JULY PRESENTATION - Delphi Energy Corp. · JULY PRESENTATION. BIGSTONE –PROLIFIC, LIQUIDS RICH...
Transcript of JULY PRESENTATION - Delphi Energy Corp. · JULY PRESENTATION. BIGSTONE –PROLIFIC, LIQUIDS RICH...
July 17, 2018
JULY PRESENTATION
BIGSTONE – PROLIFIC, LIQUIDS RICH MONTNEY
July 2018 2
Grande Prairie
Bigstone
Montney
Edmonton
Calgary
Successful delineation drilling
to the west and south
Growing condensate production
and high stable yields
Integration of owned
infrastructure leading to lower
operating costs
Alliance / Chicago natural gas
market access
Pure play MONTNEY E&P company with WORLD
CLASS ASSETS:
2018 GUIDANCE FOR SECOND HALF 2018
3July 2018
2018 capital program supported by
significant production and cash flow growth
through 2017
Condensate growth of 27% in Q1/18 over
Q1/17
Cash netbacks in Q1/18 23% greater than
Q1/17
Delineation drilling success sets up
multiple options for “ultra-rich” condensate
locations in 2018 and beyond
Production data from new wells important
input for 2H/18 planning
First Half 2018 capital program
7 new wells on production in 1H/18
1H/18 forecast takes into account production
downtime for new well completions and
amine plant construction/commissioning
Phase 1 Amine plant on-stream
Second Half 2018 capital program
4 new wells on production in 2H/18
Strong return on capital, increased cash flow largely
driven by continued condensate production growth
2018 Second
Half Guidance (1)
2018 Full Year
Guidance
Net capital program ($ million) $29 - $33 $75 - $80
Well count drilled 4 (2.6 net) – 5 (3.3 net) 8 (5.2 net)
Well count on production 4 (2.6 net) 11 (7.2 net)
Average production (boe/d) 10,000 – 10,400 10,000 – 10,200
Natural gas (mmcf/d) 37.0 – 37.5 36.0 – 36.5
Field condensate (bbls/d) 2,500 – 2,650 2,600 – 2,650
NGL’s (bbls/d) 1,400 – 1,500 1,450 – 1,500
Percent liquids (%) 40 - 41 40
Adjusted funds flow (“AFF”) ($
million)
$25 - $27 $50 - $54
Net debt (2) $160 – $166 $160 – $166
Net debt / AFF (annualized) 3.1 3.1
2018 Q4
Guidance
2017 Q4
Actuals
%
Change
Average production (boe/d) 10,600 – 10,900 9,588 12
Natural gas (mmcf/d) 38.5 – 39.0 35.4 9
Field condensate (bbls/d) 2,700 – 2,900 2,374 18
NGLs (bbls/d) 1,450 – 1,500 1,315 12
Percent liquids (%) 40 38 --
Adjusted funds flow (including
hedges) ($ million)
$14.5 - $15.0 $14.1 5
Adjusted funds flow (excluding
hedges) ($ million)
$18.0 - $18.5 $13.3 40
(1) Based on WTI crude oil price of $68 per barrel, NYMEX Henry Hub natural gas price of $2.95 per mmbtu and FX of 1.327
CAD per USD.
(2) Net debt is defined as the sum of bank debt, senior secured notes and the long term portion of unutilized take-or-pay contract
plus (minus) the working capital deficit (surplus) excluding the current portion of the fair value of the financial instruments.
