INVESTOR UPDATE DECEMBER 2014 1 LONG RUN PROFILE TSX: LRE Dividend: $0.0175/ share/ month* Shares Outstanding: 193.5 million 2015 Production Guidance: 35,000 – 36,000 Boe/d (44% oil + NGLs) * Starting with January 2015 dividend payable in February 2 CORPORATE STRATEGY • Provide long-term value to shareholders through a sustainable dividend model • Focus on operational efficiency and capital discipline • Maintain balanced production mix and opportunities 3 BUSINESS PLAN • Improve our balance sheet through a focused high-grade development program and selective non-core dispositions • Execute a focused capital program that preserves our momentum going forward, both in conventional field development and enhanced oil recovery • Provide balanced yield to investors from a long-term sustainable model • Continue to develop a balanced inventory of properties which provide flexibility in future planning as well as upside from improved cost efficiencies, operating efficiencies and enhanced recovery • Proactive hedging program to mitigate commodity price downside risk 4 2015 CORPORATE GUIDANCE • Focus on execution of a sustainable business model 2015 Guidance(1) • Surplus funds flow applied to debt Production average (Boe/d) % oil and NGLs Funds flow from operations ($ million)(2)(3) 35,000 – 36,000 44% $200 -$210 Net capital expenditures ($ million)(4) $165 Dividends ($ million)(5) $40 Dividend per share (annual) $0.21 Basic payout ratio(2)(6) 20% Total 1) 2) 3) 4) 5) 6) sustainability ratio(2)(6) 100% • Target of 1,000 – 4,000 Boe/d of divestitures to improve balance sheet • Support production momentum through 2015 and into 2016 • Dividend reinvestment plan (“DRIP”) to be implemented in the first quarter of 2015 • On-going risk management program assists in protecting funds flow in low commodity price environment 2015 guidance has been updated from the preliminary 2015 guidance released in June 2014 in order to reflect the lowering of our commodity price assumptions for 2015. 2015 Guidance as released on December 15, 2014 is based on the following assumptions: WTI US$70.00/Bbl; AECO $3.50/GJ; FX USD/CDN 1.145. June 2014 preliminary guidance was based on WTI US$92.50/Bbl; AECO $4.22/Mcf; FX USD/CDN 1.1. See “Non-GAAP Measures” section. Funds flow calculations are based on average operating costs of $13.00/Boe and average general and administration costs of $2.50/Boe for 2015. Net capital expenditures are calculated as capital expenditures net of acquisitions and divestitures. No acquisitions or divestitures are currently included in our budget. Excluding impact of the DRIP. 5 Based on mid-range of funds flow guidance, excluding impact of the DRIP. ASSET BASE October 2014 Production (estimated) Peace River Area Montney oil 13,850 Boe/d (~55% Oil & NGLs) Northern Gas (Bluesky) ALBERTA Edmonton Area Peace River Area (Montney) Deep Basin Edmonton Area (Cardium) (Viking) Viking oil 8,200 Boe/d (~60% Oil & NGLs) Deep Basin Cardium liquids-rich natural gas 11,150 Boe/d (~30% Oil & NGLs) Northern Gas Shallow decline gas 2,900 Boe/d (100% Natural gas) LRE Land 6 2015 DEVELOPMENT PLAN Capital Expenditures Well Capital Capital Expenditures (by area) $ Millions $115 Plant & Facilities ≤15 wells $20 Other* $30 TOTAL $165 ≤25 wells Deep Basin Peace River Redwater Other *Includes Geology & Geophysics, land and health, safety and environment costs Peace River Montney Deep Basin Pine Creek Cardium Deep Basin Kakwa Cardium Redwater Viking IP 30 (Boe/d)(1) 190 (63% liquids) 334 (58% liquids) 413 (20% liquids) 72 (90% liquids) IP 365 (Boe/d) (1) 105 (63% liquids) 175 (40% liquids) 265 (20% liquids) 35 (90% liquids) $2.1 $3.0 $3.4 $1.2 12-month capital efficiency (Boe/d) $20,000 $17,200 $12,800 $34,300 Estimated ultimate recovery (MBoe) 190 (63% liquids) 225 (33% liquids) 365 (20% liquids) 40 (90% liquids) On-stream cost ($MM)(2) (1) Estimated initial well rates are based on internal type curve forecasts (2) Estimated on-stream costs are based on internal historical