TIDMPANR
RNS Number : 1862U
Pantheon Resources PLC
21 November 2023
21 November 2023
Pantheon Resources plc
Strategy Update - Pathway to Financial Self-Sufficiency
Pantheon Resources plc (AIM: PANR) ("Pantheon" or the
"Company"), the oil and gas company with a 100% working interest in
the Kodiak and Ahpun projects, collectively spanning 193,000
contiguous acres in close proximity to pipeline and transportation
infrastructure on Alaska's North Slope, is delighted to take this
opportunity to consolidate the narrative around progress to
achieving its objective of sustainable market recognition of $5-$10
per barrel of 1P/1C recoverable marketable liquids by 2028.
In June 2023, Pantheon embarked on a renewed strategy, promising
to keep investors informed regularly, to share progress as it
arises and to drive progress to financial self-sufficiency as
quickly as possible and at minimum possible value dilution to
existing shareholders.
Highlights:
-- Pantheon's strategy revolves around Final Investment Decision
("FID") at Ahpun by the end of 2025, bringing it on stream in 2026,
and completing the appraisal of Kodiak ahead of its planned FID in
2028
-- Conservative estimate of the capital required for first production is $120 million
-- Pantheon's strategy to reduce the equity capital required is based on three main pillars:
o Vendor financing
o Offtaker financing
o Reserves based lending
-- For conceptual development planning purposes, Pantheon has
assumed a typical well profile based on more conservative
properties than encountered in the long term test at Alkaid-2
-- A transition programme to achieve Sarbanes-Oxley compliance
in time for a potential US listing in 2025 is underway.
David Hobbs, Pantheon's Executive Chairman, commented: "The team
has undertaken a great deal of analysis and refined our planning
case to ensure that we organise funding on an appropriately
conservative basis. We look forward to putting the whole story
together to help investors understand the different milestones on
the way to full field developments, with FID on the whole of Ahpun
planned for late 2025 and for Kodiak during 2028."
Field Definitions
Earlier this year, in an effort to simplify the understanding of
Pantheon's resources, a new naming convention was implemented,
characterising all leases into two fields; (i) Ahpun (comprised of
the geologically youngest reservoirs above the Hue Shale and mostly
in the east of the lease holdings) and (ii) Kodiak (comprised of
the deeper reservoirs below the Hue Shale but above the HRZ Shale,
mostly to the west). Within Ahpun, there are reservoirs that have a
variety of depositional facies (descriptions of where and how a
horizon was deposited) which Pantheon has previously used to
distinguish between the main reservoir members. However, this risks
giving the impression of greater certainty about the distribution
of pay zones within an overall trap (as is the case with Ahpun)
where multiple sand bodies have been deposited but share the same
basic trapping mechanism under the Decker D horizon.
In future, the Company will stop differentiating between
different horizons in its resource estimates and begin assigning
such estimates at the field level. For the time being, the
Company's previously disclosed resource estimate for Ahpun of 481
million barrels includes estimates for some members within what has
been called the Shelf Margin Deltaic ("SMD") and the upper part of
the Alkaid Zone of Interest ("Alkaid ZOI") and some, but not all,
of the resources from the Alkaid Deep, while excluding the Slope
Fan System ("SFS") and some zones within the SMD. As these
additional reservoir intervals are appraised and evaluated, their
contribution will be included in Ahpun's resource estimates.
Strategic Plan Highlights
The Company's refreshed strategy involves bringing Ahpun on
stream in 2026 with FID planned by end of 2025, completing the
appraisal of Kodiak (likely requiring an additional 3 wells) ahead
of its planned FID in 2028 and reaching positive operating
cashflows that cover capital investment needs during the
intervening period such that Kodiak's development would be fully
funded from Ahpun net revenues.
