EAGLE ENERGY INC. Investor Presentation | March 2017 Advisories - - PowerPoint PPT Presentation

EAGLE ENERGY INC.

Investor Presentation | March 2017 TSX: EGL

EXPERTISE • QUALITY • GROWTH

Advisory Regarding Forward Looking Statements:

This presentation includes statements that contain forward looking information (“forward-looking statements”) in respect of Eagle Energy Inc.’s (“Eagle”) expectations regarding its future

• perations, including Eagle’s business strategy, credit facility and future drawings, forecast estimates for Eagle’s 2017 capital budget, production, drilling opportunities and plans, operating costs,

funds flow from operations, 2017 year-end net debt levels, commodity split, tax pools, estimated field netback, hedging, reserves, corporate decline rate, timing for reinstatement of dividends, if any, and that the LMR regime will not be an impediment to future acquisition opportunities. 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

• il, 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 others things, as well as the business risks discussed in Eagle Energy Inc.’s annual information form (“AIF”) dated March 16, 2017 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 Eagle and its shareholders. No assurance is given that Eagle’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 of this presentation and may not be appropriate for other purposes. Eagle does not undertake any obligation, except as required by applicable securities legislation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. Eagle’s AIF contains important detailed information about Eagle. Copies of the AIF may be viewed at www.sedar.com and on Eagle’s website at www.eagleenergy.com.

Advisory Regarding Non-IFRS Financial Measures:

Statements throughout this presentation make reference to the term “field netbacks”, which is a non-IFRS financial measure that does 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 this measure should not be construed as an alternative to earnings (loss) calculated in accordance with IFRS. Management believes that this measure provides useful information to investors and management since it reflects the quality of production and the level of profitability. “Field netback” is calculated by subtracting royalties, operating expense and transportation and marketing expenses from revenues, which are from Eagle’s Consolidated Statement of Earnings (Loss) and Comprehensive Earnings (Loss).

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 6:1 Mcf 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.

Advisories

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“Eagle has survived the commodity price cycle, pivoted from a low growth, sustainable dividend model, and is superbly positioned to realize near-term capital appreciation and sustainable production growth.”

Return to low leverage balance sheet Positioned for oil torque Near term Sustainable Growth

Strategy

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Corporate Profile

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Notes: 1) 2017 full year production guidance and current estimated production include both working interest and royalty interest production. 2) As a condition of transferring existing licenses, approvals, and permits, the Alberta Energy Regulator require all transferees to demonstrate that they have a liability management ratio (“LMR”) of 2.0 or higher immediately following the transfer. LMR is an assets to liabilities comparison to ensure a higher likelihood that energy companies can meet future decommissioning and abandonment liabilities. The LMR for Eagle was 3.21 (as of March 4, 2017). As such, Eagle does not expect that the LMR regime will be an impediment to future acquisition opportunities for Eagle.

Current Estimated Production 3,650 boe/d 2017 Full Year Production Guidance 3,800 to 4,000 boe/d(1) Production Split 84% oil, 3% NGLs, 13% gas LMR 3.21(2) US Tax Pools $US 173 million CDN Tax Pools $CA 198 million

Ticker Shares Outstanding (basic) 42.5 million 52 Week Range $0.40 - $1.06 Recent price $0.54(1) Average daily trading volume (30 day) 103,552 shares Market Cap $22.9 million

TSX: EGL

Market Data

Notes: 1) TSX closing price on March 14, 2017.

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Term Loan Financing – Closed March 13, 2017

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 $CA 87 million ($US 65 million) Term Loan Financing – Overview

