Peters and Co. June 3 & 4, 2014 cequence energy ltd · 2014-12-22 · Recent Highlights 4 Q1 cash...
33
cequence energy ltd Peters and Co. June 3 & 4, 2014
Transcript of Peters and Co. June 3 & 4, 2014 cequence energy ltd · 2014-12-22 · Recent Highlights 4 Q1 cash...
cequence energy ltd
Peters and Co. June 3 & 4, 2014
Forward-Looking Information and Definitions
Summary of Forward-Looking Statements or Information
Certain information included in this presentation constitutes forward-looking information under applicable securities legislation. This information relates to future events or future performance of the Company. Investors are cautioned that reliance on such information may not be appropriate for making investment decisions. Many factors could cause the Company’s actual results, performance or achievements to vary from those described herein. The forward-looking information contained in this presentation is expressly qualified by this and other cautionary statements set forth in the continuous disclosure record of the Company.
For a complete description of the forward-looking statements or information and the definitions used in this presentation, see slide 31 "Forward-Looking Statements or Information and Definitions."
2
ALBERTABRITISH
COLUMBIA
PEACE RIVER
GRANDE PRAIRIE
EDMONTON
R19W3R1W5R1W6 R2R5R8R11R15R19R5R8R12R16R5R8R1194-P-1594-O-994-O-11
93
-G-2
93
-G-1
493
-J-1
193
-O-3
93
-O-1
494
-B-1
194
-G-4
94
-G-1
394
-J-5
94
-J-1
394
-O-5
Focus in the Deep Basin of Alberta
3
USA CANADA
Deep Basin
SIMONETTE PROJECT
ANSELL PROJECT
Cequence is positioned to become a significant natural gas producer in Canada with two large projects now established:
Simonette Project is ready for
accelerated development
Ansell Project now on stream
> 1.0 TCF potentially recoverable in multiple stacked formations at these two projects
Strong financial capacity
Low cost operations with facilities in place
5 year plan to grow production to over 40,000 Boepd
Recent Highlights
4
Q1 cash flow reached a record $23 million on production of
11,600 Boepd
Year-end 2P reserves grew 24% to 113 Mmboe with NPV 10% of $1 billion
2P FD&A was $11.17 per boe, F&D was $10.10 per Boe
Bank line of credit has been recently approved at $155 million, up from $120 million previously
Ansell Wilrich Project is now on production through new facilities completed in April
Corporate Profile
5
Trading Symbol TSX: CQE
Q1 Production (Boe/d) 11,600
Q1 Cashflow $23 million
52-week trading range $1.42 - $3.15
Shares outstanding 211 million
Insider ownership 13% FD
Market capitalization (1) $570 million
March 31, 2014 net debt (2) $143 million
Debt capacity (3) $215 million
Reserves P + P 113 mmboe
F,D&A(4) $11.17 per boe
Recycle Ratio on Q1 2014 netback 2.4 times
(1) Based on Cequence stock price of $2.70 (2) Net debt is calculated as net working capital less commodity contract asset and liabilities and demand credit facilities, principal value of
senior notes and excluding other liabilities. (3) Comprised of a recently approved $155 M senior credit facility and $60 M drawn CPPIB unsecured 5 year notes. (4) 2013 funding, development and acquisitions costs including future development costs calculated using proved plus probable reserves.
