Pantheon Res Regulatory News (PANR)

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 28th, 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:

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 13th 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:

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.