Corporate Presentation
Future Oriented Information
(See additional advisories at the end of this document)
•
In the interest of providing information regarding Paramount Resources Ltd.
("Paramount" or the "Company") and its future plans and operations, this
presentation contains certain forward-looking information and forward-looking
statements.
•
The projections, estimates and forecasts contained in such forward-looking
information and statements necessarily involve a number of assumptions, and are
subject to both known and unknown risks and uncertainties that may cause the
Company's actual performance and financial results in future periods to differ
materially from these projections, estimates or forecasts. The Advisories Appendix
lists some of the material assumptions, risks and uncertainties that these
projections, estimates and forecasts are based on and are subject to.
•
Accordingly, shareholders and potential investors are cautioned that events or
circumstances could cause actual results to differ materially from those predicted.
•
Founded in 1976; IPO in 1978; TSX: POU
•
Q1 2016 production: 50,161 Boe/d (~49% Liquids)
•
Market Cap: 106.2 MM shares @ $9.15/share ~ $972 Million
•
~50% insider ownership
•
Net Debt (April 30, 2016): $1.3 Billion
Corporate Profile
Operations focused on large-scale Deep Basin development
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Large contiguous acreage
•
Multi-zone potential
•
High condensate/gas ratios
•
Firm service access to infrastructure
Strategic Investments/Emerging Plays
Low Risk/Repeatable Growth
Corporate Profile
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Emerging Montney plays at Valhalla and Birch
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Emerging Duvernay play at Willesden Green
•
Oil Sands
•
Liard Basin shale gas
•
Frontier gas in northern Canada (MGM)
Deep Basin Resource
Deep Basin liquids-rich gas
resources in multiple stacked
horizons
Paramount Acreage (gross):
•
486 Sections Cretaceous Rights
•
362 Sections Montney Rights
•
170 Sections Duvernay Rights
•
Liquids-rich gas play
•
~70
+Bcf/section DGIIP
(1)•
~ 22 Tcf DGIIP + NGLs net to POU
(1)•
Potential conventional Devonian
exploration
•
Potential Duvernay Shale rock play
(1) Internal estimates: EUR denotes Estimated Ultimate Recovery, DGIIP denotes Discovered Gas Initially In Place. Please refer to "Oil and Gas Measures and Definitions" in the Advisories section of this presentation for further information.
Cretaceous
Montney
Land Position
•
40-160 Bcf/section DGIIP
(1)•
~5
+Bcf EUR/Hz well
(1)•
>10 Tcf DGIIP + NGLs net to POU
(1)Montney Gas Resource
•
Liquids-rich Montney gas play; Paramount
holds ~313 net sections of Montney rights
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Competitive well economics
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High liquids content
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Thick pay
•
High pore pressure (over pressured
Deep Basin)
(1) Please refer to the "Montney Production Rates" paragraphs in the Advisories section of this presentation for further information.
