Corporate Presentation

EXPERTISE • QUALITY • INCOME
TSX: EGL
EAGLE ENERGY INC.
Investor Presentation | August 2016
Advisories
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
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 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.
2
Strategy
“Eagle is created to provide investors with a sustainable business while
delivering stable production and overall growth through accretive investments
and acquisitions.”
Expertise
Quality
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.
Income
Eagle strives to deliver a sustainable business
to its shareholders.
3
Corporate Profile
Current Estimated Production
2016 Full Year Production Guidance
Production Split
3,900 boe/d(1)
3,400 to 3,800 boe/d(1)
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
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). 4
Market Data
Ticker
TSX: EGL
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
Notes:
1)
TSX closing price on August 5, 2016.
5
2016 Q2 Highlights
“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.”
•
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.
Notes:
1)
For more information, see Eagle’s news release issued on August 4, 2016.
6
Credit Agreement

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.
7
2016 Guidance
“Eagle expects 2016 average production to be at the upper end of the guidance
range.”
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
$5.0 million
(1)
Average Production
3,400 to 3,800 boe/d
(2)
Operating Costs per month
$2.0 to $2.4 million
Capital Budget
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.
8
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.”
Build
Financial
Liquidity
Stable
Production
Capital
Discipline
Sustainable
Business with
Growth
Potential
9
2016 Expected Funds Flow from Operations
and Corporate Payout Ratio
Eagle’s expected funds flow from operations and corporate payout ratio are calculated as follows:
Amount
Funds Flow from Operations
$15.6 million
(1)
Basic Payout Ratio
27%
(2)
Plus: Capital Expenditures
30%
Equals: Corporate Payout Ratio
57%
(3)
Notes:
(1)
(2)
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.
Eagle calculates its Basic Payout Ratio as follows:
Shareholder Dividends
=
Basic Payout Ratio
Funds Flow from Operations
(3)
Eagle calculates its Corporate Payout Ratio as follows:
Capital Expenditures + Shareholder Dividends
=
Corporate Payout Ratio
Funds Flow from Operations
(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.
10
2016 Sensitivities
Sensitivity to Commodity Price
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
Debt to Trailing Funds Flow from
Operations
62%
57%
56%
4.1x
3.7x
3.6x
Sensitivity to Production
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
Debt to Trailing Funds Flow from
Operations
59%
57%
55%
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
2016 Capital Budget
“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.”
•
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
Note:
1) The capital budget excludes future corporate and property acquisitions, which are evaluated separately on their own merit.
12
Our Properties
•
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)
13
CDN Properties – Twining Field (Alberta)
Pekisko Type Log
100/02-07-032-24W4/00
GR
0
L1_SONIC_POROSITY_CALC
0.15
-0.05 0.1
CORE_POROSITY_SHIFTED
0.15
-0.05 0.1
150
CAL
125
375
CORE_KMAX_SHIFTED
1000
IL
1000
T33N-R25W
1610
T33N-R24W
1620
Lower MNVL
Upper Pekisko
Middle Pekisko
1640
1630
W
T32N-R25W
T32N-R24W
Layer 1
1650
06/21/1973
1660
Layer 2
Lower Pekisko
Layer 2B
W
Layer 4
Approx. 70 km from
Three Hills, AB
T31N-R25W
T31N-R24W
1700
Banff
Layer 3
1690
1680
1670
Layer 2C
•
•
•
•
•
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
HS=900
14
CDN Properties – Twining Field (Alberta)
Interests in the largest Pekisko oil pool in
the WCSB
Twining Pekisko Pool Production History
Significant upside potential
•
10 horizontal wells drilled to date with
over 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%
Source: IHS public data to April 30, 2016
15
CDN Properties – Dixonville (Alberta)
50 km from
Peace River
•
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
16
CDN Properties – Dixonville (Alberta)
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
operations, trucking and marketing
Long-term potential
• Decline rate below 10%
Refurbished, optimized gathering system
Source: IHS public data
• 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
17
CDN Properties – Other - Western Canadian
Sedimentary Basin
Acquired interests in attractive
Alberta plays located in the
WCSB effective January 27,2016
•
•
Over 50
producing
non-operated
royalty
interest wells
•
10 nonoperated
working
interest wells
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)
(1)
As of January 1, 2016, calculated by Eagle’s internal qualified reserves evaluator.
18
18
US Properties – Salt Flat (Texas)
Light oil producing
o
• 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
19
US Properties – Hardeman (Texas &
Oklahoma)
Light oil producing
o
• 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
operating costs, while processing newly
acquired seismic data to define future
drilling opportunities
20
Hedging Program
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
on 1,000 bbl/d
For 2017, hedges are in place covering 750 barrels of oil per day at $US 45.00/bbl
BOE/D
•
3400
3200
3000
2800
2600
2400
2200
2000
1800
1600
1400
1200
1000
800
600
400
200
0
60%
50%
40%
30%
20%
10%
0%
Q1 2016 $US 55.86
Q2 2016 $US 51.61
2016 Avg Hedged Oil Price = $US 52.30
Note:
1)
Q3 2016 $US 51.42
Q4 2016 $US 51.33
2016 Avg Hedged Gas Price = $CA 3.00/Mcf
Average % Hedged
Source: Company Reports; National Bank of Canada, “Canadian Producer Hedge Positions – Q1 2016” issued on June 6, 2016.
21
% Hedged
•
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
Note:
1) The reserves replacement ratios are calculated by dividing total reserve additions by total working interest production for the year.
22
2015 Year-End Reserves(1)
Excellent year-over-year reserve performance
•
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 $229 million
•
Proved plus probable reserve life index of 14 years(2)
Reserves by Category
PV10 Value ($MM)
McDaniel & Associates
Price forecast
(as of Jan 1, 2016)
Year
WTI Crude Oil
$56
29%
$/bbl
2016
45.00
2017
53.60
2018
62.40
2019
69.00
2020
73.10
58%
$24
$141
10%
$8
2%
PDP
PDNP
PUD
Probable
PDP
PDNP
PUD
Probable
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.
23
Management Experience
• Eagle’s management team has an average of 25 years of experience
Years
Richard Clark
Wayne
Wisniewski
Kelly Tomyn
Scott Lovett
Jo-Anne Bund
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Corporate Finance Law - Shiningbank Energy Trust General Counsel
Petroleum EngineeringAnders Energy,
Occidental Petroleum
Controller - Various Junior
O&G Companies
Pennzoil E&P
15
16
17
18
19
Corporate Finance Law
20
21
Corporate Securities Lawyer at a Boutique Oil
and Gas Law Firm
24
25
26
BP - Various Senior Leadership Engineering and Operations
Roles
Business Development Shiningbank Energy;
Enerplus
Senior Legal
Counsel Alberta
Securities
Commission
23
27
28
Eagle - CFO
In-House
Corporate
Counsel
30
Eagle – President
& COO
Business
Development,
Eagle COO - Native EVP, Bus
American Res.
Dev
Ptnrs
Corporate Securities
Lawyer at a National
Law Firm
29
Eagle - CEO
CFO - Various Junior O&G Companies
Senior Reserves Evaluator - GLJ Petroleum
Consultants
22
Eagle - General
Counsel &
Corporate
Secretary
24
Value Proposition
Why Invest in Eagle?
•
Stable production base
•
Capital discipline
•
Experienced management team
•
Focus on improving cost efficiencies
25
APPENDIX
26
Management
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..
27
Management
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
28
Board of Directors
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
of Shiningbank
29
Production History
Average WI Production per Quarter (boe/d)
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
Production
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
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
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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