Guidance - 40% growth planned for 2014
2013 Preliminary 2014
Guidance (4)
Production (Boe/d) 10,183 (1) 13,500-14,000
Exit production (Boe/d) 12,000 15,000
Capital expenditures $111 MM $120 MM
Wells drilled 15 (11.75) 16 (14)
Operating costs per Boe $7.00 $6.85
Royalties (% of revenue) 8% 9%
Crude oil – WTI (US$/Bbl) $98.01 $95.75
Natural gas – AECO (Cdn$/GJ) $3.17 $3.50
Funds flow from operations (2) $51.3 MM $85 MM
Year end net debt and working capital deficiency(3) $111 MM $145 MM
Basic shares outstanding 210.9 MM 210.9 MM
(1) Comprised of 51.8 MMcf/d of natural gas and 1,370 Boe/d of oil and liquids (2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities (3) Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities, demand credit facilities and the aggregate principal amount of the Notes and excluding other liabilities. (4) October, 2013
6
5 Year Development Plan – 80% of drilling is assumed to be Montney at Simonette
7
Major Assumptions:
NO ADDITIONAL EQUITY
143 wells drilled in next five years (80% Montney, 20% other zones)
Base Case Montney production model and $8 million cost per well
Facilities and maintenance capital - $14 MM/yr, Land/seismic - $9 MM/yr
Conservative debt level achieved on strip gas price
5 year plan does not incorporate recent success at Ansell
8
Cequence Simonette 13-11 Compressor Station
Cequence Simonette 13-11 Compressor Station
3D SeismicCoverage
Trilogy PlantCQE W.I. = 25%Capacity 10 MMcf/d
9-10Field Compressor
Keyera ProcessingFacility Capacity 153 MMcf/d
13-11Compressor Station
CQE Land
CQE Well
CQE Field Compressor
Alliance Pipeline
CQE Gathering System
3D Seismic Outline
To Aux SableDeep Cut PlantChicago, Illinois
CQE GAS To Aux Sable
R23W5R1W6 R24R25R26R27R2
T60
T61
T62
T63
T64
Simonette Project Infrastructure -ready for full scale development
9
6 miles
13-11 Facility - Current Capacity 70 MMcf/d
Cequence Alliance Meter Station Capacity 120 MMcf/d
Cequence operates its facilities at Simonette and delivers raw gas to the Alliance Pipeline for processing at the Aux Sable Deep Cut plant in Chicago
Camp and drilling rigs will run on natural gas
Simonette Area – Q1 operating netback was $35 per Boe prior to hedging
Current facility ready for expansion to 120 MMcfd through Alliance
Potential for future additional expansion up to 100 MMcfd to TCPL.
Alberta Deep Basin Montney Competitor Lands
Cequence owns 87 net sections of
Montney land at Simonette in the liquids rich, over-pressured Montney fairway
Significant drilling activity on adjacent lands
10
KARR
WAPITI
KAKWA
RESTHAVEN
SIMONETTE
WASKAHIGAN
FIR
ANTE CREEK
Approximate TopOver Pressure
XTO
XTO
XTO
XTO
XTO
XTO
XTO
XTO XTO
XTO
XTO
XTO
XTO
XTOLand Legend
Apache Montney
ARC Montney
Athabasca Montney
CIOC Montney
CNRL Montney
Cequence Montney
Chevron Montney
CPC Montney
Delphi Montney
Donnybrook Montney
Encana Montney
Enerplus Montney
XTO Canada Montney
Kelt Montney
Lightstream Montney
Nuvista Montney
Paramount Montney
RMP Montney
7G Montney
Yoho All Rights
Legend
XTO Hzntls Licensed since 2013
R21W5R1W6 R22R23R24R25R26R2R3R4R5R6R7R8R9
T55
T56
T57
T58
T59
T60
T61
T62
T63
T64
T65
T66
T67
T68
T69
Upper Montney Liquids
11
6 miles
Three important wells completed in Q1 reinforce transition to development style pad drilling
23 pads currently built with pipeline tie-ins
12 additional pads approved for construction
Higher liquids yield on the west side of Simonette and average condensate yield now 27 Bbls per MMcf
13-35
16-10
14-24
OILGAS
Montney Rights
CQE Montney Oil WellIndustry Montney Oil Well
CQE Montney Gas Well
Industry Montney HZ Well
CQE Planned Wells
Cequence Land
R25W5R1W6 R26R27R2
R25W5R1W6 R26R27R2
T60
T61
T62
T60
T61
T62
Simonette Upper Montney Development Plan
12
6 miles
(1) See Forward-Looking Information and Definitions for definition of DPIIP and total resource
Approximately 200 locations depending on optimum well length
5 year plan will drill approximately 50% of current inventory
Current planned inter-well spacing 400 m.
