Investor Update – August 2013 Here for the long run Investor Update – August 2013

$450 million credit facility long run profile Key Metrics 2013 Q2 Production Listing TSX:LRE Shares Outstanding 126 million Enterprise Value ~$800 million Liquidity (shares/day) ~400,000 2013 Q1 Production 24,431 boe/d Oil + NGLs 12,587 mbbl/d Gas 71.1 MMcf/d Average Oil Gravity 32° API Tax Pools $1.3 billion Land Holdings 1.9 million acres P+P RLI 9.1 years 52% oil 48% natural gas $450 million credit facility

Second Quarter 2013 Highlights Increased Production and Funds Flow from Operations Average production of 24,431 boe/d, 52% crude oil and liquids Q2 ‘13 Peace Area production increased 6% from Q1 ‘13 to 9,952 boe/d Q2 ’13 Redwater production increased 6% from Q1’13 to 5,444 boe/d Funds flow from Operations of $63.2 million ($0.50 per share) Resource assessment identified Discovered Petroleum Initially-in-Place of 301.2 million barrels of oil (best case) on a portion of Long Run’s Montney lands in the Peace area

average annual boe per day Production Growth Forecast 2013 Annual Average Production of 25,000 boe per day 25,000 boe per day average annual boe per day (forecast)

2013 Target Funds Flow of $230 million A Typical BOE Q2 Netback 2013 Target Funds Flow of $230 million

Business sustainability Adding Production & Reserves Development of light oil play areas through horizontal technology Ongoing development work targeting oil at Peace in the Montney and at Redwater in the Viking Multi-year inventory of locations Opportunistic Acquisitions Target rich environment Highly experienced M&A team Enhanced Recovery Current light oil assets highly amenable to EOR Strong technical team with significant experience in initiating and maintaining EOR

Business Landscape Investor Demand This junior/intermediate yield sector has been in favour with investors over the past two years, generating returns in excess of the broader energy index on a total return basis (including yield) Growing investor demand for yield product that achieve a blend of capital appreciation and income Growing yield sector in junior / intermediate energy companies as demand for yield products continues to outstrip supply Tightening of capital markets with diminished support for equity issuances from growth (non-yield) energy companies

Reserves Strong Year -Over-Year Growth 2012 Reserve Highlights Natural Gas 47 mmboe Oil & Liquids 36 mmboe 2012 Reserve Highlights P+P Net asset value of $9.60 per share P+P reserve life index of approximately 9.1 years

Capital Spending ($275 MM) 2013 Capital Budget Targeting Growth Capital Spending ($275 MM) Number of wells 132 wells

key properties Exploration and Development Focused Northern Gas Peace River Exploration Edmonton Area

Normandville/ Girouxville PEACE RIVER AREA Dominant Position in Multi-Zone Play 600,000 net acres Primary targets are Triassic age resource plays targeting oil and liquids- rich gas Current development focus area is Girouxville/ Normandville Montney oil Worsley Peace Smoky Normandville/ Girouxville

Montney Normandville / Girouxville Current production of 9,450 BOE/d (60% oil) Resource Assessment evaluated 92 sections of land in Montney fairway Have drilled 60+ wells to-date Multi-year development inventory Initial development plan average up to 6 wells/section Have started injection on initial EOR pilot 50 wells planned in 2013 Have reduced spud to rig-release time from 11 days to 9 days over last 30 wells Normandville Peace River Area Girouxville Potential water injection wells Identified Montney Oil Historical Hz well New Hz well

Total Normandville/Girouxville Montney = 123,312 Acres Resource Assessment Identifies Significant Resource In-Place For the purpose of the Resource Assessment, 48% of LRE’s Montney acreage was evaluated by third-party engineers Unevaluated Evaluated 301.2 mmbbls of oil DPIIP(1) (best) Total Normandville/Girouxville Montney = 123,312 Acres 40 mmbbls potential unbooked oil upside (2) 25 mmbbls illustrative unbooked oil - secondary(2) 15 mmbbls illustrative unbooked oil – primary(2) 13.6 mmbbls booked 1.9 mmbbls oil produced Notes: (1) Discovered oil initially in place ("DOIIP") is evaluated in an independent resource assessment (the "Resource Assessment") prepared by Sproule Associates Limited ("Sproule") effective December 31, 2012 on a portion of Long Run's lands (the "Evaluated Areas") covering the Montney formation at Normandville and Girouxville which evaluated the discovered petroleum initially in place ("DPIIP"). The DOIIP and DPIIP currently cannot be further subcategorized as it is not possible at this time to define a recovery project for this DOIIP or DPIIP. See "Advisory" section of this Presentation with respect to additional advisories on DOIIP and DPIIP. (2) Included for illustration purposes only. Primary assumes 10% recovery of best case DOIIP; secondary recovery assumes 8% recovery of best case DOIIP. While included for illustration purposes, it should be noted that while waterflood technologies have been used in what Long Run believes to be analogous pools, the effectiveness of such techniques in the Evaluated Areas covered by the Resource Assessment has not been established. There is no certainty that enhance recovery techniques and additional infill drilling which is planned, will increase recoveries. Enhanced recovery projects have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints. Long Run's policy of orderly development on a stage basis, the short and long-term view of Long Run on commodity prices, the results of exploration and development activities of Long Run and others in the area and possible infrastructure capital constraints will determine the pace of development.