 Eagle has expanded its borrowing capacity by 24% to approximately $CA 87 million ($US 65 million), which establishes a foundation for Eagle to execute its new growth strategy over the next four years and accelerate the development of its low risk drilling inventory.  Eagle has replaced its entire $70 million authorized bank credit facility with a new four year secured term loan from White Oak Global Advisors, LLC (“White Oak”) which provides up to $87 million (the current Canadian dollar equivalent of $US 65 million) of financing. Headquartered in San Francisco, White Oak is an SEC- registered investment advisor with assets under management of approximately $US 3 billion and affords Eagle a partner that has the capacity to provide financing to fund future acquisitions.  At closing, Eagle drew approximately $82 million (the current Canadian dollar equivalent of $US 61.5 million) and can draw the remaining $US 3.5 million prior to the first anniversary of closing.  Based on Eagle’s 2016 ending net debt of $59 million and execution of its approved 2017 budget, Eagle expects 2017 ending net debt to be $71.2 million, thus affording Eagle approximately $13 million in combined working capital and undrawn term loan availability at the end of 2017 (see “2017 Outlook” section of this presentation).  Eagle’s expanded credit base, coupled with its 2017 expected funds flow from operations (see “2017 Outlook”) has allowed a four-fold increase in the capital budget from 2016. Expected growth in year-over year fourth quarter average production is 8%, but more impactful will be the exploitation of substantial, internally-identified drilling opportunities in Eagle’s Hardeman and Twining fields that the 2017 budget is expected to provide.

2017 Budget Highlights

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On March 13, 2017, Eagle announced its 2017 budget with the following highlights:  2017 capital budget of $22.8 million ($US 12.5 million for its operations in the United States and $6.6 million for its operations in Canada). Included in the $US 12.5 million capital budget is $US 3.5 million for land acquisitions on seismically-defined play trends in Eagle’s Hardeman area, which will provide a platform for economic production growth in future years.  2017 production guidance of 3,800 to 4,000 boe/d (including working interest and royalty interest volumes), resulting in 8% year-over-year fourth quarter production growth. Eagle’s proved developed producing corporate decline rate is approximately 18% per annum.  2017 field netbacks of $25.78/boe (based on the assumptions as set out below under in “2017 Outlook”).  2017 monthly operating cost guidance (inclusive of transportation) of $2.1 million to $2.3 million per month, resulting in per boe operating costs of $19.04 (figure based on the mid- range guidance level of $2.2 million per month).  2017 funds flow from operations of $16.0 million ($0.38 per share), consistent with 2016 levels and incorporating a 16% forecast decrease year-over-year of general and administrative expenses.  2017 ending net debt of $71.2 million, affording Eagle approximately $13 million in combined working capital and undrawn term loan availability at the end of 2017 (based on the assumptions set out below under “2017 Outlook”).

2017 Outlook

Notes: 1) The 2017 capital budget of $22.8 million consists of $US 12.5 million for Eagle’s operations in the United States and $6.6 million for Eagle’s operations in Canada. 2) 2017 production is forecast to consist of 84% oil, 3% natural gas liquids (“NGLs”) and 13% natural gas. These numbers include working interest and royalty interest volumes. 3) Operating expense guidance is stated on a per month basis rather than per boe basis due to the mostly fixed nature of the costs. 4) 2017 funds flow from operations is expected to be approximately $16.0 million based on the following assumptions: a) average production of 3,900 boe/d (the mid‐point of the guidance range); b) pricing at $US 55.46 per barrel WTI oil, $US 3.36 per Mcf NYMEX gas, $CA 2.79 per Mcf AECO and $US 19.41 per barrel of NGL (NGL price is calculated as 35% of the WTI price); c) differential to WTI is $US 3.18 discount per barrel in Salt Flat, $US 3.50 discount per barrel in Hardeman, $CA 11.50 discount per barrel in Dixonville and $CA 8.00 discount per barrel in Twining; d) average operating costs of $2.2 million per month ($US 0.8 million per month for Eagle’s operations in the United States and $1.2 million per month for Eagle’s operations in Canada), the mid‐point of the guidance range; and e) a foreign exchange rate of $US 1.00 equal to $CA 1.30. 5) This figure assumes average operating costs of $2.2 million per month (the mid‐point of the guidance range) and a $US 55.46 WTI price. Field netback is a non‐IFRS financial measure. Refer to the first slide of this presentation in the section titled “Advisory Regarding Non‐IFRS Financial Measures”. .