2.3 TCF DPIIP (1) in Upper Montney
Future plan to test the Lower Montney resource potential
Upper
Lower
CURRENT HORIZONAL TARGET
ZONE
POTENTIAL HORIZONAL TARGET
ZONE
0
1
2
3
4
5
6
7
8
9
10
11
12
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18
Pro
du
cin
g D
aily
Gas
Rat
e (
MM
cf/d
)
Months
CQE 5 BCF Base Case CQE 7 BCF High Case
Cequence Montney gas producers - 18 wells to date
13
`HALF CYCLE ECONOMICS BASE CASE-
Budget model HIGH CASE
IP (MMcf/d) IP 30 (MMcf/d) EUR (MBoe) Raw Gas (Bcf) Condy (MBbl) NGL (MBbl)
5.5 4.6 925 5.0 100 50
7.5 6.9
1,290 7.0 150 65
CAPEX $MM (D,C + TI) ROR BT (%) NPV $MM (10%) PAYOUT (YEARS) CAPITAL EFFICIENCY (1st YEAR, $/Boed)
7.5 60 6.6 1.6
14,000
7.5 135 12 1.0
10,000
Includes 5% GORR, Opex $4.00 per Boe Gas rate does not include liquids
Assumes 30 Bbls/MMcf of NGL’s and condensate Assume $4.00/GJ AECO, $90 WTI flat Wells with mechanical failures included
1000
1500
2000
2500
3000
3500
4000
4500
$0
$1
$2
$3
$4
$5
$6
$7
02-
22
01-
31
04-
04
16-
12
07-
22
05-
35
01-
11
10-
09
09-
25
13-
22
10-
16
09-
21
03-
18
03-
21
03-
31
14-
01
15-
31
01-
21
02-
21
14-
24
16-
10
Est.
13-
35
Est.
HZ
len
gth
dri
lled
(m
)
Dri
ll C
ost
s $
MM
Montney Drilling Costs
Drilling cost HZ length drilled
2013/14 2012/13 2011/12 2010/11
15 16 16 19 16 22 16 16 24 18 16 27 21 22 29 28 28 5 6
28 22 26
$0
$150
$300
$450
$600
$750
$900
$0
$1
$2
$3
$4
$5
$6
02-
22
01-
31
04-
04
16-
12
07-
22
05-
35
01-
11
10-
09
09-
25
13-
22
10-
16
09-
21
03-
18
03-
21
03-
31
14-
01
15-
31
01-
21
02-
21
14-
24
16-
10
Est.
13-
35
Est.
$M
pe
r Fr
ac S
tage
Co
mp
leti
on
Co
sts
$M
M
Montney Completion Costs
Completion cost Frac cost per stage # of stages
2013/14 2012/13 2011/12 2010/11
14
8-21 costs contain original well combined with re-drill 9-21 completion costs 13-35 was a re-entry of an existing vertical uphole producer 16-10 was a strat test with pilot hole and coring program
Montney Drilling and Completion Costs -Long term target of $7.5 million is achievable
Simonette Dunvegan, Falher and Wilrich plays
Dunvegan Oil and Gas/Condensate play
10-2 well 90 day IP was 13 MMcf/d
5-2 well 60 day IP was 9 MMcf/d
Cequence has 11 net sections along gas and oil trend
Up to 25 BCF/sec resource potential
Falher play
First two CQE wells – average 90 day IP of 5.5 MMCf/d with 21 bbls/MMcf condensate
Cequence has mapped 28 potential locations on 14 net existing sections
Analog pool produces 60 MMcf/d from 21 existing producers
Wilrich play
20 net sections currently mapped with 40 potential locations
Nearby Resthaven pool has excellent production history
15
Model: IP rate – 6.5 MMcf/d Reserves – 5 BCF and 20-40 Bbl/MM NGL
Area average: IP rate – 4.5 MMcf/d Reserves – 4.0 BCF and 50-150 Bbl/MM NGL
6 miles
-TOURMALINE
TOURMALINE
HUSKY
ENERPLUS
PERPETUAL
PERPETUAL
TALISMAN
CONOCO
PEYTO
Wilrich Rights
CQE Land
CEQUENCE
CQE Wilrich Wells
Wilrich Wells
R16W5R17R18R19R20
