EAGLE ENERGY INC. Investor Presentation | August 2016 Advisories - - PowerPoint PPT Presentation

EAGLE ENERGY INC.

Investor Presentation | August 2016 TSX: EGL

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 Inc.’s (“Eagle”) expectations regarding its future operations, including Eagle’s business strategy, and forecast estimates for Eagle’s capital budget, production, drilling plans, operating costs, funds flow from operations, that Eagle’s funds flow from operations will exceed capital expenditures for the second third and fourth quarters of 2016 combined, year end 2016 debt levels, timing and consequent increase in production from bringing “behind-pipe” production on-stream at Dixonville, commodity split, debt to trailing funds flow from operations, basic payout ratios, corporate payout ratios, dividends, tax pools, estimated field netback, hedging, reserves, resources and that the recent changes by the AER to its 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 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 others things, as well as the business risks discussed in Eagle Energy Trust’s (the predecessor reporting issuer to Eagle Energy Inc.) annual information form (“AIF”) dated March 17, 2016 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

• therwise. 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 terms “funds flow from operations,” “field netbacks”, ”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 level of dividends to shareholders. “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 dividends, 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. “Basic payout ratio” is calculated by dividing shareholder dividends by funds flow from operations. “Corporate payout ratio” is calculated by dividing capital expenditures plus shareholder dividends by funds flow from operations. See the “Non-IFRS financial measures” section of Eagle’s management discussion and analysis relating to its financial statements for a reconciliation of funds flow from operations and field netback to earnings (loss) for the period, the most directly comparable measures in Eagle’s financial statements.

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 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 in the oil and gas sector. Eagle owns stable petroleum producing assets in Canada and the U.S. Eagle strives to deliver a sustainable business to its shareholders.

Strategy

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Corporate Profile

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Notes: 1) 2016 full year production guidance and current estimated production include both working interest and royalty interest production. 2) In June 2016, The Alberta Energy Regulator (“AER”) announced that as a condition of transferring existing AER licenses, approvals, and permits, the AER will 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. Following Eagle’s assumption of operatorship of the Dixonville properties, the LMR for Eagle was 3.13 (as of July 22, 2016). As such, Eagle does not expect that the recent changes by the AER to its LMR regime will be an impediment to future acquisition opportunities for Eagle. 3) Based on forecast pricing of $US 47.50 per barrel WTI oil, $CA 2.47 per Mcf AECO gas and $US 16.63 per barrel of natural gas liquids (NGL price is calculated as 35% of the WTI price), a monthly dividend of $0.005 per share ($0.06 annualized), a foreign exchange rate of $US 1.00 equal to $CA 1.30, a 2016 capital budget of $CA 5.0 million, average production of 3,800 boe/d (the upper end of the guidance range) and average operating costs of $CA 2.2 million per month (the mid-point of guidance range).

Current Estimated Production 3,900 boe/d(1) 2016 Full Year Production Guidance 3,400 to 3,800 boe/d(1) Production Split 88% oil, 3% NGLs, 9% gas LMR 3.13(2) 2016 Ending Debt to Trailing Funds Flow from Operations 3.7x(3) 2016 Corporate Payout Ratio 57%(3) Dividend $0.06 per share (annualized) US Tax Pools $US 173 million CDN Tax Pools $CA 198 million

Ticker Shares Outstanding (basic) 42.5 million 52 Week Range $0.40 - $2.79 Recent price $0.68(1) Average daily trading volume (30 day) 79,650 shares Market Cap $27.6 million Equity Research Acumen Capital Partners Paradigm Capital Scotiabank Global

TSX: EGL

Market Data

Notes: 1) TSX closing price on August 5, 2016.

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2016 Q2 Highlights

Notes: 1) For more information, see Eagle’s news release issued on August 4, 2016.

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• Achieved quarterly production in excess of 4,100 barrels of oil equivalent per day (“boe/d”) for the first time in

the history of Eagle, and expects 2016 average production to be at the upper end of the guidance range.

• Reduced per boe operating costs (inclusive of transportation) by 12% from the first quarter of 2016 and 16%

from the prior year’s comparative quarter.

• Assumed operatorship of the Dixonville properties (where Eagle holds a 50% working interest) on June 1, 2016,

thereby allowing Eagle to commence pipeline upgrades in order to bring “behind-pipe” production on-stream; upgrades which the former operator, being in receivership, was not capitalized to complete. Eagle expects to add 200 to 250 boe/d of production (gross to the field) by the end of 2016.

