2

Disclaimer 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, drilling program, production, reserves, operating costs, capital expenditures, debt, credit facility, payout and recycle ratios, funds flow from operations, field netbacks, hedging, the amount and sustainability of distributions, tax pools, business strategy and plans for growth, among other things. These forward looking statements involve estimates and assumptions including those relating to timing to drill and bring wells on production, production rates, operating and capital costs, marketability of crude oil, natural gas and natural gas liquids, future commodity prices, currency exchange rates, anticipated cash flow based on estimated production, size of reserves and reservoir performance, among other things. These estimates and assumptions necessarily involve known and unknown risks, delays, challenges and other uncertainties inherent in the oil and gas industry including those relating to geology, production, drilling, technology, operations, human error, mechanical failures, transportation, processing problems and poor reservoir performance, among others things, as well as the business risks discussed in the Trust’s annual information form dated March 22, 2013 under the headings “Risk Factors” and “Forward-Looking Statements and 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 the difference 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. In addition, this presentation contains forward-looking statements attributed to third party industry sources. Accordingly, all such statements 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 date of this presentation and may not be appropriate for other purposes. Eagle’s annual information form dated March 22, 2013 contains important detailed information about Eagle and its trust units. Copies of the annual information form may be viewed at www.sedar.com and on Eagle’s website. Disclaimer Regarding Oil and Gas Measures:

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 the conversion ratio of 6 Mcf of natural gas: 1bbl of oil. Equivalency measures may be misleading, particularly if used in isolation. A 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. In addition, given that the value ratio based on the current price 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 of value.

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Eagle Energy Trust provides investors with a publicly traded, reliable distribution paying investment, with favourable tax treatment relative to taxable Canadian corporations.

Eagle pays out a portion of its available cash to unit holders on a

monthly basis to provide attractive income. 100% of Eagle’s production is in Texas, 88% of Eagle’s production is light oil.

Eagle presently holds a balanced portfolio across two fields: Luling

(Salt Flat) is a conventional field with well payouts of ~7 months; Midland (Permian) is a long life unconventional Permian Basin field.

Eagle’s strategy is to acquire on-shore petroleum assets in the

United States that have predictable cash flows and low risk unexploited development and exploitation potential.

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VISION

To create wealth for our investors by combining innovation, expertise and opportunity.

GROWTH

Our targeted lower payout ratio allows us to sustain growth and distribute income.

INCOME

To deliver predictable monthly distributions.

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BUSINESS STRATEGY

To acquire and optimize US based petroleum assets which have been adequately de-risked and have attractive metrics for:

• significant “post acquisition” production growth, followed by long term production sustainability

• strong returns on capital (2:1 recycle ratio), and

• sustainable cash-flows which underpin distributions.

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Current Working Interest Production: 3,000 boe/d

Production Guidance – full year 2013: 2,900 - 3,100 boe/d (average)

Production Split: 92% light oil and NGLs

Credit Facility: $US 61.0 million

Annual Distribution: $1.05 per unit

Current Yield (1)(2): 12.5%

Tax Pools: approx. $280 million

(1) Based on the closing price of $8.40 on August 14, 2013.

(2) Unlike fixed income securities, the Trust has no obligation to distribute any fixed amount, and reductions in, or

suspension of, cash distributions may occur that would reduce future yield.

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Ticker Symbol: EGL.UN

Units Outstanding (basic): 31.0 million

52 Week Range: $6.28 - $10.50

Recent price (Aug 14/13 close): $8.40

Average daily trading volume (30 day): 60,363 units

30 day VWAP: $8.00

Market Cap (Aug14/13): $260.7 million

Insider Ownership: 2.4% basic, 8.0% fully diluted

Equity Research: Scotia Acumen CIBC Haywood TD NBF PI Financial Canaccord

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First quarter 2013 average working interest sales volumes of 3,022 boe/d, a 26% increase from Q2 2012 and a 3% increase from Q1 2013.

Achieved a 40% reduction in field operating costs (excluding transportation) compared to Q2 2012, and a 13% reduction compared to Q1 2013. Total field operating costs including transportation were $10.22/boe. This significant reduction was primarily due to improved operating procedures, including reducing salt water volumes and costs, resizing submersible pumps and negotiating lower power contracts.

Q2 2013 funds flow from operations of $12.0 million, up 66% from Q2 2012 and consistent with Q1 2013.