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Eagle’s 2017 guidance for its capital budget, average production and monthly operating costs together with resulting funds flow from operations, ending net debt and field netback (excluding hedges) (based on management’s assumptions) are as follows:

2017 Guidance Notes Capital Budget $22.8 mm (1) Average Production 3,800 to 4,000 boe/d (2) Operating Expenses per month $2.1 to $2.3 mm (3) Funds Flow from Operations $16.0 mm (4) Ending Net Debt $71.2 mm Field Netback (excluding hedges) $25.78 / boe (5)

2017 Sensitivities

Assumptions:

1)

Operating costs are assumed to be $2.2 million per month (mid-point of guidance range)

2)

Differential to WTI is held constant

3)

The foreign exchange rate is assumed to be $US 1.00 equals to $CA 1.30, unless otherwise indicated in the table

9 Sensitivity to Commodity Price Sensitivity to Production

The following tables show the sensitivity of Eagle’s 2017 funds flow from operations to changes in commodity prices, production and foreign exchange (“FX”) rates:

Funds Flow From Operations 2017 Average Production (3,900 boe/d) FX 1.25 FX 1.30 FX 1.35 $US 45.00 WTI $13.7 mm $14.9 mm $16.0 mm $US 55.00 WTI $14.9 mm $16.0 mm $17.2 mm $US 65.00 WTI $15.0 mm $16.1 mm $17.4 mm 2017 Average Production (3,900 boe/d) (WTI $US 55, FX 1.30) 3,800 3,900 4,000 Funds Flow from Operations ($CA) $15.1 mm $16.0 mm $17.0 mm

Updated Dividend Strategy

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 Concurrent with embarking on a more growth oriented strategy, on March 13, 2017, Eagle announced the suspension of its dividend following the payment of its February dividend ($0.005 per share declared February 15, 2017, payable on March 23, 2017).  Previously, Eagle focused on a sustainable business model with capital expenditures using less than 100%

• f its annual cash flow to deliver total returns to its shareholders through both dividends and modest

production growth. However, Eagle’s capital budget for 2017, a year in which Eagle plans to build the platform for future reserves and production growth, requires 145% of Eagle’s 2017 expected cash flow. This decision makes the payment of a dividend neither sustainable nor sensible. When Eagle has successfully implemented this capital intensive phase of its growth, the Board may consider reinstating an appropriate dividend.

Highlights for the Year Ended, December 31, 2016

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Eagle achieved the following results in 2016:

• A total proved reserve replacement ratio of 184% and a total proved plus probable reserve replacement ratio
• f 272%.(1)(3)
• Total proved plus probable finding, development and acquisition costs (“FD&A”) (including changes in future

development costs) of $7.16 per barrel of oil equivalent (“boe”).(2)(3)

• An 18% year-over-year increase in the net present value of proved plus probable reserves (discounted at

10%) with minimal capital investment and within a lower forward pricing environment.

• Grew total proved plus probable reserves by 13% to approximately 20.9 million boe (68% proved, 52%

proved producing) from 18.6 million boe (70% proved, 58% proved producing).

• Average production increased by 18% year-over-year to 3,972 barrels of oil equivalent per day (“boe/d”)

(84% oil, 3% natural gas liquids and 13% natural gas).

• A 12% year-over-year reduction in per boe operating costs (inclusive of transportation).
• Funds flow from operations of $15.8 million ($10.87 per boe or $0.38 per share) and ending net debt of $59

million.

“Eagle closed out 2016 with strong reserve metrics, production exceeding the upper end of its guidance range, monthly operating costs at the lower end of its guidance range and ending net debt levels as expected.”

Note: 1) Reserves replacement is calculated by dividing reserve additions by total working interest production for the year, which, in 2016, is based on average working interest production of 3,740 boe/d. 2) Eagle calculates FD&A costs incorporating both the costs and associated reserve additions related to exploration, development and acquisitions during the year. Eagle believes that FD&A costs provide useful information to investors because it is a measure of the cost to locate new reserves and the ongoing expense of extracting petroleum throughout the lifecycle of the reserves. 3) Eagle cautions readers to the reliability of reserves replacement and FD&A costs as these measures do not have any standardized meaning and may not be comparable to similar measures presented by other issuers.

• Grew total proved plus probable reserves by 13% to approximately 20.9 million boe (68% proved, 52% proved

producing) from 18.6 million boe (70% proved, 58% proved producing)

• Before tax PV10 value on total proved plus probable reserves of approximately $270 million
• Proved plus probable reserves life index of above 14 years(2)

McDaniel & Associates Price forecast (as of Jan 1, 2017)

2016 Year-End Reserves(1)

Excellent year-over-year reserves performance

Notes: 1) Per McDaniel & Associates Consultants Ltd., and Netherland, Sewell & Associates, Inc., Eagle’s independent reserves evaluators, with an effective date of December 31, 2016. 2) Reserves life index is calculated by dividing reserves by total working interest production for the year, which, in 2016, is based on average working interest production of 3,740 boe/d. Eagle cautions readers to the reliability of reserves life index as this measures does not have any standardized meaning and may not be comparable to a similar measure presented by other issuers.