• Grew second quarter production 8% when compared to the first quarter of 2016, more than doubled second

quarter funds flow from operations to achieve $5.1 million and expects a year end 2016 debt to trailing funds flow from operations ratio of 3.7 times.

• Successfully drilled the second well of its two well drilling program at Salt Flat in Texas, with costs coming in

considerably under budget. The first well came on production in April and the second well at the end of June, with the drilling program exceeding expectations from both a cost control and productivity perspective.

“Eagle is on track to post results at the upper end of our production guidance, the lower end of our operating cost guidance and as planned for our capital spend.”

Credit Agreement

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 Sustained weakness in global commodity prices resulted in downward pressure on the price decks used by lenders to determine borrowing base levels. Results of the semi-annual redetermination finalized on May 31, 2016 set the borrowing base level at $CA 70 million and left the May 27, 2017 maturity date of the credit agreement unchanged.  At June 30, 2016 there were no covenant violations under or in connection with the credit agreement.  Eagle accelerated a portion of its 2016 capital program into the first quarter and by the end of the second quarter was 80% through its 2016 capital budget of $5.0 million. For the second, third and fourth quarters of 2016 combined, it is therefore expected that:  funds flow from operations will exceed capital expenditures;  year end 2016 debt will be reduced to approximately $58 million;  the year end debt to trailing funds flow from operations ratio will be approximately 3.7 times  Pursuant to the new term in its credit agreement that restricts Eagle from paying dividends exceeding half a cent per share per month, Eagle has reduced its monthly dividend to half a cent per share per month beginning with the June 2016 dividend.

Notes: 1) For more information, see Eagle’s unaudited interim condensed consolidated financial statements for the six months ended June 30, 2016 and related management’s discussion and analysis for a summary of the significant amendments made to the credit agreement.

2016 Guidance

Notes:

(1)

The 2016 capital budget of $CA 5.0 million consists of $US 3.0 million for Eagle’s operations in the United States and $0.8 million for Eagle’s operations in Canada. At an assumed $US 47.50 per barrel WTI oil price, Eagle’s 2016 capital budget of $5.0 million and dividend of $0.005 per common share of Eagle per month ($0.06 per share annualized) results in a corporate payout ratio of 57%.

(2)

2016 average production is expected to consist of 88% oil, 9% natural gas and 3% NGLs and includes both working interest production and royalty interest production.

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Eagle’s 2016 capital budget, average production and operating cost guidance remains unchanged from what Eagle previously announced on May 5, 2016 and June 6, 2016 as follows:

2016 Guidance Notes Capital Budget $5.0 million (1) Average Production 3,400 to 3,800 boe/d (2) Operating Costs per month $2.0 to $2.4 million

“Eagle expects 2016 average production to be at the upper end of the guidance range.”

Build Financial Liquidity Stable Production Capital Discipline

Sustainable Business with Growth Potential

Exercising Fiscal Prudence and Discipline in a Low Commodity Price Market

“We intend to continue to monitor and realign our business to operate near or within our cash flow.”

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2016 Expected Funds Flow from Operations and Corporate Payout Ratio

Notes: (1) 2016 funds flow from operations is expected to be approximately $CA 15.6 million based on the following assumptions: (a) average production of 3,800 boe/d (the upper end of the guidance range); (b) pricing at $US 47.50 per barrel WTI oil, $CA 2.47 per Mcf AECO gas and $US 16.63 per barrel of NGL (NGL price is calculated as 35% of the WTI price); (c) differential to WTI is $US 3.10 discount per barrel in Salt Flat, $US 3.50 discount per barrel in Hardeman, $CA 16.17 discount per barrel in Dixonville and $CA 12.67 discount per barrel in Twining; (d) average operating costs of $CA 2.2 million per month ($US 0.8 million per month for Eagle’s operations in the United States and $CA 1.1 million per month for Eagle’s operations in Canada), the mid-point of the guidance range; (e) foreign exchange rate of $US 1.00 equal to $CA 1.30; and (f) field netback (excluding hedges) of $16.82 per boe. (2) Eagle calculates its Basic Payout Ratio as follows: (3) Eagle calculates its Corporate Payout Ratio as follows: (4) Funds flow from operations, field netback, basic payout ratio and corporate payout ratio are non-IFRS measures. See the “Advisory regarding Non-IFRS Financial Measures” at the beginning of this presentation.