PARAMOUNT MONTNEY WELLS – KAYBOB AND GRANDE PRAIRIE
(1)Natural
Gas
(MMcf/d)
Wellhead
Liquids
(Bbl/d)
CGR
(Bbl/MMcf)
Total
(Boe/d)
Wells
IP
303.3
542
162
1,092
91
IP
902.8
382
138
849
88
IP
1802.5
253
103
670
66
IP
2702.3
227
100
610
47
IP
3602.0
190
96
523
33
Less than 30 days on production
3
Wells in progress
4
Montney "Rich" Well Economics
Assumptions
(1)
:
Capital: $7.5 MM horizontal 1.5-mile lateral well
(2)
IP
30
: 5.4 MMcf/d (restricted)
Natural Gas (raw): 5.0 Bcf
CGR(raw)
(3)
: 171 Bbl/MMcf (IP
30
)
(~72 Bbl/MMcf lifetime average)
C2-C4 NGLs: ~90 Bbl/MMcf through Deep Cut Facility
FX (USD/CAD): $0.75
Economics
(4)
@ $2.50 AECO
US$/Bbl WTI
$30
$40
$50
$60
NPV 10% $MM
-0.4
2.6
5.6
8.5
IRR
8%
30%
55%
84%
Payout (Years)
5.3
2.5
1.8
1.4
P/I
(1)
0.9
1.4
1.8
2.2
1) Please refer to "Well Economics" in the Advisories section 2) Estimated cost based on Paramount's ability to source sufficient water supply to perform slickwater fracs. Capital cost
estimate if foamed water fracs are required is $8.9 MM 3) Wellhead Condensate Gas Ratio 4) Includes processing capital fees
Montney "Ultra Rich" Well Economics
Assumptions
(1)
:
Capital: $6.7 MM horizontal 1-mile lateral well
(2)
IP
30
: 2.2 MMcf/d (restricted)
Natural Gas (raw): 2.0 Bcf
CGR(raw)
(3)
: 452 Bbl/MMcf (IP
30
)
(~192 Bbl/MMcf lifetime average)
C2-C4 NGLs: ~ 90 Bbl/MMcf through Deep Cut Facility
FX (USD/CAD): $0.75
Economics
(4)
@ $2.50 AECO
US$/Bbl WTI
$30
$40
$50
$60
NPV 10% $MM
-0.8
1.9
4.7
7.4
IRR
4%
29%
59%
92%
Payout (Years)
18.9
2.3
1.6
1.3
P/I
(1)
0.9
1.3
1.7
2.1
1) Please refer to "Well Economics" in the Advisories section 2) Estimated cost based on Paramount's ability to source sufficient water supply to perform slickwater fracs. Capital cost
estimate if foamed water fracs are required is $7.6 MM 3) Wellhead Condensate Gas Ratio 4) Includes processing capital fees
Montney Drilling/Completion Cost Reductions
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Lower drilling costs due to:
•
reduced drilling days by improving
penetration rates and efficiencies
•
lower day rates for rigs and lower
equipment rental costs
•
Lower completion costs due to:
•
the switch to 125 T/stage foamed water
frac from 60 T/stage oil-based frac
•
lower rates for pumping, hauling,
rentals, etc.
•
The use of slickwater to further reduce
completion costs
•
Moving towards 1.5 + mile laterals
(1) Estimated completion costs based on Paramount's ability to source sufficient water
supply to perform slickwater fracs.
Sale of Musreau 8-13 Complex
•
Closed sale of Musreau 8-13 processing facilites (Musreau Complex)
and related midstream assets to Pembina
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$565 MM cash (including adjustments)
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$35 MM carried plant expenditures
•
Paramount retains priority access to full facility capacity
(1)
•
Entered into a 20-year processing arrangement ramping up to 200
MMcf/d by 2019: ~$3.00/Boe impact on Musreau operating costs
•
Commitment to build 6-18 plant upon Paramount’s request
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Provides for flexibility of timing of existing transportation
arrangements
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Unlocks the value of Paramount's midstream assets and significantly
reduces infrastructure capital requirements to support future growth
Deep Basin Gas Processing Capacity
Owned and
Contracted
Raw Gas
Processing
Capacity
MMcf/d
(1)Potential
Sales
Volumes
Boe/d
(1)Musreau Complex 250
70,000
Smoky Deep Cut Facility
50
12,000
Other Kaybob area
capacity
18
3,300
Karr area capacity
40
9,700
Total
358
95,000
(1) Please refer to the heading "Deep Basin Processing Capacity" in the Advisories section.