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Year WTI Crude Oil $/bbl 2017 55.00 2018 58.70 2019 62.40 2020 69.00 2021 75.80 52% 2% 13% 29%

Reserves by Category

PDP PDNP PUD Probable $153 $10 $29 $79

PV10 Value ($MM)

PDP PDNP PUD Probable

• Eagle owns stable, oil producing properties with development

and exploitation potential located in Canada (Alberta) and in the US (Texas and Oklahoma). Eagle operates all four of its major assets.

• Dixonville Properties, AB:
• Located 50 kms northwest of Peace River
• 88 gross (43 net) producing oil wells
• 3 gross (1 net) producing gas wells
• 87 gross (44 net) water injectors
• 26,737 gross (12,322 net) acres
• Twining Field Properties, AB:
• Located in the Pekisko oil pool formation at the Twining field in East-Central Alberta
• 57 gross (34 net) producing oil wells, 4 gross (2 net) producing gas wells
• Approximately 21,561 gross (13,495 net) acres
• Salt Flat Properties, TX:
• Located in Salt Flat field in Caldwell County, TX
• 53 gross (41 net) producing oil wells
• 3,621 gross (3,021 net) acres (3,374 gross (2,775 net) held by production)
• Hardeman Properties, TX & OK:
• Located in Hardeman Basin in Hardeman County, TX, and Jackson County, OK
• 44 gross (36 net) producing oil wells
• 23,221 gross (14,042 net) acres (13,460 gross (8,370 net) held by production)
• Other Properties (WCSB), AB
• Production from 10 working interest and 69 royalty interest wells
• Producing wells are located in the Bow Island, Bigstone, Brazeay River, Sylvan Lake,

Rimbey, Ferrier, Pembina, Placid and Kakwa fields of Alberta

Our Properties

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• Operated by Eagle
• 50% working interest in a horizontal oil waterflood in the Montney “C” Formation
• Primary development started in 2004 with full scale waterflood by 2012
• 88 gross (43 net) producing oil wells, 3 gross (1 net) producing gas wells, 87 (44 net) water injectors
• 30◦API Oil, 18 mD permeability and 16-26% average porosity
• Approximately 26,737gross (12,322 net) acres

50 km from Peace River

CDN Properties – Dixonville (Alberta)

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A premier waterflood in Western Canada

• Low decline property
• Low abandonment liabilities due to long life

asset

• Over the long term, plans are to leverage off

internal waterflood expertise to improve the effectiveness of the field by developing a more efficient artificial lift strategy

• In the medium term, Eagle plans to undertake

a number of projects to improve field

• perations, trucking and marketing

Long-term potential

• Decline rate below 10%

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

CDN Properties – Dixonville (Alberta)

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Source: IHS public data to December 31, 2016

CDN Properties – Twining Field (Alberta)

• Operated by Eagle
• 65% average working interest production to Eagle from the largest Pekisko oil pool in the Western

Canadian Sedimentary Basin

• 65% light oil and natural gas liquids
• 30° API medium/light oil, 4 mD permeability and 7-8% average porosity
• Approx. 70 km from

Three Hills, AB

100/02-07-032-24W4/00

• 0.05

• 0.05

Lower MNVL Upper Pekisko Middle Pekisko Lower Pekisko Banff

Pekisko Type Log

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CDN Properties – Twining Field (Alberta)

Source: IHS public data to December 31, 2016

Interests in the largest Pekisko oil pool in the WCSB 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

Ongoing production improvements

• Including well workovers, pipeline, facilities

and subsurface work

Low declines

• Decline rate below 5%

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Twining Pekisko Pool Production History

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CDN Properties – Other - Western Canadian Sedimentary Basin

Acquired interests in attractive Alberta plays located in the WCSB effective January 27, 2016

• Royalty interest and non-operated

working interest production (30% oil and natural gas liquids)

No incremental debt, capital expenditures or overhead needed to manage production Estimated total net proved reserves of 0.94 million boe(1) Estimated total net proved plus probable reserves of 1.09 million boe(1)

• 69 producing

non-operated royalty interest wells

• 10 non-
• perated

working interest wells

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(1)

Effective date December 31, 2016, estimated by McDaniel & Associates Consultants Ltd.

