EAGLE ENERGY™ TRUSTInvestor Presentation | May 2015

TSX: EGL.UNEXPERTISE • QUALITY • INCOME

“Eagle is created to provide investors with a sustainable business while deliveringstable production and overall growth through accretive investments and acquisitions.”

Expertise

Quality

Income

Eagle’s trusted management team brings an average of 25 years of experience to the oil and gas sector.

Eagle owns stable petroleum producing assets in Canada and the U.S.

Eagle strives to deliver predictable monthlydistributions to unitholders.

Strategy

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Current Estimated Production 3,000 boe/d

Production Guidance 2,950 - 3,150 boe/d

Production Split 97% light oil

2015 Ending Debt to Trailing Cashflow 1.3 times(1)

2015 Corporate Payout Ratio 94%

Annualized Distribution(2) $0.36 per unit

US Tax Pools $US 180 million

CDN Tax Pools $CA 100 million

Corporate Profile

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Ticker

Units Outstanding (basic) 35.0 million

52 Week Range $1.57 - $6.84

Recent price $3.14(1)

Average daily trading volume (30 day) 50,949 units

Market Cap $110 million

Directors’ & Officers’ Ownership 2.9% basic, 10.6% fully diluted(2)

Equity Research Acumen Capital ResearchScotiabank

EGL.UN

Market Data

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Strong balance sheet despite a low commodity price cycle• Debt to trailing cash flow at 1.3 x(1)

• $60 million of credit available on the Trust's renewed facility and only 35%drawn on the facility at quarter end

• Strong hedging position held quarter over quarter cash flow to a decrease of25%, despite a 48% drop in realized field prices over the same period

• Maintained distributions of $0.03 per month ($0.36 per annum) for a 2015conservative corporate payout ratio projected at 94%(1)

Solid operating performance• Oil accounted for 97% of Q1 production, with reported average working

interest sales volumes of 2,995 barrels of oil equivalent per day ("boe/d")• Production on track to meet 2015 full year guidance of 2,950 to 3,150 boe/d• Reported funds flow from operations of $7.8 million ($28.67/boe) ($0.22/unit)

Highlights for the Three Months Ended March 31, 2015

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Rebalanced asset portfolio improving sustainability• August 2014 Sold Permian property in Texas for $150 million at peak of the market• December 2014 Acquired Dixonville property in Alberta for $100 million after commodity price collapse• Net result Reduced debt, increased production, reduced payout ratio, increased free cash flow

Excellent year over year reserve performance

+88% Strong increase in proved developed producing (PDP) reserves

+29% Increase in net present value of PDP reserves (discounted at 10%)

+4% Increase in total proved reserves volumes despite a decline in year over year benchmark oil prices

145% Stability reflected in total proved reserves replacement ratio

265% Total proved plus probable reserves replacement ratio

Highlights for Year Ended December 31, 2014

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Sold Permian Property(1) Bought DixonvilleProperty(2) Benefit to Eagle

Sale / Purchase Price $US 140 MM $CA 100 MM + $CA 50 MM

Working Interest Production 1,000 boe/d (2014) 1,250 boe/d

(2015) + 250 boe/pd p.a.

Free cashflow(3) $US 4 MM $CA 10.6 MM + $CA 6.6 MM

Permian for Dixonville – Our Vision In Action

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Strong Balance Sheet

Stable Production

Capital Discipline

Sustainable Distributions with Growth

Potential

Exercising Fiscal Prudence and Discipline in a Low Commodity Price Market

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• Eagle owns stable, oil producing properties with developmentand exploitation potential located in Canada (NW Alberta) and inthe US (Texas and Oklahoma).

• Dixonville Properties, AB:• Located 50 kms northwest of Peace River• 110 gross (55 net) producing oil wells• 80 gross (40 net) water injectors• Approx. 18,000 acres

• Salt Flat Properties, TX:• Located in Salt Flat field in Caldwell County, TX• 56 gross (42 net) producing wells• 19 gross (13 net) non producing wells• 3,300 (2,700 net) acres

• Hardeman Properties, TX & OK:• Located in Hardeman Basin in Hardeman County, TX, and Greer,

Harmon and Jackson Counties, OK• 47 gross (37 net) producing wells• 14 gross (13 net) non-producing• Approx. 79,000 acres

Where We Operate

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• 50% non-operated working interest in a horizontal oil waterflood in the Montney “C” Formation operated by Spyglass Resources Corp.