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Amount Funds Flow from Operations $15.6 million (1) Basic Payout Ratio 27% (2) Plus: Capital Expenditures 30% Equals: Corporate Payout Ratio 57% (3)

Eagle’s expected funds flow from operations and corporate payout ratio are calculated as follows:

Shareholder Dividends = Basic Payout Ratio Funds Flow from Operations Capital Expenditures + Shareholder Dividends = Corporate Payout Ratio Funds Flow from Operations

2016 Sensitivities

2016 Average WTI (Average Production = 3,800 boe/d) $US 37.50 (F/X 1.35) $US 47.50 (F/X 1.30) $US 57.50 (F/X 1.25)

Funds Flow from Operations

$14.4 million $15.6 million $15.9 million

Corporate Payout Ratio

62% 57% 56%

Debt to Trailing Funds Flow from Operations

4.1x 3.7x 3.6x 2016 Average Production (boe/d) (WTI = $US 47.50 / F/X 1.30) 3,700 3,800 3,900

Funds Flow from Operations

$15.1 million $15.6 million $16.1 million

Corporate Payout Ratio

59% 57% 55%

Debt to Trailing Funds Flow from Operations

3.9x 3.7x 3.6x

Assumptions:

1)

Annualized dividends are assumed to be $0.06 per share per year ($212,000 per month).

2)

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

3)

Differential to WTI is held constant.

4)

Foreign exchange rate is assumed to be $US 1.00 equal to $CA 1.30 unless otherwise indicated in the table.

5)

2016 average production is assumed to be 3,800 boe/d (the upper end of the guidance range).

11 Sensitivity to Commodity Price Sensitivity to Production

• Eagle’s 2016 capital budget is $5.0 million:

Texas and Oklahoma ($US 3.0 MM)

• Salt Flat Property
• 2 (2.0 net) horizontal oil wells
• Seismic processing, facilities, pump changes
• Hardeman Property
• Seismic processing, pump installs

Alberta ($0.8 MM)

• Dixonville Property (Non-operated)
• Pipeline and facilities capital
• Twining Property
• Facility Capital

2016 Capital Budget

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

“To the end of the second quarter of 2016, Eagle is 80% through its capital budget, with the program exceeding expectations from both a cost control and productivity perspective.”

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• 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
• 57 gross (33 net) producing oil wells, 9 gross (2 net) producing gas wells
• Approximately 41,500 gross (32,650 net) acres
• Dixonville Properties, AB:
• Appointed operator effective June 1, 2016
• Located 50 kms northwest of Peace River
• 78 gross (39 net) producing oil wells
• 81 gross (41 net) water injectors
• 19,520 gross (7,900 net) acres
• Other Properties (WCSB), AB
• Salt Flat Properties, TX:
• Located in Salt Flat field in Caldwell County, TX
• 54 gross (41 net) producing oil wells
• 3,200 (2,600 net) acres
• Hardeman Properties, TX & OK:
• Located in Hardeman Basin in Hardeman County, TX, and Greer, Harmon and

Jackson Counties, OK

• 44 gross (34 net) producing oil wells
• 28,000 acres (18,000 held by production plus 10,000 undeveloped)

Our Properties

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CDN Properties – Twining Field (Alberta)

• 70% average working interest production to Eagle from the largest Pekisko oil pool in the Western

Canadian Sedimentary Basin

• 70% light oil and natural gas liquids
• 57 gross (33 net) producing oil wells, 9 gross (2 net) producing gas wells
• 30° API medium/light oil, 4 mD permeability and 7-8% average porosity
• 41,500 gross (32,650 net) acres
• Approx. 70 km from

Three Hills, AB

• R

• R

• R

• R

• R

• R

• R

• R

• R

• R

• R

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

• 0.05

• 0.05

Lower MNVL Upper Pekisko Middle Pekisko Lower Pekisko Banff

Layer 1 Layer 2 Layer 3 Layer 2C Layer 2B Layer 4

Pekisko Type Log

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CDN Properties – Twining Field (Alberta)

Source: IHS public data to April 30, 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 and

facilities and G&G software

Low declines

• Decline rate below 5%

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Twining Pekisko Pool Production History

• Appointed operator effective June 1, 2016
• 50% working interest in a horizontal oil waterflood in the Montney “C” Formation
• Primary development started in 2004 with full scale waterflood by 2012
• 78 gross (39 net) producing oil wells, 81 (41 net) water injectors
• 30◦API Oil, 18 mD permeability and 16-26% average porosity
• Approximately 19,520 gross (7,900 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)

Source: IHS public data

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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)

• Over 50

producing non-operated royalty interest wells

• 10 non-
• perated

working interest wells

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(1)

As of January 1, 2016, calculated by Eagle’s internal qualified reserves evaluator.