MANAGING THROUGH COMMODITY PRICE CYCLES
July 2018 4
$(5.00)
$-
$5.00
$10.00
$15.00
$20.00
$25.00
Q1
/12
Q3
/12
Q1
/13
Q3
/13
Q1
/14
Q3
/14
Q1
/15
Q3
/15
Q1
/16
Q3
/16
Q1
/17
Q3
/17
Q1
/18
Netback w/o Hedge Hedge Gain
Focus on Montney
Margin Growth
Prolonged price weakness
protected by hedges
Early Stage Montney
Production GrowthReturn to Montney
Production Growth
Ne
tba
ck (
$/b
oe
)
BIGSTONE MONTNEY GROWTH
July 2018 5
Montney Production Growth
0
2,000
4,000
6,000
8,000
10,000
2012 2013 2014 2015 2016 2017 1H2018
Boe/d
Gas Liquids Non-Montney
Liquids CAGR 63%
Nat. Gas CAGR 50%
Funding Bigstone Montney Source of Funding
Cash Flow52%
Dispositions28%
Equity13%
Debt7% Cumulative
Proceeds
Montney asset growth funded largely
through cash flow and non-core asset
dispositions
Life-to-date (LTD) capital includes land
acquisitions and facility infrastructure build
out
170 gross sections of land acquired
Ownership in 100+ mmcf/d field gathering and
plant processing capacity
Focus on margin growth and ROCE
$463 million
LTD Capital
0
2,000
4,000
6,000
8,000
10,000
$0
$100
$200
$300
$400
$500
2013 2014 2015 2016 2017 Q1/18
Cum Capital Cum Proceeds Debt Production
$ m
illio
ns
CONSISTENT ECONOMIC RESERVE GROWTH
July 2018 6
Montney Reserves (mboe)
52 wells (41.1 net) drilled LTD, 4 wells planned in
2H/18
2015/16 drilling focused on infill locations
2017 drilling focused on delineating west and south
lands
3-Year Montney PDP FD&A to YE 2017
$14.40/boe
Montney Development (2012 to 2018)
0
5,000
10,000
15,000
20,000
2012 2013 2014 2015 2016 2017
Re
se
rve
s (
mb
oe
)
Proved Developed Producing
Montney Other
Montney CAGR 63%
0
20,000
40,000
60,000
80,000
2012 2013 2014 2015 2016 2017
Re
se
rve
s (
mb
oe
)
Total Proved Plus Probable
Montney Other
4
6
8
6 6
15
11
2012 2013 2014 2015 2016 2017 2018
Montney Wells brought on Production
HOW DOES DELPHI’S BIGSTONE MONTNEY RANK:
7July 2018
DEE
DEE
Bigstone Montney economics driven by field condensate and NGL’s
Recognized as a top tier liquids-weighted asset
Among the highest IRRAmong the lowest break-even gas price
NETBACK COMPARISON – MONTNEY PRODUCERS
July 2018 8
Condensate yields, total liquids content and operating netbacks are among the highest
Operating netbacks continue to increase as:
• Focus on liquids-rich West Bigstone
• Amine sweetening facility reduces operating costs (third-party processing)
• Legacy production (10% of production; 2% of operating income) decreasing as a % of total
Sources: DEE; Company MD&As
0%
10%
20%
30%
40%
50%
60%
70%
-
5.00
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
DEE DEE Montney VII NVA KEL SRX CR BIR AAV
Netback(1) First Quarter 2018
Operating netback Royalties Operating Transportation % Liquids (Total) % Condensate
(1) Excluding hedges
BUILT A DOMINANT LAND POSITION
Montney land base has grown to 170
gross sections (111 net) from 4
sections in 2011
Significant land position allows for
efficient operations, control over
infrastructure and scalable
development
19+ year drilling inventory* on
approximately 128 of 147
undeveloped sections:
400+ “Extended Reach HZ” locations
equivalent to 800+ “1 mile” industry locations
19 years of drilling inventory assuming a 3 rig
(21 well/year) program
Continue to identify and pursue
additional consolidation opportunities
* Based on 4 to 6 laterals per section and 1 to 2 layers across
the 128 sections, increasing in well density from NE to SW.
Refer to disclaimer for further details.
July 2018 9
Largest Land Position at Bigstone
July 2018 10
BIGSTONE INFRASTRUCTURE FULLY INTEGRATED
Amine plant
commissioned and
sending sweetened
Montney gas to Bigstone
14-28 natural gas
processing plant (25%
Delphi working interest)
West Bigstone 16-10
well producing to 100%
Delphi 11-03 sweet gas
plant
7-11 AMINE PLANT ON-STREAM
July 2018 11
Delphi
52 mmcf/d sour
dehydration and
compression
facility
Delphi
17 mmcf/d amine
plant to sweeten
Montney sour gas
BIGSTONE SWEET GAS PROCESSING PLANT
July 2018 12
Repsol / Delphi sweet natural gas processing plant
Delphi 25% working interest
85 mmcf/d capacity
significantly underutilized
Amine sweetened Montney gas now being processed here
Material operating cost savings
July 2018 13
NEW AMINE PLANT IMPROVES CASH NETBACK
• Commissioned April
2018
• Up to 17 mmcf/d (11
net) of raw gas
• Cash flow increases
by about $0.60/mcf(1)
on amine sweetened
gas sold on AECO
• Cash flow impact
increases to
$0.80/mcf once
Alliance lateral to
Bigstone gas plant is
reactivated
Notes:
(1) Assuming Delphi captures 75% of
the difference between netback
prices of Chicago via Alliance and
AECO via NGTL through use of
additional excess Alliance service to
generate marketing income.