T49
T50
T51
T52
Ansell Wilrich Project
16
12-31-50-17W5 Facility
Pipeline To Talisman Edson Gas Plant
6 miles
Initial de-risking of project successful
100 MMcf/d pipeline and 40 MMcf/d Phase 1 compressor/dehydration facility completed in April 2014
7 wells now on stream
Cequence owns 49% WI in a large contiguous land block and production facilities
Conclusions
17
Simonette Project – large proven Deep Basin Montney resource play with multiple uphole zones
Ansell project – Wilrich resource play in an excellent area
Financial strength - CQE has a strong balance sheet with $70 million of available credit facilities
Highly experienced Board of Directors and Deep Basin Management team with significant ownership
18
Appendix
Cequence Simonette 13-11 Compressor Station
Management and Board
19
Management Team
Paul Wanklyn - President and CEO
Howard Crone - Executive VP and COO
Steve Stretch - VP Exploration and Chief Geophysicist
Dave Gillis - VP Finance and CFO
Dave Robinson - VP Exploration and Chief Geologist
James Jackson - VP Engineering
Chris Soby - VP Land and Corporate Development
Mike Stewart - VP Operations
Erin Thorson - Controller
Board of Directors
Don Archibald - Chairman
Peter Bannister
Rob Cook
Howard Crone
Brian Felesky
Daryl Gilbert
Frank Mele
Paul Wanklyn
James Gray - Director Emeritus
Canada Pension Plan Investment Board Private Debt Placement
$60 million, 5 year unsecured notes issued at par
Closed on October 3rd, 2013
Coupon rate 9%, plus 3.0 million warrants at $2.03
Initially used to pay down outstanding bank debt
Second tranche of $60 million available subject to approval of both CPPIB and CQE
Cequence has additional financial flexibility consisting of:
Undrawn bank facility of approximately $120 million
Optional $60 million of second tranche CPPIB notes
20
Financial Highlights
Q1 2014 Q4 2013 % Change
Average Daily Production (Boe/d) 11,613 10,394 12
Funds flow from operations ($M) (1) $23,082 $14,855 55
Per share, basic and diluted $0.11 $0.07 57
Operating costs per Boe $7.40 $7.33 1
G&A per Boe $2.34 $1.65 42
Capital expenditures, net ($M) $55,318 $51,531 7
Net debt and working capital (deficiency) ($M)(2) ($143,536) ($111,433) 29
Weighted average shares outstanding (diluted) (M)
210,918 210,917 0
21
(1) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital (2) Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities and demand credit facilities, long term debt and excluding other liabilities
Production and Cash Costs
22
(1) Operating cost, transportation, G&A and Interest
Simonette and Ansell Projects will drive 40% growth in 2014
Total cash costs are in the top quartile of Canadian producers
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
2010 2011 2012 2013 2014Est.
Bo
e/d
Production (Boe/d)
Natural Gas Oil & NGL
Merger with Temple Energy
$0
$2
$4
$6
$8
$10
$12
$14
$16
$18
$20
2010 2011 2012 2013 2014Est.