Top-decile second quarter field netbacks were $52.20/boe. Realized oil prices were at a premium to benchmark $US West Texas Intermediate (WTI). Premium pricing negotiated by Eagle in its 2013 marketing arrangements contributed to top decile per boe field netbacks. With 100% of its production coming from Texas, Eagle has a substantial advantage over Canadian producers.

Q2 distributions held steady at $0.26 per unit or $0.0875 per unit per month.

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On April 22, 2013, Eagle acquired the remaining 7.5% interest in its Midland properties for cash consideration of approximately $US 8.6 million. The acquisition adds approximately 70 boe/d of production. The trust now owns all of the working interest in the Midland properties.

Increased the borrowing base under Eagle’s credit facility from $US 48.5 million to $US 61.0 million and syndicated the facility to include a second major Canadian chartered bank as a new lender.

In Q2 2013, Eagle drilled, tied in and brought on stream 3 (2.4 net) wells in Luling, Texas. Drilled 4 (4.0 net) wells and brought on stream 2 (2.0) net wells in Midland. With the 2013 drilling program commencing, as planned, in the second quarter, production contributions from the new drills placed on production late in the quarter during clean-up were negligible. The wells are performing to expectations.

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A 188% increase year-over-year in total proved reserves.

A 107% increase in year-over-year in proved developed producing reserves.

A $US 46.4 million increase in year-over-year in PV10 value of proved developed producing reserves.

Total proved plus probable reserves of approximately 16.6 million boe (68% proved, 29% proved producing).

Reserve life index of 14.3 years based on forecast 2013 production.

29.15%

4.95%

33.77%

32.13%

Reserves (Mboe) by Category

PDP

PDNP

PUD

Probable

$115.3

$13.3

$37.5

$98.1

PV10 Value ($US MM)

PDP

PDNP

PUD

Probable

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Notes: (1) Note that the capital budget amount excludes the $US 8.6 million cost of the Acquisition.

(2) 2013 funds flow from operations of $45.0 million has been estimated using the following assumptions:

a. Based on actual results through to June 30, 2013 and the Acquisition;

b. Full year average working interest production of 3,100 boe/d, which is at the upper end of the guidance range;

c. July– December benchmark pricing of $US 90.00 per barrel WTI oil, $US 2.90 per Mcf NYMEX gas and $US 39.60 per

barrel NGLs (NGLs price is calculated as 44% of the WTI price);

d. July - December field marketing contracts currently in place for both Midland and Luling;

e. July – December average operating costs (inclusive of transportation) of $13.00 per boe; and

f. July– December foreign exchange at $1.00 CDN/US.

Eagle maintains its guidance as previously provided

2013 Guidance Notes Capital Budget $US 26.0 mm (1) Working Interest Production 2,900 - 3,100 boe/d Operating Costs (inclusive of transportation) $12.00 - $14.00 per boe Funds Flow from Operations $45.0 mm (2)

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2013 Capital budget of $US 26.0 million (net to Eagle, down 40% year over year):

Midland area (commencing April 2013):

5 (4.6 net) vertical oil wells

1 (0.9) water source well

3 refracs

Luling area (commencing May 2013):

6 (5.0 net) horizontal oil wells

2 (1.6 net) salt water disposal well workovers

Addition to an existing battery

Land, seismic, workovers

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Notes: 1. Eagle calculates the Basic Payout Ratio as follows: Unitholder Distributions / Funds Flow from Operations = Basic Payout Ratio. A table showing

the sensitivity of Eagle’s Basic Payout Ratio to production and pricing is set out in the slide titled “2013 Sensitivities”. 2. Capital expenditures generally exclude corporate and property acquisitions because these are evaluated separately on their own merits. The $US

8.6 million Acquisition has therefore been excluded from this percentage. 3. Eagle calculates the Corporate Payout Ratio as follows: (Capital Expenditures + Unitholder Distributions) / Funds Flow from Operations = Corporate

Payout Ratio. A table showing the sensitivity of Eagle’s Corporate Payout Ratio to production and pricing is set out in the slide titled “2013 Sensitivities”.

4. Assumes 65% unitholder participation in Eagle’s Premium DRIPTM and distribution reinvestment programs is unchanged throughout 2013. As is the case with any manner of equity funding, Eagle weighs the benefits from this method of financing and will make adjustments as deemed prudent.

5. Increased due to the $US 8.6 million Acquisition being financed by bank debt. 6. The borrowing base under the credit facility is $US 61.0 million.