SECURE MARKET ACCESS FOR GROWTH
July 2018 14
Alliance
• 57 mmcf/d of firm and priority interruptible service
• Access to premium pricing via Chicago City Gate
• Delphi captures value of excess service through assignment at a premium or marketing activity(1)
TCPL
• 24 mmcf/d firm service
• Low cost service for growth beyond 2018
Delphi/Alliance
Full Path Service to Chicago
(1) Delphi captures the value of excess Alliance firm service either by assigning it to 3rd parties at a premium above cost or by using it to transport
3rd party natural gas purchased in Alberta/BC and sold in Chicago to generate marketing income.
Contracted Transportation
Service (mmcf/d)
GAS MARKETING IN 2018 – 100% EXPOSED TO CHICAGO PRICING
July 2018 15
(1) Based on estimated average daily gas sales in the last nine months of 2018.
(2) Based on an average of 18 mmcf/d of excess firm service on Alliance and assumes that Delphi captures 75% of arbitrage between Chicago
and AECO.
• Approximately 80% of natural gas sold in Chicago generating
significantly higher pricing than AECO.
• AECO exposure is hedged through marketing income earned on
excess Alliance firm service.
Increase in
spread between
AECO and
Chicago
Change in
AECO revenue
($ mm/year)
Change in
premiums
earned on
excess Alliance
service (2)
($mm/year)
Change in
cash flow
($mm/year)
US$0.20 /
mmbtu
(1.0) 1.3 0.3
Delphi Cash Flow Sensitivity to AECO-Chicago Basis
Worsening AECO-Chicago basis increases
Delphi cash flow in 2018
Natural Gas Sales by Market in 2018 (1)
Chicago Gas Sales in 2018 (1)
CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSET
July 2018 16
(1) Based on strip pricing as of May 17, 2018
• The undiscounted value of the arbitrage between AECO and Chicago netback prices available
through Delphi’s Alliance service is approximately $25 million through 2021.
Value of AECO-Chicago Arbitrage Available through
Delphi’s Alliance Transportation Service
Arbitrage between AECO and Chicago Available
through Delphi’s Alliance Transportation Service(1)
Delphi’s Alliance service worth approximately $25 million (1)
PROVEN RISK MANAGEMENT PROGRAM
Majority of near term production is
hedged
Event driven natural gas hedging
strategy with a long term view of
relatively balanced supply & demand;
Strategy is proven and repeatable
over 2 - 4 year “peak to trough”
event cycles
Risk management contracts generally
put in place over a 12 - 48 month period
Over an 11 year period risk
management program has:
Realized $113 million in hedging
gains
Increased revenues by 9%
Increased cash flow by 20%
Added $3.65/boe to netback
July 2018 17
Consistent Hedge Performance
-$15
-$10
-$5
$0
$5
$10
$15
$20
$25
$30
$35
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Hedging Gains/Losses ($millions)
Cold winter lifting natural
gas prices in 2014
Natural gas
price spike in
2008Steady decline of natural
gas prices from 2009 to
2013
Collapse of natural gas and
crude oil prices
Commodity Hedges Q1 2018 Q2 2018 Q3 2018 Q4 2018 2019
Natural gas (mcf/d) 20.0 21.0 21.0 17.4 10.2
Average hedge price
(C$/mcf)3.62 3.61 3.62 3.64 3.41
Crude oil (bbl/d) 2,256 2,500 2,100 2,100 798
