JULY 2017 UPDATE
1
INTRODUCTION
Started Sept 2010, fourth ‘Storm’ since Nov 1998
• history of discipline with capex & focus on per share growth
Market cap $480 MM ($4/share), TSX-V symbol “SRX”
• 121 MM shares + 8 MM options
• officer + director ownership 14% (16% FD)
Q1/17 prod’n 16,947 boe/d (17% NGL), +24% per share YOY
Q1/17 debt $98 MM (1.4 X funds flow), bank line $165 MM
Growth from developing Montney at Umbach (NE BC)
• large land position with multi-year hz drilling inventory, liquids rich
natural gas (36 bbls/mmcf Q1/17), hz rates & reserves getting better
Large resource in Horn River Basin, leverage to nat gas price
2
PRODUCTION
H2/17 forecast
19,000 to 21,000 boe/d
April – May/17 ~18,300 boe/d
Q2/17 est 14,000 boe/d, impacted by
McMahon GP turnaround June 5 to
July 10 (longer vs forecast June 5 - 26)
prod’n per share
+248% last 4 years
3
CASH COSTS PER BOE
Q1/17 prod’n cost $5.84/boe declined
14% from 2016 (prod’n growth & new
processing arrangement at Umbach)
transportation excluded from controllable cash costs as sales price
for volumes shipped on the Alliance Pipeline includes a deduction for
the pipeline tariff (artificially reduces transportation cost)
4
FUNDS FLOW
2017 funds flow
increases with prod’n
growth (+30%) & lower
costs (-$1.50/boe)
Q1/17 NGL + cond
~17% prod’n
~35% revenue
+$5/boe to revenue
5
COST OF RESERVE ADDITIONS
all-in reflects
total capital
investment
PDP FD&A
reflects actual
capital and
well results
1P & 2P FD&A
is based on
estimates of
future well
performance
& FDC
2016 PDP FD&A
$6.89/boe with
35% of capex for
infrastructure
expansion
(~full-cycle)
6
MAJOR AREAS
Umbach Montney
109,000 net acres
16,600 Boe/d*
Horn River Basin
large shale gas resource in HRB,
needs higher nat gas price
growth from Montney development
at Umbach (liquids rich nat gas)
78,000 net acres
300 Boe/d*
*Q1/17 production
7
UMBACH AREA (NE British Columbia)
Montney liquids rich gas
• 155 net sections
109,000 net acres
• raw gas 1,200 – 1,300 btu/scf
1% H2S requires sour gas plant
(McMahon or Stoddart GP’s)
access 3 sales pipelines
from McMahon GP
(to Chicago, Stn 2, AECO)
Q1/17 16,600 Boe/d
• Q1/17 liquids 36 bbls/mmcf,
60% condensate
Drill hz in 10 - 13 days
• shallow depth 1,550 metres
F&D $5 - $6/Boe (full-cycle)
• $4.3 MM/hz drill & complete
(2016 actual $3.8 MM/hz)
• SRX mgmt est 6.3 - 7.0 Bcf raw
InSite 2016 Upper Montney
2P ult 2.8 – 7.1 Bcf raw
Montney producing hz’s in grey
8
UMBACH LAND POSITION
Montney productive
across area
Storm’s lands still at
an early stage
• 2P on 21% of lands
• prod hz’s on 7% of lands
155 net sections
55.4 net hz’s drilled
planning ~4 hz’s/section
400 m interwell spacing
9
UMBACH ACTIVITY
total field compression
115 mmcf/d raw
(Q1/17 88 mmcf/d raw)
increase to 150 mmcf/d
raw for $7 MM
(supports growth to
27,000 boe/d)
inventory of 10 drilled
hz’s end Q1 with 2
completed hz’s
2016 hz’s
2017 hz’s
10
UMBACH HZ COSTS
accounting
system costs
incl pad, roads
2017 drill &
compl -19% per
frac vs 2016
costs declining
with lower
service costs
and operational
changes (mud
system, multiwell pads,
water logistics)
DRILLING hz’s fracs
2015
10 23
2016
12 31
2017
6 32
length
cost
1,295 m $2.0 MM
1,540 m $1.9 MM
1,540 m $1.9 MM