Future Capacity
200 MMcf/d Raw Gas less 23% Shrinkage = 154 MMcf/d Sales Gas (25,667
Boe/d) + 22,000 Bbl/d condensate + 18,000 Bbl/d NGLs
Price
(1)
Yield (Bbl/MMcf)
Deep-Cut Sales Gas
$2.65/Mcf
154 MMcf/d
$408,100
Condensate
$49.00/Bbl
110
22,000 Bbl/d
$1,078,000
Butane
$29.00/Bbl
12.5
2,500 Bbl/d
$72,500
Propane
$5.00/Bbl
25
5,000 Bbl/d
$25,000
Ethane
$14.00/Bbl
52.5
10,500 Bbl/d
$147,000
Total:
65,667 Boe/d
$1,730,600/day
Royalty
5%
($86,530/day)
Transportation and
NGLs processing
($4.00/Boe)
$(262,668/day)
Operating Cost
($5.75/Boe)
($377,585/day)
Netback
Annual
24 MMBoe/yr
$1,003,817/day
$366 MM
$15.29/Boe
Illustrative Deep-Cut - Montney Wells
12
(1) WTI = US$40/Bbl, AECO = $2.50/Gj, F/X (USD/CAD) = $ 0.75
Willesden Green
Duvernay Shale Play
•
61,252 acres of land (100% WI)
•
Drilled and completed 3 Hz Duvernay wells
to date:
•
Two standing wells to be re-entered at a
later date
Paramount has explored for ideal combinations
of rock quality/liquids ratio/pressure gradient
Cumulative production to March 31, 2016
Natural Gas
MMcf
Oil and NGLs
MBbl
03/16-13-39-5W5
171.2
96
7-19-39-5W5
118.5
31
3-28-39-5W5
55.8
29
Total 345.5
156
Montney
•
Montney shale play (50% WI)
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Seven Hz Montney wells to date
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NGL yields average 50 Bbl/MMcf
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New 20 MMcf/d facility onstream December 2015
14
•
Montney/Doig Play
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16 wells currently tied in
•
Evaluating long term production/economics to determine
future investment levels
Valhalla: ~65 sections (~49 net) Montney/~56 sections (~42 net) Doig rights
Birch: ~60 sections (~30 net) Montney rights
Paramount 100% Subsidiary Investments
(1) As publicly disclosed by a large U.S. public E&P company with significant landholdings in the Liard Basin. The resource evaluation disclosed by such E&P company was not noted as having been prepared independently or by a qualified reserves evaluator or auditor (as such terms are defined in NI 51-101) or in accordance with the COGE Handbook. This information is relevant to Paramount’s landholdings in the Liard Basin as the information is in respect of landholdings in the Liard Basin that are close to Paramount’s lands and are, accordingly, likely to have similar geology. (2) Based on publicly available information.
Reserves
(1)
1) Principal properties reserves, exclude bitumen reserves related to the Hoole oilsands development. Reserves evaluated by McDaniel &Associates Consultants Ltd. in accordance with National Instrument 51-101 definitions, standards and procedures as at December 31, 2015. Columns may not add due to rounding.
Summary
Exposure to significant reserve opportunities
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Deep Basin: Montney, Cretaceous
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Valhalla: Montney, Doig
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Birch: Montney
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Willesden Green: Duvernay
Significant asset value
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Trilogy
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MEG Energy
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Cavalier Energy
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Liard Shale Gas
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Northern Frontier Resources
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Investment Portfolio
Paramount continues to provide long-term value creation for
shareholders
Advisories
Forward-Looking InformationCertain statements in this presentation constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward-looking information in this presentation includes, but is not limited to:
exploration, development and associated operational plans and strategies; reserves and resources estimates (including internal estimates of DGIIP); projected EURs for Paramount’s Deep Basin wells; projected type well production profiles and associated net present value, internal rate of return and payout estimates (and the initial production rate, reserves, capital and operating cost, shrinkage, natural gas liquids yield and pricing and frac fluid and intensity assumptions used to generate such profiles and estimates); forecast drilling and completion costs for new wells; the anticipated effects of the sale of the Musreau 8-13 processing facilities (including in respect of Musreau area operating costs); the Company's projected future Deep Basin processing capacity; illustrative deep-cut project economics (including the commodity price, royalty rate, capital and operating cost, production volume, natural gas liquids yield, well reserves, cash flow and payout examples and assumptions used therein); and general business strategies and objectives.
Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this presentation or Paramount’s continuous disclosure documents:
future natural gas, natural gas liquids (including condensate), oil and bitumen prices; royalty rates, taxes and capital, operating, general & administrative and other costs; foreign currency exchange rates and interest rates; general economic and business conditions; the ability of Paramount to obtain the required capital to finance its exploration, development and other operations and meets its commitments and financial obligations; the ability of Paramount to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out its activities; the ability of Paramount to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; the ability of Paramount to market its natural gas, natural gas liquids (including condensate), oil and bitumen successfully to current and new customers; the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, liquids yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations; the timely receipt of required governmental and regulatory approvals; and anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins and the construction, commissioning and start-up of new and expanded facilities).
Although Paramount believes that the expectations reflected in such forward looking information are reasonable, undue reliance should not be placed on them as Paramount can give no assurance that such expectations will prove to be correct. Forward-looking information is 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 Paramount and described in the forward-looking information. These risks and uncertainties include and/or relate (but are not limited) to:
fluctuations in natural gas, natural gas liquids (including condensate), oil and bitumen prices; changes in foreign currency exchange rates and interest rates; the uncertainty of estimates and projections relating to future revenue, future production, reserve additions, liquids yields (including condensate and natural gas ratios), resources recoveries, royalty rates, taxes and costs and expenses; the ability to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; operational risks in exploring for, developing and producing natural gas, natural gas liquids (including condensate), oil and bitumen; the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost; potential disruptions or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities); processing, pipeline, de-ethanization, and fractionation infrastructure outages, disruptions and constraints; risks and uncertainties involving the geology of oil and gas deposits; the uncertainty of reserves and resources estimates (including internal estimates of DGIIP); general business, economic and market conditions; the ability to generate sufficient cash flow from operations and obtain financing to fund planned exploration, development and operational activities and meet current and future commitments and obligations (including product processing, transportation, de-ethanization, fractionation and similar commitments and debt obligations); changes in, or in the interpretation of, laws, regulations or policies (including environmental laws); the ability to obtain required governmental or regulatory approvals in a timely manner and to enter into and maintain leases and licenses; the effects of weather; the timing and costs of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination; uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders; the outcome of existing and potential lawsuits, regulatory actions, audits and assessments; and other risks and uncertainties described elsewhere in this presentation and in Paramount’s filings with Canadian securities authorities, including its Annual Information Form.
The foregoing list of risks is not exhaustive. Additional information concerning these and other factors which could impact Paramount are included in Paramount’s most recent Annual Information Form. The forward-looking information contained in this presentation is made as of the date hereof and, except as required by applicable securities law, Paramount 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.
Oil and Gas Measures and Definitions
This presentation contains disclosure expressed as "Boe", "MBoe", "MMBoe" and "Boe/d". All natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. During the year ended December 31, 2015, the value ratio between crude oil and natural gas was approximately 22:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.
Paramount has provided information with respect to certain of its plays and emerging opportunities which is "analogous information" as defined in NI 51-101. This analogous information includes Paramount's internally generated production type curves for certain of its wells and internal estimates of DGIIP (as defined in the Canadian Oil and Gas Evaluation Handbook) and EUR (as defined in the Society of Petroleum Engineers - Petroleum Resources Management System). This analogous information is derived from Paramount's internal sources as well as from a variety of publicly available information sources which are predominantly independent in nature (however, it is not clear in all cases whether analogous information derived from public sources was prepared by a qualified reserves evaluator or in accordance with the Canadian Oil and Gas Evaluation Handbook). These type curves and estimates are subject to the specific assumptions identified by Paramount with respect thereto, and the other assumptions contained in these advisories. No reserves, or resources other than reserves, are assigned to these type curve or EUR estimates and, accordingly, such estimates may not be representative of the actual production rates or resources associated with Paramount's wells and properties DGIIP is the most specific category which could be assigned to Paramount’s Deep Basin Montney and other resources, and, accordingly, there is uncertainty that it will be commercially viable to produce any particular portion of such resources. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