Montney Existing facilities Substantial Throughput Capacity Normandville Oil Battery 5,000 bopd 15 MMcf/d Peace River Area Donnelly Gas Plant 28 MMcf/d to sales Girouxville Oil Battery 5,000 bopd 12 MMcf/d

Montney Horizontal Type Curve Economics 12-month capital efficiency of approximately $16,000/boe/d Current differentials provide average operating netback of $56.34/boe IP 30 250 boe/d IP 90 200 boe/d NPV BT @ 8% $3.5 million On-stream cost ~$2 million Payout 12 months Recycle ratio (12 month) 3.9x Estimated ultimate recovery 175 mboe Profit to investment ratio 2.75x Average working interest 98% API gravity 28 degrees IRR 137% Recent horizontal Montney oil wells using 25-stage, cemented liner completions (28 wells – Q4 2012, Q1 2013) Historical Montney oil type curve

Edmonton Core Area Cherhill & Redwater Cherhill & Redwater produce a combined 6,800 boe/d (82% oil) Primary targets are Viking / Mannville and Mississippian oil horizons Significant infrastructure in-place Land position of 80,000 net acres Edmonton Viking Shoreface

Viking - Redwater Significant Development Inventory Current production ~4,500 boe/d (90% oil) Viking oil horizontal multi-frac / multilateral play 38° API oil 40,000 net acres (62 sections) of horizontally undeveloped land Up to 32 wells per section 68 wells planned in 2013 Currently employing revised completion technique

Redwater facilities Redwater North Compressor Station 2-2.5 MMcf/d Redwater North Oil Battery 3,000 bopd 2.0 MMcf/d Bruderheim North Oil Battery 2,000 bopd 500 Mcf/d Bruderheim South Oil Battery 1,200 bopd 2.0 MMcf/d 17

Redwater Type Curve Economics IP 30 65 boe/d IP 90 50 boe/d NPV BT @ 8% $1.0 million On-stream cost $1.2 million Payout 18 months Recycle ratio (12 month) 2.1x Estimated ultimate recovery 40 mboe Profit to investment ratio 1.8x Average working interest 90% API gravity 38 degrees IRR 54% 12-month capital efficiency of approximately $29,000/boe/d Average operating netback of approximately $63.48/boe Recent horizontal Viking oil wells (41 wells – Q4 2012, Q1 2013) Historical Viking oil type curve

Business Plan Focus on operational efficiency and ingenuity Maximize ‘bang for the buck’ with targeted capital spending Maintain a reasonable balance sheet Provide growth through development of tight oil and natural gas, strategic acquisitions and enhanced oil recovery Create a strong, balanced, mid-cap oil and natural gas exploration company

Corporate Information TSX:LRE Contacts Bill Andrew Chair and CEO (403) 261-6012 Dale Miller President Jason Fleury Vice President, Capital Markets (403) 261-8302 Main: 403-261-6012 Toll-Free Investor Line: 1-888-598-1330 Email: information@longrunexploration.com Web: www.longrunexploration.com Corporate Office Long Run Exploration Ltd. Livingston Place, West Tower Suite 400, 250 – 2nd Street SW Calgary, AB T2P 0C1