COMPL’N
2015
2016
2017
hz’s
11
10
4
fracs
22
25
35
length
cost
1,360 m $2.4 MM
1,300 m $1.9 MM
1,670 m $2.5 MM
11
UMBACH HZ PERFORMANCE
12
UMBACH TYPE CURVE
13
UMBACH HZ FIELD CONDENSATE RATES
14
UMBACH HZ ECONOMICS
using 7.0 Bcf
type curve based
on 2016 hz’s
incl G&A + interest
($1.78/boe 2016),
full-cycle ROR = 19%
BC Stn 2
$2.10/GJ
flat prices
15
UMBACH ADDITIONAL INFORMATION
Processing deal at McMahon GP reduced op cost eff Jan/17
• Q1/17 corporate op cost $5.84/boe, -14% vs 2016 avg
• committed ~70% current prod’n (55 mmcf/d raw for 15 years & 10
mmcf/d raw for 5 years) with ROFR to add up to 35 mmcf/d
Umbach Q1/17 field operating netback
• Stn 2 spot $2.36/GJ, ATP $2.93/GJ [1.25 GJ/mcf]
• Chicago spot US$2.95/mmbtu, monthly US$3.40/mmbtu [1.18 mmbtu/mcf]
• nat gas sales: ATP 6%, Stn 2 spot 30%, Chi spot 12 %, Chi monthly 52%
• Edm light $63.99/bbl
nat gas
$3.25/mcf price reduced by Alliance tariff $1.66/mcf
liquids
$47.95/bbl 75% Edmonton light oil price (60% is cond)
Revenue $24.53/boe 81,900 mcf/d, 2,930 bpd cond & NGL
Transport
$0.64/boe $0.07/mcf, $1.63/bbl
Royalties
$1.88/boe 7.7%
Op Cost
$5.68/boe op cost for Umbach only
Op Netback $16.33/boe
16
PROCESSING & TRANSPORTATION
To preserve operational & budget flexibility, target ~80% of
prod’n covered by firm processing & transport
Firm processing 75 mmcf/d raw in 2017 (68 mmcf/d sales)
• average 60 mmcf/d raw McMahon, 15 mmcf/d raw Stoddart
• ROFR to add up to 35 mmcf/d raw at McMahon
Firm transport increases to 102 mmcf/d sales in 2018
• diversifying nat gas sales to minimize impact of regional pricing diffs
2017
2018
Alliance Pipeline - Chicago 51 mmcf/d
55 mmcf/d 86% of Q1/17
prod’n on firm,
Alliance Pipeline - ATP
5
5
remainder on
Spectra to BC Stn 2
16
29
IT to Chicago
and/or Stn 2
Spectra/TCPL to AECO
13
72 mmcf/d 102 mmcf/d
interruptible (IT) on Alliance for up to 25% of firm (adds ~15 mmcf/d)
17
HEDGING (July 6/17)
Hedging to support growth
growth is not hedged
• target: 50% of current prod’n hedged 1 to 12 months forward
25% of current prod’n hedged 13 to 24 months forward
Fixed price hedges
~43% forecast 2017 prod’n
Q2–Q4/17: 29.9 mmcf/d AECO $3.35/mcf (37,400 GJ/d @ $2.68/GJ)
9.7 mmcf/d Chi Cdn$4.94/mcf (12,100 GJ/d @ $3.95/GJ)(1)
1,150 bpd WTI Cdn$65.01 X $69.43/bbl
2018: 0.6 mmcf/d AECO $3.50/mcf (750 GJ/d @ $2.80/GJ)
15.5 mmcf/d Chi Cdn$4.75/mcf (19,400 GJ/d @ $3.80/GJ)(1)
510 bpd WTI Cdn$66.45 X $70.11/bbl
(1)
deduct ~Cdn$1.35/GJ from Chicago price for transport to get McMahon plantgate price
Price differential hedges
2017:
2018:
8,000 GJ/d AECO – BC Stn 2 diff -$0.40/GJ
35,000 mmbtu/d Chicago – AECO diff +US$0.58/mmbtu
3,000 GJ/d AECO – BC Stn 2 diff -$0.35/GJ
18
GUIDANCE
uses 6.3 Bcf type curve
for hz drills at Umbach
Umbach hz D&C
$4.3 MM
(+13% vs 2016)
can reduce capex to ~$57 MM
and maintain 16,500 boe/d
Dec/15 - Dec/16
McMahon
GP turnaround
declinethan
~33%
longer
forecast (35 days
vs f/c 21 days), not expected
to impact guidance
19
WESTERN CANADIAN NAT GAS PRICES
AECO weakening vs US
markets as Eastern
Canada demand declining
& export pipelines to US
are currently full (need
more pipeline takeaway)
Rover pipeline Q1/18 may
displace some WCSB
exports to Ontario???
