11	%
	Transportation	(2.27	)	(1.31	)	73	%	(2.06	)	(1.26	)	63	%
	Netback ⁽²⁾	33.58		43.63		-23	%	36.33		41.37		-12	%


(1) Gross revenue includes petroleum and natural gas revenue plus realized gains and losses on financial commodity derivative contracts. (2) See “Non-GAAP Measurements”

CAPITAL EXPENDITURES

Exploration and evaluation assets, property and equipment, net	$000s
Balance at December 31, 2011	585,826
Additions	210,410
Guide Arrangement	505,802
Disposals	(110,525	)
Decommissioning liability additions	28,392
Capitalized share-based and deferred compensation	839
Derecognition expense	(784	)
Non-monetary transactions	6,373
Depletion and depreciation	(121,568	)
Impairment of property and equipment	(144,116	)
Balance at December 31, 2012	960,649

Year ended December 31	2012				2011
	$000s		%		$000s	%
Land	15,157		7		41,195	23
Geological and geophysical	3,612		2		4,543	3
Drilling and completion	149,293		71		102,344	57
Plant and facilities	43,160		21		31,292	17
Inventory	(1,313	)	(1	)	228	–
Other assets	501		–		393	–
Exploration & evaluation assets, property & equipment expenditures	210,410		100		179,995	100

SHARE INFORMATION

The following table summarizes the outstanding shares of Long Run as of December 31:

	2012	2011
Common Shares	110,107,152	67,355,377
Non-Voting Convertible Shares	15,512,858	15,613,564
Options	8,042,000	4,849,135
Warrants to purchase 0.4167 Common Shares	2,300,000	–

RESERVES

At December 31, 2012, total proved reserves as a percentage of proved plus probable reserves were 65 percent. All of our reserves were evaluated, effective December 31, 2012, in a report (the “Sproule Report”) prepared by the independent engineering firm Sproule Associates Limited (“Sproule”).

The following summarizes the Corporation”s crude oil, natural gas and natural gas liquids reserves and the net present value of the future net revenues therefrom using forecast prices and costs as evaluated in the Sproule Report. The reserve estimates contained in the Sproule Report have been calculated in compliance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Under NI 51-101, proved reserves estimates are defined as having a high degree of certainty with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be equal to or greater than the proved plus probable reserves estimate. The reserves estimates set forth below are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

Additional information with respect to the Corporation”s reserves at December 31, 2012 will be contained in the Corporation”s Annual Information Form for the year ended December 31, 2012 which will be filed on SEDAR at www.sedar.com on or before March 31, 2013.

Gross reserves are the total of the Corporation”s working interest share before deduction of royalties owned by others and without including any of the Corporation”s royalty interests. Net reserves are the total of the Corporation”s working interest reserves after deducting amounts attributable to royalties owned by others, plus the Corporation”s royalty interest reserves.

SUMMARY OF OIL AND GAS RESERVES

AS OF DECEMBER 31, 2012

FORECAST PRICES AND COSTS

		RESERVES
		LIGHT AND MEDIUM OIL		HEAVY OIL		NATURAL GAS		NATURAL GAS LIQUIDS		TOTAL
RESERVES CATEGORY		Gross (Mbbl)	Net (Mbbl)	Gross (Mbbl)	Net (Mbbl)	Gross (MMcf)	Net (MMcf)	Gross (Mbbl)	Net (Mbbl)	Gross (MBOE)	Net (MBOE)

Proved Developed
	Producing	7,667	6,571	829	713	132,183	119,131	2,421	1,566	32,947	28,705
	Non-Producing	233	205	159	130	16,103	13,697	293	184	3,368	2,802
Proved
	Undeveloped	8,942	7,965	553	469	42,908	38,823	695	504	17,342	15,408
Total Proved		16,842	14,741	1,540	1,312	191,194	171,651	3,409	2,254	53,657	46,915
Probable		11,719	9,856	1,254	1,061	90,234	79,641	1,497	1,003	29,508	25,193
Total Proved plus Probable		28,561	24,597	2,794	2,373	281,428	251,291	4,905	3,257	83,165	72,109

PRICING

Pricing utilized in the Sproule Report was an average of the January 1, 2013 pricing forecast of each of Sproule, GLJ Petroleum Consultants Ltd. and McDaniel & Associates Consultants Ltd. and are summarized below.