Advisory Forward Looking Statements Certain information herein may constitute forward-looking statements under applicable securities laws. Forward-looking statements herein include management's go-forward business strategy, management's assessment of future plans and operations, drilling plans and the number of wells to be drilled in 2012, type curves for various plays and the performance of wells to be drilled based on such type curves, 2012/2013 capital budget and expenditures and the allocation thereof, 2012/2013 funds flow, 2012/2013 average production and production growth, anticipated commodity mix for 2012/2013. Plans to build facilities and timing thereof, estimated well and on stream costs of wells, plans to use secondary recovery methods including waterflood and infill drilling to increase recovery from Long Run’s Montney resource and pro forma information about the company. Forward-looking statements necessarily involve 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 and other risks identified in Long Run's annual information form date March 2012 and available for review under Long Run's SEDAR profile at www.sedar.com. Forward-looking statements or information are based on a number of factors and assumptions as stated herein which have been used to develop such statements and information but which may prove to be incorrect. Although Long Run 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 Corporation can give no assurance that such expectations will prove to be correct. The forward-looking statements contained herein are made as at the date hereof 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, events or otherwise, except as may be required by applicable securities laws. Included herein is an estimate of Long Run's 2013 funds flow related thereto which is based on the various assumptions as to production levels, commodity prices and exchange rates and that drilling and service costs for 2013 will be similar to the 2012 cost level and other assumptions stated herein. To the extent such estimate constitutes future oriented financial information or a financial outlook, they were approved by management of Long Run on May 22, 2012, and such future oriented financial information or financial outlook is included herein to provide readers with an understanding of Long Run's anticipated funds flow and Long Run's ability to fund its expenditures based on the assumptions described and estimated herein. Readers are cautioned that the information may not be appropriate for other purposes. Netbacks are calculated by subtracting royalties, transportation costs and operating costs from revenues. Disclosure provided herein in respect of barrels of oil equivalent (boe) 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 that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Type curves presented herein are not necessarily reflective of the performance of future wells.

Advisory Forward Looking Statements The Resource Assessment mentioned was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The following definitions from NI-51-101 and COGE Handbook are used in this presentation: “Production” means the cumulative quantity of petroleum that has been recovered at a given date. "Discovered Oil Initially in Place – DOIIP and DPIIP referred to herein is based on the Resource Assessment effective December 31, 2012 prepared by Sproule. DPIIP means the quantity of petroleum that is estimated, at a given date, to be contained in known accumulations prior to production. The recoverable portion of petroleum-initially-in-place includes cumulative production, reserves and contingent resources; the remainder is categorized as unrecoverable. The 301.2 Mmbbl (best case) DOIIP referred to in this presentation, includes 13.6 Mmbbl of proved plus probable reserves as evaluated in the independent reserve evaluation prepared by Sproule effective December 31, 2012 and 1.9 MMBBL of cumulative production to December 31, 2012. All estimates of DPIIP and DOIIP, including reserves and production, represent gross resources, meaning the company's working interest share in the resources before deducting royalties and without including any royalty interest of the company. Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. In the case of reserves, the best estimate is proved plus probable reserves. The DPIIP and DOIIP estimates include unrecoverable volumes and are not an estimate of the volume of the substance that will ultimately be recovered. For low, best and high estimates of the DPIIP and DOIPP, further definitions related thereto, positive and negative factors relating to the DPIIP and DOIIP and risk factors relating thereto, please refer to the presentation of the Corporation dated July 2, 2013. There is no certainty that it will be commercially viable to produce any portion of the resources. BOES – Disclosure provided herein in respect of barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1Bbl 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 of 6:1; utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Reserve Disclosure – The estimates for reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. Reserves are further classified according to the level of certainty associated with the estimates as follows: Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. "Unrecoverable" is that portion of DPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. All estimates of DPIIP, including reserves and production, represent gross resources, meaning the company's working interest share in the resources before deducting royalties and without including any royalty interests of the Company. DPIIP estimates were determined using probabilistic methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. Uncertainty ranges are described in the COGE Handbook as, low, best and high as for reserves and resources as follows: Low estimate is considered to be a conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources at the low end of the estimate range have the highest degree of certainty - a 90 percent confidence level - that the actual quantities recovered will equal or exceed the estimate. In the case of reserves, the low estimate is proved reserves. Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50 percent confidence level that the actual quantities recovered will equal or exceed the estimate. In the case of reserves, the best estimate is proved plus probable reserves. High estimate is considered to be an optimistic estimate of the quantity of resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those resources at the high end of the estimate range have a lower degree of certainty - a 10 percent confidence level - that the actual quantities recovered will equal or exceed the estimate. In the case of reserves, the high estimate is proved plus probable plus possible reserves. The Discovered Petroleum-Initially-In-Place estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered.