Investor Presentation | October 2015 - - PowerPoint PPT Presentation

™

Investor Presentation | October 2015

TSX: EGL.UN

EXPERTISE • QUALITY • INCOME

• 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, debt to 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. 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

• f 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 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

• thers 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 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. 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

• f 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 its

trust 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 are non-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. Investors should 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 provide useful 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 expenditures and 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 measure as 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 by excluding 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 to short-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.

Advisories

• 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 the conversion 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 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. The estimated values of the future net revenues of the reserves disclosed in this presentation do not represent the market value of such reserves. There is no assurance that such price and cost 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 the estimated 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 defined in 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 into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as “reserves” and “contingent resources” and the remainder classified as at the evaluation date 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 the thickness 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 estimated based 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 under development, 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 a project 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 uncertainty that it will be commercially 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

• f Reserves presented in this presentation have been prepared by McDaniel & Associates Consultants Ltd. for Eagle’s Canadian properties and Netherland, Sewell & Associates, Inc. for

Eagle’s U.S. properties, Eagle’s independent qualified reserves evaluators.

• “Eagle is created to provide investors with a sustainable business while delivering

stable 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 monthly distributions to unitholders.

Strategy

• Strategic Canadian Acquisition(1)

On August 20, 2015, Eagle closed the acquisition of a private oil and gas company (“Privateco”) with petroleum assets in the Twining Field in Alberta (the “Transaction”). The Transaction was valued at approximately $30 million, including Privateco’s indebtedness, and was funded out of Eagle’s existing credit facility of $US 85 million. It was completed by the amalgamation of Privateco with a newly incorporated operating subsidiary of the Trust.

Highlights:

• 2.1 MMboe of proved reserves and 7.2MMboe of proved plus probable reserves
• Production of approximately 750 boe/d from 92 gross (48 net) wells in the largest Pekisko oil pool in the

Western Sedimentary Basin

• 64% light oil and natural gas liquids
• 80% working interest in approximately 41,502 gross (32,650 net) acres
• Majority operated
• Approximately $92 million of tax pools, including approximately $40 million of non-capital losses
• Eagle’s 2015 debt to cash flow of approximately 2x(2)
• Over 10% accretive to Eagle cash flow per unit
• Eagle’s corporate payout ratio maintained below 100%(2)
• Eagle’s current corporate decline rate maintained below 20%

Note: 1) For more information, see Eagle’s news releases dated July 22, 2015 and August 20, 2015. 2) Based on forecast pricing at $US 55.00 per barrel WTI oil, $US 3.00 per Mcf NYMEX gas and $US 19.25 per barrel of NGLs, and foreign exchange rate of $US 1.00 equal to $CA 1.30.

• Current Estimated Production

3,750 boe/d 2015 Full Year Production Guidance 3,150 to 3,350 boe/d Production Split 94% light oil 2015 Ending Debt to Trailing Cashflow 2.1x(1) 2015 Corporate Payout Ratio <100%(1) Annualized Distribution(2) $0.36 per unit US Tax Pools $US 180 million CDN Tax Pools $CA 192 million

Corporate Profile

Notes: 1) Based on forecast pricing at $US 55.00 per barrel WTI oil, $US 3.00 per Mcf NYMEX gas and $US 19.25 per barrel of NGLs, and foreign exchange rate

• f $US 1.00 equal to $CA 1.30.

2) Monthly 3¢ distribution, $0.36 annualized per unit.

• Ticker

Units Outstanding (basic) 34.9 million 52 Week Range $1.45 - $5.40 Recent price $1.91(1) Average daily trading volume (30 day) 72,016 units Market Cap $67 million Directors’ & Officers’ Ownership 2.9% basic, 10.6% fully diluted(2) Equity Research Acumen Capital Partners Paradigm Capital Scotiabank Global

TSX: EGL.UN

Market Data

Notes: 1) TSX closing price on September 30, 2015. 2) Average exercise price of options = $5.70.

• Continued

financial flexibility and

• perating

performance despite a low commodity price cycle

• Second quarter average working interest sales volumes of 3,034 boe/d (96% oil, 2%

natural gas liquids, 2% natural gas)

• 35% increase from the first quarter, with second quarter funds flow from operations of

$10.5 million ($38.14 per boe) due in part to field operating expenses reductions

• Second quarter unitholder distributions maintained at $0.09 per unit ($0.03 per unit

per month)

• Approximately $CDN 66 million of unutilized credit facility ($CDN 36 million proforma

the August 20th acquisition) and a $4.2 million working capital surplus at the end of the second quarter

• 69% of the $13.7 million capital program for 2015 has been executed with results

performing to expectations

Highlights for the Three Months Ended June 30, 2015

• Strong

Balance Sheet Stable Production Capital Discipline

Sustainable Distributions with Growth Potential

Exercising Fiscal Prudence and Discipline in a Low Commodity Price Market

• Eagle owns stable, oil producing properties with development

and exploitation potential located in Canada (Alberta) and in the US (Texas and Oklahoma).