For the avoidance of doubt, the Company's estimate of the
contingent resources in the Ahpun Field remains at some 481 million
barrels of marketable liquids and the development of the field is
planned in two stages. The first will access some 200 - 300 million
barrels expected to be recoverable from pads located within the
disturbed corridor alongside the Dalton Highway and Trans Alaska
Pipeline System (TAPS). The second stage is expected to access the
remainder from pads located further to the South and West (i.e.
outside the disturbed corridor).
Netherland, Sewell & Associates, Inc. ("NSAI") is developing
a resource estimate for Ahpun, including both the deeper horizons
tested in the Alkaid-1 and Alkaid-2 wells and the remaining,
geologically shallower shelf break horizons encountered in Pipeline
State, Talitha-A and flow tested in the Alkaid-2 re-entry. This
report will be issued around the middle of 2024.
NSAI has already delivered an independent 2C contingent resource
estimate for the Kodiak Field with oil, condensates and natural gas
liquids ("NGL") totalling nearly 1 billion barrels. Pantheon has
previously presented analysis based on reducing maximum depths of
burial ("Dmax") leading to expected improvements in reservoir
properties in Kodiak moving further to the Northwest from Theta
West-1. The Company is continuing its analysis of the updip
resources to support the future appraisal programme prior to
Kodiak's FID in 2028. Pantheon believes these additional resources
will support the Company's previously disclosed management estimate
of total expected ultimate recovery ("EUR") for Kodiak of 1.78
billion barrels.
Development of the discovered resources will be conducted in a
similar manner to the Permian Basin, with year-round operations
from well pads connected by gravel roads. This is normal practice
on the North Slope. The precise transition from Ahpun to Kodiak
development will be an economic decision following FID for Kodiak.
From the portfolio of available drilling locations, Pantheon will
allocate capital to the highest value well or cluster of wells,
optimising for the value delivered to the aggregate portfolio.
The eventual optimum development plan may result in incremental
pads moving from East to West or it may involve more significant
step outs to the Northwest (expected to contain the highest quality
resources). The planning assumptions for the base case development
are explained below - assuming all drilling locations exhibit only
the reservoir quality encountered in the test of the "Alkaid ZOI"
horizon in the Alkaid-2 well, as reported early in 2023. In
reality, the Company expects the resources in the Northwest of the
193,000 acre lease position to consist of more than 1,000 ft of pay
with up to 50% of the reservoir exceeding the commonly recognised
threshold to be classified as conventional.
Capital Investment and Funding
The entire development of Ahpun and Kodiak, using the
conservative planning basis noted above, is likely to require more
than 2,000 wells, including gas and water injection wells, over the
long life of the field. This will cost approximately $25 billion in
today's money. This seems like a very large sum, but in common with
many such projects, most of the development costs will be incurred
after the fields have begun production and through the reinvestment
of production revenues and debt. The more relevant figures are:
-- the capital that needs to be invested prior to production start-up;
-- the maximum negative cumulative cashflow prior to being able
to access secured debt (expected to be reserves based lending);
and
-- the maximum negative cumulative cashflow beyond which future
capital and operating costs are self-funding - the Company refers
to this as financial self-sufficiency.
These sums have previously been estimated conservatively at $120
million prior to production start and $300 million maximum negative
cumulative cashflow on the Ahpun development (plus potentially $50
million of Kodiak appraisal costs). A more detailed description of
how these figures can be calculated is provided below.
The net negative cashflow up to the point at which debt funding
could be drawn down depends on a number of factors, including how
the Company's oil is marketed (in whole cargoes or lifted in
combination with other producers) and the precise timing of when
additional groups of wells are brought on stream. For simplicity,
Pantheon's development plan modelling assumes no reserve based
lending is available until the first year's nine production wells
are all on stream.
The strategy for minimising dilution of existing shareholder
value is built on three main pillars:
I. Vendor financing - negotiating a delay in the timing of
payments for services during the first twelve months of activity,
at a commercial interest rate, in return for a long term, directly
negotiated contract for the proposed 1,000+ wells based on market
rates and margins with incentives for beating cost targets to
create a win-win relationship. The share of costs that could be
subject to such arrangements is expected to exceed $100 million
during the first 12 months of development, of which the majority
will be incurred after first production.