Average hedge price
(C$/bbl)70.50 71.20 72.41 72.41 72.91
OPERATIONS UPDATE
July 2018 18
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
San
d L
b/f
t
`
Gen 1
Gen
2
Gen 3
Gen 4
Gen 5
Gen 6
West Bigstone
19July 2018
Montney Frac Generation Design Evolution
UNDERSTANDING RESULTS OF EVOLVING FRAC DESIGN
East Bigstone
$0
$5,000
$10,000
$15,000
$20,000
$/b
oe
pd
Montney Drill & Complete Capital Efficiency
IP30 IP90
Evolution to significantly more
sand moving to West Bigstone
More at West - less at East
Optimizing frac sizes to
maximize capital efficiency
Mill / clean-out of a ball drop
liner in a 2017 pad well brought
production back in line with
expectations
Successful result of 65 stage
hybrid frac at 16-10 West
Bigstone (Gen 6)
On-going testing of new ball
drop technologies
July 2018 20
Initial production
performance of 13-9
(and other pad wells)
was below expectations
A partial mill/clean-out
of the ball drop liner has
brought production
back in-line with
expectations
Offset FracWell
clean-out
Field Condensate up 66%
Natural Gas up 50%
14 days 18 days
UNDERSTANDING PAD WELL OPERATIONS / RESULTS
MONTNEY ECONOMIC MODEL
July 2018 21
Note: See Montney Economic Model Assumptions in the Forward Looking Statement and Important Notes
Economics/Metrics - Flat Pricing: WTI US$65/bbl, NYMEX US$2.80/mmbtu
Type Rich Type
Well Well
Payout yrs 1.6 1.4
IRR % 53% 74%
NPV 10 MM$ $4.5 $9.3
PI 1.6 2.3
F&D $/boe $7.31 $6.34
Target Capital
D,C,E&TI MM$ $7.0 $8.0
Initial Sales Production (IP30 - first 30 day average)
Gas mmcf/d 5.1 3.6
Field Condensate(2) bbl/mmcf 86 183
Total Liquids (C3+)(2,3) bbl/mmcf 129 227
Total Liquids (C3+)(2,3) bbl/d 662 822
Total IP30 boe/d 1,515 1,426
IP365 (first 365 day average)
Gas mmcf/d 2.9 2.2
Field Condensate(2) bbl/mmcf sales 58 114
Total Liquids (C3+)(2,3) bbl/mmcf sales 101 158
Total Liquids (C3+)(2,3) bbl/d 294 348
Total IP365 boe/d 778 717
Reserves (sales)
Gas bcf 3.7 4.0
Liquids (C3+)(2,3) mmbbl 0.3 0.6
Total mmboe 1.0 1.3
Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Wells
30+ stage Slickwater Completion
INCREASING CONDENSATE YIELDS
July 2018 22
Condensate Gas Ratios Significantly Greater in West Bigstone with Frac Design Changes
15-10
10-27
16-23
15-24
15-3011-17
15-21
13-30
2-1
2-78-2116-15
3-26
13-2316-27
12-2716-24
13-24
14-30
14-2414-27
13-21
15-2314-11
16-9
14-21
16-21
15-8
15-11
13-15
15-9
13-9
13-17
14-9
16-18
13-10
9-8
0
50
100
150
200
250
0 50 100 150 200 250 300 350
IP1
80
CG
R (
bb
l/m
mcf
sale
s)
IP30 CGR (bbl/mmcf sales)
Delphi Bigstone Montney - IP180 CGR vs. IP30 CGR
West Type Well - Stabilized CGRType Well - Stabilized CGR
West wells
East wells
Initial Production (IP) Rate Well Performance (1)
Delphi Bigstone Montney
Total Sales Field CGR Total Sales Field CGR Total Sales Field CGR Total Sales Field CGR
(boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf)
Average West Wells 1,062 238 843 177 684 151 563 135
Average East Wells 1,361 109 1,146 81 971 70 768 61
Average All Wells 1,271 148 1,059 109 897 91 730 75
(1) Average production for 2 mile, toe-up, slickwater fraced wells calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes.