• 1,250 boe/d working interest to Eagle (99% oil)• Primary development started in 2004 with full scale waterflood by 2012• 190 horizontal wells (110 producers, 80 injectors)• 30◦API Oil, 18 mD permeability and 16-26% average porosity• Approx. 18,000 acres• 147 million barrels Discovered Oil Initially-in-Place,(1) recovery factor to date is 6%

50 km from Peace River

CDN Properties – Dixonville (Alberta)

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Source: IHS public data

A premier waterflood in Western Canada • Low decline, high netbacks• Low abandonment liabilities due to long

life asset

Long-term potential• Decline rate below 10%• Reserve life index

• Total Proved - 15 years • Total Proved Plus Probable - 22

years

Refurbished, optimized gathering system• Pipeline remediation program, including

poly liner installation in emulsion gathering system

Low maintenance and capital costs• Maintenance capital below $1 million

per year to Eagle• Operating costs of $16 to $18/boe• Free cash flow over $10 million

CDN Properties – Dixonville (Alberta)

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Light oil producing

• 35oAPI oil from the Edwards limestone formation, located in the Salt Flat field in Caldwell County, South Central Texas

• Acquired an 80% working interest in 2010

Low cost development technology • Eagle is redeveloping the pool using low

cost horizontal well drilling technology to capture additional oil:

• Eagle has drilled over 55 horizontal wells

• Completed numerous successful production enhancement and operating cost reduction projects

• Shot a comprehensive 3D seismic program in 2014

Additional location opportunity

• Eagle continues to identify additional locations and optimizations to capture additional recovery

US Properties – Salt Flat (Texas)

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Light oil producing• 45oAPI oil from the Chappel and Atoka

Conglomerate formations located in Hardeman County, Texas and Greer, Harmon and Jackson Counties, Oklahoma

79,000 gross acres of land • ~50 producing wells, gathering

systems and associated assets

Low risk, low cost, high opportunity • Eagle will drill low risk development

wells and deploy capital to reduce operating costs, while processing newly acquired seismic data to define future drilling opportunities

Seismic Time Map of the Top of the Mississippi showing the recently drilledWells-Nichols #4 well

US Properties – Hardeman (Texas & Oklahoma)

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• Total proved plus probable reserves of approximately 16 million boe (71% proved, 61% provedproducing)(1)

• PV10 value on total proved reserves of approximately $216 million or $5.10/unit(1)

• Proved reserve life index of 14 years based on the mid-point of 2015 average working interestproduction guidance

61%

2%

8%

29%

Reserves by Category (Mboe)

PDP PDNP PUD Probable

$180

$11

$24

$62

PV10 Value ($ MM)

PDP PDNP PUD Probable

WTI CrudeOil

Year $US/bbl____________________________2015 $65.002016 $75.002017 $80.002018 $84.902019 $89.302020 $93.80

McDaniel & AssociatesPrice forecast

(as of Jan 1, 2015)

2014 Year-End Reserves

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• Eagle’s 2015 capital budget is $13.7 million:

Texas and Oklahoma ($US 9.9 MM)• Salt Flat Property

• 3 (3.0 net) horizontal oil wells

• Seismic processing, horizontal pump installations

• Hardeman Property

• 3 (3.0 net) vertical wells

• 1 (1.0 net) salt water disposal well

• Seismic and facilities capital

Alberta ($1.4 MM)• Dixonville Property

• Maintenance capital on waterflood

• Gathering system completion

2015 Guidance and Capital Budget

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2015 Guidance

Capital Budget $13.7 mm

Working Interest Production 2,950 to 3,150 boe/d

Operating Costs per Month(1) $1.8 to $2.0 mm

Funds Flow from Operations(2) $28.1 mm

Field Netback (excluding hedges) $26.41/boe

2015 Guidance

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2015 GuidancePayout Ratios

Basic Payout Ratio(1) 45%

Plus: Capital Expenditures 49%

Equals: Corporate Payout Ratio(2) 94%

Financial Strength

Debt to Trailing Cash Flow(3) 1.3x

• Eagle’s conservative payout ratio is designed to support the Trust’s sustainability

2015 Guidance & Sustainability

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Sensitivities to Commodity Price

2015 Average WTI

(Production 3,050 boe/d)

$US 50 (FX 1.30) $US 60 (FX 1.25) $US 70 (FX 1.20)

Cash Flow $25.6 $28.1 $30.3

Corporate Payout Ratio 105% 94% 86%

Debt to Trailing Cash Flow 1.5x 1.3x 1.1x

Sensitivities to Production

2015 Average Production (boe/d)

(WTI $US 60, F/X 1.25)

2,950 3,050 3,150

Cash Flow $27.3 $28.1 $29.0

Corporate Payout Ratio 97% 94% 91%

Debt to Trailing Cash Flow 1.3x 1.3x 1.2x

• For 2015, Eagle is within its comfort zone for payout ratio and debt levels over a wide range of commodity prices

2015 Sensitivities

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• Eagle has price protection on more than 50% of its production through to June2015. The mark-to-market value of Eagle’s hedges as of March 31, 2015 is$CAD 12.0 MM.