II. Offtake financing - negotiating bankable contracts from
buyers of marketable liquids and, if appropriate, natural gas.
Liquids have the potential to be financed through volumetric
production payments, among other options. The State of Alaska has
made significant progress in moving a gas pipeline project forward
for delivery of natural gas to South Central Alaska with subsequent
exports of LNG. Pantheon believes it would be well positioned to
secure some sales of associated gas that would otherwise be
reinjected into its reservoirs.
III. Reserves based lending - once production is established
from enough wells to meet lender risk management criteria on
diversification, the Company will seek to draw down on lending
facilities, which would have been arranged prior to production
start-up, supported by borrowing base calculations from mutually
accepted third party engineers. The modelled production profile for
a typical production well ("type curve") is outlined below in the
Company's "Planning Basis". For illustrative purposes, based on
previous calculations, each such modelled incremental well brought
on stream has the potential to deliver an estimated $20-$25 million
of fresh liquidity, allowing a rapid drawdown on such a facility up
to an initial target of $250 million; sufficient to achieve the
total of $350 million prior to Kodiak FID and to achieve financial
self-sufficiency when combined with other funding channels.
In aggregate, other than the expected satisfaction of the
Convertible Bond, due for repayment by mid December 2026, Pantheon
intends to reduce the amount of additional equity capital required
substantially. However, the timing and quanta of each of these
funding options is uncertain and there can be no guarantees of
success with all or any of these options. The Company's confidence
in achieving a successful outcome is, however, built on its
conservative planning basis that provides substantial upside to
potential funders above the base case.
In parallel with these funding avenues, the Company is exploring
options with one or more potential farm-in partner(s) who, if
discussions were to progress, might contribute to the capital costs
of bringing the assets on stream in return for a working interest
in the leases or economically equivalent structure. Any transaction
is only likely if it represents less dilution of value to
shareholders than alternative avenues. Pantheon management believes
there is appreciable strategic value in its operatorship and 100%
working interest in the resources.
Base Case for Development Planning
For conceptual development planning purposes, Pantheon has
developed an Ahpun field "type curve" - a term meaning a
representative, typical well production profile. The Company
applied the most conservative of these estimates for rates and
volumes to generate the type curve (previously presented at the
June 28(th) , 2023 webinar).:
-- IP30 (average production rate over the first 30 days) of
1,500 barrels per day ("bpd") of marketable liquids
-- 1 million barrels of marketable liquids EUR
For conservatism, this was derived from the performance seen in
the 90 day flow test of the deepest, lowest quality reservoir
horizon in the Ahpun field:
Year 1 2 3 4 5 6 7 8 9 10
barrels
per day 953 466 298 225 183 154 134 119 107 96
---- ---- ---- ---- ---- ---- ---- ---- ---- ---
The analysis results in a 60% first year decline rate (from
1,500 bpd in the first month of stabilised production to 600 bpd in
the 13(th) month) before levelling off to an ultimate 10% decline
rate. This type curve was created by estimating the performance
from doubling the lateral length (from 5,000 ft to 10,000 ft) and
doubling the frac efficiency to 40% (i.e. less than half the more
typical 80% experienced in major unconventional plays in the US
lower 48 and less than the c. 50% achieved in the subsequent frac
of the shallower horizon in the Alkaid-2 wellbore). In other words,
the conceptual development plan is based on there being no
improvement in well performance beyond that demonstrated to be
feasible at the Alkaid-2 location.