Non-GAAP Measures
In this presentation "Net Debt“, “Adjusted EBITDA" and "Capital Expenditures", collectively the non-GAAP measures, are used and do not have any standardized meaning as prescribed by GAAP. Net Debt is a measure of a company's overall debt position after adjusting for certain working capital amounts and is used by Paramount’s management to assess its overall leverage position. Adjusted EBITDA equals net loss: (i) before interest and financing, share-based compensation, depreciation and depletion, exploration and evaluation, gain or losses on the sale of oil and gas properties, accretion of asset retirement obligations, unrealized foreign exchange gains or losses, unrealized gains or losses on financial commodity contracts, write-downs of investments in securities, gains or losses on the sale of investments, income or loss from equity-accounted investments, income from discontinued operations and income tax expense or recovery; and (ii) plus dividends from investees. Adjusted EBITDA is commonly used to assist management and investors in measuring our ability to fund capital programs and meet financial obligations. Capital Expenditures provides management and investors with information regarding the Company’s total spending on wells and infrastructure projects, other property, plant and equipment, land and property acquisitions, capitalized interest and geological and geophysical costs incurred. The closest GAAP measure to exploration and development expenditures is property, plant and equipment and exploration cash flows under investing activities in the Company’s Consolidated Statement of Cash Flows, which includes all of the items included in exploration and capital expenditures, except for geological and geophysical costs, which are expensed as incurred.
Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers.
Well Economics
Illustrative type well economics based on four wells per pad drilled with a single rig. Actual capital costs for Montney wells will be different due to a number of factors including, but not limited to the number of wells drilled on a particular pad and the number of rigs used, the number of completions done concurrently at a particular site, the number of wells using shared surface facilities, the timing of field operations and the effects of weather. Condensate gas ratios ("CGRs") for wells are calculated by dividing total hydrocarbon liquids by total raw natural gas in each case as produced at the wellhead. Sales volumes will be lower due to shrinkage. The term "P/I" refers to “profitability index” and is calculated by dividing estimated net cash flows (excluding capital invested, before tax, discounted at 10 percent) by capital invested (discounted at 10 percent).
Montney Production Rates
Production rates are the average gross volumes per day measured at the wellhead over the initial 30, 90, 180, 270 and 360 producing days commencing from the day after load oil volumes were completely recovered for wells completed with oil-based fluids, and the first producing day for wells completed with water-based fluids (the "Initial Production Period"). Days when the wells did not produce were excluded. CGRs were calculated for each well over the applicable Initial Production Period by dividing total hydrocarbon liquids volumes by total raw natural gas volumes in each case as produced at the wellhead. CGRs were calculated as of April 30, 2016. On-stream dates of wells range from January 2012 to January 2016.
Deep Basin Processing Capacity
The term "Owned and Contracted Raw Gas Processing Capacity" as used in the table on the "Deep Basin Gas Processing Capacity" page, means the total raw natural gas capacity available to the Company in the listed facilities by virtue of being an owner in the facility or having contracted firm-service or priority interruptible rights to use capacity in facilities owned by third parties. The stated capacities refer to the maximum capacities under existing agreements and facilities and following initial ramp-up periods in certain circumstances.
The term "Potential Sales Volumes" as used in the table on the "Deep Basin Gas Processing Capacity" page, means the potential volumes of saleable natural gas and NGLs (expressed on a combined basis in Boe/d) that could result from processing the associated quantities of raw natural gas set out in the "Owned and Contracted Raw Gas Processing Capacity" column in that table. These potential sales volumes should not be construed as a projection of Paramount's Deep Basin production at or by any particular date, as they will include some unavoidably commingled third-party production, and are subject to a number of factors and contingencies including the following: (a) production volumes sufficient to fill Paramount's capacity will not be available in all periods and under certain conditions; (b) during maintenance periods and at other times, the facilities will not operate at design capacity; and (c) NGLs sales volumes will vary depending on the liquids content of individual wells and the manner in which the facilities are operated. The potential sales volumes for each facility have been estimated assuming that natural gas processing and condensate stabilization capacity is fully utilized.