averages 7 ENHANCED OIL RECOVERY (EOR) Waterflood Current Waterflood Pilots • Major oil projects under waterflood Area Formation Pilot Start Date Expansion Start Date # of Injectors Normandville Montney May 1, 2013 December 4, 2014 9 This initial phase of EOR covers five sections Girouxville Montney October 24, 2013 January 2015 4 This initial phase of EOR covers 1.5 sections Redwater Viking December 9, 2013 December 8, 2014 5 Comments Expansion consists of a second pilot in the southern portion of the Redwater field • Cost effective reserve additions • Increases recovery • Lowers finding & development costs • Uses existing land base • Moderates production declines • Stabilizes production rates • Source of free funds flow 8 PEACE RIVER MONTNEY Normandville/Girouxville Normandville Normandville Oil Battery • 5,000 bopd • 15 mmcf/d Donnelly Gas Plant • Montney horizontal oil development • 950m vertical depth • October estimated production of 11,100 Boe/d (60% oil and NGLs) • Medium gravity oil (28o API) • Key infrastructure in place • Recent oil gathering system expansion at Girouxville oil battery & gas handling expansion at Donnelly gas plant • EOR commenced • 35 mmcf/d Girouxville Oil Battery • 5,000 bopd • 15 mmcf/d Girouxville Montney Shoreface LRE Land LRE Wells 9 DEEP BASIN CARDIUM Pine Creek/Edson Pine Creek 13-09 LRE Battery/Compressor Station • 6,500 boe/d 13-19 LRE Multiwell Oil Battery • 1,200 bbl/d • 10.5 mmcf/d (100%) • Cardium horizontal light oil development • 1,800m - 1,900m vertical depth • Bluesky horizontal liquids-rich natural gas development • 2,400m vertical depth • October estimated production of 7,200 Boe/d (30% oil and NGLs) • Significant infrastructure in place 16-14 LRE Compressor Station • 20 mmcf/d (100%) 01-13 LRE Gas Plant • 30 mmcf/d (97%) Talisman Gas Plant • 400 mmcf/d (2.7% LRE WI) Edson LRE Land LRE Wells 10 DEEP BASIN Kakwa/Wapiti • Cardium horizontal liquids-rich natural gas • 1,000m - 1,600m vertical depth • October estimated production of 3,950 Boe/d (30% liquids) • Liquids or NGL content of 40-50 Bbl/Mmcf • First two-well pad at Kakwa currently undergoing completions, with the second two-well pad expected to be completed in early 2015 Wapiti Kakwa LRE Land LRE Wells 11 REDWATER VIKING 07-21 Redwater North Oil Battery • 5,000 bbls/d • 4.0 mmcf/d T59 Redwater 05-17 Redwater North Compressor Station • 4.5 mmcf/d T57 06-11 Eastgate Gas Plant • 1.0 mmcf/d • Viking horizontal oil development • 700m vertical depth • October estimated production of 4,700 Boe/d (85% liquids) • Light oil (38o API) • Key infrastructure in place • EOR commenced 05-04 Redwater Central Oil Battery • 3,000 bbls/d • 1.0 mmcf/d 03-31 Redwater Central Oil Battery • 2,000 bbls/d • 1.0 mmcf/d 15-07 Bruderheim North Oil Battery • 2,000 bbls/d • 500 mcf/d R24 R22 Viking Shoreface R20W4 LRE Land 15-24 Bruderheim South Oil Battery • 3,000 bbls/d • 2.0 mmcf/d 12 BOYER • Bluesky natural gas • 200m - 500m vertical depth • October estimated production of 2,900 Boe/d (100% natural gas) • Shallow decline (8%/year) • 690,000 net acres • Current drilling density less than 1.5 wells per section under vertical development. Potential exists for horizontal development • 70 MMcf/d of additional operated processing capacity available LRE Land LRE Wells 13 Natural Gas Crude Oil RISK MANAGEMENT Costless Collars Volume Pricing October 1, 2014 – December 31, 2014 2,000 Bbl/day WTI US $88.00 - $92.50/Bbl October 1, 2014 – December 31, 2014 2,000 Bbl/day WTI US $88.00 - $92.60/Bbl October 1, 2014 – December 31, 2014 1,650 Bbl/day WTI US $95.00 - $98.80/Bbl January 1, 2015 – December 31, 2015 2,500 Bbl/day WTI US $95.00 - $97.50/ Bbl Fixed Price Volume Pricing October 1, 2014 – December 31, 2014 500 Bbl/day WTI CAD $100.80 October 1, 2014 – April 30, 2015 1,000 Bbl/d WTI US $85.00/Bbl October 1, 2014 – April 30, 2015 1,000 Bbl/d WTI US $90.00/Bbl Calls Volume Pricing October 1, 2014 – December 31, 2014 500 Bbl/d WTI US $85.00/Bbl October 1, 2014 – December 31, 2014 500 Bbl/d WTI US $100.00/Bbl January 1, 2015 – December 31, 2015 500 Bbl/d WTI US $85.00/Bbl Costless Collars Volume Pricing October 1, 2014 – December 31, 2014 19,000 GJ/day CDN $3.50-$4.02/GJ October 1, 2014 – March 31, 2015 13,000 GJ/day CDN $3.50-$3.75/GJ October 1, 2014 – December 31, 2014 10,000 GJ/day CDN $3.50-$3.90/GJ October 1, 2014 – December 31, 2015 5,000 GJ/day CDN $4.00-$4.50/GJ October 1, 2014 – December 31, 2015 5,000 GJ/day CDN $4.00-$4.51/GJ January 1, 2015 – December 31, 2015 20,000 GJ/day CDN $3.50-$4.00/GJ January 1, 2015 – December 31, 2015 11,000 GJ/day CDN $3.50-$4.35/GJ Fixed Price Volume Pricing October 1, 2014 – October 31, 2014 5,000 GJ/day $3.505/GJ October 1, 2014 – October 31, 2014 5,000 GJ/day $3.65/GJ October 1, 2014 – October 31, 2014 10,000 GJ/day $3.745/GJ • Financial hedges mitigate risk associated with commodity price volatility • Improves predictability of funds flow • Current oil production hedging: • ~75% hedged for Q4 2014 • ~50% hedged for Q1 2015 • ~40% hedged for full year 2015 • Current natural gas production hedging : • ~55% hedged for Q4 2014 • ~45% hedged Q1 2015 • ~40% hedged for full year 2015 14 2014 CORPORATE GUIDANCE 2014 Updated Guidance (at November 5, 2014)(1)(2) Production average (Boe/d) Guidance includes estimated results from the Deep Basin acquisition assets for 7 months and the Crocotta acquisition assets for 5 months • 2014 updated guidance assumes Q4 2014 pricing of WTI US $85.00/Bbl; AECO $4.00/Mcf; FX USD:CDN 1.1 31,400 % oil and NGLs 49% Funds flow from operations(1) ($ million) $300 Development capital ($ million) $285 Net capital expenditures(2) ($ million) $259 Dividends ($ million) $66 1) 2) • See “Non-GAAP Measures” section. Capital expenditures (development capital) net of acquisitions and divestitures, excluding the Deep Basin and Crocotta acquisitions. Net acquisitions and divestitures are as at September 30, 2014. 15 TAX POOLS Maximum Annual Deduction $ Millions Capital Cost Allowance (UCC) Up to 25% $370 Canadian Oil & Gas Property Expense (COGPE) Up to 10% $440 Canadian Development Expense (CDE) Up to 30% $630 Up to 100% $150 Deducted against taxable income $250 Tax Pools Canadian Exploration Expense (CEE) Non-Capital Loss Carry Forward Estimated Total Corporate Tax Pools (at September 30, 2014) $1,840 16 CORPORATE INFORMATION TSX:LRE Contacts Bill Andrew Chair & CEO (403) 261-6012 Dale Miller President & COO (403) 261-6012 Corine Bushfield Senior Vice President & CFO (403) 261-6012 Dale Orton Senior Vice President, Development (403) 261-6012 Lauren Kimak Investor Relations (403) 716-3222 1-888-598-1330 Main: Toll-Free Investor Line: Email: Web: 403-261-6012 1-888-598-1330 [email protected] www.longrunexploration.com 17 ADVISORIES Forward Looking Statements: This document contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of Long Run's anticipated future operations, management focus, objectives, corporate strategies and business plan, financial, operating and production results and opportunities including expected effects of recent acquisitions and financings; October 2014 estimated production for each of the Company's core property areas; 2014 updated guidance including average production, commodity mix, funds flow from operations, development capital, net capital expenditures and total dividends; 2015 guidance including average production, commodity mix, funds flow from operations, total dividends and total dividends per share, basic payout ratio and total sustainability ratio; the Company's plans to reduce debt with additional funds flow; the Company's plans to divest up to 4,000 Boe/d; the Company's plans to institute a dividend reinvestment plan and the timing thereof; estimated ultimate recoveries; anticipated initial production rates; type curve performance; expected base decline rates; timing of the commencement of various enhanced oil recovery operations and the anticipated impact on operations; and the availability