2013 Guidance Notes Payout Ratios (as a percentage of funds flow)

Basic Payout Ratio (i.e.: Distribution at $1.05/unit annually) 71% (1)

Plus: Capital Expenditures 57% (2)

Equals: Corporate Payout Ratio 128% (3)

Adjusted Payout Ratio (Distribution - DRIP proceeds + Capital Expenditures) 83% (4)

Financial Sterngth

Debt to trailing cashflow 0.88x (5)

% Drawn on credit facility at end of period 66% (6)

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Assumptions: 1. Annual distributions are held at current levels of $1.05

per unit per year. 2. No new equity issued other than distribution

reinvestment program. 3. Field operating costs, including transportation of

$13.00 per boe.

Sensitivity of Funds Flow to Commodity Price and Production 2013 (April-Dec) Average WTI $US 80.00 $US 90.00 $US 100.00

2013 Average WI Production (boe/d)

2,900 $40.7 $42.0 $44.1 3,100 $44.1 $45.0 $48.1 3,300 $47.4 $49.4 $52.2

Sensitivity of Corporate Payout Ratio to Commodity Price and Production 2013 (April-Dec) Average WTI $US 80.00 $US 90.00 $US 100.00

2013 Average WI Production (boe/d)

2,900 144% 140% 133% 3,100 133% 128% 122% 3,300 124% 119% 112%

Sensitivity of Basic Payout Ratio to Commodity Price and Production 2013 (April-Dec) Average WTI $US 80.00 $US 90.00 $US 100.00

2013 Average WI Production (boe/d)

2,900 79% 77% 73% 3,100 73% 71% 67% 3,300 68% 65% 62%

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Field Netback1,2

1. Field netback is a non-IFRS financial measure. Field netback is calculated by subtracting royalties, operating costs and transportation costs from revenues. 2. For the three months ended June 30, 2013. Excludes impact of hedging. Canadian dollars. Natural gas converted on a 6:1 basis.

$52.20

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16

Recycle Ratio1,2

1. Sourced from publicly available company disclosure; where AIF not provided, based on press release. 2. Recycle ratio is calculated as 2012 average operating netback divided by proved + probable FD&A (including FDC) cost per barrel for the year ended December 31, 2012.

1.9x

–

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Type Curve Decline Rates Year Salt Flat Midland

1 46% 62% 2 32% 31% 3 24% 42% 4 19% 20% 5 16% 14%

6 to 10 12% 8% 10+ 10% 6%

*Commodity assumptions (US$): Oil $90/bbl and Gas: $2.90/Mcf

0

20

40

60

80

100

120

6 12 18 24 30 36 42 48 54 60 66 72 78 84 90 96 102 108 114

boe/

d

Month of Production

Midland

Salt Flat

Uphole recompletion in lower pressure zones: - $250,000 workover - 50 mboe added - 8 month payout

Payout: 7 months

Payout: 40 months

On-stream cost Operating Economic Well Well Cost EUR/Well Avg. 1st Yr Prod Payout Netback Recycle IRR F&D Limit

Field Inventory ($MM) (Mboe) ($/boe/d) (mths) ($/boe) Ratio % ($/boe) yrs

Salt Flat 32 $0.9 107 $12,857 7 $52.83 6.3x 494% $8.41 15 Midland 42 $2.9 206 $45,222 40 $41.29 3.0x 30% $13.85 48

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0

500

1000

1500

2000

2500

3000

3500

boe/

d

Month of Production

2017 Drills

2016 Drills

2015 Drills

2014 Drills

2013 Drills

Base

2013 2014 2015 2016 2017 Base Production (boe/d) 3000 3000 3000 3000 3000 Decline rate (%) 22% 19% 20% 17% 13% Required Make-up (boe/d) 660 570 605 510 384 Capital Efficiency ($/boe/d) $26,730 $26,730 $26,730 $26,730 $26,730 Sustaining Capital ($ MM) $17.6 $15.2 $16.2 $13.6 $10.3

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Current hedges lock in 1,600 bbl/d at US$87 - $108 WTI and account for 51% of 2013 production guidance.

0200400600800

1000120014001600180020002200240026002800300032003400

Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14

BBL/

D - O

IL

Hedging Summary

91.15 Fixed Price

91.15 Fixed Price

93.25 Fixed Price

95 X 103.75 Costless Collar

98 Fixed Price

103 Fixed Price

90 X 91.60 Costless Collar

87 X 89.70 Costless Collar

95 X 108 Costless Collar

2013 Production Guidance

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Solid metrics:

92% light oil and NGL’s, 8% natural gas.

Premium netbacks.

Competitive operating costs.

Excellent balance sheet – prudent use of debt.

Experienced management team and Board.

Demonstrated ongoing organic growth.