IP30 IP90 IP180 IP365
INCREASING NETBACKS
July 2018 23
Field Condensate on a BOE basis↑ Higher realized price
↓ Lower operating cost
↓ Lower transportation cost than
natural gas
% Change
West vs East
Revenue 25%
Royalty 25%
Operating costs (15%)
Transportation (2%)
Netback 47%
(1) Based on US$ 65 WTI, US$2.80 NYMEX gas, 2018 estimated field differentials, operating costs and transportation costs per unit for each
product stream and average royalty rates.
Corporate netbacks increase with addition of higher condensate yield wells
Impact of Production Composition on IP90 Operating
Netback for Bigstone Montney(1)
$3 $3 $3
$9 $8 $7
$5 $5 $5
$21 $23
$32
-
5.00
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
50.00
East All Wells West
Reve
nu
e ($
/BO
E)
Royalties Opcosts Transportation Operating netback
2H 2018 MONTNEY DRILLING PLANS
July 2018 24
Offsetting successful delineation
at West Bigstone
16-10 IP30:
913 bbls/d field condensate
1,434 boe/d 66% liquids
15-19 IP90:
605 bbls/d field condensate Highest yet for Delphi
1,300 boe/d 58% liquids
119 gross locationsbased on single Montney layer
5 to 6 wells per section
15-19
16-10
FORWARD-LOOKING STATEMENTS
AND IMPORTANT NOTES
The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relateto future events or the Company’s future performance and are based upon the Company’s internal assumptions and expectations. All statements other than statements ofpresent or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words “expect”,“anticipate”, “continue”, “estimate”, “may”, “will”, “should”, “believe”, "intends”, “forecast”, “plans”, “guidance”, “budget” and similar expressions. More particularly and withoutlimitation, this presentation contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crudeoil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general andadministrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi’s ability to fund ongoingcapital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of developmentand exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimesand tax laws and future environmental regulations. Furthermore, statements relating to “reserves” are deemed to be forward-looking statements as they involve the impliedassessment, based on certain estimates and assumptions that the reserves described can be profitable in the future. The forward-looking statements and informationcontained in this presentation are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which theforward-looking statements and information contained in this presentation are based: the stability of the global and national economic environment, the stability of andcommercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management’sexpectations, production levels of Delphi being consistent with management’s expectations, the absence of significant project delays, the stability of oil and gas prices, theabsence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, includingoperating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oiland natural gas volumes, prices and availability of oilfield services and equipment being consistent with management’s expectations, the availability of, and competition for,among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistentwith management’s expectations, weather affecting Delphi’s ability to develop and produce as expected, contracted parties providing goods and services on the agreedtimeframes, Delphi’s ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates,the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi’s ability to market oil and natural gas successfully tocurrent and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that theCompany relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meettiming and production expectations. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply anddemand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of materialvariances from previously communicated expectations. Financial outlook information contained in this presentation about prospective results of operations, financial positionor cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of therelevant information currently available. Readers are cautioned that such financial outlook information contained in this presentation should not be used for purposes otherthan for which it is disclosed. Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can giveno assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements andinformation address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi’s actual results,performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be giventhat any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive therefrom. Should one ormore of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from thosecurrently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such asoperational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, theuncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation,environmental risks, competition from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmentalregulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect theCompany’s operations or financial results are included in the Company’s most recent Annual Information Form and other reports on file with the applicable securitiesregulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Readers are cautioned that the foregoing list of factors is not exhaustive.Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation for the purpose of providing the readers with theCompany’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligationto update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required byapplicable securities laws. The forward-looking statements contained in this presentation are expressly qualified in their entirety by this cautionary statement.
July 2018 25
FORWARD-LOOKING STATEMENTS
AND IMPORTANT NOTESThe following criteria reflects Montney economic modeling assumptions herein the presentation. 1. Flat pricing: NYMEX $2.80/mmbtu US, $3.59/mmbtu CDN; WTI
$65.00/bbl USD; C5 $78.77/bbl CDN. 2. Type Well stabilized field condensate beyond month six is 45 bbl/mmcf sales; Rich Type Well stabilized field condensate
production beyond month one is 103 bbl/mmcf sales. 3. C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 44 bbl/mmcf sales. 4.
