News Column

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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CALGARY, ALBERTA -- (Marketwire) -- 03/07/13 -- LONG RUN EXPLORATION LTD. (TSX: LRE) ("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%OperationsDaily 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 585,826Additions 210,410Guide Arrangement 505,802Disposals (110,525)Decommissioning liability additions 28,392Capitalized share-based and deferred compensation 839Derecognition expense (784)Non-monetary transactions 6,373Depletion 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 23Geological and geophysical 3,612 2 4,543 3Drilling and completion 149,293 71 102,344 57Plant and facilities 43,160 21 31,292 17Inventory (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 67,355,377Non-Voting Convertible Shares 15,512,858 15,613,564Options 8,042,000 4,849,135Warrants 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 ------------------------------------------------ Gross Net Gross Net Gross NetRESERVES CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf)----------------------------------------------------------------------------Proved Developed Producing 7,667 6,571 829 713 132,183 119,131 Non-Producing 233 205 159 130 16,103 13,697Proved Undeveloped 8,942 7,965 553 469 42,908 38,823 ------------------------------------------------Total Proved 16,842 14,741 1,540 1,312 191,194 171,651Probable 11,719 9,856 1,254 1,061 90,234 79,641 ------------------------------------------------Total Proved plus Probable 28,561 24,597 2,794 2,373 281,428 251,291 ------------------------------------------------ ------------------------------------------------ RESERVES -------------------------------- NATURAL GAS LIQUIDS TOTAL -------------------------------- Gross Net Gross NetRESERVES CATEGORY (Mbbl) (Mbbl) (MBOE) (MBOE)------------------------------------------------------------Proved Developed Producing 2,421 1,566 32,947 28,705 Non-Producing 293 184 3,368 2,802Proved Undeveloped 695 504 17,342 15,408 --------------------------------Total Proved 3,409 2,254 53,657 46,915Probable 1,497 1,003 29,508 25,193 --------------------------------Total Proved plus Probable 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 --------------------------------------- Edmonton Oil Hardisty Natural Gas Price Heavy Alberta Spot WTI Cushing 40 degrees 12 degrees Gas Oklahoma API APIPrice($Cdn/McYear ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) f)----------------------------------------------------------------------------Forecast2013 90.71 85.68 62.75 3.352014 91.64 90.61 67.58 3.802015 92.30 91.60 68.62 4.182016 96.17 95.48 72.15 4.712017 97.29 96.59 72.98 5.122018 98.44 97.71 73.81 5.362019 99.94 99.21 74.95 5.452020 101.76 101.03 76.33 5.572021 103.61 102.88 77.74 5.672022 105.54 104.81 79.22 5.772023 107.46 106.69 80.64 5.872024 109.43 108.65 82.11 5.992025+ Escalated oil, gas and product prices at 1.83% per year thereafter Butanes Pentanes Plus Price Inflation Exchange Edmonton Edmonton Rates(1) Rate(2)Year ($Cdn/Bbl) ($Cdn/Bbl) %/Year ($US/$Cdn)----------------------------------------------------------------------------Forecast2013 94.89 64.19 1.83 1.002014 96.57 69.01 1.83 1.002015 95.97 70.91 1.83 1.002016 100.08 73.88 1.83 1.002017 101.22 74.74 1.83 1.002018 102.41 75.60 1.83 1.002019 104.00 76.76 1.83 1.002020 105.88 78.17 1.83 1.002021 107.82 79.60 1.83 1.002022 109.85 81.11 1.83 1.002023 111.82 82.57 1.83 1.002024 113.85 84.10 1.83 1.002025+ 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) -------------------------------------------------- 0 5 10 15 20RESERVES CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$)----------------------------------------------------------------------------Proved Developed Producing 773,203 639,904 552,564 490,061 442,829 Non-Producing 59,791 44,491 35,243 29,077 24,677Proved Undeveloped 308,144 212,822 151,919 109,868 79,236 --------------------------------------------------Total Proved 1,141,138 897,217 739,726 629,007 546,742Probable 789,387 526,439 379,381 287,140 224,942 --------------------------------------------------Total Proved plus Probable 1,930,525 1,423,656 1,119,107 916,147 771,684 -------------------------------------------------- -------------------------------------------------- AFTER INCOME TAXES DISCOUNTED AT (%/year) -------------------------------------------------- 0 5 10 15 20RESERVES CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$)----------------------------------------------------------------------------Proved Developed Producing 773,203 639,904 552,564 490,061 442,829 Non-Producing 59,791 44,491 35,243 29,077 24,677Proved Undeveloped 308,144 212,822 151,919 109,868 79,236 --------------------------------------------------Total Proved 1,141,138 897,217 739,726 629,007 546,742Probable 628,527 426,660 312,662 240,210 190,672 --------------------------------------------------Total Proved plus Probable 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) Sproule / Dec $ 739.7 $ 1,119.1 