$/B
oe
Total Cash Costs ($/Boe) (1)
Netback Table – Q1 2014
Simonette Corporate
Total
Average daily production (Boe/d) 8,263 11,612
Natural gas (MMcf/d) 41.7 59.9
Oil and liquids (Bbls/d) 1,308 1,630
Sales price ($/Boe) $45.76 $44.29
Royalties ($/Boe) ($4.08) ($4.13)
Operating cost ($/Boe) ($5.59) ($7.40)
Transportation cost ($/Boe) ($1.13) ($1.52)
Operating netback $34.96 $31.25
G&A ($/Boe) ($2.34)
Interest ($/Boe) ($1.79)
Cashflow netback ($/Boe) $22.14
23
Note: AECO C spot price of $5.59 CDN$/Mcf and WTI crude oil price of $98.65 US$/Bbl
Hedging
Contract Type Volume
GJ/d CAD Price
2014 January 1, 2014 to December 31, 2014 Average Gas
Swap 30,000
$3.45/GJ AECO or $4.00/Mcf
2015 January 1, 2015 to March 31, 2015 Average Gas
Swap 20,000
$3.79/GJ AECO or $4.40/Mcf
2015 April 1, 2015 to December 31, 2015 Average Gas
Swap 10,000
$3.73/GJ AECO or $4.32/Mcf
24
(1) Percentage calculated assuming current forecast production net of royalties and an estimated heat content
Reserves and Finding Costs – solid growth per share in reserves and value
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
2010 2011 2012 2013
FD&A ($/Boe)
Proved + Probable (Incl FDC)
25
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0
20
40
60
80
100
120
140
2010 2011 2012 2013
Proved + ProbableTotal Proved2P per share
49
91
67
3
4
5
6
0
200
400
600
800
1000
1200
2010 2011 2012 2013
2P Reserve Value
Reserve Value 2P per share
Proved + Probable GLJ Dec.31, 2013
$1,036
$525
$715
$797
Reserves
113
MM
Bo
e
Bo
e/s
har
e
$M
M
$/s
har
e
3 year average $11.61per Boe
Reserves increased 130% since 2010
Reserve value has doubled since 2010
0
5,000
10,000
15,000
20,000
1.00 2.00 3.00 4.00 5.00 6.00 7.00
NP
V 1
0%
BT
($M
)
Flat AECO Gas Price ($/MMBtu)
3.0 BCF + NGL's 5.0 BCF + NGL's 7.0 BCF + NGL's
26
Montney Half Cycle Economics - Sensitivity to Flat Gas
Price and Recoverable Gas in Place per Well
Assumptions: Net NGL Yield: 30 Bbl/MMcf C3+ Capital: $7.5 MM Oil Price: $90/Bbl WTI
Notes: With 5% GORR, Oil $90/Bbl, C3 $31.5/Bbl,C4 $70/Bbl, C5+ $95/Bbl
Simonette Deep Basin Stack
27
Dunvegan
Falher Bluesky / Gething
Montney Wilrich
3075
3050
3025
3000
2950
2975
Simonette Upper
Simonette Lower
CURRENT HORIZONAL
TARGET ZONE
POTENTIAL HORIZONAL
TARGET ZONE
CEQUENCE LAND
R22W5R1W6 R23R24R25R26R27R2R3R4
T59
T60
T61
T62
T63
T64
T65
28
5-25 BCF
5-24 BCF 5-24 BCF
5-25 BCF
30-60 BCF
Dunvegan
Falher
Wilrich
Gething
Upper Montney
Zone Total Resource Potential/Sec (1)
2,400m
2,950m
3,100m
2,700m
2,500m
2,800m
(1) See Forward-Looking Information and Definitions for definition of total resource
6 miles
Multiple Zones with Significant Resource Potential at Simonette
Alberta Deep Basin - Montney HZ First 6 month cumulative gas production
29
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
Cu
m G
as (
BC
F)
Cequence Wells
Average of CQE Wells 540 MMcf
Average All Wells 390 MMcf
Industry Wells
137 gas wells with production to Dec. 31, 2013, Geoscout data Oil wells excluded.