	OIL
Year	WTI Cushing Oklahoma ($US/Bbl)	Edmonton Oil Price 40° API ($Cdn/Bbl)	Hardisty Heavy 12° API ($Cdn/Bbl)	Natural Gas Alberta Spot Gas Price($Cdn/Mcf)	Pentanes Plus Edmonton ($Cdn/Bbl)	Butanes Price Edmonton ($Cdn/Bbl)	Inflation Rates⁽¹⁾%/Year	Exchange Rate⁽²⁾($US/$Cdn)

Forecast
2013	90.71	85.68	62.75	3.35	94.89	64.19	1.83	1.00
2014	91.64	90.61	67.58	3.80	96.57	69.01	1.83	1.00
2015	92.30	91.60	68.62	4.18	95.97	70.91	1.83	1.00
2016	96.17	95.48	72.15	4.71	100.08	73.88	1.83	1.00
2017	97.29	96.59	72.98	5.12	101.22	74.74	1.83	1.00
2018	98.44	97.71	73.81	5.36	102.41	75.60	1.83	1.00
2019	99.94	99.21	74.95	5.45	104.00	76.76	1.83	1.00
2020	101.76	101.03	76.33	5.57	105.88	78.17	1.83	1.00
2021	103.61	102.88	77.74	5.67	107.82	79.60	1.83	1.00
2022	105.54	104.81	79.22	5.77	109.85	81.11	1.83	1.00
2023	107.46	106.69	80.64	5.87	111.82	82.57	1.83	1.00
2024	109.43	108.65	82.11	5.99	113.85	84.10	1.83	1.00
2025+	Escalated oil, gas and product prices at 1.83% per year thereafter

(1) Inflation rates for forecasting prices and costs.

(2) Exchange rates used to generate the benchmark reference prices in this table.

NET PRESENT VALUE OF FUTURE NET REVENUE

NET PRESENT VALUES OF FUTURE NET REVENUE ⁽¹⁾



		BEFORE INCOME TAXES DISCOUNTED AT (%/year)					AFTER INCOME TAXES DISCOUNTED AT (%/year)
RESERVES CATEGORY		0 (MM$)	5 (MM$)	10 (MM$)	15 (MM$)	20 (MM$)	0 (MM$)	5 (MM$)	10 (MM$)	15 (MM$)	20 (MM$)

Proved Developed
	Producing	773,203	639,904	552,564	490,061	442,829	773,203	639,904	552,564	490,061	442,829
	Non-Producing	59,791	44,491	35,243	29,077	24,677	59,791	44,491	35,243	29,077	24,677
Proved Undeveloped		308,144	212,822	151,919	109,868	79,236	308,144	212,822	151,919	109,868	79,236
Total Proved		1,141,138	897,217	739,726	629,007	546,742	1,141,138	897,217	739,726	629,007	546,742
Probable		789,387	526,439	379,381	287,140	224,942	628,527	426,660	312,662	240,210	190,672
Total Proved plus Probable		1,930,525	1,423,656	1,119,107	916,147	771,684	1,769,665	1,323,876	1,052,388	869,216	737,414

(1) Net present value of future net revenue does not represent fair market value. Tables may not add due to rounding.

NET ASSET VALUE

As at December 31, 2012

	$ million
PV10% (Before Tax)	TP			P+P
Reserve Value ⁽¹⁾	$	739.7		$	1,119.1		Sproule / Dec 31, 2012
Undeveloped land ⁽²⁾	$	75.7		$	75.7
Net Debt ⁽³⁾	$	(293.1	)	$	(293.1	)
Net Asset Value	$	522.3		$	901.7
Basic Shares O/S (million) ⁽⁴⁾		125.6			125.6
NAV/share	$	4.16		$	7.18

PV5% (Before Tax)
Reserve Value ⁽¹⁾	$	897.2		$	1,423.7		Sproule / Dec 31, 2012
Undeveloped Land ⁽²⁾	$	75.7		$	75.7
Net Debt ⁽³⁾	$	(293.1	)	$	(293.1	)
Net Asset Value	$	679.8		$	1,206.3
Basic Shares O/S (million) ⁽⁴⁾		125.6			125.6
NAV/share	$	5.41		$	9.60

(1) Reserve value is the net present value of future net revenues before tax which does not represent fair market value, as derived from the Sproule Report.