Predictable distributions.

Poised to grow production on existing assets.

Expect to grow by continuing to transact.

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Total Pre-Tax EV / Entity Value / ReserveUnit Market Entity Debt / Yield DACF Volume % Gas 2013E Daily P+P Life Index

Price Cap Value 2013E CF Current 2013E 2013E 2013E Production Reserves P+P8/14/2013 $MM $MM x % x boe / d % $/ boe / d $/ boe years

Crescent Point $39.00 $15,127 $17,079 1.0 x 7.1% 8.1 x 117,500 9% $145,354 $28.05 14.2 Vermilion $56.04 $5,772 $6,448 1.0 x 4.3% 9.3 x 40,750 33% $158,221 $39.11 11.1 Baytex $41.94 $5,316 $6,050 1.3 x 6.3% 9.4 x 57,500 11% $105,211 $20.75 13.9 Lightstream $7.54 $1,516 $3,714 3.1 x 12.7% 4.5 x 47,000 17% $79,029 $18.06 12.0 Bonterra $49.73 $1,550 $1,729 0.9 x 6.7% 8.5 x 12,000 27% $144,046 $24.51 16.1 Argent $10.07 $585 $729 1.7 x 10.4% 7.8 x 5,750 30% $126,799 $22.55 15.4 Parallel $3.84 $221 $458 5.5 x 15.6% 8.1 x 7,000 36% $65,361 $9.69 18.5 Zargon $6.93 $208 $320 1.8 x 10.4% 4.7 x 4,800 34% $66,567 $11.63 15.7

Average 2.0 x 9.2% 7.5 x 36,538 25% $111,323 $21.79 14.6

$8.40 $284 $330 1.3x 12.5% 7.3 x 3,000 4% $110,105 $20.06 15.0

Notes: (1) Production and reserves stated gross of royalties using a 6:1 equivalent conversion. (2) Total debt includes long-term debt, working capital deficiency and convertib le debentures. (3) Leverage ratios exclude option proceeds. (4) Cash flow forecasts based on consensus estimates. (5) Production forecasts based on company guidance and street consensus estimates. (6) Reserve Life Index calculated based on 2013E production, adjusted for acquisitions and divestitures. (7) Unlike fixed income securities, the Trust has no ob ligation to distribute any fixed amount, and reduction in, or suspensions of cash distributions may occur that will reduce future yield. (8) Eagle Energy Trust reserves as at December 31, 2012; Reserve Life Index calculated based on midpoint of 2013E production guidance of 2,900 - 3,100 boe/d announced August 2013.

Source: Scotiabank Global Banking & Markets, Bloomberg, Company Reports.

Daily Production

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Richard Clark, B.A. (Econ), LLB, Director, President and Chief Executive Officer Nineteen years in the legal profession as a founding partner at a boutique oil and gas law firm, then ten years at a Canadian national law firm, specializing in corporate finance, securities, M&A and venture capital. Extensive experience in the royalty trust sector. Kelly Tomyn, CA, Chief Financial Officer Former VP Finance and CFO for numerous public & private companies with over twenty-three years of financial experience with E&P companies. Former controller for Shiningbank.

Wayne Wisniewski, P.E., MBA, Vice President, Operations (Houston) Thirty years of oil and gas engineering and operations experience. Last 13 years of career spent in a senior operations management role in the Houston office of a major international E&P company.

Continued..

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Continued.. Robert Cunningham, Vice President, Business Development (Houston) Over twenty-five years experience in the oil and gas industry involving business development, finance, energy

banking and risk management. James Elliott, CA, Vice President, Finance Over sixteen years of corporate finance and financial accounting experience, including 14 years in the oil and gas industry. Jo-Anne Bund, LLB, General Counsel and Corporate Secretary Seventeen years of experience in corporate finance, securities, and M&A, including with a national law firm, with

a securities regulator and as corporate counsel.

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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 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, Eagle Energy, Former Director of Shiningbank

EAGLE’S AREAS OF ACTIVITY

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Corp. Office

Luling Field Office

Permian Field Office

Palo Pinto Properties

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Caldwell County - Luling, Texas

27

Caldwell County - Luling, Texas

28

Caldwell County - Luling, Texas

29

Martin County - Midland, Texas

…

30

CONTACT: Richard W. Clark, CEO

Tel: (403) 531-1575

Kelly Tomyn, CFO Tel: (403) 531-1574

Eagle Energy Inc. 2710, 500 – 4th Avenue SW

Calgary, AB T2P 2V6 info@EagleEnergyTrust.com