Alberta Deep Basin Montney HZ Drilling Analysis – CQE among most efficient drillers
30
Includes pilot wells, does not include re-entries
0
2000
4000
6000
8000
10000
12000
0
50
100
150
200
250
300
2012 and older - 245 wells
Mea
sure
d D
epth
(m
)
0
2000
4000
6000
8000
10000
12000
0
50
100
150
200
250
300
Me
ters
dri
lled
pe
r d
ay (
m)
2013 – 63 wells
CQE P50 187 m/day
All Wells P50 123 m/day
Mea
sure
d D
epth
(m
)
Competitor Wells Cequence Wells
CQE P50 137 m/day
All Wells P50 107 m/day
Cequence Wells Competitor Wells Measured Depth Measured Depth
Forward-Looking Statements or Information and Definitions
Certain statements included in this presentation constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information concerning Cequence in this presentation may include, but are not limited to, statements or information with respect to: guidance, forecasts and related assumptions; expected production growth and cash flow growth and the respective timing thereof; use of proceeds from the CPPIB Private Debt Placement; the Company's plan to not issue additional equity until year-end 2018; capital spending; expected resource potential and future reserves; hedging objectives; business strategy and objectives; type curves; drilling, development and exploration plans and the timing, associated costs and results thereof; future net debt and funds flow; commodity pricing and expected royalties; costs associated with operating in the oil and natural gas business; and future production levels, including the composition thereof. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. The Company believes that the expectations reflected in such forward-looking statements or information are reasonable; however, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of operating the Company’s business; the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.
Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties may cause actual results to differ materially from the forward-looking statements or information. The material risk factors affecting the Company and its business are contained in the Company's Annual Information Form which is available at SEDAR at www.sedar.com.
The forward-looking statements or information contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this presentation are expressly qualified by this cautionary statement.
31
Forward-Looking Statements or Information and Definitions
Additional Advisories
This presentation contains references to terms commonly used in the oil and gas industry. Netback is not defined by IFRS in Canada and is referred to as a non-GAAP measure. Netbacks equal total revenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyze operating performance.
Funds flow from operations is a non-GAAP term that represents cash flow from operating activities before adjustments for decommissioning liability expenditures and changes in working capital. The Company evaluates its performance based on earnings and funds flow from operations. The Company considers funds flow from operations to be a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company's calculation of funds flow from operations may not be comparable to that reported by other companies. Funds flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of income (loss) per share.
"Total resources" are that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. Total resources include that quantity of petroleum that is internally estimated, at a given date, to be contained in known accumulations, prior to production, plus those quantities in accumulations yet to be discovered.
Discovered Petroleum in Place ("DPIIP") and "Contingent Resources": DPIIP is equivalent to discovered resources and is defined in the Canadian Oil and Gas Evaluation Handbook ("COGEH") as that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves and contingent resources; the remainder is unrecoverable. "Contingent Resources" are defined in COGEH as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be economically recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. The Contingent Resources estimates and the DPIIP estimates are estimates only and the actual results may be greater or less than the estimates provided herein. There is no certainty that it will be commercially viable to produce any portion of the resources except to the extent identified as proved or probable reserves.
"Best estimate" is defined in COGEH with respect to entity level estimates, as the value derived by an evaluator using deterministic methods that best represent the expected outcome with no optimism or conservatism. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
The foregoing outlook and guidance has been provided to assist investors in analyzing the Company’s anticipated development strategies and prospects and it may not be appropriate for other purposes and actual results could differ from the guidance provided above. Cequence refers to initial production rates which may not be indicative of long term well performance.
BOEs are presented on the basis of one BOE for six Mcf of natural gas. Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation. A BOE 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.
For the three months ended March 31, 2014, the ratio between the average price of West Texas Intermediate (“WTI”) crude oil at Cushing and NYMEX natural gas was approximately 21:1 (“Value Ratio”). The Value Ratio is obtained using the first quarter 2014 WTI average price of $98.65 (US$/Bbl) for crude oil and the first quarter 2014 NYMEX average price of $4.72 (US$/MMbtu) for natural gas. This Value Ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value.
32
Contacts: Paul Wanklyn President & CEO [email protected]
www.cequence-energy.com 3100, 525 - 8th Avenue SW Calgary AB T2P 1G1
Phone: 403-229-3050 Fax: 403-229-0603
David Gillis Vice President, Finance & CFO [email protected]