US Properties – Salt Flat (Texas)

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 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 Greer, Harmon and Jackson Counties, Oklahoma

28,000 gross acres of land

• 18,000 acres held by production
• 44 gross (34 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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• Eagle’s coverage through its 2016 hedging program is well above the 25% weighted average hedge position of its

junior peers(1)

• For the remainder of 2016, Eagle has an average 1,666 bbls/d hedged at WTI $US 51.37, which is

approximately 44% of expected production

• 1,429 Mcf/d (240 boe/d) of natural gas hedged at $CA 2.97/Mcf
• A differential hedge between the Edmonton Light Sweet oil price and the WTI oil price at $US 3.65 per barrel
• n 1,000 bbl/d
• For 2017, hedges are in place covering 750 barrels of oil per day at $US 45.00/bbl

Hedging Program

Note: 1) Source: Company Reports; National Bank of Canada, “Canadian Producer Hedge Positions – Q1 2016” issued on June 6, 2016.

Q1 2016 $US 55.86 Q2 2016 $US 51.61 Q3 2016 $US 51.42 Q4 2016 $US 51.33 2016 Avg Hedged Oil Price = $US 52.30 2016 Avg Hedged Gas Price = $CA 3.00/Mcf 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 % Hedged BOE/D

2015 Year-End Reserves Highlights

+10% Increase in year-over-year proved developed producing (PDP) reserves +14% Increase in year-over-year total proved reserves +16% Increase in year-over-year total proved plus probable reserves volumes 234%(1) Stability reflected in total proved reserves replacement ratio 307%(1) Strong total proved plus probable reserves replacement ratio

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Note: 1) The reserves replacement ratios are calculated by dividing total reserve additions by total working interest production for the year.

• Total proved plus probable reserves of approximately 18.6 million boe (70% proved, 58% proved producing)
• PV10 value on total proved plus probable reserves of approximately $229 million
• Proved plus probable reserve life index of 14 years(2)

McDaniel & Associates Price forecast (as of Jan 1, 2016)

2015 Year-End Reserves(1)

Excellent year-over-year reserve 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, 2015. Note that reserves associated with the January 27, 2016 acquisition of Maple Leaf are not in these figures. 2) The reserve life index calculation is based on average daily production of 3,400 boe/d.

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Year WTI Crude Oil $/bbl 2016 45.00 2017 53.60 2018 62.40 2019 69.00 2020 73.10

$141 $8 $24 $56

PV10 Value ($MM)

PDP PDNP PUD Probable

58% 2% 10% 29%

Reserves by Category

PDP PDNP PUD Probable

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 - CEO Wayne Wisniewski Petroleum Engineering- Anders Energy, Occidental Petroleum Pennzoil E&P BP - Various Senior Leadership Engineering and Operations Roles Eagle – President & COO Kelly Tomyn Controller - Various Junior O&G Companies CFO - Various Junior O&G Companies Eagle - CFO Scott Lovett Senior Reserves Evaluator - GLJ Petroleum Consultants Business Development - Shiningbank Energy; Enerplus Business Development, COO - Native American Res. Ptnrs Eagle - EVP, Bus Dev Jo-Anne Bund Corporate Securities Lawyer at a Boutique Oil and Gas Law Firm Senior Legal Counsel - Alberta Securities Commission Corporate Securities Lawyer at a National Law Firm In-House Corporate Counsel Eagle - General Counsel & Corporate Secretary

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Value Proposition Why Invest in Eagle?

• Stable production base
• Capital discipline
• Experienced management team
• Focus on improving cost efficiencies

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APPENDIX

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

Wayne Wisniewski, P.E., MBA, President and 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

Continued..

Management

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Continued… Scott Lovett,

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

• 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

• 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) 2016 average production guidance includes both working interest and royalty interest production (shown at the upper end of the 3,400 to 3,800 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 2016 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 3,800

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