The successful re-entry of the Alkaid-2 well to test the
shallower reservoir interval demonstrated the benefit of a revised
frac design (fewer perforations, finer proppant, higher pump rates
and additional chemicals to prevent emulsion blockage in the
reservoir), justifying the Company's confidence in the opportunity
to more than double the frac efficiency. The reservoir quality in
the geologically shallower horizons of Ahpun (which are thicker and
better developed to the south and west of the Alkaid-2 location, is
an order of magnitude higher than was encountered in the 5,000 ft
lateral. Furthermore, the initial estimates of the gas-oil ratio
are lower than experienced in the original 90 day test, implying
upside from the perspective of fluid composition. None of these
incremental benefits arising from the subsequent field test are
currently incorporated into the type curve.
This conservative development planning basis implies that some
650 wells would be required to produce the entire contingent
recoverable resource based on 60 acres of drainage area per well
(assuming 10,000 ft laterals and 300 ft horizontal frac
propagation) including the gas/water injection wells.
To give an idea of the resilience of the economics of these
wells at $80 per barrel ("bbl") ANS (the quoted price of Alaskan
North Slope Crude, delivered to a US West Coast Refinery), the
payback on this profile is estimated to be less than 12 months.
Even at $70/bbl, this payback period is calculated at less than a
year.
In planning the Kodiak Field base case, the Company has used the
same type curve and cost. This is despite a reservoir with some
1,000 ft of productive pay, the shallower depth of wells and the
expectation of superior quality conventional reservoir representing
50% of the net pay. This means that a large number of wells may not
require 10,000 ft laterals with 60 frac stages, but instead can be
completed at materially lower cost as conventional horizontal or
highly inclined producers with a single longitudinal frac
(analogous to wells in the Kuparuk Field and the Santos operated
Pikka development).
Future appraisal wells will determine the optimum development of
Kodiak but, in the interests of conservatism, the Company is
assuming that there will be no improvements in reservoir or fluid
properties beyond those already encountered in the Alkaid-2 well
(i.e. ignoring the increase in average porosity confirmed in Theta
West-1 and the anticipated continuation of the improvements to the
Northwest).
Detailed Cost Breakdown for Capital Cost to First Production
In previous webinars and press releases, the Company has
estimated the costs of achieving first production at $120 million,
consisting of:
-- $20 million for the tie-in to the TAPS main oil line (with a capacity of 200,000 bpd)
-- $20 million to upgrade the existing production facilities,
including a chiller for NGL recovery
-- $20 million each for three production wells for a total of
$60 million for drilling and completion
-- $20 million for overheads between now and production start up
Again, for the avoidance of doubt, the Ahpun FID is for the full
field development. The $120 million outlined above is just the cost
of the three wells expected to be drilled by the time production
starts up as well as the other items listed above. It is assumed
that the cost of converting the Alkaid-2 well to be an injector is
included in this total (included in the cost of facilities
upgrade).
Detailed Calculation of Maximum Cumulative Negative Cashflow
The Company has estimated the maximum cumulative negative
cashflow at $300 million (before any financing arrangements are
included and excluding approximately $50 million for further
appraisal wells at Kodiak). This is based on drilling 10 wells in
the first year (of which eight would be production wells) and a
further 16 wells in the second year (of which 12 would be
production wells). Modelling the first and second year averages
from the type curve, and adding the wells evenly throughout the
year after production start-up, results in average production
through the seven months to the end of the first year of
development of approximately 5,300 bpd (4,350 bpd net of
royalties). Pantheon's latest estimates of operating costs are
$12,500 per well per month plus $3/bbl of gross production. Thus,
the position at the end of the first year of development if ANS
averaged $80/bbl is modelled to be:
Year 1 Costs ($287 million)*
$120 million to first production
$105 million for seven further wells at $15 million each
$30 million of Capex for Phecda pad & production facility to
allow two rigs operating
$5 million of Opex (on 5,300 bpd average)
$8 million of Tariffs & Tankers
$5 million of G&A Overhead
$14 million of Royalties
Revenues before tax ($81 million)*
$81 million (on 5,300 bpd average x $72/bbl after quality
adjustment)
Cumulative negative net cashflow by end of first year = $206
million*
*modelled numbers may not add exactly because of rounding
In the second year, again with ANS Crude selling at $80 per
barrel, this nets back to around $72/bbl at the entry to the
pipeline after adjusting for quality. Production during the second
year is modelled to average 12,700 bpd (10,400 bpd net of
royalties), which would yield approximately $270 million of
revenues net of royalties. Tariffs of $32 million, capital costs of
around $240 million and operating costs including G&A of around
$22 million during the year would result in an approximate
breakeven for the year but the peak net cumulative cash outflow
would be around $230 million as a result of production building up
through the year. The incremental expected cumulative outflow to
get to the $300 million (maximum negative cumulative cashflow on
the Ahpun development) figure assumes worst cases for marketing of
ANS crude and TAPS transportation services.