solutions include:
• WCSB decline ~25% per year
NGTL receipts down YOY
Q1/17 11.5 Bcf/d
Q1/16 11.8 Bcf/d
• AB demand increases with
oilsands & retiring coal plants
• future pipeline expansions to
US on Alliance, TCPL (ABC),
Enbridge (Spectra T-south)
Storm mitigating risk by diversifying
sales (Alliance capacity to Chicago
for ~60% f/c 2017 prod’n)
20
AECO - BC STATION 2 PRICE DIFFERENTIAL
majority of BC
prod’n growth
goes onto TCPL
to AECO (does
not impact Stn 2)
upcoming TCPL expansions:
Towerbirch +0.9 Bcf/d Apr/18
N Montney +1.5 Bcf/d Apr/19
[reduces AECO – Stn 2 diff?]
AECO – Stn 2
diff has
narrowed
since Dec/15
21
US NATURAL GAS SUPPLY/DEMAND
Bullish nat gas price with US demand > supply
• since Jan/15, US supply (prod’n + net imports) declined 5.2 Bcf/d
• exports increasing with ~9 Bcf/d LNG facilities operating or under
construction and new pipelines to Mexico +6 Bcf/d by 2018
demand/supply gap
widening in 2017
22
SUMMARY
Results improving (Q1/17 funds flow +125%/share YOY)
Montney at Umbach is liquids rich, higher quality resource
• liquids +$5/boe Q1/17 revenue, 2016 PDP FD&A $6.89/boe
Prod’n growth strong relative to capital investment
• 2016 +3,200 boe/d YOY (+33%) vs $66 MM capex
• 2017 forecast +4,200 boe/d YOY (+32%) vs $75 - $80 MM capex
Improving Montney hz rates/reserves (longer & more fracs)
Infrastructure supports growth to 27,000 boe/d (Q4/18?)
Capital program offers flexibility (speed-up or slow down)
Growth is supported by current commodity prices
• 2017 is a ‘cash flow budget’ using April/17 prices for Q2 – Q4/17
[April/17: AECO $2.68/GJ, Stn 2 $2.33/GJ, Chi spot/monthly ~US$3.00/mmbtu,
WTI US$51/bbl, Edm light ~Cdn$64/bbl, FX 0.744]
23
STORM RESOURCES LTD. CONTACT INFO
For further information please contact:
Brian Lavergne, President and Chief Executive Officer
Michael Hearn, Chief Financial Officer
Carol Knudsen, Manager Corporate Affairs
Address: #200, 640 – 5th Avenue S.W., Calgary, Alberta T2P 3G4
Phone:
(403) 817-6145
Fax:
(403) 817-6146
Website: www.stormresourcesltd.com
24
ADVISORY
Reserves – All reserves in this presentation are, unless indicated otherwise, as at December 31, 2016 as evaluated by Insite Petroleum
Consultants Ltd. in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook
and National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities.
Boe Presentation - for the purpose of calculating unit revenues and costs, natural gas is converted to a barrel of oil equivalent (“Boe”) using
six thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless otherwise stated. Barrels of oil equivalent (“Boe”) may be
misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“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. All Boe
measurements and conversions in this report are derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one
barrel of oil.
Type Curves – Certain type curves presented herein represent estimates of production decline and ultimate volumes expected to be
recovered over the life of a well. The 3.7 mmcf/d IP365 (which represents the average 365 day initial production rate) and 6.3 Bcf raw
(which represents the ultimate volumes expected to be recovered from the well over the life based on the type curve) Upper Montney
type curve and the 4.1 mmcf/d IP365 and 7.0 Bcf raw Upper Montney type curve are management generated type curves based on the
InSite type curves used in the 2016 reserve evaluation with the same decline profile but, different initial rates. Individual wells may be
higher or lower but over a larger number of wells management expects the average to align to the type curve.
Forward-Looking Information - certain information set forth in this presentation, including management’s assessment of Storm’s future
plans and operations, contains forward-looking statements. These statements are based on current beliefs and expectations based on the
information available at the time the applicable assumptions were made. By their nature, forward-looking statements are subject to
numerous risks, uncertainties and assumptions, some of which are beyond the Company’s control, including the material risks described in
Storm’s Annual Information Form dated March 31, 2017 under “Risk Factors” and Management’s Discussion and Analysis for the year
ending December 31, 2016 under “Business Risks”, the effect of general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack
of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and
external sources. Readers are advised that the assumptions used in the preparation of such information, although considered reasonable at
the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements.