• Twining Field Properties, AB:
• Located in the Pekisko oil pool formation at the Twining field in East-Central Alberta
• 92 gross (48 net) producing wells
• Approximately 41,502 gross (32,650 net) acres
• Dixonville Properties, AB:
• Located 50 kms northwest of Peace River
• 110 gross (55 net) producing oil wells
• 80 gross (40 net) water injectors
• 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
• 79,000 acres

Where We Operate

• CDN Properties – Twining Field (Alberta)
• 80% working interest in the largest Pekisko oil pool in the Western Canadian Sedimentary Basin
• Production of approximately 750 boe/d (64% light oil and natural gas liquids)
• 92 gross (48 net) producing wells
• 30 API medium/light oil, 4 mD permeability and 7-8% average porosity
• Approximately 41,502 gross acres (32,650 net)
• Estimated ~900 million barrels of discovered oil initially-in-place(1), with a current recovery factor of <5%

Note: 1) Per Privateco’s internal reserves evaluator with an effective date of March 31, 2015.

• Approx. 70 km from

Three Hills, AB

• R

• R

• R

• R

• R

• R

• R

• R

• R

• R

• R

• 0.05

• 0.05

Lower MNVL Upper Pekisko Middle Pekisko Lower Pekisko Banff

Pekisko Type Log

• CDN Properties – Twining Field (Alberta)

Source: IHS public data

The largest Pekisko oil pool in the WCSB

• Will allow Eagle to sustain a current

corporate production rate of approximately 3,750 boe/d for over 5 years

Significant upside potential

• 10 horizontal wells drilled to date with
• ver 30 additional drilling locations
• Waterflood in certain areas of the field

has the potential to double recovery factors in the area

Low declines, long reserve life

• Decline rate below 5%
• Reserve life index
• Total Proved – 2.1 Mmboe(1)
• Total Proved Plus Probable –

7.2 Mmboe(1)

Robust returns

• Attractive, economic returns in the

current commodity price environment

Note: 1) Per Privateco’s independent reserves evaluator with an effective date of March 31, 2015.

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

Spyglass Resources Corp.

• Primary development started in 2004 with full scale waterflood by 2012
• 190 horizontal wells (110 producers, 80 injectors)
• 30API Oil, 18 mD permeability and 16-26% average porosity
• Approximately 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)

Note: 1) Per McDaniel and Associates Consultants Ltd., Eagle’s independent reserves evaluator, with an effective date of December 31, 2014.

• 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

CDN Properties – Dixonville (Alberta)

Source: IHS public data

• Light oil producing
• 35
• API 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

• perating 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)

16

Light oil producing

• 45
• API 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

• perating costs, while processing

newly acquired seismic data to define future drilling opportunities

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

US Properties – Hardeman (Texas & Oklahoma)

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

producing)

• PV10 value on total proved reserves of approximately $216 million or $5.10/unit
• Proved reserve life index of 14 years based on the mid-point of 2015 average working interest

production 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 Crude Oil Year $US/bbl ____________________________ 2015 $65.00 2016 $75.00 2017 $80.00 2018 $84.90 2019 $89.30 2020 $93.80

McDaniel & Associates Price forecast (as of Jan 1, 2015)

2014 Year-End Reserves(1)

Excellent year over year reserve performance

Note: 1) Per McDaniel and Associates Consultants Ltd., Eagle’s independent reserves evaluator, with an effective date of December 31, 2014.

• 2014 Year-End Reserves Highlights

+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 145% Stability reflected in total proved reserves replacement ratio 265% Excellent total proved plus probable reserves replacement ratio

• 2015 Guidance

Capital Budget(1) $16.2 MM Working Interest Production 3,150 to 3,350 boe/d Operating Costs per Month(2) $2.0 to $2.2 MM Funds Flow from Operations(3) $31.6 MM Debt to Trailing Cash Flow 2.1x Field Netback (excluding hedges) $23.37/boe