The precise moment that financial self-sufficiency is achieved
is sensitive to the exact timing of wells coming on stream and the
price realisation. Pantheon's strategy will be to maximise
liquidity to weather the inevitable expected "unexpecteds" (events
that cannot be defined without the benefit of hindsight but are
anticipated to occur) without diluting more than necessary to
preserve value for existing shareholders.
Company Best Estimate for Development Planning (based on SLB
Analysis)
Development studies by SLB indicate an alternative type curve
for the Alkaid horizon substantially in excess of Pantheon's base
planning case estimates. Utilising this analysis, Pantheon has
created a best estimate using an IP30 of 2,700 bpd and EURs of 1.65
million barrels. Improvements seen in the shelf break horizons in
Ahpun and the updip portions of Kodiak would see rates and volumes
comfortably exceeding these.
Utilising these estimates, and modelling monthly production
rates for each well as it is added, the rate of production build up
is more rapid with a peak cumulative net cash outflow of $160
million and financial self-sufficiency being achieved before the
end of 2026. However, it seems more prudent to plan on the basis of
the more conservative type curve.
-ENDS-
Further information, please contact:
Pantheon Resources plc +44 20 7484 5361
David Hobbs, Executive Chairman
Jay Cheatham, CEO
Justin Hondris, Director, Finance and Corporate
Development
Canaccord Genuity plc (Nominated Adviser
and broker)
Henry Fitzgerald-O'Connor
James Asensio
Gordon Hamilton +44 20 7523 8000
BlytheRay
Tim Blythe
Megan Ray
Matthew Bowld +44 20 7138 3204
In accordance with the AIM Rules - Note for Mining and Oil &
Gas Companies - June 2009, the information contained in this
announcement has been reviewed and signed off by David Hobbs, a
qualified Petroleum Engineer, who has nearly 40 years' relevant
experience within the sector.
Notes to Editors
Pantheon Resources plc is an AIM listed Oil & Gas company
focused on developing the Ahpun and Kodiak fields located on state
land on the Alaska North Slope ("ANS"), onshore USA where it has a
100% working interest in 193,000 acres. Certified contingent
resources attributable to these projects exceeds 1 billion barrels
of marketable liquids, located adjacent to Alaska's Trans Alaska
Pipeline System ("TAPS").
Pantheon's stated objective is to demonstrate sustainable market
recognition of a value of $5-$10/bbl of recoverable resources by
end 2028. This will require targeting Final Investment Decision
("FID") on the Ahpun field by the end of 2025, building production
to 20,000 barrels per day of marketable liquids into the TAPS main
oil line, and applying the resultant cashflows to support the FID
on the Kodiak field by the end of 2028.
A major differentiator to other ANS projects is the close
proximity to existing roads and pipelines which offers a
significant competitive advantage to Pantheon, allowing for
materially lower infrastructure costs and the ability to support
the development with a significantly lower pre-cashflow funding
requirement than is typical in Alaska.
The Company's project portfolio has been endorsed by world
renowned experts. Netherland, Sewell & Associates ("NSAI")
estimate a 2C contingent recoverable resource in the Kodiak project
that total 962.5 million barrels of marketable liquids and 4,465
billion cubic feet of natural gas. NSAI is currently working on
estimates for the Ahpun Field.
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END
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