of tax pools to be used against income generated by the Company. Forward-looking information typically uses words such as "anticipate", "believe", "project", "expect", "goal", "plan", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future. The forward-looking information is based on certain key expectations and assumptions made by Long Run's management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve and resource volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labor and services; the impact of increasing competition; ability to market oil and natural gas successfully; and Long Run's ability to access capital. Although the Company believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Long Run can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that the Company will derive there from. Readers are cautioned that the foregoing lists of risks and factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Management has included the above summary of assumptions and risks related to forward-looking information provided in this corporate presentation in order to provide shareholders and potential investors with a more complete perspective on Long Run's future operations and such information may not be appropriate for other purposes. These forward-looking statements are made as of the date of this document and Long Run disclaims any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. 18 ADVISORIES Included herein are estimates of Long Run's 2015 funds flow from operations, total dividends and total dividends per share, basic payout ratio and total sustainability ratio based on assumptions provided herein and other assumptions utilized in arriving at Long Run's capital budget. Also included herein are estimates of Long Run's 2014 funds flow from operations and total dividends. To the extent such estimates constitute a financial outlook, they were approved by management on December 15, 2014 and are included herein to provide readers with an understanding of the effects of the anticipated funds available to Long Run to fund its capital expenditures, dividends and the effects thereof and readers are cautioned that the information may not be appropriate for other purposes. Statements relating to "reserves" are also 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 that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein. BOE: "Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl 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 the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 Bbl, utilizing a conversion ratio at 6 mcf: 1 Bbl may be misleading as an indication of value. Initial Production Rates and Type Curves: Initial production rates disclosed herein may not necessarily be indicative of long-term performance or ultimate recovery. Type curves presented herein are not necessarily reflective of the performance of future wells. Non-GAAP Measures: This document contains terms commonly used in the oil and gas industry, such as funds flow from operations, basic payout ratio and total sustainability ratio. 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. These measures are commonly used in the oil and gas industry and by Long Run to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Long Run's determination of these measures may not be comparable to that reported by other companies. Funds flow from operations is calculated as cash flow from operating activities before changes in noncash working capital and abandonment expenditures. Basic payout ratio is calculated by dividing dividends by funds flow from operations. Total sustainability ratio is defined as net capital expenditures plus dividends divided by funds flow from operations. Long Run has provided information on how these measures are calculated in the Management’s Discussion and Analysis for the three and nine months ended September 30, 2014 dated November 5, 2014, which is available under the Company’s SEDAR profile at www.sedar.com. 19