2015 Guidance

Notes: (1) The 2015 capital budget of $16.2 million consists of $US 9.9 million for Eagle’s operations in the United States and $4.2 million for Eagle’s operations in Canada. (2) 2015 operating costs result in field netbacks (excluding hedges) of approximately $23.37 per boe at $US 55.00 WTI. (3) 2015 funds flow from operations is approximately $31.6 million based on the following assumptions: a. Average working interest production of 3,250 boe/d (the mid-point of the guidance range); b. Forecast pricing at $US 55.00 per barrel WTI oil, $US 3.00 per Mcf NYMEX gas and $US 19.25 per barrel of NGL (NGL price is calculated as 35% of the WTI price); c. Differential to WTI is a $US 2.25 discount per barrel in Salt Flat, a $US 2.70 discount per barrel in Hardeman, a $CA 20.50 discount per barrel in Dixonville and a $CA 15.15 discount per barrel in Twining; d. Average operating costs of $2.1 million per month ($US 0.9 million per month for Eagle’s operations in the United States and $0.9 million per month for Eagle’s operations in Canada) being the mid-point of the guidance range; and e. Foreign exchange rate of $US 1.00 equal to $CA 1.30.

• Eagle’s 2015 capital budget is $16.2 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 ($4.2 MM)

• Dixonville Property
• Maintenance capital on waterflood
• Gathering system completion
• Twining Property
• 2 (2.0 net) horizontal wells

2015 Capital Budget

• Eagle continues to maintain a prudent hedging program

35% of production for 2015 One third of current production hedged for calendar 2016

• Eagle has 1,430 mcf/d of gas hedged at $3.00/mcf for 2016

Q3 Avg Price = $US 69.95 Q4 Avg Price = $US 74.98 2016 Avg Price = $US 59.16

Hedging Program

200 400 600 800 1000 1200 1400 1600

BBL/D OIL

22

Management Experience

• Eagle’s management team has an average of 25 years of experience

Years 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Richard Clark Corporate Finance Law - Shiningbank Energy Trust General Counsel Corporate Finance Law Eagle - President & CEO Wayne Wisniewski Petroleum Engineering- Anders Energy, Occidental Petroleum Pennzoil E&P BP - Various Senior Leadership Engineering and Operations Roles Eagle - COO Kelly Tomyn Controller - Various Junior O&G Companies CFO - Various Junior O&G Companies Eagle - CFO Eric McFadden Co-head Investment Banking, Calgary - Scotia Capital Windpower Development

• CEO

EVP, Business Development - Superior Plus Eagle - VP, Capital Markets & BusDev Scott Lovett Senior Reserves Evaluator - GLJ Petroleum Consultants Business Development - Shiningbank Energy; Enerplus Business Development, COO - Native American Res. Ptnrs Eagle - VP, Corporate & BusDev Jo-Anne Bund Securities and Corporate Law at a boutique oil and gas firm Senior Legal Counsel - Alberta Securities Commission Securities and Corporate Law Corporate Counsel - Walton Intl. Eagle - General Counsel & Corporate Secretary

23

Value Proposition Why Invest in Eagle?

• Strong balance sheet
• Stable production base
• Capital discipline
• Experienced management team
• Predictable monthly income

• APPENDIX

• 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 in corporate 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&P company

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

• Continued…

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

Development

• Over 18 years experience in the oil and gas industry, including

reservoir evaluations, acquisitions and divestments, business planning 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 as corporate counsel

Management

• 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

28

• Current working interest production of approximately 3,750 boe/d

Production History

Notes: 1) Q4/14 production is after the Permian asset disposition and before the Dixonville asset acquisition. 2) Guidance is mid-point for full year 2015, including the Twining Field acquisition which closed August 20, 2015.

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 Q2/15 2015 Guidance 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 3,034 3,250 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

Average WI Production per Quarter (boe/d)

• 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 of liquefied natural gas, rail and pipeline infrastructure enhances Canada’s access to non-U.S. markets

Crude Oil Price Comparison

30.00 40.00 50.00 60.00 70.00 80.00 90.00 100.00 110.00

WTI (NYMEX) - Cushing ($US/bbl)

CDN Light Sweet ($CDN/bbl) WCS ($CDN/bbl)

• Contact

Kelly Tomyn, CFO

Tel: (403) 531-1574

Eric McFadden, VP, Capital Markets & Business Development

Tel: (587) 233-1799

Richard W. Clark, President and CEO

Tel: (403) 531-1575

Eagle Energy Inc. Eagle Hydrocarbons Inc.

2710, 500 – 4th Avenue SW 3005, 333 Clay Street Calgary, AB T2P 2V6 Houston, TX 77002 info@EagleEnergyTrust.com www.eagleenergytrust.com

TSX: EGL.UN