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) Sproule / Dec $ 897.2 $ 1,423.7 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 --------------------------------------- Gross Proved Gross Plus Gross Proved Probable ProbableFACTORS (Mbbl) (Mbbl) (Mbbl)----------------------------------------------------------------------------December 31, 2011 12,678 8,301 20,979Extensions 232 1,177 1,409Infill Drilling 1,081 521 1,602Technical Revisions (192) (2,301) (2,493)Discoveries 0 0 0Acquisitions 9,283 7,095 16,379Dispositions (3,623) (3,139) (6,762)Economic Factors (166) 65 (101)Production (2,453) 0 (2,453) ---------------------------------------December 31, 2012 16,842 11,719 28,561 --------------------------------------- --------------------------------------- HEAVY OIL --------------------------------------- Gross Proved Gross Plus Gross Proved Probable ProbableFACTORS (Mbbl) (Mbbl) (Mbbl)----------------------------------------------------------------------------December 31, 2011 741 397 1,138Extensions 15 44 59Infill Drilling 69 12 81Technical Revisions (69) (100) (169)Discoveries 0 0 0Acquisitions 1,213 986 2,199Dispositions (14) (50) (64)Economic Factors (99) (35) (134)Production (317) 0 (317) ---------------------------------------December 31, 2012 1,540 1,254 2,794 --------------------------------------- --------------------------------------- NATURAL GAS LIQUIDS NATURAL GAS ------------------------------------------------------------ Gross Gross Proved Proved Gross Gross Plus Gross Gross Plus Proved Probable Probable Proved Probable ProbableFACTORS (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf)----------------------------------------------------------------------------December 31, 2011 4,824 1,604 6,428 63,934 24,496 88,430Extensions 1 3 3 150 753 903Infill Drilling 3 1 4 770 336 1,106Technical Revisions (1,811) (601) (2,413) (16,269) (8,515) (24,784)Discoveries 0 0 0 0 0 0Acquisitions 846 528 1,373 155,665 74,615 230,280Dispositions (32) (20) (52) (1,635) (1,175) (2,810)Economic Factors (52) (17) (69) (1,329) (276) (1,605)Production (369) 0 (369) (10,092) 0 (10,092) ------------------------------------------------------------December 31, 2012 3,409 1,497 4,906 191,194 90,234 281,428 ------------------------------------------------------------ ------------------------------------------------------------ TOTAL ------------------------------ Gross Proved Gross Gross Plus Proved Probable Probable FACTORS (MBOE) (MBOE) (MBOE) ---------------------------------------------- December 31, 2011 28,899 14,385 43,283 Extensions 273 1,349 1,622 Infill Drilling 1,281 590 1,871 Technical Revisions (4,783) (4,422) (9,205) Discoveries 0 0 0 Acquisitions 37,286 21,045 58,331 Dispositions (3,942) (3,405) (7,347) Economic Factors (538) (34) (571) Production (4,820) 0 (4,820) ------------------------------ December 31, 2012 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 Proved P+P Proved P+P----------------------------------------------------------------------------Capital Expenditures ($M) Exploration and development expenditures (2) $ 99,131 $ 99,131 $ 138,854 $ 138,854 Change in future development capital ("FDC") $ (62,096) $ (46,541) $ 140,282 $ 160,148 All in exploration and development capital $ 37,035 $ 52,590 $ 279,136 $ 299,002 Acquisition (net of disposition)(3) $ 449,839 $ 488,428 $ 383,519 $ 383,519 Total Capital $ 486,874 $ 541,018 $ 662,656 $ 682,522----------------------------------------------------------------------------Reserve Additions Development (3,767) (6,283) 5,346 6,699 Acquisitions (net of dispositions) 33,344 50,984 17,488 24,465 Total Additions (including revisions) 29,578 44,702 22,834 31,164----------------------------------------------------------------------------Finding and Development Costs (F&D - $/boe) F&D with change in FDC (4)(5) (1) (1) $ 52.22 $ 44.63Finding, development and acquisition costs FD&A with change in FDC (4)(5) $ 16.46 $ 12.10 $ 29.02 $ 21.90------------------------------------------------------------------------------------------------------------------------------ 3-Year Avg./Total Proved P+P--------------------------------------------------Capital Expenditures ($M) Exploration and development expenditures (2) $ 309,944 $ 309,944 Change in future development capital ("FDC") $ 140,142 $ 205,286 All in exploration and development capital $ 450,086 $ 515,230 Acquisition (net of disposition)(3) $ 836,580 $ 875,169 Total Capital $ 1,286,667 $ 1,390,399--------------------------------------------------Reserve Additions Development 5,118 5,717 Acquisitions (net of dispositions) 51,032 75,465 Total Additions (including revisions) 56,150 81,183--------------------------------------------------Finding and Development Costs (F&D - $/boe) F&D with change in FDC (4)(5) $ 87.95 $ 90.12Finding, development and acquisition costs FD&A with change in FDC (4)(5) $ 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.



Contacts:
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
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