Q1 Avg price= $US 90.72 Q2 Avg price = $US 90.72 Q3 Avg Price = $US 69.95 Q4 Avg Price = $US 74.98

2016 Average Price = $US 65 WTI

Hedging Program

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• Current working interest production of approximately 3,000 boe/d

Q1/11 Q2/11 Q3/11 Q4/11 Q1/12 Q2/12 Q3/12 Q4/12 Q1/13 Q2/13 Q3/13 Q4/13 Q1/14 Q2/14 Q3/14 Q4/14 Q1/15

2015Forecast

(mid-point)

Production 1,269 1,214 995 2,023 2,169 2,400 2,825 2,986 2,928 3,022 3,052 2,994 3,010 3,341 2,859 1,929 2,995 3,050

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Production History

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Richard Clark, B.A. (Econ), LLB, Director, President and Chief Executive Officer• 19 years in the legal profession as a founding partner at a boutique oil and

gas law firm, then 10 years at a Canadian national law firm, specializing incorporate finance, securities, M&A and venture capital

• Extensive experience in the royalty trust sector

Wayne Wisniewski, P.E., MBA, Chief Operating Officer (Houston)• 30 years of oil and gas engineering and operations experience• Last 13 years of career spent in a senior operations and engineering

management role in the Houston office of a major international E&Pcompany

Kelly Tomyn, CA, Chief Financial Officer• Former VP Finance and CFO for numerous public & private companies

with over 25 years of financial experience with E&P companies• Former controller for Shiningbank

Continued..

Management

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Continued…

Scott Lovett, M.Sc., MBA, P.Eng, Vice President, Corporate & BusinessDevelopment

• Over 18 years experience in the oil and gas industry, includingreservoir evaluations, acquisitions and divestments, businessplanning and strategic analysis

Eric McFadden, Vice President, Capital Markets & Business Development• Over 25 years of experience in the corporate finance, capital

markets, management and business development industries,including eleven years in the energy industry

Jo-Anne Bund, B.A., LLB, General Counsel and Corporate Secretary• 19 years of experience in corporate finance, securities, and M&A,

including with a national law firm, with a securities regulator and ascorporate counsel

Management

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David Fitzpatrick, P.Eng., Chairman• Former Chief Executive Officer of Shiningbank

Bruce Gibson, CA, Chair of Audit Committee• Former Chief Financial Officer of Shiningbank

Warren Steckley, P.Eng., Chair of Reserves and Governance Committee• Former President and Chief Operating Officer, Barnwell of Canada,

Former Director of Shiningbank

Joseph Blandford, P.Eng., Chair of Compensation Committee• Retired Oilman, Resides in Houston, TX

Richard Clark, B.A. (Econ), LLB, Director• President and Chief Executive Officer of Eagle; Former Director of

Shiningbank

Board of Directors

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APPENDIX

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• Eagle’s production in Texas and Oklahoma has realized a premium sales price• Eagle believes that Canadian pricing differentials, which have been high and volatile over the past few

years but have recently narrowed, will continue to narrow over the coming years as the expansion ofliquefied natural gas, rail and pipeline infrastructure enhances Canada’s access to non-U.S. markets

30.00

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80.00

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110.00

Mar-12 Jun-12 Sep-12 Dec-12 Mar-13 Jun-13 Sep-13 Dec-13 Mar-14 Jun-14 Sep-14 Dec-14 Mar-15

WTI (NYMEX) - Cushing ($US/bbl) CDN Light Sweet ($CDN/bbl) WCS ($CDN/bbl)

Crude Oil Price Comparison

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Eagle’s trusted management team brings an average of 25 years of experience to the oil and gas sector.

Eagle owns stable petroleum producing assets in Canada and the U.S.

Eagle strives to deliver predictable monthlydistributions to unitholders.

FootnotesSlide 3: (1) Based on forecast of $US 60.00 WTI and foreign exchange rate of $US 1.00 equals to $CA 1.25.