(2) As internally evaluated at $75.7 million using an average of $98.91 per acre.

(3) See “Non-GAAP Measurements”

(4) Basic shares include outstanding common shares and outstanding non-voting convertible shares.

(5) The above does not include asset retirement obligations. The Sproule Report included abandonment costs only for undeveloped locations with reserves.

RESERVES RECONCILIATION

	LIGHT AND MEDIUM OIL						HEAVY OIL
FACTORS	Gross Proved (Mbbl)		Gross Probable (Mbbl)		Gross Proved Plus Probable (Mbbl)		Gross Proved (Mbbl)		Gross Probable (Mbbl)		Gross Proved Plus Probable (Mbbl)

December 31, 2011	12,678		8,301		20,979		741		397		1,138

Extensions	232		1,177		1,409		15		44		59
Infill Drilling	1,081		521		1,602		69		12		81
Technical Revisions	(192	)	(2,301	)	(2,493	)	(69	)	(100	)	(169	)
Discoveries	0		0		0		0		0		0
Acquisitions	9,283		7,095		16,379		1,213		986		2,199
Dispositions	(3,623	)	(3,139	)	(6,762	)	(14	)	(50	)	(64	)
Economic Factors	(166	)	65		(101	)	(99	)	(35	)	(134	)
Production	(2,453	)	0		(2,453	)	(317	)	0		(317	)

December 31, 2012	16,842		11,719		28,561		1,540		1,254		2,794

	NATURAL GAS LIQUIDS						NATURAL GAS						TOTAL
FACTORS	Gross Proved (Mbbl)		Gross Probable (Mbbl)		Gross Proved Plus Probable (Mbbl)		Gross Proved (MMcf)		Gross Probable (MMcf)		Gross Proved Plus Probable (MMcf)		Gross Proved (MBOE)		Gross Probable (MBOE)		Gross Proved Plus Probable (MBOE)

December 31, 2011	4,824		1,604		6,428		63,934		24,496		88,430		28,899		14,385		43,283

Extensions	1		3		3		150		753		903		273		1,349		1,622
Infill Drilling	3		1		4		770		336		1,106		1,281		590		1,871
Technical Revisions	(1,811	)	(601	)	(2,413	)	(16,269	)	(8,515	)	(24,784	)	(4,783	)	(4,422	)	(9,205	)
Discoveries	0		0		0		0		0		0		0		0		0
Acquisitions	846		528		1,373		155,665		74,615		230,280		37,286		21,045		58,331
Dispositions	(32	)	(20	)	(52	)	(1,635	)	(1,175	)	(2,810	)	(3,942	)	(3,405	)	(7,347	)
Economic Factors	(52	)	(17	)	(69	)	(1,329	)	(276	)	(1,605	)	(538	)	(34	)	(571	)
Production	(369	)	0		(369	)	(10,092	)	0		(10,092	)	(4,820	)	0		(4,820	)

December 31, 2012	3,409		1,497		4,906		191,194		90,234		281,428		53,657		29,509		83,165

(1) The Corporation has no unconventional reserves (Bitumen, Synthetic Crude Oil, Natural Gas from Coal, etc.).

FD&A


		2012						2011				3-Year Avg./Total
		Proved			P+P			Proved		P+P		Proved		P+P

Capital Expenditures ($M)
	Exploration and development expenditures ⁽²⁾	$	99,131		$	99,131		$	138,854	$	138,854	$	309,944	$	309,944
	Change in future development capital (“FDC”)	$	(62,096	)	$	(46,541	)	$	140,282	$	160,148	$	140,142	$	205,286
	All in exploration and development capital	$	37,035		$	52,590		$	279,136	$	299,002	$	450,086	$	515,230
	Acquisition (net of disposition)⁽³⁾	$	449,839		$	488,428		$	383,519	$	383,519	$	836,580	$	875,169
	Total Capital	$	486,874		$	541,018		$	662,656	$	682,522	$	1,286,667	$	1,390,399

Reserve Additions
	Development		(3,767	)		(6,283	)		5,346		6,699		5,118		5,717
	Acquisitions (net of dispositions)		33,344			50,984			17,488		24,465		51,032		75,465
	Total Additions (including revisions)		29,578			44,702			22,834		31,164		56,150		81,183

Finding and Development Costs (F&D – $/boe)
	F&D with change in FDC ⁽⁴⁾⁽⁵⁾		⁽¹	⁾		⁽¹	⁾	$	52.22	$	44.63	$	87.95	$	90.12
Finding, development and acquisition costs
	FD&A with change in FDC ⁽⁴⁾⁽⁵⁾	$	16.46		$	12.10		$	29.02	$	21.90	$	22.91	$	17.13

(1) New management and the new evaluator viewed the development plans in certain properties differently than previously evaluated, resulting in 2012 F&D being negative and therefore not being meaningful. For both FD&A and F&D, the 2012 values are included in the three year averages.

(2) 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 reserve additions for that year.

(3) In 2012, the acquisition costs related to corporate acquisitions reflect the fair market value. In prior years the acquisition costs related to the corporate acquisitions reflect the consideration paid plus the net debt assumed, both valued at closing and does not reflect the fair market value allocated to the acquired oil and gas assets under generally accepted accounting principles.

(4) Calculation includes reserve revisions. Long Run calculates FD&A costs which incorporate both the costs and associated reserve additions related to acquisitions net of any dispositions during the year. Since acquisitions can have a significant impact on Long Run”s annual reserve replacement costs, the Corporation believes the FD&A costs provide a more meaning portrayal of Long Run”s cost structure.

(5) The 2012 FD&A calculations were based on Long Run”s reserves at December 31, 2012 evaluated by Sproule and WestFire”s reserves at December 31, 2011. The FD&A calculations prior to 2012 were based on WestFire”s reserves from December 31, 2009 to December 31, 2011.

Non-GAAP Measurements

The MD&A contains terms commonly used in the oil and gas industry, such as funds flow from operations, funds flow from operations per share, and operating netback. These terms are not defined by International Financial Reporting Standards (IFRS) and should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings as determined in accordance with IFRS as an indicator of Long Run”s performance. Management believes that funds flow from operations is a useful financial measurement which assists in demonstrating the Corporation”s ability to fund capital expenditures necessary for future growth or to repay debt. Long Run”s determination of funds flow from operations may not be comparable to that reported by other companies. All references to funds flow from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital and abandonment expenditures. The Corporation calculates funds flow from operations per share by dividing funds flow from operations by the weighted average number of common shares outstanding.

Long Run uses the term net debt in the MD&A and presents a table showing how it has been determined. This measure does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other companies.

Long Run is a Calgary-based intermediate oil company focused on light-oil development and exploration in western Canada. For further information about Long Run, visit the Company”s website at www.longrunexploration.com.

Advisories

Oil and Gas Information:

Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Forward Looking Statements:

Certain information regarding Long Run in this news release including management”s assessment of future plans and operations, 2013 capital expenditures budget and nature of expenditures, 2013 expected average production and crude oil and liquids production, nature of development capital expenditures and the effects thereof, expected timing of receipt of regulatory approval for pilot project at the Peace area and the anticipated effects of new design and completion systems at Redwater, are forward looking statements. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties including, without limitation, risks related to closing of the disposition and satisfaction of the conditions precedent thereto, the effect of the business combination and resulting operations, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration results; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list of factors and assumptions is not exhaustive. Additional information on these and other factors that could affect Long Run”s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at Long Run”s website (www.longrunexploration.com). Furthermore, the forward looking statements contained in this news release are made as at the date of this news release and Long Run does not undertake any obligation to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Contact:

Long Run Exploration Ltd.
William E. Andrew
Executive Chairman and Chief Executive Officer
(403) 261-6012
Long Run Exploration Ltd.
Dale A. Miller
President
(403) 261-6012
Long Run Exploration Ltd.
Jason Fleury
Vice President, Capital Markets
(403) 261-8302
Long Run Exploration Ltd.
Investor Relations
(888) 598-1330
information@longrunexploration.com
www.longrunexploration.com

Long Run Exploration Ltd. Announces Financial Results for the Fourth Quarter and Year Ended December 31, 2012 and 2012 Year End Reserve Results

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