US Properties – Salt Flat (Texas)

Light oil producing

• 36
• 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
• Operated by Eagle

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

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Light oil producing

• 45
• API oil from the Chappel and Atoka

Conglomerate formations located in Hardeman County, Texas and Jackson County, Oklahoma

• Operated by Eagle

23,221 gross acres of land

• 13,460 gross acres held by production
• 44 gross (36 net) producing oil 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

US Properties – Hardeman (Texas & Oklahoma)

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APPENDIX

• For Q1 2017, hedges are in place covering 1,871 barrels of oil per day at an average WTI price of $US 50.04/bbl
• For the remainder of 2017, hedges are in place covering 1,625 barrels of oil per day at an average WTI price of

$50.84.

• In addition, Eagle has a differential hedge between Edmonton Light Sweet oil price and the WTI oil price in place at

$US 3.25 per barrel on 1,000 bbl/d for 2017.

Hedging Program

Q1 2017 $US 50.04 Q2 2017 $US 50.84 Q3 2017 $US 50.84 Q4 2017 $US 50.84 2016 Avg Hedged Oil Price = $US 50.62 Average % Hedged

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0% 10% 20% 30% 40% 50% 60% 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 Jan‐17 Feb‐17 Mar‐17 Apr‐17 May‐17 Jun‐17 Jul‐17 Aug‐17 Sep‐17 Oct‐17 Nov‐17 Dec‐17

% Hedged BOE/D

2017 Capital Budget Details

Note: 1) The capital budget excludes future corporate and property acquisitions, which are evaluated separately on their own merit.

Eagle’s board of directors has approved a 2017 capital budget of $22.8 million ($US 12.5 million in the United States and $6.6 million in Canada), consisting of the following:

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• Salt Flat, Texas
• 2 (2.0 net) horizontal oil wells
• Seismic processing, facilities, pump changes
• Land and abandonments
• Hardeman, Texas and Oklahoma
• 2 (2.0 net) horizontal oil wells
• Seismic processing, pump installs
• Land
• Dixonville, Alberta
• Pipeline and facilities
• Geological and geophysical work
• Twining, Alberta
• 3 (3.0) net horizontal oil wells
• Facility capital
• Abandonment

Richard Clark, B.A. (Econ), LLB, Director and Chief Executive Officer

• Over 20 years in the legal profession as a founding partner at a boutique
• il and gas law firm, then 10 years at a Canadian national law firm,

specializing in corporate finance, securities, M&A and venture capital

Wayne Wisniewski, P.E., MBA, President and Chief Operating Officer (Houston)

• Over 30 years of oil and gas engineering and operations experience
• 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 oil and gas companies

Continued..

Management

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Continued… Scott Lovett,

M.Sc., MBA, P.Eng, Executive Vice President, Business Development

• Over 20 years experience in the oil and gas industry, including

reservoir evaluations, acquisitions and divestments, business planning and strategic analysis

Jo-Anne Bund, B.A., LLB, General Counsel and Corporate Secretary

• Over 20 years of experience in corporate finance, securities, and

M&A, including with a national law firm, with a securities regulator and as in-house corporate counsel

Management

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David Fitzpatrick, P.Eng., Chairman

• President and Chief Executive Officer, Veresen Midstream
• 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 and Chair of Compensation Committee

• Former President and Chief Operating Officer, Barnwell of

Canada, Former Director of Shiningbank

Richard Clark, B.A. (Econ), LLB, Director

• President and Chief Executive Officer of Eagle; Former Director
• f Shiningbank

Board of Directors

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Production History

Notes: 1) 2017 average production guidance includes both working interest and royalty interest production (shown at the mid-point of the 3,800 to 4,000 guidance range). 2) Q4/14 production is after the Permian asset disposition and before the Dixonville asset acquisition.

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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 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16 2017 Guidance Production 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 3,607 3,783 3,854 4,147 4,085 3,803 3,900

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 Average WI Production per Quarter (boe/d)