(2) Unlike fixed income securities, the Trust has no obligation to distribute any fixed amount, and reductions in, or suspension of, cashdistributions may occur which would reduce future yield.

Slide 4: (1) TSX closing price on May 4, 2015.(2) Average exercise price of options at March 31, 2015 = $5.70.

Slide 5: (1) Using a foreign exchange rate of $US 1.00 equal to $CA 1.25.

Slide 7: (1) Based on January to June 2014 annualized field netback.(2) Based on estimated 2015 field netback at $US 60.00 WTI.(3) “Free cashflow” is a non-IFRS measure defined as cashflow from the property less capital expenditures. See “Advisory regarding non-

IFRS financial measures.”

Slide 10: (1) Per McDaniel and Associates Consultants Ltd. reserves evaluator. See “Advisory regarding Oil and Gas Measures and Estimates.”

Slide 14: (1) It should not be assumed that the present values of estimated future net revenue are representative of the fair market value of thereserves. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recoveryand estimates of reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will berecovered. Actual reserves may be greater than or less than the estimates provided.

Slide 16: (1) 2015 operating cost forecast result in field netbacks (excluding hedges) of $26.41 per boe at $60.00 WTI.(2) Based on the following assumptions:

a) Average working interest production of 3,050 boe/d (the mid-point of guidance range);b) Forecast pricing at $US 60.00 per barrel WTI oil, $US 3.00 per Mcf NYMEX gas and $US 21.00 per barrel of NGL (NGL price is

calculated as 35% of the WTI price) and foreign exchange rate of $US 1.00 equal to $CA 1.25;c) WTI discount per barrel is $US 6.15 in Salt Flat, $US 2.70 in Hardeman and $CA 15.00 discount per barrel to $CA WTI in

Dixonville; andd) Average operating costs of $1.9 million per month ($US 980,000 per month for Eagle’s operations in the United States and $CA

700,000 per month for Eagle’s operations in Canada), being the mid-point of guidance range.

Slide 17: (1) Basic Payout Ratio = Unitholder distributions / Funds flow from Operations.(2) Corporate Payout Ratio = Capital Expenditures + Unitholder distributions / Funds flow from Operations.(3) As at March 31, 2015.

Slide 20: (1) Q4/14 production is after the Permian asset disposition and before the Dixonville asset acquisition.(2) 2015 estimated production includes Dixonville production.

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Advisory Regarding Forward Looking Statements:

This presentation includes statements that contain forward looking information (“forward-looking statements”) in respect of Eagle Energy Trust’s expectations regarding its future operations,including Eagle’s investment and business strategy, and forecast estimates for Eagle’s capital budget, production, drilling plans operating costs, funds flow from operations, commodity split, debtto trailing cashflow, basic and corporate payout ratios, annual distribution, tax pools, estimated field netback, free cashflow, hedging and reserves, resources and capital efficiency in 2015. Theseforward looking statements involve estimates and assumptions including those relating to timing to drill and bring wells on production, production rates, operating and capital costs, marketabilityof crude oil, natural gas and natural gas liquids, future commodity prices, future currency exchange rates, anticipated cash flow based on estimated production, size of reserves and reservoirperformance, among other things. These estimates and assumptions necessarily involve known and unknown risks, delays, challenges and other uncertainties inherent in the oil and gas industryincluding those relating to geology, production, drilling, technology, operations, human error, mechanical failures, transportation, processing problems and poor reservoir performance, amongothers things, as well as the business risks discussed in the Trust’s annual information form dated March 19, 2015 under the headings “Risk Factors” and “Advisory-Forward-Looking Statementsand Risk Factors”.

The forward-looking statements included in this presentation should not be unduly relied upon. Actual results may differ from the forward-looking information in this presentation, and thedifference may be material and adverse to the Trust and its unitholders. No assurance is given that the Trust’s expectations or assumptions will prove to be correct. Accordingly, all suchstatements are qualified in their entirety by reference to, and are accompanied by, the information and factors discussed throughout this presentation. These statements speak only as of the dateof this presentation and may not be appropriate for other purposes. Eagle’s annual information form dated March 19, 2015 contains important detailed information about Eagle and itstrust units. Copies of the annual information form may be viewed at www.sedar.com and on Eagle’s website at www.eagleenergytrust.com.

