Disclaimer Regarding Forward Looking Statements: This presentation - - PowerPoint PPT Presentation

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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 is an energy trust created to provide 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.

• 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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PLAN FOR GROWTH

• Upon acquiring a lower PDP % asset, Eagle intends to increase the

historical rate of capital investment in the near term to grow production, optimize operations and maximize drilling inventory.

• After the “ramp up”, Eagle expects cash flow from each asset to:
• sustainably support Eagle’s distribution,
• fund the capital to replace declines with less than 50% of

cash flow, and

• Deliver moderate annual production growth on that asset.
• Eagle may acquire higher PDP % assets if production is sustainable.

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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: 95% light oil and NGLs Credit Facility: $US 61.0 million Annual Distribution: $1.05 per unit Current Yield (1)(2): 13.8% Tax Pools:

• approx. $280 million

(1) Based on the closing price of $7.62 on May 23, 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): 30.3 million 52 Week Range: $6.28 - $10.94 Recent price (May 23/13 close): $7.62 Average daily trading volume (30 day): 88,773 units 30 day VWAP: $7.03 Market Cap (May 14/13): $231.2 million Insider Ownership: 2.4% basic, 8.0% fully diluted Equity Research: Scotia Acumen CIBC Haywood TD NBF PI Financial

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• First quarter 2013 average working interest sales volumes of 2,928 boe/d exceeded

Eagle’s first quarter plan and were unchanged from Q4 2012 production levels.

• Achieved a 37% reduction in field operating costs (excluding transportation)

compared to Q1 2012, and a 20% reduction compared to Q4 2012. Total field

• perating costs including transportation were $11.18/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.

• Q1 2013 funds flow from operations of $11.9 million, up 30% from Q1 2012 and up

20% from Q4 2012.

• Top-decile first quarter field netbacks were $52.59/boe. Canadian dollar realized oil

prices were 103% of benchmark $US WTI. Premium pricing negotiated by Eagle in its 2013 marketing arrangements contributed to top decile per boe field and

• perating netbacks, giving Eagle a substantial revenue advantage over producers
• f Canadian oil.
• Q1 distributions held steady at $0.26 per unit or $0.0875 per unit per month without

increasing debt per unit from the fourth quarter 2012.

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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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• On April 22, 2013, Eagle acquired the remaining 7.5% interest in its oil and natural

gas properties in the Permian Basin located near Midland for cash consideration of approximately $US 8.5 million. The acquisition adds approximately 70 boe/d of

• production. The trust now owns 100% working interest in these properties.
• Upon completion of the 2012 year end reserves report and the closing of the

acquisition, the borrowing base under Eagle’s credit facility was increased from $US 48.5 million to $US 61.0 million.

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Notes: (1) Increased due to the acquisition of the remaining 7.5% interest in its oil and natural gas properties at the Permian Basin, located near Midland, Texas (the “Acquisition”). Eagle now owns 100% working interest in these properties. Note that the capital budget amount excludes the initial $US 8.5 million cost of the Acquisition. (2) The Acquisition, which closed April 22, 2013, is expected to add approximately 70 boe/d production volumes. This results in no change to previously stated production range guidance or operating cost guidance. (3) 2013 funds flow from operations of $45.0 million (previous funds flow guidance of $41.0 million) has been estimated using the following assumptions: a. Based on actual results through to March 31, 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 (previous funds flow guidance assumption used 3,000 boe/d, which was at the mid-point of guidance range); c. April – December benchmark pricing unchanged from previous funds flow guidance assumptions: $US 90.00 per barrel WTI

• il, $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. April – August field marketing contracts currently in place for both Midland and Luling; e. September – December $2.23 per barrel discount from WTI in Midland (excluding transportation) and a $1.71 per barrel discount from WTI in Luling (excluding transportation), which is based on the assumptions used in the latest reserve report, since no field marketing contracts are yet in place for this period; f. April – December average operating costs (inclusive of transportation) unchanged from previous funds flow guidance assumption of $13.00 per boe; and g. April – December foreign exchange unchanged from previous funds flow guidance assumption at $1.00 CDN/US.

Updated Previous 2013 Guidance 2013 Guidance Notes Capital Budget $US 26.0 mm $US 24.0 mm (1) Working Interest Production 2,900 ‐ 3,100 boe/d 2,900 ‐ 3,100 boe/d (2) Operating Costs (inclusive of transportation) $12.00 ‐ $14.00 per boe $12.00 ‐ $14.00 per boe (2) Funds Flow from Operations $45.0 mm $41.0 mm (3)

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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 initial acquisition capital of $US 8.5 million relating to the 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 8.5 million Acquisition being financed by bank debt. 6. Effective April 22, 2013, the borrowing base under the credit facility was increased to $US 61.0 million.