Type Well reserves and production performance are internal management estimates and were prepared by a qualified reserves evaluator in accordance with the COGE
Handbook. 21 horizontal, toe-up Montney wells at East Bigstone with at least 30 stage fracs were time normalized, averaged and used to determine a proved plus probable
reserve estimate. 5. Six horizontal Montney wells at West Bigstone were time normalized, averaged and used to determine a proved plus probable reserve estimate. 6.
Type well reserve and production estimates are used for illustrative purposes and internal corporate planning and may not reflect the actual performance of future wells.
Economics are half cycle and include target capital to drill, complete, equip and tie-in. No costs for land, central facilities, field gathering infrastructure, corporate costs, etc.
are included.
For further details on the completion and clean-up test results of the 15-19-59-23W5 well, please see the Company’s press release dated January 16, 2018.
This presentation discloses the Company’s future potential drilling opportunities. Unbooked locations are internal estimates based on the Company’s prospective acreage
and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed
reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling
activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all
unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations
on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals,
seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the
unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling
locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty
whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
July 2018 26
APPENDIX
July 2018 27
INDIVIDUAL MONTNEY WELL DATA
July 2018 28
Initial Production (IP) Rate Well Performance (1)
Well(2) Frac Design Horizontal Number
Generation Length of Fracs Total Sales Field Condy Total Sales Field Condy Total Sales Field Condy Total Sales Field Condy
to Gas Yield to Gas Yield to Gas Yield to Gas Yield
(metres) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf)
Average 1st Gen Frac 2,668 20 1,213 48 807 36 557 33 397 31
Average 2nd Gen Frac 2,572 30 1,398 86 1,160 72 946 65 719 58
14-30 3rd 2,729 37 1,840 78 1,407 66 1,112 55 805 57
14-24(3) 3rd 2,602 37 1,119 132 976 92 792 76 585 65
14-27(3) 3rd 2,887 37 1,414 140 1,280 97 1,082 83 835 70
13-21(3) 3rd 2,781 37 1,204 252 1,077 194 962 166 679 172
15-23 3rd 2,865 37 1,153 93 909 66 779 54 612 47
14-11 3rd 2,846 42 1,212 106 1,028 65 870 53 642 49
16-09 4th 2,855 40 1,161 121 849 108 685 106 495 100
14-21 3rd 2,788 40 1,606 180 1,258 145 968 128 702 115
16-21 3rd 2,858 40 1,968 134 1,541 102 1,258 103 907 85
15-8 4th 2,740 40 1,243 216 1,118 185 890 152 659 137
15-11 3rd 2,866 40 1,375 80 1,178 54 929 46 656 43
13-15 3rd 2,891 40 1,579 106 1,205 85 943 73 664 69
15-09(3) 3rd 2,864 40 756 196 625 149 504 137 369 122
13-09(3) 4th 2,813 40 895 185 668 164 543 151
13-17(3) 3rd 2,876 40 562 112 575 69 486 62
14-09(3) 4th 2,863 40 865 213 677 160 542 139 407 126
16-18(3) 4th 2,881 40 500 182 605 87 519 69
13-10 4th 2,848 39 1,161 167 1,118 101 843 91
9-21(3) 4th 2,841 40 899 140 715 109
16-12 4th 2,859 39 717 300 618 217 546 191
9-8 4th 2,574 38 941 202 833 141 661 123
13-7 4th 2,847 40 753 245 652 189 540 172
14-15 5th 2,879 49 1,130 139 1,054 99 887 82
15-19 5th 2,862 49 1,828 228 1,300 183
14-10(3) 5th 2,856 47 902 132 790 99
16-07 5th 2,853 50 607 319 565 208
16-10 6th 2,855 65 1,434 310
16-11 4th 2,855 50 1,060 90 923 69
14-18 4th 2,875 50 1,306 156 1,083 103
16-19 5th 2,860 50 953 245 722 188
Average 3rd, 4th & 5th Gen Frac 2,829 42 1,138 173 943 124 788 105 644 90
(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes.
(2) Wells listed chronologically by rig release date.
(3) Initial production restricted.
IP30 IP90 IP180 IP365
2300, 333 – 7th Avenue SW
Calgary, Alberta T2P 2Z1
P (403) 265-6171
F (403) 265-6207
www.delphienergy.ca
July 2018 29