Advisory Regarding Non-IFRS financial measures:

Statements throughout this presentation make reference to the terms “funds flow from operations,” “field netbacks,” “free cash flow,” “basic payout ratio” and “corporate payout ratio,” which arenon-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers. Investorsshould be cautioned that these measures should not be construed as an alternative to earnings (loss) calculated in accordance with IFRS. Management believes that these measures provideuseful information to investors and management since they reflect the quality of production, the level of profitability, the ability to drive growth through the funding of future capital expendituresand the sustainability of distributions to unitholders.

“Funds flow from operations” is calculated before changes in non-cash working capital and abandonment expenditures. Management considers funds flow from operations to be a key measureas it demonstrates Eagle’s ability to generate the cash necessary to pay distributions, repay debt, fund decommissioning liabilities and make capital investments. Management believes that byexcluding the temporary impact of changes in non-cash operating working capital, funds flow from operations provides a useful measure of Eagle’s ability to generate cash that is not subject toshort-term movements in non-cash working capital.

“Field netback” is calculated by subtracting royalties and operating expenses from revenue.

“Free cash flow” is calculated by subtracting capital expenditures from field netbacks for the property.

“Basic payout ratio” is calculated by dividing unitholder distributions by funds flow from operations.

“Corporate payout ratio” is calculated by dividing capital expenditures plus unitholder distributions by funds flow from operations.

See the "Non-IFRS financial measures" section of the Trust's Management Discussion and Analysis for the three months ended March 31, 2015 for a reconciliation of funds flow from operationsand field netback to earnings (loss) for the period, the most directly comparable measure in the Trust's audited annual consolidated financial statements.

Advisories

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Advisories (continued)

Advisory Regarding Oil and Gas Measures and Estimates

This presentation contains disclosure expressed as barrel of oil equivalency (“boe”) or boe per day (“boe/d”). All oil and natural gas equivalency volumes have been derived using theconversion ratio of 6Mcf of natural gas: 1 bbl of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of 6 Mcf: 1 bbl is based on an energyequivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the currentprice of oil as compared to natural gas is significantly different from the energy equivalent of six to one, utilizing a boe conversion ratio of 6 Mcf: 1 bbl would be misleading as an indication ofvalue.

The estimated values of the future net reserves of the reserves disclosed in this presentation do not represent the market value of such reserves. There is no assurance that such price andcost assumptions will be attained and variances could be material. The recovery and estimates of reserves provided in this presentation are estimates only and there is no guarantee that theestimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided.

This presentation contains references to estimates of oil classified as Discovered Oil Initially-In-Place (“DOIIP”) which are not, and should not be confused with, oil reserves. DOIIP is definedin the Canadian Oil and Gas Evaluation Handbook (“COGEH”) as the quantity of oil that is estimated to be in place within a known accumulation prior to production. DOIIP is divided intorecoverable and unrecoverable portions, with the estimated future recoverable portion classified as “reserves” and “contingent resources” and the remainder classified as at the evaluationdate as “unrecoverable”. The accuracy of resource estimates is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment.The size of the resource estimate could be positively impacted, potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or thethickness of the reservoir is larger than what is currently estimated based on the interpretation of seismic and well control. The size of the resource estimate could be negatively impacted,potentially in a material amount if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimatedbased on the interpretation of the seismic and well control.

“Contingent resources” are those quantities of oil estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology underdevelopment, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal,environmental, political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with aproject in the early evaluation stage. There are no estimates of Contingent Resources included in this presentation.

Estimates of DOIIP described in this presentation are estimates only; the actual resources may be higher or lower than those calculated in the independent evaluation. There is no certaintythat it will be economically viable to produce any portion of the resources. The estimates of DOIIP have been prepared by McDaniel & Associates Consultants Ltd. in accordance with NI 51-101 and the COGEH and are effective as of January 1, 2015. The estimates of Reserves presented in this presentation have been prepared by McDaniel & Associates Consultants Ltd. forEagle’s Canadian properties and Netherland, Sewell & Associates, Inc. for Eagle’s U.S. properties, Eagle’s independent qualified reserves evaluators.

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Contact

Kelly Tomyn, CFOTel: (403) 531-1574

Richard W. Clark, President and CEOTel: (403) 531-1575

Eric McFadden, VP, Capital Markets & Business DevelopmentTel: (587) 233-1799

Eagle Energy Inc. Eagle Hydrocarbons Inc.2710, 500 – 4th Avenue SW 3005, 333 Clay StreetCalgary, AB T2P 2V6 Houston, TX 77002info@EagleEnergyTrust.comwww.eagleenergytrust.com

TSX: EGL.UN

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