Updated Previous Payout Ratios (as a percentage of funds flow) 2013 Guidance 2013 Guidance Notes Basic Payout Ratio (i.e.: Distribution at $1.05/unit annually) 71% 77% (1) Plus: Capital Expenditures 57% 59% (2) Equals: Corporate Payout Ratio 128% 136% (3) Adjusted Payout Ratio (i.e., Distribution ‐ DRIP proceeds + Capital Expenditures) 83% 85% (4) Financial Sterngth Debt to trailing cashflow 0.88x 0.78x (5) % Drawn on credit facility at end of period 66% 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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Question: “Given Eagle’s current unit price is equity financing through the DRIP (distribution re-investment program) considered dilutive? Eagle’s Response: “No, and here’s why”

• Eagle utilizes DRIP financing to fund the portion of its capital program which

exceeds available cash flow after paying distributions. If the rate of return generated by the capital program exceeds the cost of such DRIP financing to Eagle, it’s accretive. With the 2012 recycle ratio of 1.9 times, every dollar of capital invested generates $1.90, the results are accretive.

• Although a lower unit price results in additional DRIP equity being issued,

when put in context, the impact is not drastic. By way of example, when comparing the current effect of the DRIP to the effect when Eagle’s unit price approximates July – October 2012 levels ($10.00 per unit):

• Annual DRIP unit issuances increase from 7% to 9% of total units

issued and outstanding

• Annual distributions increase by 1.3% (or $410,000)

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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 March 31, 2013. Excludes impact of hedging. Canadian dollars. Natural gas converted on a 6:1 basis.

$52.59 $0 $10 $20 $30 $40 $50 $60 $70

Vermilion Eagle PetroBakken Renegade Crescent Point Whitecap Bonterra Argent Zargon Longview Trilogy ARC Penn West Enerplus Pengrowth Baytex Peyto Parallel Bonavista Twin Butte

$/boe

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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 – 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x 4.5x 5.0x

PetroBakken Baytex Crescent Point Whitecap Eagle ARC Renegade Bonterra Peyto Bonavista Vermilion Parallel Trilogy Pengrowth Twin Butte Enerplus Argent Penn West

Recycle Ratio (x)

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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

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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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) 3,000 3,000 3,000 3,000 3,000 Decline rate (%) (YoY avg.) 28% 19% 20% 17% 13% Required Make‐up (boe/d) 835 570 605 510 385 Capital Efficiency ($/boe/d) $26,730 $26,730 $26,730 $26,730 $26,730 Sustaining Capital ($ MM) $22.3 $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.

200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 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 ‐ OIL

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:
• 95% light oil and NGL’s, 5% 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 / Reserve Unit 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+P

5/15/2013

$MM $MM x % x boe / d % $/ boe / d $/ boe years

Crescent Point $38.13 $14,583 $16,646 1.1 x 7.2% 8.7 x 114,000 9% $146,014 $27.34 14.6 Vermilion $50.90 $5,151 $5,889 1.2 x 4.7% 9.0 x 40,000 32% $147,216 $35.72 11.3 Baytex $39.51 $4,961 $5,608 1.2 x 6.7% 9.5 x 57,000 11% $98,383 $19.23 14.0 PetroBakken $7.95 $1,576 $3,810 3.3 x 12.1% 4.8 x 47,000 16% $81,058 $18.52 12.0 Bonterra $50.11 $1,640 $1,754 1.1 x 6.6% 8.5 x 12,000 25% $146,190 $24.87 16.1 Argent $10.22 $508 $624 1.6 x 10.3% 7.8 x 5,550 28% $112,420 $19.30 16.0 Parallel $3.79 $216 $447 5.4 x 15.8% 7.9 x 7,000 36% $63,900 $9.47 18.5 Zargon $6.15 $184 $304 1.9 x 11.7% 4.4 x 4,800 33% $63,419 $11.08 15.7 Average 2.1 x 9.4% 7.6 x 35,919 24% $107,325 $20.69 14.8 $7.49 $228 $277 1.1x 14.0% 6.2 x 3,000 4% $92,270 $17.71 14.3 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 convertible 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 obligation 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 May 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.

Dusty Dumas, Controller (Houston)

• Over twenty-five years experience in financial and reporting roles, including functioning as a controller, vice

president finance and chief financial officer for both public and private companies.

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

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Caldwell County - Luling, Texas

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Caldwell County - Luling, Texas

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Martin County - Midland, Texas

…

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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