Storm’s actual results, performance or achievement, could differ materially from those expressed in, or implied by, these forward-looking
statements. Storm disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of
new information, future events or otherwise, except as required under securities law. Reference is made to “Forward-Looking Statements”
in Storm’s Management’s Discussion and Analysis for the year ending December 31, 2016 dated March 2, 2017 which may be found on
Storm’s website at www.stormresourcesltd.com or on SEDAR at www.sedar.com and which are hereby incorporated by reference in this
presentation and which outline a number of assumptions, risks, and uncertainties associated with forward-looking statements.
25
APPENDIX
NAT GAS PRICING USING 2018 FWD STRIP
2018 FWD STRIP (July 6/17)
NYMEX
US$2.92/mmbtu
NYMEX - Chicago diff - US$0.16/mmbtu
FX
1.291
AECO
$2.34/GJ
AECO – BC Stn 2 diff -$0.44/GJ
Sell in Chicago (Alliance pipeline)
Sell at AECO (Spectra + TCPL pipelines)
Sell at BC Stn 2 (Spectra T-north pipeline)
AECO
$2.34/GJ
TCPL & Spectra 1 yr tariffs + fuel -$0.47/GJ
@ McMahon Gas Plant
Cdn$1.87/GJ
$2.38/mcf
AECO
AECO – BC Stn 2 diff
Spectra 1yr tariff + fuel
@ McMahon Gas Plant
2018 sales pipeline
commitments:
remainder on IT
to Chicago or
BC Stn 2 (where
net price is
highest)
NYMEX
NYMEX - Chicago diff
Chicago price
Alliance tariff + fuel
@ McMahon Gas Plant
US$2.92/mmbtu
-US$0.16/mmbtu
Cdn$3.38/GJ
-$1.32/GJ
Cdn$2.06/GJ
$2.61/mcf
$2.34/GJ
-$0.44/GJ
-$0.17/GJ
Cdn$1.73/GJ
$2.20/mcf
Alliance Pipeline to Chicago 55 mmcf/d (69,000 GJ/d)
Chicago price less pipeline toll + fuel ~$1.32/GJ
sale at McMahon Gas Plant, pipeline toll deducted from price
Alliance Pipeline to ATP 5 mmcf/d (6,000 GJ/d)
ATP price less pipeline toll + fuel ~$0.60/GJ
Spectra T-north 29 mmcf/d (36,000 GJ/d)
BC Stn 2 price less pipeline toll + fuel ~$0.17/GJ
Spectra T-north & TCPL (Groundbirch) 13 mmcf/d (16,000 GJ/d)
AECO price less pipeline toll + fuel ~$0.47/GJ
Alliance PITS to Chicago (interruptible or “IT”) up to 15 mmcf/d or 25% of firm
HORN RIVER BASIN ‘HRB’ (NE BC)
Shale gas from Muskwa,
Otter Park, Evie shales
• 78,000 net acres, 100% WI
• 119 net sections
Drilled 2 hz’s & 2 verticals to
validate commerciality
• 1 producing hz, 1 standing hz
STORM RESULTS VS MARCELLUS/UTICA
9 public Marcellus/Utica
producers
• AR, COG, ECR, EQT, GPOR,
REXX, RICE, RRC, SWN
• Q1/17
12.9 Bcfe/d (+15% YOY)
debt $21 B (2.6 X annual CF)
• 2016: capex 178% of funds
flow, issued $7 B equity,
prod’n +10% YOY
Storm Q1/17 netback is competitive
Marcellus/Utica
price
$3.19/mcfe
hedging
-$0.03
cash costs -$1.46
funds flow $1.71/mcfe
excl hedges $1.74/mcfe
Storm
$4.05/mcfe Storm is competitive; higher funds
flow netback & improving hz results
-$0.38
-$1.70
pipeline tariffs reduce price for
$1.96/mcfe Marcellus/Utica (Rover $1/mmbtu,
$2.34/mcfe Atlantic Sunrise $0.77/mmbtu)
MARCELLUS/UTICA PRODUCERS CAPEX VS FUNDS FLOW
with capex > funds flow,
Marcellus/Utica growth
needs higher nat gas
price or outside capital
(equity, hedging)